China’s Gas Development Strategies

Shell and DRC Editors

Advances in Oil and Gas Exploration & Production

Advances in Oil and Gas Exploration &Production

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Rudy Swennen, Department of Earth and Environmental Sciences,K.U. Leuven, Heverlee, Belgium

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Shell International and The DevelopmentResearch Center (DRC) of the StateCouncil of the People’s Republicof ChinaEditors

China’s GasDevelopment Strategies

EditorsShell InternationalShell CentreLondonUK

The Development Research Center(DRC) of the State Council of thePeople’s Republic of ChinaBeijingChina

ISSN 2509-372X ISSN 2509-3738 (electronic)Advances in Oil and Gas Exploration & ProductionISBN 978-3-319-59733-1 ISBN 978-3-319-59734-8 (eBook)DOI 10.1007/978-3-319-59734-8

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Foreword I

How to Encourage the Development of Natural Gasas a Major Energy Source in China

Widespread development of natural gas is a textbook approach adopted bydeveloped countries and in emerging economies during optimisation andupdating of energy systems. It is also widely recognised as being a keytransitional route in the move towards future sustainable energy sourcesystems. From the perspective of China, whether or not to follow this generalpattern and the challenges, opportunities and policies required to achieve thedevelopment of natural gas are issues of major concern to policy makers,academics and the business world in general. In order to respond to thesequestions, following from the previous instalment of the China Mid- toLong-term Energy Development Strategic Joint Study, the State CouncilDevelopment Research Center and Shell organised a number of internationaland local institutions to join forces in conducting further strategic researchinto the development of natural gas in China. This has received extensivesupport from both the Chinese and British governments, and on December 2,2013, Premier Li Keqiang and Prime Minister David Cameron witnessed thesigning of bilateral cooperation documents in respect of this. After a year anda half of research, the results of this research have been collated, and form thebasis for the following primary viewpoints and judgements.

Global Natural Gas Development Trends Against the Backdrop of theShale Natural Gas Revolution

1. There are plentiful global natural gas resources, and these will go onto take a more significant role in future energy systems. There aresufficient global natural gas resources to allow for an additional 200 yearsof extraction, conventional natural gas and unconventional natural gas,each accounting for about a half. There are 50 years of viable confirmedreserves, while the rate at which further reserves are confirmed is greaterthan the consumption. In the last 10 years, there has been 2.7% growth innatural gas consumption, making it the fastest growing fossil energy type.In 2014, natural gas accounted for 23.8% of global energy consumption,

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and it is predicted that by 2035 natural gas will have become the largestglobal energy source.

2. Natural gas trade and pricing approaches will undergo majorchanges, and there will be an increase in terms of the interconnect-edness of the global natural gas market. The increase in importance ofLNG in addition to the rapid increase in the number of LNG exportingand importing nations will increase the fluidity of the global natural gasmarket. Natural gas pricing mechanisms will automatically adjust. Cur-rently, the price of 43% of global wholesale natural gas is established bymarket competition and is not pegged against oil prices. As both trade andpricing models change, there will be an increase in the interconnectednessof the three main regional markets of the Americas, Europe and Asia,with the difference in prices shrinking, and developing towardsintegration.

3. In the short term, there will be a large drop in natural gas prices, butin the long term the price of imported natural gas in China will not beexcessively low. There has recently been a relaxation in terms of naturalgas supplies, with a large drop in natural gas prices, as the price ofJapanese LNG has dropped from $20/MMBtu in 2014 to the current priceof around $7. But in the long term, the price of natural gas when it arrivesat Chinese coastal regions from Australia, the United States and Canada,the main newly developed sources of LNG, will not remain below the$10/MMBtu level for long due to development, liquefaction and transportcosts being fairly high.

4. China’s share of the global natural gas market is gradually rising,making it necessary to become more actively involved in the inter-national natural gas market. In 2014, the share of global natural gasconsumption accounted for by China was less than 5%, but by 2030 thiswill have grown to between 9% and 12%. There are abundant globalnatural gas resources in China, and China also has fairly large natural gasresources. Increases in natural gas consumption in China will not result ina pronounced increase in the global market price. Apart from this, Chinashould not always be on the receiving end of fluctuations in the inter-national natural gas price, and it should be possible for the nation to take amore active role in the international natural gas market via trade andinvestment.

Changes in the Mode of Supply of China’s Natural Gas in the Futureand Main Sources of Conflict

1. China’s economic development is entering a stage of a “new normal”,with energy demand entering a stage of medium rate increases. Therate at which China’s economy has been developing has already transi-tioned from a high rate of growth towards a medium-high rate of growth.There will be major changes in economic structures, with the tertiaryindustry proportion growing while the secondary industry proportiondrops. A peak in steel, cement and other heavy/chemical industries will

vi Foreword I

occur in the period surrounding the 13th Five-Year Plan. Energy demandwill revert from a high growth rate to a medium growth rate, while it ispredicted that by 2020 total energy consumption may reach 5 billiontonnes of standard coal. Between 2016 and 2020, average annual growthwill be approximately 3%, while by 2030 it is possible that energyconsumption may have reached 5.7 billion tonnes of standard coal.

2. If appropriate policies are put in place, China’s natural gas demandwill still continue to grow relatively quickly. Development of the ser-vice industry, expanding urbanisation and atmospheric pollution controlwill drive continuous growth in natural gas consumption. Quantitativeanalysis indicates that, under the current policy climate, natural gasconsumption will have reached 300 billion cubic metres by 2020,reaching 450 billion cubic metres by 2030, respectively accounting for8.0% and 11.0% of energy consumption. With enhanced environmentalmeasures and imposition of a carbon tax, natural gas consumption wouldreach 350 billion cubic metres by 2020 and 580 billion cubic metres by2030, respectively accounting for 10.8% and 15.4% of energy con-sumption. This is a significant increase when compared to the 5.8%proportion in 2014. Residential gas, natural gas heating, transport gas,industrial gas and power generation gas will be fields in which a relativelyrapid rate of growth of natural gas use occurs.

3. There is significant potential in terms of natural gas supplies withinChina, natural gas import capacity will increase by a large amount.China actually has fairly plentiful natural gas resources. Based on Min-istry of Land and Resources data, there are 40 trillion cubic metres ofaccessible natural gas reserves (dynamic appraisal of national oil and gasreserves in 2013), while there are 25 trillion cubic metres of shale naturalgas and 10 trillion cubic metres of coalbed methane. Annual detection ofnew reserves is increasing rapidly, reaching 1.1 trillion cubic metres in2014. However, extraction is both difficult and costly, requiring bothtechnical and institutional innovation, before potential resources can beconverted to actual output. Under the current institutional arrangements,the natural gas output for 2020 and 2030 will be 230 billion cubic metresand 380 billion cubic metres respectively, while shale natural gas willaccount for 40 billion cubic metres and 80 billion cubic metres respec-tively. If institutional systems were reformed, the 2020 and 2030 naturalgas output quantities would be 270 billion cubic metres and 470 billioncubic metres respectively, shale natural gas accounting for 60 billioncubic metres and 150 billion cubic metres respectively. In terms ofimports from abroad, pipeline gas import capacity will reach between 135and 165 billion cubic metres by the end of 2020, with LNG importsreaching approximately 65 billion cubic metres. If one then adds to thatthe coal gasification output capacity currently planned for construction, in2020, there will be a supply capability of between 415 billion and 495billion cubic metres. By 2030, between 665 billion and 800 billion cubicmetres of supply capacity will exist.

Foreword I vii

4. Pronounced changes will occur in supply and demand relationships,requiring correct handling of the challenges faced in the developmentof natural gas. From the above supply and demand analysis, supply anddemand of natural gas will begin to exhibit a wider balance over the next5 to 10 years. Supply quantities will no longer be a major factorrestricting the development of natural gas. Low efficiency, high prices,difficulties in transport and inflexible institutional arrangements willgradually become more significant, while the main sources of conflict inthe development of the natural gas industry will undergo a transformation.If appropriate adjustments are not immediately made to policy, themomentum necessary to achieve a rapid rate of natural gas growth will belost and this will have an enduring effect on the development of thenatural gas industry.

Strategy for the Development of Natural Gas Over the Next 15 Years

1. Great efforts should be made towards developing natural gas, inorder to develop natural gas into becoming a major energy source.Natural gas is clean, highly efficient and convenient. Regardless ofwhether it is the issues of controlling atmospheric pollution or increasingthe efficiency of energy systems that concern us, or the need to providepeak regulation that will be necessary with the future development ofrenewable energy on a huge scale, each of these requires large-scaledevelopment of natural gas. Natural gas presents effective investmentopportunities, due to its potential for massive growth allied with the factthat there is no excess output capacity. If access to markets were relaxed,there is the potential for annual investment of as much as CNY 400billion, which would result in a 0.6% increase in GDP. It is safe to saythat expansion of effort in the development of natural gas, in order todevelop it into a major energy source, conforms to the general patternsencountered in the evolution and updating of global energy systems andthe urgent needs for economic and social development encountered inChina.

2. Natural gas should be developed in a safe, highly efficient and sus-tainable manner. By safe, we are really referring to two layers of safetyinvolving natural gas resource assurances and manufacturing and opera-tions, as these are prerequisites for the development of the natural gasindustry. Increasing local supplies in addition to expanding the sources ofimported gas and increasing modes of import are both essential to thisprocess. At the same time, national natural gas network connections needto be improved, which should be accompanied by construction ofmulti-level natural gas storage in order to ensure stable operation. Highefficiency relates to increasing efficiency in natural gas exploration,transport and usage, as this will form the foundation of the developmentof natural gas in China. Sustainability relates to the balancing of eco-logical and environmental needs that the development of natural gasallows, this being a major aim of developing natural gas. At the same timeas extraction, delivery and usage occur, special attention needs to be paid

viii Foreword I

to environmental protection and the sustainability of resource supplies.Sustainability concepts must be applied to the design and planning of theoverall energy systems. In particular, this can be achieved by ensuringthat the external costs of environmental pollution are fully reflected, inorder to allow for the full adoption of natural gas.

3. Clarification of the strategic aims and pathways to be adopted in thedevelopment of natural gas. The aim is that by 2020, the share ofprimary energy consumption accounted for by natural gas should reach10%, with consumption increasing to 350 billion cubic metres. By 2030,the share of primary energy consumption accounted for by natural gasshould reach 15%, with consumption reaching 580 billion cubic metres.The main pathways are: guiding and nurturing the natural gas con-sumption market, accelerating the diversification of upstream natural gassupplies, creating a safe, fair and transparent natural gas pipeline transportand storage network, relying on technical innovation to improve thetechnical standards of the industry, actively promoting natural gas pricingreforms, and creating a modern natural gas market system and govern-ment regulatory system.

Guiding and Nurturing the Natural Gas-consuming Market, Expandingthe Scope of Natural Gas Usage

1. Key to expanding the use of natural gas is improving its economiccompetitiveness. Central heating, natural gas power generation andindustrial fuels have a low natural gas price tolerance and, under thecurrent pricing system, natural gas is not competitive. To increase naturalgas competitiveness would, first, require the internalisation of externalcosts, the effects on the environment and health of energy use wouldtherefore need to be reflected, which would allow greater advantage to betaken of natural gas environmental strengths. Second, natural gas usageefficiency needs to be improved, an improvement in efficiency helping torestrict the increasing costs of energy usage.

2. Increase environmental monitoring and improve energy usage effi-ciency, with the replacement of dispersed coal usage. The replacementof dispersed coal usage is one of the most important areas in whichnatural gas should be developed. First, environmental monitoring wouldbe increased, with online coal boiler pollution and emissions reductiondetection systems, capable of real-time monitoring of waste gas emis-sions. Second, more effort would be put into energy-saving upgrades,improving energy usage efficiency, with the government providing acertain amount of fiscal support. Third, in China’s eastern and centralregions, where there are major issues in terms of controlling atmosphericpollution, no additional new coal-fired boilers should be permitted, withgas use becoming obligatory. It is predicted that by 2030, the replacementof dispersed coal usage would require 280 billion cubic metres of naturalgas.

Foreword I ix

3. Enhance planning and technical standards, accelerating the devel-opment of gas use in transport. In transport, natural gas is capable ofreplacing oil. It reduces emissions and has major significance in terms ofenergy safety and environmental protection, apart from which it is botheconomical and viable. The construction of gas filling stations andinfrastructure should be accelerated. Industry standards that encompassthe complete production chain should be created so as to adopt suitablesafety and regulatory standards. Full advantage should be taken of thepower of government purchasing to lead this development, increasing theusage of natural gas-powered buses. It is predicted that by 2030, gas usedin transport will reach 75 billion cubic metres.

4. Improve pricing mechanisms, encouraging appropriate developmentof gas power generation. Where base load generation is concerned,natural gas does not present any advantages compared to coal. But naturalgas is well suited to peak regulation and integrated thermoelectric cool-ing, both of which are essential aspects of power systems. First, there is aneed to establish peak and trough electricity and gas prices, which willallow better usage of the peak regulation effect, thereby allowing lowprice gas to be used to generate high-price electricity. Second, the loca-lised manufacture of key technology needs to be achieved, which willreduce equipment and maintenance costs. Third, the introduction ofenvironmental taxes is needed, accompanied by carbon trading, whichthen allows advantage to be taken of the benefits natural gas powergeneration presents in terms of being clean and environmentally friendly.It is predicted that by 2030, peak regulation and base load generation willaccount for between 60 and 70 billion cubic metres of natural gas, whilegas consumption for cogeneration and distributed type energy sourcegeneration will be approximately 100 billion cubic metres.

5. Peak regulation, residential and chemical industry gas pricing,reduction of cross-subsidising between different users. Residential usegas and chemical industry gas have been priced below the cost of supplyfor a long period of time, the subsidies for this having been borne by otherusers. Residential use gas prices should be adjusted up to above the gassupply cost, with most residential users being perfectly capable of with-standing price increases, while special case social groups could be pro-vided with subsidies. From the point of view of chemical industry users,establishing market mechanisms such as peak and trough gas pricing andinterruptible gas pricing would still provide them with price discounts.However, maintaining prices at less than the cost of supply in the longterm is not sustainable and there is a need to establish a timeframe forbringing chemical industry gas prices into line.

Introduction of New Market Entities, Large-scale Increases in NaturalGas Supplies

1. Introduction of new development modes to the fields of conventionaloil and gas. China has ample sources of gas, but key to supply is the issueof institutional regulation. New development modes need to be introduced

x Foreword I

to the fields of conventional oil and gas. One of these is the relaxation ofmarket access, which would involve allowing state-owned energy com-panies that already own shale natural gas rights, or overseas energycompanies already active in the oil and gas industry access to conven-tional oil and gas mineral rights. The second would be adjustment of theminimum prospecting investment: the minimum prospecting investmentshould be increased by a factor of between three and five, which wouldchange the current phenomena of areas being occupied without anyprospecting taking place. The third would be the creation of confirmednatural gas reserve trading mechanisms and a trading platform, whichwould then allow the development of latent reserves by allowing thecirculation of mineral rights.

2. More extensive and bolder regulatory reform, establishing regionaltrials in the fields of unconventional oil and gas. Not only doesunconventional gas require new technology, it has an even greater needfor institutional reform. It would be possible to establish a regional trial inthe Sichuan basin and surrounding areas, which would explore the fol-lowing areas. First, regarding mineral rights management, resources otherthan those currently under production by one of the three main oilcompanies, or those which have been confirmed and where extractionwork is currently taking place, should be uniformly put out to tender.Second, regarding market access, it should be provided not only to otherstate-owned enterprises, but also to privately owned enterprises andoverseas businesses. With respect to foreign investors, independentlyowned foreign enterprises that satisfy technical and environmental stan-dards and that have passed state safety assessments should be allowedaccess. Apart from this, new breakthroughs could be made in terms ofdistribution of benefits accruing from such resources, reform of mixedownership structures and environmental monitoring.

3. Diversification of imported gas sources and importing modes. Ingeneral terms, China’s natural gas imports are secure. Of greater impor-tance is diversification in terms of sources of imports, entities involved,contract durations and pricing mechanisms in order to spread risks outmore evenly. First, this would require increased LNG import fromIndonesia, Australia, North America and East Africa, which would allowfurther diversification of the sources of imported gas. Second would bethe introduction of long-term, mid-term and short-term spot tradingcontract portfolios, with pricing based on a combination of oil and typicalnatural gas centre pricing indices. Third would be the introduction of newpurchasing entities, encouraging large-scale end users to buy natural gasfrom the international market.

4. Development of natural gas trade and overseas investment from acommercial perspective. Encourage overseas investment in natural gas,including regional investment and investment in individual nations whichare major sources of gas imports. Investment should satisfy the strategicdirection of China’s policies, in addition to ensuring that such activity iscommercially profitable to the greatest extent, basing project cooperationon economic considerations. Of course, expectations should be realistic

Foreword I xi

where it comes to high-price contracts that have been signed in the pastand an approach should be sought to ensure that the historical coststherein are shared by both commercial enterprises and the nation.

Enhanced Planning and Construction of Pipeline Networks and GasStorage Facilities, in Order to Ensure Interconnected Networks and FairAccess

1. Accelerate the construction of basic infrastructure, to overcomestorage and transport bottlenecks. Efforts need to be made to ensurethat by 2020 the pipeline network extends to 150,000 km, with a gasdelivery capacity of 400 billion cubic metres. This should be extended to250,000 km by 2030, and gas delivery capacity should exceed 690 billioncubic metres, establishing the “western gas piped east, northern gas goingsouth, maritime gas reaching the land, supplies being based on whicheveris nearest” approach to supply. The working capacity of gas storagefacilities should reach between 35 and 40 billion cubic metres by 2020,reaching 65 billion cubic metres by 2030. Large-scale gas storage banksand LNG tanks capable of providing seasonal peak regulation, small-scaleLNG daily urban peak regulation tanks, CNG spherical tanks and asso-ciated storage installations need to be constructed.

2. Planning and realisation of interconnected networks needs to beenhanced. The interconnectedness of basic infrastructure is key toensuring the safety and stability of natural gas operations. The nationalpipeline backbone requires interconnected junction stations and branchlines, provincial pipeline network backbones connecting to distributionhubs, thus allowing flexible distribution, with subterranean gas storageand LNG receiving stations connecting to the state-owned long-distancepipeline backbone, in conjunction with the creation of regional networksbased on adjacent provinces and cities. During the planning stage this willrequire effective cooperation, which will allow connection between dif-ferent networks; government departments will need to adopt a unifiedapproach to the construction of infrastructure, in addition to providingback-up during both implementation and subsequent follow-up.

3. Introduction of societal capital, encouraging the diversification ofinvestment entities. Under the premise of a unified plan, involvement byall types of capital in natural gas infrastructure investment should beencouraged. The three main oil companies should open up constructionof the national pipeline backbone to outside investment, allowing theentry of societal capital. The planned Western No. 4 line, the WesternNo. 5 line, the new Guangdong–Zhejiang line and other such majornational natural gas backbone pipelines should be constructed as jointventures using societal capital. Removal of the monopoly of provincialgas companies for the construction of provincial infrastructure, com-pletely opening provincial branch pipeline construction rights to outsideinvestment, will allow companies that are appropriately qualified to takepart in construction and operation in a compliant manner.

xii Foreword I

4. By clarifying and establishing functional roles and regulatory oper-ations, it is possible to achieve the separation of pipeline service andsales businesses and to allow third-party access. Promote the divisionof pipeline services and sales businesses in terms of business operations,finances and legal status. Regulate the scope of business operations,costing rules, operational modes and openness of information. Introducethird-party access to services as soon as possible. Ensure effective mon-itoring of access contracts, service prices and service quality, in order toensure that operators provide non-discriminatory services.

5. Clarify responsibility for gas storage and improve pricing mecha-nisms in order to ensure gas supply security. Implement a tiered gasstorage management regime. The state can be responsible for strategicnatural gas storage facilities, upstream natural gas companies can bear theresponsibility and duties of providing seasonal peak regulation andemergency storage, and individual provincial gas companies can bear theresponsibilities and duties of providing daily and hourly peak regulation.Implement peak and trough pricing for various types of users, in order toencourage sensible consumption, finally acting to compensate for troughsand peaks. Establish a real-time, sensitive advance warning emergencyresponse system.

Accelerate Development of Pricing Mechanism and Government Regu-latory System Institutional Reforms, Creating a Modern Natural GasMarket System

1. Optimise current pricing approaches, in order to resolve conflictingpricing. First, the netback method needs to be implemented as soon aspossible. The reference oil price level and pricing conversion indices needto be adjusted, as these should reflect changes in the cost price of alter-native energy sources and should not be based on the previous price ofhigh cost gas imported by the three large oil companies. At the same time,the pricing adjustment frequency needs to be changed, with the aim thatseasonal pricing adjustments should be introduced. Second, the transportcosts and prices applied to long-distance pipelines, branch pipelines,provincial pipelines, municipal pipelines and distribution pipeworkshould be established in a scientific and appropriate manner. Greaterregulation should be applied to this, in order to ensure appropriate returnson pipeline investment. Third, a revision of metering standards and val-uation methods is necessary, with conversion from flow quantity-based ormass-based pricing to calorific-based pricing. It will also be necessary toaccelerate elimination of inappropriate charging activities by localgovernment.

2. Encourage market-set natural gas prices, accelerating the creation ofnatural gas trading centres. In locations where natural gas sources arerelatively diversified and there are fairly abundant supplies, such asShanghai, Guangdong, Zhejiang and Jiangsu, remove regulation of theprovincial and municipal gate prices, the prices then being set directly byupstream and downstream users. Encouraging the creation of regional

Foreword I xiii

trading centres would then accelerate the creation of Shanghai, Beijing,Guangdong, Hubei and Xinjiang natural gas trading centres. Effortsshould be made to establish Shanghai as the international trade andpricing centre. The creation of natural gas trading centres must commencewith the introduction of spot trading, at which point futures trading canthen be developed.

3. Improve overall energy regulation and establish a single, indepen-dent, specialist regulatory system. Increase efforts to establish an overallenergy regulator, which will be responsible for establishing energystrategy, planning and policy; it would also be responsible for adjust-ments in the balance of total energy sources, thus ensuring energysecurity, while regulating energy structures, being responsible for bothenergy conservation and energy efficiency. This would also be respon-sible for greater data collection and analysis, energy-related scientific andtechnological innovation and international energy cooperation. Create aunified energy regulator, which in addition to having environmental andterritorial resource regulatory functions would gradually implement reg-ulation of the economic and social aspects of the complete energy pro-duction chain, creating an independent, unified, specialist energyregulatory body and a comprehensive regulatory system.

4. Deepen natural gas-related legislation, establishing a complete legalsystem. Establish a comprehensive legal framework, centred on an “Oiland Natural Gas Law”, which sets out natural gas-specific legislation.One of the main objectives is to perfect resource ownership rights andexploration and extraction contracts. Another is to apply productionsafety and environmental subsidies, transnational investment, import andexport trade and other such legislation to the regulation of infrastructureconstruction and operation, storage, sale and usage, safety and advancewarning and emergency response. The relationship between the Oil andNatural Gas Pipeline Protection Law and other laws must be coordinatedaccording to legal interpretation.

The above topics have been formulated based on many different sug-gestions after extensive discussion. It would be right to say that these topicsconsist of an open, collaborative and inclusive study, with the membersof the various teams coming from many different institutions, with Chineserepresentatives coming from the government, research institutes and stateenergy companies as well as private enterprises. The achievements of thisproject are based on the assimilated knowledge of all of these parties andinvolve an ongoing knowledge-sharing process. In addition, when it came toestablishing the details pertinent to each area and the conclusions drawn, thiswas achieved through constant discussions between a number of consultantsfor each topic as well as being based on the suggestions of specialists in eachfield, and involved field trips to Shanghai, Zhejiang, Sichuan and Chongqingto properly assess each aspect of the production chain. During the course ofresearching this project, the research teams submitted many different internalreports, on topics including: negotiation of the China–Russia natural gas eastpipeline project; natural gas pricing reform; oil and gas storage; and shale

xiv Foreword I

natural gas development. They have also attracted comments from the StateCouncil on a number of occasions in relation to support for instigation of therelated reforms and policies. After the research into the topics in question wascomplete, the main conclusions and a summary report were submitted to theleaders of the State Council and attracted further comments and a positiveresponse. Of course, as open research, inaccuracies and oversights are dif-ficult to avoid, and experts and friends are invited to kindly provide theirfeedback and corrections where deemed appropriate.

Li WeiDirector of the State Council Development

Research Center

Foreword I xv

Foreword II

Joining Hands in Dealing with the Challenges Presentedby Energy and the Climate

On behalf of Royal Dutch Shell, it has been an honour to work with theDevelopment Research Center (DRC) of the State Council on China’s energyevolution. In our previous joint research, we looked broadly at the country’senergy system. In this project, we have focused on China’s gas development.

The aim was to provide insights to help shape China’s 13th Five-YearPlan, and this meant facing a very tight timescale. The DRC and Shell teamshave risen to the challenge. The standard of work is high, especially seeingthe pace at which the teams had to work, and the results are very rich andinsightful.

The teams have worked together exceptionally well, with each sidecontributing their own specific expertise. DRC brought a deep understandingof China’s energy system and the development challenges to be addressed,and this was complemented by Shell’s international experience and knowl-edge of global gas markets, regulatory mechanisms and the drivers of gasdemand.

Why is gas important? One of the world’s toughest challenges is meetinggreater long-term demand for energy. According to the IEA, global demandis expected to be 37% higher in 2040. Population growth, economic devel-opment and the need to provide access to modern energy to more people arecritical factors in bolstering demand. China is no exception to these trends.

China will need all sources of energy to meet demand, including naturalgas. But this is only one part of the picture. Another is the role the energysector can play in building a sustainable future if it reduces the impact ofenergy production and use on the environment. When burned for power, gasproduces around half the CO2 and one-tenth of the air pollutants that coaldoes. Using more gas will therefore help address China’s environmentalchallenges.

Natural gas is also flexible. A gas-fired plant takes less time to start andstop than a coal-fired plant. This makes gas an ideal partner to intermittentenergy sources like wind and solar, which are increasingly crucial to thefuture of the China’s energy system.

xvii

The 12th Five-Year Plan (2011–2015) showed a clear will to diversifyChina’s energy sources with a view to ensuring a cleaner, more sustainableenergy system. The promotion of natural gas was one of its key elements.The 13th Five-Year Plan (2016–2020) is expected to keep natural gas as apriority in China’s energy planning.

This report offers insights on how best to increase the share of gas in theenergy mix while balancing the objectives of energy security, energyaffordability and the environment. The DRC and Shell worked hard togetherto map out the different factors which drive the increasing share of gas in theglobal energy system; and how to apply the insights to the local context todetermine the potential for gas in China. Globally, a key factor has been thechanging level and mix of economic activity in various countries, such as aswitch from industry to services. The move to natural gas from other energysources, in particular oil, was another key factor.

Another important element of this study was grappling with complexeconomic and technical factors to develop credible outlooks for natural gasproduction in China. The teams have considered many sources of gas,including conventional gas, unconventional shale gas, coal bed methane andsynthetic natural gas production from coal.

This study was also aimed at building confidence that at expected levels ofgas imports, including both pipeline and liquefied natural gas (LNG), there issufficient diversity of supply that energy security will not be an issue forChina. Finally, the study looked at the international experiences of marketliberalisation and diversifying gas infrastructure and applied them to theChina context. This was done in a way which will benefit China but stillrespects its important political principles and values.

The work has resulted in robust and pragmatic policy recommendations. Itincludes supply-side measures to accelerate domestic gas production anddemand measures to promote gas usage in China. It also considers thereforms needed in the midstream.

The DRC’s collaboration with Shell demonstrates how governments andcompanies can collaborate effectively over energy and climate challenges,and I believe other countries will be keen to learn from this.

The DRC and Shell have established and demonstrated the ability to worktogether. I now look forward to further collaboration on topics where we cancombine Shell’s international energy market experience with DRC’s deepunderstanding and thought leadership on China’s development.

Ben van BeurdenCEO, Royal Dutch Shell

xviii Foreword II

Acknowledgements

Shell International project team:

• Mallika Ishwaran, Senior Economist, Shell International Limited• Martin Haigh, Senior Energy Advisor, Shell International Limited• Taoliang Lee, LNG Markets Advisor, Shell Eastern Petroleum Private

Limited• Shangyou Nie, Competitive Intelligence Advisor, Shell International

Exploration and Production B.V.• Cindy Wang, Government Affairs-Policy and Integrated Gas & New

Energy Business Support, Shell (China) Limited

DRC project team:

• Zhaoyuan Xu, Director of Research, Research Department of IndustrialEconomy Development Research Center of the State Council

• Xiaoming Wang, Director of Research, Research Department of Indus-trial Economy, Development Research Center of the State Council

ProjectChair

Minister Wei Li,Development Research Centerof the State Council of China

Ben van Beurden,CEO, Royal Dutch Shell

ProjectExecutive

Vice President (Vice Minister) ShijinLiu, Development Research Centerof the State Council of China

Xinsheng Zhang,Executive Chairman,Shell Companies in China

ProjectSponsor

Changwen Zhao, Director-General,Research Department of IndustrialEconomy, Development ResearchCenter of the State Council

Jeremy Bentham,VP Global BusinessEnvironment,Shell International B.V.

ProjectTeam Lead

Jinzhao Wang, Deputy DirectorGeneral of Research Department ofForeign Economic Relations,Development Research Center of theState Council

William King, Group StrategyAdvisor Shell International B.V.

xix

• Jigang Wei, Director of Research, Development Research Center of theState Council

• Zhonghong Wang, Secretary of the Party Committee andVice-Director-General of China Economic Times, Development ResearchCenter of the State Council

With special thanks to Vivid Economics, Aurora Energy Research andOxford Institute for Energy Studies.

xx Acknowledgements

Contents

1 General Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1 Global Trends in the Natural Gas Industry . . . . . . . . . . 1

1.1.1 Abundant Resources, and a Greater Rolefor Natural Gas in the Future . . . . . . . . . . . . . 1

1.1.2 Changes to the Global Trade and Pricing,and a More Interconnected Market . . . . . . . . . 2

1.1.3 Falling Oil Prices and Their Effect on NaturalGas Markets—but no Great in the Priceof Imported Gas in China in the Mediumto Long Term . . . . . . . . . . . . . . . . . . . . . . . . 3

1.1.4 China’s Share of the Global Natural GasMarket Is Slowly Growing—China MustBecome an Active Player in the InternationalNatural Gas Market . . . . . . . . . . . . . . . . . . . . 5

1.2 China’s Natural Gas Supply and Demand and ItsPrimary Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . 61.2.1 The Chinese Economy’s New Normal . . . . . . . 61.2.2 Growth Natural Gas Demand in China. . . . . . . 61.2.3 Potential to Expand Domestic Natural Gas

Supply and Import Capacity in China . . . . . . . 71.2.4 Key Problems Facing the Development

of the Natural Gas Industry . . . . . . . . . . . . . . 91.3 China’s Natural Gas Industry Development Strategy

for the Next 15 Years . . . . . . . . . . . . . . . . . . . . . . . . 111.3.1 National Strategy and Policy Are Crucial

for Natural Gas Industry Developmentin China. . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

1.3.2 Strategic Objectives of High Efficiency,Safety and Sustainability . . . . . . . . . . . . . . . . 13

1.3.3 Clearly Defined Channels and Targetsof the Natural Gas Industry . . . . . . . . . . . . . . 14

1.4 Raising Efficiency and Supporting Improved Policiesto Expand Natural Gas Use . . . . . . . . . . . . . . . . . . . . 16

xxi

1.4.1 Strengthen Environmental Regulation, ImproveResource Utilisation Efficiency, SubstituteNatural Gas for Coal . . . . . . . . . . . . . . . . . . . 17

1.4.2 Improve Planning and Technological Standards,and Promote the Development of NaturalGas Transportation . . . . . . . . . . . . . . . . . . . . 18

1.4.3 Improve the Pricing Mechanism, Makingthe Development of Natural Gas ElectricalPower Generation Justifiable. . . . . . . . . . . . . . 19

1.4.4 Adjust Gas Prices for Residential and ChemicalIndustry Use, and Reduce Cross-Subsidiesfor Different Users . . . . . . . . . . . . . . . . . . . . 21

1.5 Measures to Ensure a Safe and Efficient Gas Supply . . . 221.5.1 Attracting New Players to Resource

Exploitation to Expand NaturalGas Production . . . . . . . . . . . . . . . . . . . . . . . 22

1.5.2 Achieving Import Diversification, Safeguardingthe Security of Natural Gas Imports. . . . . . . . . 27

1.5.3 Accelerating the Construction of PipelineNetwork, Promoting NetworkInterconnectivity . . . . . . . . . . . . . . . . . . . . . . 29

1.5.4 Accelerate the Construction of Natural GasReserve Facilities and ImplementCorresponding Institutional Reform . . . . . . . . . 32

1.5.5 Improve Technology Capacity and Strengthenthe Long-Term Development Capability. . . . . . 35

1.6 Constructing a Modern Natural Gas Market Mechanismand Management System . . . . . . . . . . . . . . . . . . . . . . 361.6.1 Liberalisation of the Upstream Sector and True

Import Liberalisation . . . . . . . . . . . . . . . . . . . 361.6.2 Step-by-Step Natural Gas Price Reform,

Accelerated Construction of NaturalGas Trade Hubs . . . . . . . . . . . . . . . . . . . . . . 38

1.6.3 Clear Allocation of Functions and RobustSupervision to Support Unbundlingand Third-Party Access . . . . . . . . . . . . . . . . . 40

1.6.4 Strengthen Energy Resource Management,Establish a Regulatory System and BuildRegulatory Capacity . . . . . . . . . . . . . . . . . . . 42

1.6.5 Support the Development of ProfessionalServices and Technological Companies;Use Market Forces to Promote the Expansionof the Division of Labour. . . . . . . . . . . . . . . . 43

1.7 Deepen the Laws and Regulations System of the GasSector, and Establish a Sound Legal System. . . . . . . . . 44

xxii Contents

PART I Analysis of Natural Gas Demand

2 Developments in Global Natural Gas Consumption . . . . . . 492.1 Major Factors Affecting Natural Gas Consumption

Growth in Other Countries . . . . . . . . . . . . . . . . . . . . . 492.1.1 Proportion of Energy Consumption of Natural

Gas in Various Countries . . . . . . . . . . . . . . . . 492.1.2 Breakdown of Natural Gas Consumption

Growth in Seven Benchmark Countries . . . . . . 522.1.3 The Importance of Fuel Switching in Natural

Gas Demand Growth . . . . . . . . . . . . . . . . . . . 542.2 Primary Factors Motivating Switching from Other Fuels

to Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 562.2.1 Various Approaches to Natural Gas

Replacement. . . . . . . . . . . . . . . . . . . . . . . . . 572.2.2 Analysis of Driving Factors in OECD Member

Countries Switching to Natural Gas . . . . . . . . . 582.2.3 Further Analysis of Motivating Factors

for a Country to Switch to Natural Gas . . . . . . 602.2.4 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

2.3 The Influence of Natural Gas Price on Demand . . . . . . 652.3.1 The Relationship Between Natural Gas Price

Changes and Changes in Demand in OECDCountries Is not Pronounced. . . . . . . . . . . . . . 65

2.3.2 Limited Effect on Demand of Differencein Price Between Natural Gas and OtherEnergy Sources. . . . . . . . . . . . . . . . . . . . . . . 68

2.4 Current State of Natural Gas Use in Chinaand Future Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . 712.4.1 Sector Distribution and Total Gas Consumption

in China Since 2000 . . . . . . . . . . . . . . . . . . . 712.4.2 Mid- to Long-Term Energy and Natural Gas

Development Plans in China. . . . . . . . . . . . . . 732.4.3 Mid- to Long-Term Natural Gas Development

Trends for China Based on InternationalExperiences . . . . . . . . . . . . . . . . . . . . . . . . . 75

3 Potential for Natural Gas to Act as a Substitute Fuelin China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 773.1 Power Generation: Cost Comparison of Gas

as a Substitute for Coal in Power Generation . . . . . . . . 773.1.1 Direct Cost Comparison Between Gas

Generation and Coal Generation . . . . . . . . . . . 783.1.2 Other Factors Influencing the Competitiveness

of Gas-Fired Power Generation . . . . . . . . . . . . 793.1.3 Conclusions Regarding the Prospects of Gas

Replacing Coal in Power Generation . . . . . . . . 823.2 Transport: Analysis of Natural Gas as a Substitute

for Diesel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Contents xxiii

3.2.1 Primary Motivators for Natural Gas to ReplaceDiesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

3.2.2 Natural Gas Oil Replacement Price Tolerancein the Urban Transport Sector . . . . . . . . . . . . . 84

3.2.3 Commercial Vehicle Natural Gas DieselReplacement Price Tolerance . . . . . . . . . . . . . 85

3.2.4 Ship Transport Natural Gas Diesel ReplacementPrice Tolerance . . . . . . . . . . . . . . . . . . . . . . . 86

3.2.5 General Factors in the Transportation MarketRelating to Gas Replacement of Diesel . . . . . . 87

3.2.6 Potential Prospects for Transportation MarketNatural Gas Demand . . . . . . . . . . . . . . . . . . . 88

3.3 Urban Use: Assessment of Price Tolerancefor Natural Gas to Replace Other Fuels . . . . . . . . . . . . 893.3.1 Price Tolerance is Relatively High for

Residential Usage of Natural Gas . . . . . . . . . . 893.3.2 Price Tolerance is also Quite Resilient

in Commercial Service Natural Gas Use. . . . . . 913.3.3 Price Tolerance is Weak for Centralised Urban

Heating Using Natural Gas . . . . . . . . . . . . . . . 913.4 Industrial Use: Cost Comparison of Natural Gas

Replacing Other Energy Sources . . . . . . . . . . . . . . . . . 923.4.1 Price Tolerance is Very Low for Replacement

of Fuel Oil by Natural Gas in theGlass Industry. . . . . . . . . . . . . . . . . . . . . . . . 92

3.4.2 Price Tolerance is Relatively Weakfor the Ceramics Industry for Replacementof Coal Gas by Natural Gas . . . . . . . . . . . . . . 93

3.4.3 Natural Gas Price Tolerance is RelativelyPoor for Steam Production as a Replacementfor Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

3.5 Chemicals: Potential for Increased Natural GasUse in the Production Process . . . . . . . . . . . . . . . . . . 943.5.1 Price Tolerance of Natural Gas is Extremely

Low for the Manufacture of SyntheticAmmonia . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

3.5.2 Price Tolerance of Natural Gas is VeryWeak for the Manufacture of Methanol . . . . . . 94

3.5.3 Price Tolerance of Natural Gas is Very Strongfor the Manufacture of Hydrogen . . . . . . . . . . 95

3.6 China’s Natural Gas Demand Curve and Waysto Increase Natural Gas Consumption . . . . . . . . . . . . . 953.6.1 China’s Natural Gas Prices in 2013 . . . . . . . . . 953.6.2 Natural Gas Demand Curve for China

in 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 963.6.3 Implementation Model of Effective Demand

and Actual Natural Gas Consumption Basedon Natural Gas Price Reform Targets . . . . . . . 98

xxiv Contents

4 Environmental and Social Value of Natural Gas . . . . . . . . 1014.1 Losses Caused by Atmospheric Pollution in China . . . . 101

4.1.1 Atmospheric Pollution is a Key Cause of Deathin China. . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

4.1.2 Losses from Injury to Health Causedby Atmospheric Pollution in China Accountfor 3–12% of GDP . . . . . . . . . . . . . . . . . . . . 102

4.2 The Environmental Value of Natural Gas as a Substitutefor Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1044.2.1 Environmental Pollution and Economic Losses

Incurred During Coal Production. . . . . . . . . . . 1044.2.2 Environmental Pollution and Economic Loss

During Coal Transportation . . . . . . . . . . . . . . 1054.2.3 Estimates of Environmental Pollution and

Economic Losses Arising from Coal Use . . . . . 1064.2.4 Environmental Value Assessment for Natural

Gas Substituting Coal . . . . . . . . . . . . . . . . . . 1064.3 Social Value of Natural Gas as a Substitute for Coal . . . 106

4.3.1 Social Loss of Coal Production. . . . . . . . . . . . 1074.3.2 Social Loss of Coal Use . . . . . . . . . . . . . . . . 1074.3.3 Social Value Assessment of Natural Gas

as a Substitute for Coal . . . . . . . . . . . . . . . . . 1074.4 China’s Achievements in Energy Conservation

and Emissions Reduction . . . . . . . . . . . . . . . . . . . . . . 1084.4.1 Targets and Main Measures for Sulphur

Dioxide Emission Reduction During the Periodof the 12th Five-Year Plan . . . . . . . . . . . . . . . 108

4.4.2 Emissions Reduction Results Achieved Duringthe 11th Five-Year Plan Period . . . . . . . . . . . . 109

4.4.3 Enormous Potential for Natural Gas toSubstitute for Coal in Industrial Fueland Residential Heating . . . . . . . . . . . . . . . . . 109

5 Analysis of Medium- to Long-Term Natural Gas Demandand Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1135.1 The Natural Gas Supply-Demand Model . . . . . . . . . . . 113

5.1.1 Basic Characteristics of the Model . . . . . . . . . 1135.1.2 Main Intensifications and Adjustments Made

Towards Studies of Natural Gasin This Model. . . . . . . . . . . . . . . . . . . . . . . . 114

5.2 Simulation Scenarios for Analysis Simulationsof Natural Gas Demand . . . . . . . . . . . . . . . . . . . . . . . 1165.2.1 Key Assumptions of the Standard Scenario . . . 1165.2.2 Key Assumptions of the Policy-Driven

Scenario. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1175.3 Natural Gas Supply and Demand in the Standard

Scenario. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1185.3.1 Speed of Economic Growth and International

Comparison . . . . . . . . . . . . . . . . . . . . . . . . . 118

Contents xxv

5.3.2 Mid- to Long-Term Changes in IndustrialStructures. . . . . . . . . . . . . . . . . . . . . . . . . . . 119

5.3.3 Energy Consumption and Structural Change . . . 1215.3.4 Demand for Natural Gas and Main Increases

in Consumption . . . . . . . . . . . . . . . . . . . . . . 1235.4 Natural Gas Supply and Demand in the Policy-Driven

Scenario. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1265.4.1 Total Natural Gas Supply and Demand . . . . . . 1265.4.2 Effects on Pollutant Discharge of Natural

Gas Consumer Demand Growth . . . . . . . . . . . 1275.4.3 Main Areas of Natural Gas Demand . . . . . . . . 1285.4.4 Demand Curve for Natural Gas in China

in 2030 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

6 Analysis of China’s Natural Gas Use Policiesand Suggested Reforms . . . . . . . . . . . . . . . . . . . . . . . . . . . 1336.1 Development of China’s Natural Gas Use Policy . . . . . 133

6.1.1 The Encouraging Consumption Stage . . . . . . . 1336.1.2 Restricted Usage Stage . . . . . . . . . . . . . . . . . 1336.1.3 Flexible Restrictions Stage . . . . . . . . . . . . . . . 134

6.2 “Optimisation” of Natural Gas Use Structuresand Policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1376.2.1 China’s Natural Gas Use Structure . . . . . . . . . 1376.2.2 Worldwide There Is no Such Thing

as “Optimised” Gas Use Structure . . . . . . . . . . 1376.2.3 Market Pricing Adjustments Would

Automatically Result in “Optimisation”of Natural Gas Use Structures. . . . . . . . . . . . . 138

6.3 Natural Gas Use and Natural Gas Price Controls. . . . . . 1396.3.1 Natural Gas Price Control Policies in China . . . 1396.3.2 The Effect of Pricing Mechanisms in Keeping

Natural Gas Prices Low . . . . . . . . . . . . . . . . . 1406.3.3 The Influence of a High Fixed Price

for Natural Gas . . . . . . . . . . . . . . . . . . . . . . . 1426.3.4 Removal of Natural Gas Price Restrictions

Would See the Disappearance of Natural GasUse Policies . . . . . . . . . . . . . . . . . . . . . . . . . 143

6.4 The Relevance of the 1978 U.S. Natural Gas PolicyAct for China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1446.4.1 Legislative Background . . . . . . . . . . . . . . . . . 1446.4.2 Contents of the Legislation. . . . . . . . . . . . . . . 1456.4.3 Implementation . . . . . . . . . . . . . . . . . . . . . . . 1466.4.4 Lessons for Natural Gas Usage

Policy in China. . . . . . . . . . . . . . . . . . . . . . . 1466.5 Policy Recommendations for Encouraging Natural

Gas Use. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1476.5.1 Improve Environmental Supervision, Replacing

Dispersed Coal Use with Natural Gas . . . . . . . 148

xxvi Contents

6.5.2 Optimise the Electricity Pricing Scheme,and Increase the Economical NaturalGas Power Generation . . . . . . . . . . . . . . . . . . 148

6.5.3 Strengthen Planned Guidance to PromoteNatural Gas in Transportation . . . . . . . . . . . . . 149

6.5.4 Reduce Cross-Subsidisation Between DifferentUsers, and Encourage Industrial andCommercial Natural Gas Use . . . . . . . . . . . . . 150

6.5.5 Extend Carbon Emission Trading Rights,and Actualise the Environmental Valueof Natural Gas . . . . . . . . . . . . . . . . . . . . . . . 151

PART II Analysis of Gas Supply for China

7 China’s Natural Gas Resource Potential and ProductionTrends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1557.1 Natural Gas Resource Potential . . . . . . . . . . . . . . . . . . 155

7.1.1 Resource Potential for Chinese Conventionaland Unconventional Natural Gas . . . . . . . . . . . 155

7.1.2 Changes in Natural Gas ResourceAssessments . . . . . . . . . . . . . . . . . . . . . . . . . 155

7.2 Proved Natural Gas Reserves . . . . . . . . . . . . . . . . . . . 1577.2.1 Conventional Natural Gas . . . . . . . . . . . . . . . 1577.2.2 Coalbed Methane . . . . . . . . . . . . . . . . . . . . . 1587.2.3 Shale Natural Gas . . . . . . . . . . . . . . . . . . . . . 158

7.3 Growth of Natural Gas Production . . . . . . . . . . . . . . . 1597.3.1 Conventional Natural Gas . . . . . . . . . . . . . . . 1597.3.2 Coalbed Methane . . . . . . . . . . . . . . . . . . . . . 1597.3.3 Shale Natural Gas . . . . . . . . . . . . . . . . . . . . . 161

7.4 Conventional and Unconventional Natural GasProduction Forecasts . . . . . . . . . . . . . . . . . . . . . . . . . 1617.4.1 2020 Production Volume Forecast . . . . . . . . . . 1617.4.2 2030 Annual Production Forecast . . . . . . . . . . 162

7.5 Accelerating the Development of China’s DomesticNatural Gas Resources. . . . . . . . . . . . . . . . . . . . . . . . 1637.5.1 Clarify Development Paths . . . . . . . . . . . . . . . 1637.5.2 Adjust Lowest Exploration Commitments. . . . . 1647.5.3 Maintain Reasonable Prices . . . . . . . . . . . . . . 1647.5.4 Establish Trade Mechanisms and Trade

Platforms for Proved Natural Gas Reserves . . . 1657.5.5 Accelerate Development of Unconventional

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . 165

8 International Natural Gas Supply and QuantitiesAvailable to China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1978.1 Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1978.2 Current and Future Sources of Global Natural

Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198

Contents xxvii

8.2.1 Current and Projected Global NaturalGas Resources . . . . . . . . . . . . . . . . . . . . . . . 198

8.2.2 Global LNG Trade Development. . . . . . . . . . . 1998.2.3 Trends in Global LNG Trade . . . . . . . . . . . . . 1998.2.4 Developments in the Global LNG Export

Market. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1998.2.5 Growing Natural Gas Demand in China,

India and Other Emerging Markets . . . . . . . . . 2018.2.6 The Influence of Oil Price Declines Future

Natural Gas Trade . . . . . . . . . . . . . . . . . . . . . 2028.3 China’s Current Natural Gas Imports and Future

Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2048.3.1 China’s Current Natural Gas Imports . . . . . . . . 2048.3.2 Potential Source Nations for China’s Future

LNG Imports . . . . . . . . . . . . . . . . . . . . . . . . 2058.3.3 Trends in China’s Future Natural Gas

Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2088.4 China’s Natural Gas Trade Policies

and Recommendations for Reform . . . . . . . . . . . . . . . 2158.4.1 China’s Current Natural Gas Trade Policies . . . 2158.4.2 Recommendations for Adjustments to China’s

Natural Gas Trade Policy . . . . . . . . . . . . . . . . 2178.5 Conclusions for Chinese Natural Gas Supply

and Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221

9 Analysis of China’s Natural Gas InfrastructureDevelopment Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2339.1 Current Development of Natural Gas Infrastructure . . . . 233

9.1.1 Current State of Infrastructure Development . . . 2339.1.2 Assessment of Development Levels

and Existing Problems . . . . . . . . . . . . . . . . . . 2359.2 Opportunities and Challenges . . . . . . . . . . . . . . . . . . . 237

9.2.1 The Energy Development Strategy ActionPlan (2014–2020) . . . . . . . . . . . . . . . . . . . . . 237

9.2.2 Policy Catalyses Rapid Developmentof the Natural Gas Industry . . . . . . . . . . . . . . 238

9.2.3 The Atmospheric Pollution PreventionAction Plan . . . . . . . . . . . . . . . . . . . . . . . . . 238

9.2.4 Existing Pipeline Network CapabilitiesAre Insufficient. . . . . . . . . . . . . . . . . . . . . . . 238

9.2.5 Peak Shaving Capabilities Are SeverelyLacking . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238

9.2.6 Increasing Pressure for Safe Operations . . . . . . 2399.3 Natural Gas Infrastructure Development Strategy . . . . . 239

9.3.1 Guiding Considerations . . . . . . . . . . . . . . . . . 2399.3.2 Development Objectives. . . . . . . . . . . . . . . . . 2399.3.3 Development Strategy . . . . . . . . . . . . . . . . . . 240

9.4 Standardising Infrastructure Planning and DiversifyingInvestment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 244

xxviii Contents

9.4.1 Infrastructure Construction Planningand Project Progress Oversight . . . . . . . . . . . . 244

9.4.2 Promote Construction of Entitiesand Investment Diversification . . . . . . . . . . . . 244

9.5 Establishing Fair Third-Party Access toInfrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2459.5.1 Create the Conditions for Third-Party

Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2459.5.2 Establish Open and Transparent Oil

and Gas Management and OperationRelease Platforms . . . . . . . . . . . . . . . . . . . . . 246

10 Analysis of China’s Peak Shaving and Natural GasStorage Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24710.1 Importance of Natural Gas Reserves for

Peak Shaving . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24710.2 Issues and Challenges . . . . . . . . . . . . . . . . . . . . . . . . 248

10.2.1 Rapid Increase in Natural Gas Consumptionand Peak Period Demand . . . . . . . . . . . . . . . . 248

10.2.2 Gas Reserve Peak Shaving CapabilitiesInsufficient . . . . . . . . . . . . . . . . . . . . . . . . . . 249

10.3 Key Objectives and Considerations Going Forward . . . . 25310.3.1 Basic Considerations . . . . . . . . . . . . . . . . . . . 25310.3.2 Major Objectives. . . . . . . . . . . . . . . . . . . . . . 253

10.4 Recommendations for Developing Natural Reservesfor Peak Shaving . . . . . . . . . . . . . . . . . . . . . . . . . . . 25410.4.1 Accelerate the Formulation of Natural Gas

Peak Shaving Emergency Response Plans . . . . 25410.4.2 Emphasise Gas Reserve Facility Legal

and Regulatory Construction. . . . . . . . . . . . . . 25410.4.3 Accelerate Natural Gas Peak Shaving

Emergency Reserve Facility Construction. . . . . 25410.4.4 Formulate Proactive Tax and Price Policies . . . 25510.4.5 Accelerate Gas Reserve Management System

Reforms. . . . . . . . . . . . . . . . . . . . . . . . . . . . 25610.4.6 Establish Prompt and Flexible Warning

Systems for Emergency Response . . . . . . . . . . 256

PART III Creation of Natural Gas Market Mechanisms andReform of Natural Gas Management Systems

11 China’s Current Natural Gas Market Mechanismsand Regulatory System . . . . . . . . . . . . . . . . . . . . . . . . . . . 26111.1 Current State of Natural Gas Market Mechanisms . . . . . 261

11.1.1 Natural Gas Upstream Market. . . . . . . . . . . . . 26111.1.2 Natural Gas Midstream Market . . . . . . . . . . . . 26311.1.3 Natural Gas Downstream Market . . . . . . . . . . 269

11.2 Current State of China’s Natural Gas RegulatorySystems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 269

Contents xxix

xxx Contents

11.2.1 Upstream Market Administrative System . . . . . 26911.2.2 Midstream Market Administrative System . . . . 27511.2.3 Downstream Market Administrative System . . . 278

11.3 Challenges Faced by the Current System . . . . . . . . . . . 28011.3.1 Over-Centralisation of Mineral Rights

and Lack of Exploration . . . . . . . . . . . . . . . . 28011.3.2 Bundling of Infrastructure, Low Utilisation

and Blocking Access to Upstream Markets. . . . 28111.3.3 Irrational Pricing Mechanisms, Which Dampen

Incentive to Build Gas Storage . . . . . . . . . . . . 28211.3.4 Downstream Pipeline Operator Regional

Monopolies and Cross-Subsidising BetweenDifferent Users . . . . . . . . . . . . . . . . . . . . . . . 283

11.3.5 Incomplete Supervisory Systems andInsufficient Supervisory Capability . . . . . . . . . 283

12 International Experience of Liberalisation and Evolutionof Natural Gas Markets . . . . . . . . . . . . . . . . . . . . . . . . . . 28712.1 Incentivising New Entrants and Establishing

Competitive Natural Gas Markets . . . . . . . . . . . . . . . . 28712.2 Opening the Upstream Sector to Competition . . . . . . . . 28712.3 Orderly and Gradual Implementation of Pipeline

Access Policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28912.4 Third-Party Access: The First Step to Infrastructure

Reform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29112.5 Unbundling: An Important Element of Liberalisation

of Natural Gas Markets . . . . . . . . . . . . . . . . . . . . . . . 29312.6 Natural Gas Pricing Reform as Part of the Market

Liberalisation and Development Process. . . . . . . . . . . . 29412.7 The Role of Natural Gas Trading Markets . . . . . . . . . . 29612.8 Establishment of an Independent and Legally Protected

Regulatory System . . . . . . . . . . . . . . . . . . . . . . . . . . 29912.9 A Roadmap for Natural Gas Market Reform . . . . . . . . 301

13 Regulatory System Reform to Support NaturalGas Market Liberalisation . . . . . . . . . . . . . . . . . . . . . . . . 30313.1 Direction of Reforms. . . . . . . . . . . . . . . . . . . . . . . . . 30313.2 Key Pillars of Reform . . . . . . . . . . . . . . . . . . . . . . . . 304

13.2.1 Pillar I: Establish a Diversified, Competitive,Open, Orderly Modern NaturalGas Market System . . . . . . . . . . . . . . . . . . . . 304

13.2.2 Pillar II: Create a Pricing System that Reflectsthe Extent of Scarcity of Resources,the Market Relationships of Supply andDemand and Environmental Externalityand a Green Financial and Taxation System . . . 305

13.2.3 Pillar III: Establish a Service-CentredNatural Gas Administration witha Legal Basis . . . . . . . . . . . . . . . . . . . . . . . . 306

13.3 Reform Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . 307

14 Roadmap for Natural Gas Market Liberalisationand Regulatory Reform. . . . . . . . . . . . . . . . . . . . . . . . . . . 30914.1 Roadmap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309

14.1.1 Upstream Sector Roadmap . . . . . . . . . . . . . . . 30914.1.2 Midstream Roadmap . . . . . . . . . . . . . . . . . . . 31014.1.3 Downstream Roadmap . . . . . . . . . . . . . . . . . . 311

14.2 Key Measures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31214.2.1 Creation of Market Systems . . . . . . . . . . . . . . 31314.2.2 Completion of a Natural Gas Pricing

Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . 31514.2.3 Removal of Pipeline Transport Bottlenecks . . . 31514.2.4 Further Regulatory Reform. . . . . . . . . . . . . . . 31714.2.5 Further Reform of the State-Owned

Oil and Gas Companies . . . . . . . . . . . . . . . . . 32014.2.6 Establish and Improve the Services Market. . . . 321

15 Policy Measures and Safeguards to Support NaturalGas Market Liberalisation and Regulatory Reform . . . . . . 32315.1 Create and Complete a Natural Gas Legislative

Framework. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32315.2 Deepen Reform of Oil and Gas Regulations . . . . . . . . . 32415.3 Deepen Reform of the Fiscal and Tax Systems . . . . . . . 32515.4 Establish and Complete a Natural Gas Data

Management System . . . . . . . . . . . . . . . . . . . . . . . . . 32715.4.1 Data Submission . . . . . . . . . . . . . . . . . . . . . . 32715.4.2 Standardised Data Management. . . . . . . . . . . . 32815.4.3 Database Development and Information

Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . 32815.5 Increase Reform and Technical Innovation

in the Natural Gas Sector . . . . . . . . . . . . . . . . . . . . . . 32815.6 Expand International Energy Co-operation . . . . . . . . . . 330

PART IV International Experience from the Developmentof Gas Markets Globally

16 International Development Trends . . . . . . . . . . . . . . . . . . . 33516.1 Global Natural Gas Markets . . . . . . . . . . . . . . . . . . . . 33516.2 International Experiences of Liberalising the Natural

Gas Value Chain. . . . . . . . . . . . . . . . . . . . . . . . . . . . 33616.3 Liberalisation of Different Segments of the Natural

Gas Value Chain. . . . . . . . . . . . . . . . . . . . . . . . . . . . 33716.4 Natural Gas Energy Security and Social Influence. . . . . 338

17 The Global Natural Gas Market . . . . . . . . . . . . . . . . . . . . 34517.1 An Overview of the Global Energy Market . . . . . . . . . 34517.2 Factors Driving Demand . . . . . . . . . . . . . . . . . . . . . . 348

17.2.1 The Main Factors Driving Demand . . . . . . . . . 34817.2.2 Natural Gas Price Elasticity and China. . . . . . . 349

Contents xxxi

17.3 Supply and Demand Imbalances . . . . . . . . . . . . . . . . . 35017.3.1 Summary of Global Resources . . . . . . . . . . . . 35017.3.2 Regional Imbalances . . . . . . . . . . . . . . . . . . . 35317.3.3 Inter-regional Natural Gas Trade . . . . . . . . . . . 35517.3.4 Unconventional Natural Gas Resources . . . . . . 360

17.4 Pricing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36117.4.1 Current Pricing Regulations . . . . . . . . . . . . . . 36217.4.2 The Relationship Between the Price of Natural

Gas and the Price of Oil . . . . . . . . . . . . . . . . 36617.4.3 Chinese Pricing Mechanisms . . . . . . . . . . . . . 36917.4.4 The Influence of Chinese Demand

on the World Market . . . . . . . . . . . . . . . . . . . 370

18 An Overview of International Regulatory Experience . . . . . 37918.1 Regulatory Reform . . . . . . . . . . . . . . . . . . . . . . . . . . 381

18.1.1 The Reasons for Regulation . . . . . . . . . . . . . . 38118.1.2 The Process of Market Liberalisation Across

the Natural Gas Value Chain . . . . . . . . . . . . . 38218.2 Market Liberalisation. . . . . . . . . . . . . . . . . . . . . . . . . 384

18.2.1 Core Initiatives for Liberalisation . . . . . . . . . . 38418.2.2 Political and Economic Factors of Market

Liberalisation . . . . . . . . . . . . . . . . . . . . . . . . 39018.2.3 The Impact of Market Liberalisation

on Domestic Mining . . . . . . . . . . . . . . . . . . . 39118.2.4 Market Liberalisation and Ancillary Policies . . . 392

18.3 Case Studies of Natural Gas Market Liberalisation . . . . 39318.3.1 Case Study 1: United States . . . . . . . . . . . . . . 39318.3.2 Case Study 2: Europe . . . . . . . . . . . . . . . . . . 40118.3.3 Case Study 3: United Kingdom. . . . . . . . . . . . 40818.3.4 Case Study 4: Japan . . . . . . . . . . . . . . . . . . . 41318.3.5 Case Study 5: South Korea . . . . . . . . . . . . . . 419

19 A Close Look at the Natural Gas Industry Chain. . . . . . . . 42519.1 The Upstream Segment: Fiscal Policies and Licensing

Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42519.1.1 International Taxation and Licensing Systems

Regulating Upstream Production . . . . . . . . . . . 42619.1.2 Case Study 1: The United States—Leasing,

Taxation and Development of InformationSharing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 426

19.1.3 Case Study 2: Australia—Licensing, Financeand Taxation, and Third-Party Access . . . . . . . 428

19.1.4 Case Study 3: Argentina—The SpecialLicensing System and EncouragingInvestment . . . . . . . . . . . . . . . . . . . . . . . . . . 430

19.1.5 Case Study 4: Mexico—Reopening the Marketand Round Zero Tender . . . . . . . . . . . . . . . . . 431

xxxii Contents

19.2 The Midstream Segment: Building Infrastructureand Managing Access . . . . . . . . . . . . . . . . . . . . . . . . 43419.2.1 Balancing Third-Party Access and Investment

Incentives. . . . . . . . . . . . . . . . . . . . . . . . . . . 43719.2.2 International Experience of Managing

Midstream Asset Access . . . . . . . . . . . . . . . . 43819.2.3 Case Study 1: The UK North Sea—The

Framework for Negotiated Third-PartyAccess . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 441

19.2.4 Case Study 2: Japan and SingaporeLNG—National Power and the Influenceof Oligopoly. . . . . . . . . . . . . . . . . . . . . . . . . 444

19.2.5 Case Study 3: The United States—MasterLimited Partnerships . . . . . . . . . . . . . . . . . . . 449

19.3 Unbundling Midstream Infrastructure. . . . . . . . . . . . . . 45119.3.1 Models of Unbundling. . . . . . . . . . . . . . . . . . 45319.3.2 Key Insights from the Case Studies . . . . . . . . . 45319.3.3 Case Study 1: The UK—The Long and

Difficult Road to Spinoff . . . . . . . . . . . . . . . . 45719.3.4 Case Study 2: Europe—The Step-by-Step

Progression Towards Spinoff and the Multitudeof Choices . . . . . . . . . . . . . . . . . . . . . . . . . . 458

19.3.5 Case Study 3: Japan—Market CharacteristicsRestricting Unbundling . . . . . . . . . . . . . . . . . 460

19.3.6 Unbundling LNG Terminals and Gas StorageFacilities . . . . . . . . . . . . . . . . . . . . . . . . . . . 461

19.4 The Downstream Segment: Natural Gas TradingHubs and the Liberalisation of Wholesale NaturalGas Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46219.4.1 Pros and Cons of Natural Gas Hubs . . . . . . . . 46319.4.2 The Important Inspiration of International

Experience in the Development of NaturalGas Trading Hubs . . . . . . . . . . . . . . . . . . . . . 465

19.4.3 Case Study 1: The United States—RegionalPrice Balances and Short-Term Pricing . . . . . . 466

19.4.4 Case Study 2: Continental Europe—MarketConditions for Natural Gas HubDevelopment . . . . . . . . . . . . . . . . . . . . . . . . 466

19.4.5 Case Study 3: The UK—Two Natural GasMarket Reform Bills . . . . . . . . . . . . . . . . . . . 467

19.4.6 Establishing Natural Gas Hubs in China. . . . . . 468

Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 473

Further Reading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 475

Contents xxxiii

Abbreviations

Bod Barrels of oil per dayCCHP Combined cooling, heating and powerCHP Combined heat and powerCNG Compressed natural gasCNY Chinese yuanEIA US Energy Information AdministrationGDP Gross domestic productIEA International Energy AgencyLNG Liquefied natural gasLPG Liquefied petroleum gasMMBtu Million British thermal unitsmtpa Million tonnes per annumNOC National Oil CompanyOECD Organisation for Economic Co-operation and DevelopmentOPEC Organization of the Petroleum Exporting CountriesTSCE Tonnes of standard coal equivalent

xxxv

List of Figures

Fig. 1.1 Global natural gas supply and demand . . . . . . . . . . . . 2Fig. 1.2 Evolution of global natural gas pricing mechanism . . . 3Fig. 1.3 Natural gas demand volume and its role in energy

consumption under the different scenarios. . . . . . . . . . 7Fig. 1.4 Natural gas price adaptability of different user

categories (in CNY/m3) . . . . . . . . . . . . . . . . . . . . . . 17Fig. 1.5 Proportion of natural gas imports and import diversity

in selected countries. . . . . . . . . . . . . . . . . . . . . . . . . 29Fig. 1.6 National natural gas pipeline concept . . . . . . . . . . . . . 31Fig. 2.1 Proportion of energy consumption of each country

accounted for by natural gas and proportionof global natural gas consumption of each country . . . 50

Fig. 2.2 Natural gas consumption in seven benchmarkcountries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Fig. 2.3 Changes between 1982 and 2012 in the proportionof natural gas consumption of seven benchmarkcountries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Fig. 2.4 Contribution of increased economic activityin increasing demand for natural gas . . . . . . . . . . . . . 53

Fig. 2.5 Influence of energy intensity changes on naturalgas demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Fig. 2.6 Influence of fuel switching on natural gas . . . . . . . . . 55Fig. 2.7 Factor breakdown of benchmark country natural

gas demand: overall results . . . . . . . . . . . . . . . . . . . . 55Fig. 2.8 Natural gas replacement pathways in China and

benchmark countries (1980–2012) . . . . . . . . . . . . . . . 57Fig. 2.9 Changes in energy usage from coal to natural gas . . . . 58Fig. 2.10 Regression results for 2012 natural gas share

in OECD countries . . . . . . . . . . . . . . . . . . . . . . . . . 59Fig. 2.11 Size of service industry and natural gas share

of energy mix, 1980–2010 . . . . . . . . . . . . . . . . . . . . 61Fig. 2.12 Size of manufacturing industry and natural gas share

of energy mix, 1980–2010 . . . . . . . . . . . . . . . . . . . . 61Fig. 2.13 Urbanisation and natural gas share of energy mix,

1980–2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

xxxvii

Fig. 2.14 Comparison of pollution resulting from naturalgas power generation and from coal power generation,per unit calorific value . . . . . . . . . . . . . . . . . . . . . . . 62

Fig. 2.15 PM10 emission levels and natural gas share of heatand power generation, 1970–2010 . . . . . . . . . . . . . . . 63

Fig. 2.16 Relation between power generation, SO2 emissionlevels and natural gas share of heat and powergeneration, 1970–2010 . . . . . . . . . . . . . . . . . . . . . . . 63

Fig. 2.17 Relationship between growth in demand for naturalgas and pricing in three sectors in the United States. . . 66

Fig. 2.18 Relationship between growth in demand for naturalgas and pricing in three sectors in theUnited Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Fig. 2.19 Relationship between growth in demand for naturalgas and pricing in industry in Japan. . . . . . . . . . . . . . 67

Fig. 2.20 Relationship between growth in demand for naturalgas and pricing in the residential and industrialsectors in Germany . . . . . . . . . . . . . . . . . . . . . . . . . 67

Fig. 2.21 Relationship between sector gas price and sharein OECD countries (2012) . . . . . . . . . . . . . . . . . . . . 68

Fig. 2.22 Residential gas share and pricing differences betweengas and electricity . . . . . . . . . . . . . . . . . . . . . . . . . . 69

Fig. 2.23 Industrial sector natural gas proportion and variancein natural gas and electricity price . . . . . . . . . . . . . . . 70

Fig. 2.24 Natural gas and electricity price differenceand demand growth . . . . . . . . . . . . . . . . . . . . . . . . . 70

Fig. 2.25 Natural gas and coal price difference and demandgrowth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Fig. 2.26 Chinese energy source consumption structure (%) . . . . 72Fig. 2.27 Natural gas consumption in China by sector . . . . . . . . 73Fig. 2.28 Natural gas prices in China and other countries . . . . . . 74Fig. 2.29 Long-term movements in natural gas price and

demand in OECD countries . . . . . . . . . . . . . . . . . . . 74Fig. 3.1 Preliminary comparison of coal power generation

and natural gas power generation costs. . . . . . . . . . . . 78Fig. 3.2 Power generation cost analysis . . . . . . . . . . . . . . . . . 80Fig. 3.3 Coal power emissions relative cost (CNY/kWh) . . . . . 81Fig. 3.4 Terminal price tolerance for users in various

natural gas sectors . . . . . . . . . . . . . . . . . . . . . . . . . . 97Fig. 3.5 Terminal price tolerance of main gas market users

in terms of energy substitution . . . . . . . . . . . . . . . . . 97Fig. 3.6 Effective 2013 China natural gas market

demand curve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98Fig. 4.1 Top five causes of death of residents in China . . . . . . 102Fig. 4.2 Hazard cost estimation for main pollutants

in Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103Fig. 4.3 Economic loss caused by atmospheric pollution

as a percentage of GDP . . . . . . . . . . . . . . . . . . . . . . 104

xxxviii List of Figures

Fig. 4.4 Further effects of atmospheric pollution . . . . . . . . . . . 105Fig. 4.5 Proportion of new technology use in newly built

coal-fired power stations in China . . . . . . . . . . . . . . . 109Fig. 4.6 Reduction of sulphur dioxide and nitrogen oxides

emission during the 11th Five-Year Plan period . . . . . 110Fig. 4.7 Change in the sources of PM2.5 and OC

(organic carbon) during the 11th Five-year Plan . . . . . 110Fig. 5.1 Main structures of the CGE model used

in this study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114Fig. 5.2 Development levels in China and international

comparisons in the standard scenario . . . . . . . . . . . . . 118Fig. 5.3 Growth speed in China and international comparisons

in the standard scenario . . . . . . . . . . . . . . . . . . . . . . 119Fig. 5.4 Growth speed in China and international comparisons

in the standard scenario . . . . . . . . . . . . . . . . . . . . . . 120Fig. 5.5 Primary, secondary and tertiary industries in China

and international comparisons in the standardscenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

Fig. 5.6 Change in high energy consumption industryratio under baseline scenario . . . . . . . . . . . . . . . . . . . 122

Fig. 5.7 Total energy consumption in standard scenario . . . . . . 122Fig. 5.8 Medium- to long-term energy production structure

in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123Fig. 5.9 Medium- to long-term energy consumption structure

in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124Fig. 5.10 Natural gas production and consumption in the

standard scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . 125Fig. 5.11 Medium- to long-term changes in ratio of natural gas

consumption in China . . . . . . . . . . . . . . . . . . . . . . . 125Fig. 5.12 Medium- to long-term power generation structural

changes in China. . . . . . . . . . . . . . . . . . . . . . . . . . . 126Fig. 5.13 Natural gas supply and demand in the policy-driven

scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127Fig. 5.14 Ratio of natural gas in total energy sources

in the policy-driven scenario . . . . . . . . . . . . . . . . . . . 128Fig. 5.15 Demand curve for natural gas in China in 2030 . . . . . 131Fig. 6.1 Changes in production and consumption of natural

gas in the United States from 1970 to 2012 . . . . . . . . 145Fig. 7.1 China’s annual increase in proved conventional

natural gas reserves . . . . . . . . . . . . . . . . . . . . . . . . . 157Fig. 7.2 Natural gas production volume in China. . . . . . . . . . . 159Fig. 7.3 Conventional natural gas consumption volume

in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160Fig. 7.4 Existing system natural gas production volume

forecasts (100 million m3) . . . . . . . . . . . . . . . . . . . . 162Fig. 7.5 Natural gas production forecasts in a partially

adjusted system environment (100 million m3) . . . . . . 162

List of Figures xxxix

Fig. 7.6 Licensing rights usage fee structure . . . . . . . . . . . . . . 181Fig. 7.7 Malaysia production share contracts . . . . . . . . . . . . . . 183Fig. 7.8 UK shale finance system competitiveness

(Woodmac study) . . . . . . . . . . . . . . . . . . . . . . . . . . 186Fig. 7.9 Mexico oil and gas production . . . . . . . . . . . . . . . . . 190Fig. 7.10 Mexican NOC prior to reforms . . . . . . . . . . . . . . . . . 191Fig. 7.11 Mexico’s Round Zero reform prospects . . . . . . . . . . . 193Fig. 7.12 World natural gas upstream openness. . . . . . . . . . . . . 194Fig. 8.1 Growth in global natural gas supply

and demand totals . . . . . . . . . . . . . . . . . . . . . . . . . . 198Fig. 8.2 International LNG trade volume (1990–2013) . . . . . . . 199Fig. 8.3 Global natural gas regional production

capacity (2012) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200Fig. 8.4 Global in-progress LNG plant regional production

capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201Fig. 8.5 Global LNG regional production capacity

(2017 existing and in-progress capacity) . . . . . . . . . . . 202Fig. 8.6 Global LNG future supply and demand layout . . . . . . 203Fig. 8.7 WTI oil price trends (2004–2015) . . . . . . . . . . . . . . . 204Fig. 8.8 Chinese natural gas import sources . . . . . . . . . . . . . . 206Fig. 8.9 Comparison of China’s natural gas import prices

and other international natural gas prices . . . . . . . . . . 206Fig. 8.10 China LNG imports . . . . . . . . . . . . . . . . . . . . . . . . . 210Fig. 8.11 Global spot trade market change trends this year . . . . . 210Fig. 8.12 China natural gas receiving station construction. . . . . . 211Fig. 8.13 China’s future natural gas imports . . . . . . . . . . . . . . . 213Fig. 8.14 Future Chinese natural gas import source nation

proportions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214Fig. 8.15 North American LNG supply . . . . . . . . . . . . . . . . . . 226Fig. 8.16 Global natural gas import and export . . . . . . . . . . . . . 227Fig. 8.17 Major natural gas resource reserve nations

and China’s potential natural gas export nations . . . . . 231Fig. 9.1 China’s natural gas pipeline network distribution. . . . . 234Fig. 9.2 LNG receiving station distribution map . . . . . . . . . . . 235Fig. 9.3 Underground gas storage distribution . . . . . . . . . . . . . 236Fig. 9.4 China’s natural gas pipeline construction . . . . . . . . . . 236Fig. 9.5 Interconnectivity between various entity natural

gas infrastructures across the country . . . . . . . . . . . . . 242Fig. 11.1 Oil and gas exploration rights and mineral rights

registered areas in 2012 . . . . . . . . . . . . . . . . . . . . . . 262Fig. 11.2 China’s natural gas infrastructure. . . . . . . . . . . . . . . . 263Fig. 12.1 Timeline of development of pipeline regulatory policy

in the United States and Europe . . . . . . . . . . . . . . . . 289Fig. 12.2 Timeline in the reform of the US natural

gas market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302Fig. 14.1 Diagrammatic representation of the natural gas

markets after complete separation of salesand pipeline transport. . . . . . . . . . . . . . . . . . . . . . . . 312

xl List of Figures

Fig. 14.2 Diagrammatic representation of a spot tradingmarket system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312

Fig. 16.1 China’s natural gas import diversification . . . . . . . . . . 339Fig. 16.2 China’s import security as compared

to major nations . . . . . . . . . . . . . . . . . . . . . . . . . . . 340Fig. 16.3 Japan’s LNG supply sources are diversified . . . . . . . . 341Fig. 16.4 Sources of China’s natural gas . . . . . . . . . . . . . . . . . 342Fig. 16.5 Time points when major nations promoted

market liberalisation reforms . . . . . . . . . . . . . . . . . . . 343Fig. 16.6 Gas reserve volume as a proportion of consumption,

showing planned increase for China. . . . . . . . . . . . . . 343Fig. 17.1 Natural gas’s share of global energy consumption . . . . 346Fig. 17.2 Changes in share in the energy mix between oil,

gas and coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346Fig. 17.3 Rising diversity in natural gas supply and demand

up to 2040 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 347Fig. 17.4 Sources of demand for natural gas

2012 versus 2040 . . . . . . . . . . . . . . . . . . . . . . . . . . 348Fig. 17.5 The 15 countries with the largest proven recoverable

natural gas reserves . . . . . . . . . . . . . . . . . . . . . . . . . 351Fig. 17.6 The major natural gas producing and consuming

regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 354Fig. 17.7 Natural gas supply and demand growth rates of

various regions, 1990–2013 . . . . . . . . . . . . . . . . . . . 354Fig. 17.8 Unconventional natural gas reserves by region . . . . . . 355Fig. 17.9 The increasing polarisation of regions into

suppliers and consumers of natural gas. . . . . . . . . . . . 356Fig. 17.10 Types of global natural gas trade. . . . . . . . . . . . . . . . 356Fig. 17.11 Global inter-regional pipeline natural gas trade . . . . . . 357Fig. 17.12 Global LNG trade . . . . . . . . . . . . . . . . . . . . . . . . . . 358Fig. 17.13 Comparison of competitiveness between pipeline

natural gas and LNG . . . . . . . . . . . . . . . . . . . . . . . . 359Fig. 17.14 Changes in natural gas contract types. . . . . . . . . . . . . 361Fig. 17.15 Key price indices and Japan’s average import price . . . 363Fig. 17.16 Current and proposed LNG regasification terminals

in North America, 2004 . . . . . . . . . . . . . . . . . . . . . . 364Fig. 17.17 Progressive divergence by different degrees from

oil prices of Asian oil-linked natural gas prices . . . . . . 365Fig. 17.18 Proposed LNG export terminals in North America,

February 2015. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 366Fig. 17.19 Sabine Pass LNG sale and purchase agreement

structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 367Fig. 17.20 Henry Hub natural gas prices could be higher

than natural gas prices linked to oil prices . . . . . . . . . 368Fig. 17.21 The relationship between natural gas price

and oil prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 368Fig. 17.22 China’s 2030 energy mix, natural gas consumption

and power generation energy mix, by scenario . . . . . . 372

List of Figures xli

Fig. 17.23 Global natural gas and coal demand, by regionand scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 373

Fig. 17.24 Trends in global natural gas production by regionand scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 374

Fig. 17.25 Global primary energy demand 2015–2030by region and scenario . . . . . . . . . . . . . . . . . . . . . . . 375

Fig. 17.26 Decline in China’s coal demand and leakageof capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 375

Fig. 17.27 Global natural gas hub price change trend forecasts . . . 376Fig. 17.28 Hybrid computable general equilibrium (CGE)

model used by Aurora for global modelling . . . . . . . . 377Fig. 18.1 The natural gas value chain . . . . . . . . . . . . . . . . . . . 382Fig. 18.2 Five steps to successful natural gas market

liberalisation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 385Fig. 18.3 The sequence of five regulatory reforms

and potential market reactions . . . . . . . . . . . . . . . . . . 390Fig. 18.4 Phases, development and key regulations in the

establishment of a liberalised natural gas marketin the US, 1978–1992 . . . . . . . . . . . . . . . . . . . . . . . 393

Fig. 18.5 US natural gas transmission pipelines. . . . . . . . . . . . . 399Fig. 18.6 US natural gas consumption before, during

and after the period of market liberalisation . . . . . . . . 400Fig. 18.7 Phases, development and key regulations in the

establishment of a liberalised natural gas marketin Europe, 1971–2013 . . . . . . . . . . . . . . . . . . . . . . . 402

Fig. 18.8 European Union natural gas consumption volumeand structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 406

Fig. 18.9 European Union transnational pipelinesand LNG terminal distribution. . . . . . . . . . . . . . . . . . 407

Fig. 18.10 Phases, development and key regulationsin the development of the British naturalgas market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 409

Fig. 18.11 National Grid completely owned and operatedBritish transmission networks . . . . . . . . . . . . . . . . . . 411

Fig. 18.12 UK natural gas consumption by sector, 1960–2012 . . . 412Fig. 18.13 Phases, development and key regulations

in the development of the Japanese naturalgas market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 413

Fig. 18.14 Japan natural gas market sales volume, 2012 . . . . . . . 415Fig. 18.15 Japan’s natural gas market liberalisation progress . . . . 416Fig. 18.16 Japan LNG terminals and high-pressure pipelines . . . . 417Fig. 18.17 Major components of Japanese natural gas

consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 418Fig. 18.18 Four major country suppliers of LNG gas imports

to Japan since 2000 . . . . . . . . . . . . . . . . . . . . . . . . . 419Fig. 18.19 Phases, development and key regulations

in the establishment of a liberalised naturalgas market in Korea. . . . . . . . . . . . . . . . . . . . . . . . . 420

Fig. 18.20 Korean natural gas consumption by sector . . . . . . . . . 421

xlii List of Figures

Fig. 18.21 Korean natural gas industry structure . . . . . . . . . . . . . 422Fig. 18.22 Korean LNG terminals and pipeline networks . . . . . . . 423Fig. 18.23 Major importers of natural gas to Korea, 2012 . . . . . . 424Fig. 19.1 US federal public land surface and underground

levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 427Fig. 19.2 Australia’s natural gas basins and major

transmission pipelines . . . . . . . . . . . . . . . . . . . . . . . 429Fig. 19.3 Natural gas production in Queensland, Australia . . . . . 429Fig. 19.4 Argentina’s primary basins and LNG receiving

stations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 432Fig. 19.5 Argentina’s natural gas production and

consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 433Fig. 19.6 Oil and natural gas production in Mexico . . . . . . . . . . 433Fig. 19.7 Pemex reserves analysis after bid round zero . . . . . . . 434Fig. 19.8 Pemex unconfirmed resources, 2014 . . . . . . . . . . . . . 435Fig. 19.9 Suggested timeline for a new round of tenders . . . . . . 435Fig. 19.10 The balance of factors needed in the regulatory

framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 438Fig. 19.11 The three layers of agreements supporting North

Sea usage rights . . . . . . . . . . . . . . . . . . . . . . . . . . . 439Fig. 19.12 Analysis of regulatory frameworks. . . . . . . . . . . . . . . 443Fig. 19.13 Market diversification in Singapore,

2004 versus 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . 445Fig. 19.14 Japanese LNG facilities and their proximity

to large cities and manufacturing hubs . . . . . . . . . . . . 447Fig. 19.15 Shell midstream partners pipelines . . . . . . . . . . . . . . . 450Fig. 19.16 Unbundling is the separation of midstream business

from that of upstream and downstream business . . . . . 452Fig. 19.17 The path of unbundling (ultimate ownership rights

unbundling might not be necessary) . . . . . . . . . . . . . . 455Fig. 19.18 Streamlined unbundling process (three steps only) . . . . 455Fig. 19.19 Correlation of domestic natural gas production

volumes and levels of and timing of unbundling . . . . . 456Fig. 19.20 The position of natural gas hubs in connecting

buyers and sellers . . . . . . . . . . . . . . . . . . . . . . . . . . 463Fig. 19.21 Hub development and its support from regulatory

measures and their market effects . . . . . . . . . . . . . . . 470

List of Figures xliii

List of Tables

Table 1.1 Natural gas consumption under the differentscenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Table 1.2 Natural gas market characteristics of majorcountries and regions. . . . . . . . . . . . . . . . . . . . . . . . 37

Table 1.3 Five methods for the unbundling natural gaspipeline network and natural gas transmission . . . . . . 41

Table 2.1 Role of four variables in OECD country naturalgas share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Table 3.1 Taxi price tolerance of natural gas as replacementfor petrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

Table 3.2 Bus price tolerance of natural gas as replacementfor diesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

Table 3.3 Transport lorry price tolerance of natural gasas replacement for diesel . . . . . . . . . . . . . . . . . . . . . 86

Table 3.4 Shipping price tolerance of natural gasas replacement for diesel . . . . . . . . . . . . . . . . . . . . . 87

Table 3.5 Price tolerance for residential usage naturalgas replacement of liquefied gas . . . . . . . . . . . . . . . . 90

Table 3.6 Price tolerance for residential usage natural gasreplacement of electricity . . . . . . . . . . . . . . . . . . . . . 90

Table 3.7 Residential disposable income price tolerancefor natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

Table 3.8 Price tolerance for commercial service usageof natural gas as replacement for liquefied gas . . . . . . 91

Table 3.9 Price tolerance for commercial service usageof natural gas as a replacement for electricity . . . . . . . 91

Table 3.10 Urban centralised heating price toleranceof natural gas as a replacement for coal . . . . . . . . . . . 92

Table 3.11 Glass industry price tolerance of natural gasas replacement for fuel oil . . . . . . . . . . . . . . . . . . . . 92

Table 3.12 Ceramics industry natural gas price toleranceas a replacement for coal gas . . . . . . . . . . . . . . . . . . 93

Table 3.13 Industrial boiler steam production price toleranceof natural gas as a replacement for coal . . . . . . . . . . . 93

Table 3.14 Natural gas tolerance in production of syntheticammonia as replacement for coal . . . . . . . . . . . . . . . 94

Table 3.15 Methanol production price tolerance of naturalgas as replacement for coal-based production . . . . . . . 94

xlv

Table 3.16 Hydrogen production price tolerance of naturalgas as replacement for coal-based production . . . . . . . 95

Table 3.17 Station price subsidies in each province . . . . . . . . . . . 96Table 3.18 Effective demand of natural gas in China based

on the Shanghai benchmark price in 2013 . . . . . . . . . 99Table 4.1 Calculation table for the economic loss caused

by pollution produced by one ton of raw coal . . . . . . 107Table 4.2 Dosage-effect function of inhalable particulate

matter PM10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108Table 5.1 Subdivision of industries in the model of

this study. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115Table 5.2 Growth speed and growth momentum

in the standard scenario . . . . . . . . . . . . . . . . . . . . . . 118Table 5.3 Industry structures in the standard scenario . . . . . . . . 120Table 5.4 Developed countries in the post-industrialisation

era . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121Table 5.5 Natural gas consumption based on primary usage

(100 million m3) according to use. . . . . . . . . . . . . . . 129Table 5.6 Natural gas energy source replacement price list

by province (calculated at the international oil priceof $80 per barrel) . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Table 5.7 Market demand for natural gas in China in 2030(100 million cubic metres) . . . . . . . . . . . . . . . . . . . . 132

Table 6.1 China’s natural gas consumption structure in 1998(excluding Hong Kong) . . . . . . . . . . . . . . . . . . . . . . 134

Table 6.2 Natural gas prices in 2005 after price adjustments(CNY/1000 m3) . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

Table 6.3 2007 natural gas usage policy. . . . . . . . . . . . . . . . . . 135Table 6.4 2012 natural gas usage policy. . . . . . . . . . . . . . . . . . 136Table 6.5 2003–2011 China natural gas use structure. . . . . . . . . 137Table 6.6 Maximum natural gas gate prices by province

(region, city) after 2015 price adjustments . . . . . . . . . 140Table 6.7 Baseline manufacturer’s prices (first-gate station)

for domestic land-based natural gas afterMay 2010 price adjustments. . . . . . . . . . . . . . . . . . . 141

Table 6.8 Gate natural gas prices by province after the 2013price reform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143

Table 7.1 Resource potential and state of developmentof various natural gas resources in China . . . . . . . . . . 156

Table 7.2 China’s natural gas resource volume . . . . . . . . . . . . . 156Table 7.3 China’s historical natural gas resource assessment

results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157Table 7.4 Coalbed methane newly added proved reserve data

table . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158Table 7.5 China’s coalbed methane production volume

in recent years . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160Table 7.6 National coalbed methane results of selection

of favourable target regions . . . . . . . . . . . . . . . . . . . 172

xlvi List of Tables

Table 7.7 National proved coalbed methane reserve forecast(100 million m3). . . . . . . . . . . . . . . . . . . . . . . . . . . 172

Table 7.8 National coalbed methane production growthforecasts (100 million m3) . . . . . . . . . . . . . . . . . . . . 173

Table 7.9 Operating and in-progress coal methane projects. . . . . 173Table 7.10 China’s current coal methane projects with road

permits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174Table 8.1 China’s natural gas imports, by source . . . . . . . . . . . 205Table 8.2 China’s LNG long-term contracts . . . . . . . . . . . . . . . 209Table 8.3 China’s future pipeline natural gas import

capacities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212Table 8.4 China’s existing natural gas trade policies . . . . . . . . . 218Table 8.5 China’s natural gas supply volume

(100 billion m3) . . . . . . . . . . . . . . . . . . . . . . . . . . . 221Table 8.6 2015 China natural gas supply volume

and structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 222Table 8.7 2020 China natural gas supply volume

and structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 222Table 8.8 2030 China natural gas supply volume

and structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 222Table 8.9 Most proved conventional natural gas reserves

by country . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 230Table 8.10 China’s existing and planned natural gas import

pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231Table 10.1 China’s natural gas peak demand calculations

(100 million m3). . . . . . . . . . . . . . . . . . . . . . . . . . . 249Table 10.2 China’s constructed underground gas reserves . . . . . . 251Table 11.1 Oil and gas exploration rights and extraction rights

registrations in 2012 . . . . . . . . . . . . . . . . . . . . . . . . 262Table 11.2 Details of the main natural gas pipelines built

in China, 1996–2014. . . . . . . . . . . . . . . . . . . . . . . . 265Table 11.3 LNG receiving stations online in 2014 in China

(�104 tonnes/year) . . . . . . . . . . . . . . . . . . . . . . . . . 267Table 11.4 LNG receiving station projects under construction

or planned for construction in China(�104 tonnes/year) . . . . . . . . . . . . . . . . . . . . . . . . . 268

Table 11.5 Construction status of main subterranean gasstorage facilities in China. . . . . . . . . . . . . . . . . . . . . 270

Table 11.6 Main provincial capital and urban gas enterprisesin 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 272

Table 12.1 Main characteristics of natural gas marketsof various countries and regions . . . . . . . . . . . . . . . . 288

Table 12.2 Five key unbundling models . . . . . . . . . . . . . . . . . . 295Table 12.3 Conditions for creation of a natural gas trading

centre . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 297Table 12.4 The energy regulators of different countries . . . . . . . . 300Table 17.1 Remaining technically recoverable natural gas

resources (end 2013) . . . . . . . . . . . . . . . . . . . . . . . . 348

List of Tables xlvii

Table 17.2 Top 10 countries with technically minable reservesof shale natural gas . . . . . . . . . . . . . . . . . . . . . . . . . 360

Table 17.3 Regional market pricing characteristics . . . . . . . . . . . 362Table 18.1 Market traits of five natural gas markets

plus China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 384Table 19.1 The influence of the nature of competition

on midstream infrastructure regulation choices . . . . . . 440Table 19.2 Differing LNG management systems resulting

from different market traits in Singapore and Japan . . . 444Table 19.3 Shell Midstream Partners ownership rights

allocation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 451Table 19.4 Operational changes resulting from five types

of unbundling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 454Table 19.5 European LNG receiving stations and gas reserve

facilities and their voluntary unbundling . . . . . . . . . . 462Table 19.6 Necessary preconditions in three areas

for the successful development of a naturalgas hub . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 465

xlviii List of Tables

1General Summary

Natural gas is an efficient, easy to use fuel. Thereare abundant resources, and advances in tech-nology have brought increased supply and lowercosts. The golden age of natural gas has arrived,and in the future it will play an even greater rolein the global energy system. In China, thedevelopment of the natural gas industry must bepromoted as part of the optimisation of energyresources to control atmospheric pollution whilemeeting the energy needs for economic growth.Efficient, safe and sustainable development of thenatural gas industry requires the rationalisation ofthe structure of the industry, greater demand,increased supply, improved safety, higher effi-ciency and the creation of a modern natural gasindustrial system and government managementsystem. This will lead to natural gas becomingone of the main energy sources in China.

1.1 Global Trends in the NaturalGas Industry

1.1.1 Abundant Resources,and a Greater Rolefor Natural Gasin the Future

According to International Energy Agency(IEA) statistics, global current natural gasresources stand at 751 trillion m3, and at thepresent levels of production, these can beexploited for more than 200 years. Theseresources include 420 trillion m3 of conventionalgas reserves and 331 trillion m3 of unconven-tional gas reserves, with the latter including206 trillion m3 of shale natural gas, 76 tril-lion m3 of tight natural gas and 47 trillion m3 ofcoalbed methane. The proven reserves (resourceswhich can be extracted under current economicand technological conditions) are estimated at185.7 trillion m3 and can be exploited for morethan 50 years. Moreover, the new resourcesdiscovered every year exceed consumption, andnatural gas resource to production ratio of 55.1 isshowing a steady upward trend. It is, therefore,safe to conclude that in the future gas reserveswill remain abundant.

The importance of natural gas in the globalenergy structure is growing all the time. Theglobal consumption of natural has grown byapproximately 2.7% between 2005 and 2014, thefastest of any fossil fuel (BP 2014). Assumingcontinued strong consumption growth in thefuture, natural gas consumption may increase at

* This chapter was compiled by Jinzhao Wang andChangwen Zhao, with important guidance and finalvetting provided by Wei Li, Shijin Liu, Junkuo Zhang,Laiming Zhang, Guoqiang Long and Bin Yu from theDevelopment Research Center of the State Council. Thestudy group consultants and core experts providedimportant suggestions for revision. International teammembers and Chinese team members also offeredimportant contributions to the drafting of the report.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_1

1

approximately 2% per annum until 2030, and by2035 it will become the largest primary energysource (IEA, Current Policies Outlook). The totalsupply and demand for natural gas is expected tohave grown from 3.1 trillion m3 in 2010 toapproximately 5 trillion in 2030 (Fig. 1.1).

Recently, due to factors such as sluggisheconomic recovery, the low price of coal andlarge subsidies received by the renewable energysources industry, the growth in the demand fornatural gas in developed countries such as theEU, the USA and Japan has been limited.Demand in non-OECD nations is much higher,and is expected to continue to be so: in the periodup to 2030, non-OECD countries are expected toaccount for 80% of the increase in global naturalgas consumption.

1.1.2 Changes to the Global Tradeand Pricing, and a MoreInterconnected Market

Advances in liquefied natural gas (LNG) tech-nology have greatly changed the global naturalgas trade, and the proportion of LNG in globaltrade is gradually growing. In 2013, the volume

of the international gas trade stood at 1 tril-lion m3, of which 320 billion (32%) was LNG(IGU 2014). This share has grown and diversi-fied dramatically over the last few decades. In1990 there were eight LNG-exporting countriesand nine LNG-importing countries. The numbershave now grown to approximately 30 and 20respectively, and future estimates are that thiswill continue to grow, creating a much moreliquid global market. There have also beenextensive changes in which nations export LNG.Australia’s production capacity has been growingrapidly, and recent investments into seven LNGprojects there will bring its total annual capacityto 85 billion m3 (95 billion m3 if projects underconstruction in neighbouring Papua New Guineaare included). The success of the shale naturalgas industry in the USA has turned the countryinto another potential exporter. The capacity ofLNG projects now under construction worldwideis now estimated at 130 billion m3, and if theseprojects become operational as planned, totalglobal annual production capacity of LNG isexpected to rise from 390 billion m3 in 2012 toapproximately 520 billion by 2017. Exports fromAustralia, the United States and Canada areexpected to affect the global LNG trade structure

Natural gas demand by 2020 Natural gas supply by 2030

Liquefied naturalgas (LNG)

Inter-regional pipelinenatural gas

Supplying nation market shale gas

Supplying nation market conventional natural gas

2030 – 5000(1 billion

cubic metres)

2030 – 5000(1 billion

cubic metres)

2010 – 3100(1 billion

cubic metres)

2010 – 3100(1 billion

cubic metres)

UnitedStates

growth of >30%

Asiagrowth

of>40%

Middle Eastgrowth

of 12%

2010 2020 2025 2030

Fig. 1.1 Global natural gas supply and demand

2 1 General Summary

the most, and with this change come both ben-efits and risks to China’s LNG imports.1

The pricing of natural gas has also beenchanging. Formerly dominated by linkage to oilprice and by long-term supply agreements, nowthere is a diversity of methods in modern marketsfor setting the price for natural gas, and there isalso regional variation in prices.2 The 2014report by International Gas Union (IGU) showedthat just 19% of natural gas was linked to oilprice (Fig. 1.2).

Changes in the natural gas trade and pricingmethods have increased the interconnectivity ofnatural gas markets. Previously, gas marketswere regional—Europe, Asia and North Americawere the three main regional markets, and thewas a large price differential between them,caused by the regional differences in resources,transportation methods and pricing methods.

North American prices were the lowest, followedby Europe and then Asia. In extreme cases, Asianprices were double those in Europe and quadru-ple those in North America. With the changes intrade and pricing mechanisms, the interactionbetween the markets will strengthen, reducingthe price gap, and putting the global market onthe road to greater integration.

1.1.3 Falling Oil Prices and TheirEffect on Natural GasMarkets—but no Greatin the Price of ImportedGas in China in theMedium to Long Term

International oil prices, which in June 2014 stoodat over 100 $/bbl (Brent), have more than halved,and in October 2015 were below 50 $/bbl.Where gas price is linked to oil price, this hasmeant a substantial fall in gas price. In Japan,LNG prices fell from 20 $/MMBtu in 2014 to thecurrent level of 7 $/MMBtu. Gas-importingcountries whose supply agreements are basedmainly on spot prices or short-term contracts

Competitive prices

Regulated prices

0%

0% 100%

0%

20%2005

more spot, equal decline in regulated and long-term

more spot, less long-term, constant

regulated

more spot, less regulated, constant

long-term

201380%

40%60%

60%40%

80%20%

20% 40% 60% 80% 100%100% Long-term

contracts

The world in aggregate, and particularly Europe, OECD Asia and the FSU are moving towards prices determined by competitive gas markets

The world in aggregate, and particularly Europe, OECD Asia and the FSU are moving towards prices determined by competitive gas markets

North America

Europe

Asia

OECD Asia

Central and South America

FSU

Africa

MENA

World

North America

Europe

Asia

OECD Asia

Central and South America

FSU

Africa

MENA

World

Gas in North America is almost entirely competitively pricedGas in North America is almost entirely competitively priced

Half of European gas is now competitively pricedHalf of European gas is now competitively priced

Fig. 1.2 Evolution of global natural gas pricing mechanism. Note The width of the line increases with time; if a linemoves towards the corner of the triangle, this indicates a tendency towards that pricing method

1For Australia, the United States and Canada, LNGdevelopment has an influence on Chinese imports. Furtherdiscussion is provided in Sect. 8.3.2Contracts linked to oil prices can also be competitive, butit is fixed-price gas contracts that are generally morecompetitive, and are able to more rapidly respond tochanges in the market.

1.1 Global Trends in the Natural Gas Industry 3

have also seen a fall in the cost of imports. As forthe gas supplier countries, the largest impact wason current projects under construction, as manyof those had been launched with the expectationof high oil prices, and the profitability of suchprojects will have reduced, with some perhapsbecoming no longer profitable. Falling oil priceshave also greatly affected planned natural gasprojects in the long term. The total capacity ofprojects where final investment decision has beenmade is 30 billion m3, and for those at theFront-End Engineering Design phase is 370 bil-lion, while the capacity of projects at even earlierphases has reached 500 billion (IGU 2014).Falling oil prices have affected the investmentprocess for several of these projects. The finalinvestment decision has been postponed, forexample, for the Browse gas project in Australiaand for Canada’s Pacific Northwest Project. Theglobal fall in oil prices is caused adjustments innatural gas markets. The falling oil prices haveresulted in natural gas supply being lower thanpredicted, and this will, to a certain extent, pro-vide a limit to how low international natural gasprices can sustainably fall.

Causes of the Current Fall in Oil Pricesand Future TrendsThe shale oil and gas revolution in theUnited States has changed the global oiland gas supply structure and changed theinternational balance of power as regardsprice control.

The breakthrough in the shale oilindustry stem originated in advances inthe US hydraulic fracturing technology,and in 2011 the supply of natural gasovertook demand, leading to a fall inprices. The effects of the shale revolutionthe made themselves felt in oil, and therewas a large increase in US oil output in2011, with supply rising from 5.5 millionbarrels per day to 9.3 million in 2014, anincrease of 3.8 million barrels per day injust three years. This increase allowed the

United States to overtake the output ofboth Iran and Iraq, the number two andnumber three OPEC producers, theequivalent of the United States havingbecome, in the space of three years, amajor OPEC nation.

More importantly, the shale oil and gasrevolution has changed the internationalbalance of power in price control. Previ-ously, oil supply capacity and demandwere such that Saudi Arabia was able toregulate market balance using its sparecapacity of 2–3 million barrels per day—they were effectively able to set oil prices.Currently US shale oil output is 4.2 millionbarrels per day and production is able torespond rapidly to higher market prices.The result is a flattening of the global oilsupply curve and a reduction in the abilityfor Saudi Arabia to use its capacity tomanage international oil prices.

The slowdown in Chinese demand hasalso greatly affected the global demand foroil. Demand in China grew by an averageof 6.5% per year between 2004 and 2013,an annual increase of 500 million barrelsper day, accounting for 45% of the annualglobal increase of 1.1 million barrels perday. In some years the increase in demandfor oil in China exceeded 1 million barrelsper day, and the oil bull market of the past10 years is to a certain extent attributableto this rapid growth of Chinese demand.However, recently there has been a slow-down in the growth of China’s oil demand,with growth falling to 3.7% or 0.39 millionbarrels per day. In 2014, growth fell fur-ther, to 2.3% or 0.22 million barrels perday, slipping below the past 10-year aver-age. The slowdown in the growth of theChinese economy might have become thenorm, and the situation of demandexceeding supply caused by high-speedChinese economic growth might neverreturn.

4 1 General Summary

The medium- to long-term view is that the oilprices may recover to 70–80 $/bbl, with theaverage cost of US shale oil at 60–70 $/bbl. Asglobal demand gradually grows, it will absorbthe spare capacity we see now, and internationaloil prices will again exceed the cost of supply ofshale and other unconventional oil.

Therefore, in the short and medium term,natural gas supply will exceed demand.Asian natural gas spot prices may slide to below7–8 $/MMBtu. This can be an opportunity forChina to expand natural gas usage, providedthere is timely liberalisation of imports. In themedium to long term, if there is to be increaseduse of natural gas this will require improvementsin the efficiency of usage and a rationalisedpricing system. Also, the costs of natural gasexploitation, liquefaction and transportation inAustralia, the United States and East Africa arehigh, and, once delivered to Chinese ports, theprice is expected to exceed 10 $/MMBtu.

1.1.4 China’s Share of the GlobalNatural Gas Market IsSlowly Growing—ChinaMust Become an ActivePlayer in theInternational Natural GasMarket

In 2014, China’s consumption of natural gasstood at 183 billion cubic metres—less than 5%of the world’s total—but it is expected to risequickly in the future. According to several dif-ferent development strategies, by 2030 China’sconsumption of natural gas will rise to 450–570 billion m3 (9–12% of total global con-sumption) and account for 15–25% of the globalincrease in natural gas demand.

The increase in China’s natural gas con-sumption is not expected to lead to a markedincrease in global prices. First, China has abun-dant resources of natural gas, and domestic

production can cover part of the increase inconsumption. Second, global natural gas resour-ces are plentiful. If China sends out a cleardemand signal to global markets, this can stim-ulate upstream investment to expand future sup-ply capacity, without having a significant impacton global gas price. Third, ending the nationalreliance on coal will cause Chinese coal prices tofall, and, as China accounts for over 50% ofglobal coal consumption, this could have amaterial impact on international coal prices.Developing countries, more sensitive to eco-nomic costs, may increase their coal consump-tion and reduce their consumption of natural gas,thus triggering a global crowding-out effect and,to a certain extent, hedging against the rise inprice caused by the increase in Chinese demand.Quantitative model analysis shows that activemeasures to increase the consumption of nationalgas would only lead to an approximately 4%increase in international gas prices.

China must stop being a natural gas consumernation, passively accepting natural gas marketprices, and should, using trade and investment,play an active role in the international natural gasmarket. Chinese enterprises could play this rolevia equity investment, joint development andprovision of technical services. By implementingthe ‘One Belt, One Road’ development strategy,China will have an opportunity to establish anin-depth partnership with major naturalgas-producing countries such as Russia, Turk-menistan, Qatar and Iran. This is undoubtedly agreat opportunity for China to connect to theglobal natural gas industry. Moreover, China canactively move forward the core natural gas con-struction projects, raising its status both in thedomestic market and in the East Asian market.By 2030, the demand for natural gas fromdeveloping countries, such as India, is expectedto enter a phase of explosive growth and Chinawould be able to be proactive, yet operate from aposition of security, in the face of global marketcompetition.

1.1 Global Trends in the Natural Gas Industry 5

1.2 China’s Natural Gas Supplyand Demand and Its PrimaryChallenges

1.2.1 The Chinese Economy’s NewNormal

The characteristics of China’s new economicnormality are as follows. First, the speed ofeconomic growth has shifted from fast to med-ium. According to forecasts, GDP growth duringthe 13th Five-Year Plan period is expected to bein the region of 6.66%, followed by 5.56%between 2021 and 2025, and 4.64% in 2026–2030. It is hoped that in 2020 GDP per capitawill reach $10,000 (using 2013 fixed prices andbasing the calculation on an annual appreciationrate of yuan renminbi of 0.5%), rising to 20,000in 2030. The second characteristic is the struc-tural change in the Chinese economy. Currentlythe Chinese economy is in the late stage ofindustrialisation, which is expected to be com-pleted by 2020. The industrial structure isexpected to change—the proportion of the ser-vice industry in the economy is expected to riseto 53.1% in 2020 and 61.2% in 2030, while thecontribution of secondary industry will shrink to39.8% and 33.4%, respectively. In the industrialsector, the contribution of heavy chemicalindustry will decrease, with the demand for steel,cement and other heavy chemical industrypeaking around the period of the 13th Five-YearPlan. As far as energy is concerned, China’sdemand will go back to medium growth from fastgrowth. Model predictions tell us that in 2020 thetotal energy consumption will reach 5 billiontons, a 3.4% average annual increase between2010 and 2020, and in 2030 the energy con-sumption will increase further to 5.7 billion tons.

1.2.2 Growth Natural Gas Demandin China

Even though there has been a slowdown ineconomic growth and energy demand, thedemand for natural gas will continue to increasefor a period of time in the future. The first reason

is the low contribution of natural gas to totalenergy consumption. In 2014 Chinese con-sumption of natural gas stood at 183 billion m3,which, according to the latest statistics, accoun-ted for 5.8% of total energy consumption thatyear. Globally, that proportion stands at 23.8%,with more than half of countries at 20–40%.During the 30-year period between 1982 and2012, the United States, Japan, Germany and theUnited Kingdom saw the part played by naturalgas in their energy consumption grow from 23, 9,12 and 27%, respectively, to 40, 33, 29 and 45%.The same statistics for the emerging economiesof Turkey, Malaysia and Egypt show an increasefrom 1, 2 and 9% to 41, 48 and 63% respectively,a huge increase for both the developed and theemerging economies.

The second reason is that the expansion of theservices industry, growing urbanisation and thecontrol of atmospheric pollution all spur on thecontinuing growth of natural gas consumption.The data for the developed countries shows thatfor each 1% increase in the service industry thereis a corresponding 0.84% increase in the contri-bution of natural gas to the total energy con-sumption. One cause for such a close linkbetween the growth of the service industry andthe increase in natural gas consumption is thatthe demand for high-quality energy sources riseswith economic development, and especially withthe growth of the services industry. The secondcause, and an important one, is the people’sdemand for clean air, a consequence of growingurbanisation, accompanies the growth of theservices industry. The experience of developedcountries shows a close relationship betweennatural gas consumption and fine particulateatmospheric pollution—as the role of natural gasin energy consumption rises, it is followed by alarge drop in the airborne concentration of fineparticles.

We have carried out a quantitative scenarioanalysis on the future demand for natural gas.The results of the analysis are as follows. Underthe “business as usual” scenario, in 2015 thedemand for natural gas approaches 200 bil-lion m3. In 2020 it will break the 300 billion m3

barrier, and in 2030 it will exceed

6 1 General Summary

450 billion m3. The fastest growth is expected tooccur in residential usage: gas, heating, transportand electricity generation. Despite the predictedfast growth in natural gas consumption under the“business as usual” scenario, the targets for nat-ural gas industry development stipulated in the12th Five-Year Plan and the Medium- toLong-Term Energy Resources DevelopmentStrategy will not be met. This clearly illustratesthat, in order to meet these targets, more effectivepolicies must be adopted to further boost thegrowth of the demand for natural gas.

Using model testing we have concluded thatthe most effective economic measures are thestrengthening of environmental regulation andthe setting of carbon prices by introducing car-bon trading and carbon tax. Under the conditionsof stronger environmental regulation and carbonpricing, the Chinese demand for natural gas mayindeed reach the 12th Five-Year Plan targets ofconsumption of 350 billion m3 by 2020 and580 billion by 2030. These policies will lead tothe proportions of natural gas in national energyconsumption of 10.8 and 15.4% respectively, alarge increase on the 2014 figure of 5.8%(Fig. 1.3).

Under the policy scenario, the areas where theincrease in natural gas consumption is expectedto be the fastest are those sensitive to changes inthe coal prices and in the environmental costs.These include gas heating, gas electricity gener-ation and transport. Compared with the “businessas usual” scenario, in 2030 the consumption ofnatural gas for electricity generation will rise to45 billion m3. Gas heating is another area withgreat demand potential, which is also very sen-sitive to cost changes, and under the policy sce-nario, the consumption of natural gas for heatingis expected to rise to 30 billion m3. For the otherareas, such as the residential use of gas, thechanges in demand are relatively small(Table 1.1).

1.2.3 Potential to Expand DomesticNatural Gas Supplyand Import Capacityin China

The statistics tell us that China is rich in coal,lacks oil and is poor in natural gas—but in factChina has rather abundant natural gas resources.

One hundred million cubic metres

Business as usualscenario ratio

6000

5000

4000

3000

2000

1000

0

25.0%

20.0%

15.0%

10.0%

5.0%

0.0%

Government policy scenario ratio

Business as usual scenario consumption rate

Government policy scenario consumption rate

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

4.8%4.8% 6.0%

6.1%

8.0%

10.8%9.5%

13.1%

11.0%

15.4%

Fig. 1.3 Natural gas demand volume and its role in energy consumption under the different scenarios

1.2 China’s Natural Gas Supply and Demand and Its Primary Challenges 7

According to Ministry of Land and Resources oiland gas data for 2013, China’s conventional gasresources stand at 68 trillion m3, of which40 trillion m3 are recoverable. China also pos-sesses extensive unconventional gas resources,comparable in size with its conventional resour-ces—25 trillion m3 of recoverable shale naturalgas and 11 trillion m3 of recoverable coalbedmethane. As for newly discovered provenresources, in 1986–1990 less than 40 billion m3

of natural gas deposits were confirmed, in 1991–1995 this figure rose to almost 100–150 bil-lion m3 in 1996–2000, to 300 billion m3 in2001–2005, to 320 billion m3 in 2006–2010, andin the three-year period between 2011 and 2013the proven geological reserves exceeded600 billion m3, reaching the 1.1 trillion m3 markin 2014. The volume of the recoverable newlyconfirmed reserves exceeds 500 billion m3, and,based on the data from the previous years, wecan expect proven resources to continue to growin the future. China’s production of conventionalnatural gas billion cubic metres in 2014 was128 billion m3 with, in addition, 2.6 billion m3

of coal seam gas and 1.3 billion m3 of shalenatural gas.

China might possess abundant natural gasresources, but even so, natural gas extraction inChina is very difficult and the costs high. Onethird of all the recoverable natural gas in China is

tight natural gas, deemed to be an unconven-tional resource outside China, and its extractionis more difficult and expensive than that of thecommon natural gas. Many of the conventionalgas deposits in China lie very deep, are rich insulphur and have high extraction costs. China hasvery rich shale natural gas resources, but, apartfrom few locations such as Fuelling in Chongq-ing, most of the deposits of shale natural gas aresituated at great depth with difficult surfaceconditions, and the exploration and exploitationcosts are thus higher than in the United States.Innovation, both in technology and in organisa-tion, is needed to exploit the full potential ofthese resources.

Analysis has shown that, with things organ-ised as they currently are, by 2020 conventionalgas output may reach 180 billion m3, shale nat-ural gas 40 billion m3 and coal seam gas10 billion m3, bringing total natural gas output to230 billion m3. In 2030, conventional natural gasoutput will rise to 260 billion m3. The totaloutput of shale natural gas is expected to rise to80 billion m3, as the output from SouthernSichuan and East Sichuan’s Longmaxi shaleformations is expected to increase, and outputbreakthroughs are expected at other shale naturalgas fields. Rough estimates predict that the out-put of coal seam gas will reach 40 billion m3,with coal seam gas contributing 20 billion m3,

Table 1.1 Natural gas consumption under the different scenarios

Business as usual scenario Policy scenario

2015 2020 2025 2030 2015 2020 2025 2030

Extractive industry 151 169 138 115 150 188 161 141

Petroleum processing and cokingindustry

143 216 286 356 144 228 304 384

Non-metal mineral industry 132 179 179 180 137 236 251 265

Metallurgical industry 79 101 97 98 82 138 140 148

Natural gas power generation 249 499 766 1120 257 673 1057 1574

Natural gas heating 57 252 415 589 59 349 601 887

Transport 269 435 623 787 268 446 652 842

Chemical industry 316 402 420 456 314 396 415 454

Other industries 168 177 205 233 176 246 287 326

Residential 405 576 683 742 397 548 662 734

Total 1968 3005 3811 4678 1985 3447 4531 5756

8 1 General Summary

and coal bed tight natural gas and shale naturalgas another 20 billion m3. The total gas output inChina will thus reach 380 billion m3. If anorganisational reform is carried out, more playersare attracted to open up and exploit the resource,and further technological breakthroughs areachieved, then in 2020 the output of shale naturalgas could reach 60 billion m3, coal seam gas15 billion m3, and coal bed tight gas and shalenatural gas 15 billion m3, bringing the total to270 billion m3. By 2030, conventional gas out-put could rise to 280 billion m3. An output of150 billion m3 of shale natural gas can beachieved by 2030 if the new system used inSouthern and East Sichuan production proves tobe effective, and is used successfully at othershale formations. Rough estimates predict thecoal seam gas output to reach 40 billion m3, thuspushing the total natural gas output to 470 bil-lion m3. Moreover, the coal gas industry can alsogrow, and may reach production capacity of30 billion m3 by 2020 and 50 billion by 2030.The methane hydrate industry is expected toremain at the research and development andexperimental and demonstration stages in 2030,as large-scale commercialisation of this energysource remains very difficult.

Turning to consider imports from overseas,China’s import capacity is undergoing rapidgrowth. Central Asia–China Gas PipelineLines A, B and C are already operational, withtotal capacity of 55 billion m3/year. The capacityof Line D of the same pipeline is 30 bil-lion m3/year and this is estimated to becomeoperational in 2016. The Myanmar–China Pipe-line became operational in 2013 and has acapacity of 12 billion m3/year. The contractshave been signed for the construction of China–Russia East Route pipeline, which is estimated tostart operations around 2018, and have capacityof up to 38 billion m3/year. The Memorandumof Understanding was signed in November 2014for the western China–Russia pipeline route,planned to start operations before the year 2020,and its capacity is expected to reach 30–60 bil-lion m3/year. In total, by 2020 China’s importcapacity via pipelines will reach approximately

100 billion m3/year, rising to 135–165 billionm3 by 2030.

As far as LNG imports are concerned, accordingto the already signed contracts, including sales andpurchase contracts, letters of intent and memoran-dums of understanding, the import volumewill risefrom the current 25 billion m3 to approximately57 billion in 2020. The Australian contribution toLNG imports will increase greatly, from the current5 billion m3 to approximately 25 billion in 2015.Other major contributors to this import growth areCanada (8 billion m3), Russia (4 billion m3),Papua New Guinea (3 billion m3) and other thirdparties (9 billion m3). Regarding LNG terminalconstruction, the capacity of China’s LNG termi-nals may reach 85–225 billion m3/year, greatlysurpassing the expected future volume of LNGimports. Based on these facts, and considering thelong-term LNG and pipeline contracts that Chinahas already signed, in the coming fewyears China’scapacity for natural gas imports is expected to growquickly, from 53 billion m3 in 2013 to over160 billion m3 in 2020 and is expected to reach210–240 billion m3 in 2030.

If both domestic supply and imports are addedup, the estimation is that the total supply capacitywill reach 425–495 billion m3 by 2020, rising to640–800 billion m3 in 2030. It is important tomake it clear that these capacities can only bereached if breakthroughs are made in the devel-opment of the domestic natural gas, and espe-cially non-conventional gas, resources, and if theinternational contracts are fulfilled. The annualcapacity and import capacity depend on growingdemand, opening up of domestic resources,progress made in the construction of internationalprojects, and changes in the domestic and theinternational supply prices.

1.2.4 Key Problems Facingthe Developmentof the Natural GasIndustry

The past 10 years saw a rapid growth of naturalgas demand, with demand exceeding supply, but

1.2 China’s Natural Gas Supply and Demand and Its Primary Challenges 9

in the coming five to ten years the situation isexpected to be different. As domestic outputgrows and import capacity increases, the supplyand demand for natural gas will have reached abroad general equilibrium. According to modelanalysis, even under the scenario of strengthenedenvironmental regulation and levying of carbontax, the demand for natural gas will reachapproximately 350 billion m3 in 2020 and580 billion in 2030, but the supply capacity willexceed 400 and 600 billion m3 in the same years.Supply is no longer the key factor in inhibitingthe growth of natural gas industry, as the prob-lems facing the industry have changed greatly.The increase in natural gas consumption that wesaw over the past few years has slowed downgreatly, and the current problems that havegradually emerged are low efficiency, high pri-ces, problematic transportation and organisa-tional inflexibility. The key problems at all thelinks in the industrial chain—resource extraction,transportation, sale and usage—must be system-atically identified understood and addressed.

First, the environmental benefits and theeconomic value of natural gas must be realised inorder to boost its consumption. Natural gas is anideal substitute for other fuels—it is a clean,environmentally friendly, efficient and easilyregulated energy source. However, the problemwhen comparing it with coal is its persistentlyhigher price. Burning of natural gas does notproduce SO2 and soot, but this environmentalbenefit is not factored into the cost equation.When used in electricity generation, natural gashas a great advantage—its capacity for regulationand response—but its potential to be used forpeak shaving has not yet been exploited either.The thermal efficiency of natural gas when usedfor CCHP generation is twice that of coal, but weare having difficulties realising this potential tosave energy and reduce greenhouse gas emis-sions. Failure to externalise the economic andenvironmental benefits of using natural gas willmake the maintenance of the previously fastconsumption growth problematic. Now that totalChinese resource consumption has entered amedium growth period of 3–4% per annum, anincrease in the natural gas consumption cannot

come solely from the demand for new energysources, but must also, to a great extent, comefrom coal and oil substitution. Currently, thesurplus production of coal in China is extremelysevere, with prices at their historical minimum,and, if we cannot exploit the environmental andeconomic benefits of natural gas, it will havedifficulties competing with coal and the slow-down of its consumption growth will continue.

Second, we can, using a rational price,achieve a sufficiently stable supply. According toour modelling, compared to current levels, by theyears 2020 and 2030 China’s consumption ofnatural gas will double and treble respectively.Failure of domestic production to keep up willlead to gas imports quickly rising to over 50%,and supply security issues will then impede thesustainable development of China’s natural gasindustry. In addition to the protection of naturalresources, price levels and market stability arealso critical. Currently, the upstream explorationand exploitation of national resources are notcompetitive with imports. This results in irra-tional resource allocation and rapidly risingupstream natural gas costs. The price in thecontracts signed recently is relatively high. Thereis an objective reason for this—currently demandis higher than supply on the international naturalgas market—but another reason is the misplacedbelief by the three largest players in the oilindustry that their market superiority allows themto pass the high price downstream. Allowing theupstream costs of natural gas to grow further mayresult in exceeding the potential for end userswitching and thus running the risk of makingnatural gas unsellable at this high price.

Third, we must achieve safe, fair and trans-parent interoperability of natural gas transmis-sion and distribution. In recent years China’snatural gas pipeline network has grown greatlyand the construction of the unified pipeline net-work framework is already at preliminary stage.The length of the network stands at 80,000 km,three times the figure for 2004. However, takingthe medium- to long-term view of natural gasconsumption and demand, the transmission anddistribution capacity of the network are far fromsufficient, and we need to mobilise and apply the

10 1 General Summary

capacity of all forces for its development,investment and construction. Looking at themarket structure, there is a lack of overall plan-ning, pipeline transmission and sales services arebundled together and there is a severe problem ofmarket monopolisation. There are also a wholeseries of problems, from insufficient branch linesand peak storage facilities to pipeline networkoperational safety.

Fourth, we must standardise markets andpricing. Pricing mechanisms are key if we wantto co-ordinate the benefits which extend down,up and mid-stream on the industrial chain, andthey will have direct relationship with healthysustainable economic development in China.There is currently a great deal of governmentintervention in price setting in China, and withthe pricing management arrangements as theystand, the government is over-regulating in someareas, while other areas are left completely dis-regarded. Currently, in pricing, the net presentvalue method is being gradually replaced by the“cost plus” method, but the situation still existswhen only the upstream urban gate price can beset, without a way to solve the problem of dis-connecting oil and gas prices. The midstreampipeline transmission services are bundled withterminal sale services, there is a lack of stan-dardised fees for pipeline transmission and, dueto lack of supervision, provincial andmetropolitan networks artificially inflate theirprices. The downstream sales market is monop-olised by local gas companies, and also there is across-subsidy issue between industrial clients andprivate residential users. The inverted situationhas arisen, where the price for industrial clients ishigher than that for private individuals, whichabsurdly contradicts the international principle oflarge customers enjoying lower prices. This isalso detrimental to coal substitution and envi-ronmental protection.

Fifth, a modern natural gas industrial systemand government regulatory mechanism must beformed. A reconstruction of Chinese natural gasindustry setup and market management systemmust be carried out in order to support andbenefit the growth of Chinese natural gas market.Looking at the market situation, it is clear that the

market is currently dominated by single largeplayers—state-owned enterprises. No matterwhere you look, at the ownership of resources orthe pipeline construction and operation, themarket share of the three large oil companiesexceeds 90%, with the share of PetroChina aloneat over 70%. There is currently virtually nomarket competition in the industry and there isno sign of rising efficiency. It will, therefore, beextremely difficult to sustain the predicted futureoutput of 580 billion m3. In the past, the gov-ernment relied primarily on administrative com-mand when it came to managing the natural gasindustry, which is not suited to a diversified,competitive and flexible industrial system. Wemust gradually explore the transition from the“full control” to the “standardised regulation”method, set clear regulation content andmethodology, and assess its cost and feasibility.

1.3 China’s Natural Gas IndustryDevelopment Strategyfor the Next 15 Years

1.3.1 National Strategy and PolicyAre Crucial for NaturalGas IndustryDevelopment in China

We have developed two scenarios for the futuredevelopment of China’s natural gas industry.According to the “business as usual” scenario,influenced by expensive natural gas, cheap coaland oil and weak environmental policies, thegrowth of the demand for natural gas will slowdown, and natural gas will remain a niche energysource. In the event of there being no break-throughs in non-conventional gas sectors such asshale and coal seam gas, growth in supply willalso slow. With natural gas being currentlywidely available on the international market,imports into China will rise rapidly, but volatilityin international markets will start raising prob-lems of supply security. Without extensiverestructuring of natural gas production andmanagement systems, the industry will lackdynamism, have low operational efficiency and,

1.2 China’s Natural Gas Supply and Demand and Its Primary Challenges 11

as the price for both imported and domesticallyproduced gas remains relatively high, growth inthe natural gas market will be restricted, and theentire development of the natural gas industry inChina will enter a bottleneck.

The other scenario is a “transformation” or“revolution” scenario. On the demand side, therelevant policies must be formulated and imple-mented, levying environmental and carbon taxesto reflect external environmental costs. Concur-rently, stronger competition will drive the costmarkedly down, leading to rapid expansion ofthe market, with natural gas gradually becomingthe main energy source. For supply, as newplayers are attracted to the market, the output ofshale and coal seam gas will rise greatly, withmost of the supply becoming domestic, and thedomestic market, via the influence of the inter-national market, will undergo optimisation andadjustment. The new players on the market willbring with them a greater degree of competition,markedly driving down supply costs, and push-ing development into an optimal cycle. A multi-faceted, highly competitive market will thenemerge, together with a modern, rationallystructured industrial system. The industrial sys-tem will be adapted and transformed—the role ofthe government, which previously gave priorityto planning and direct instructions, will give wayto regulation fundamentally by the market itself.A modern regulatory system will emerge—therole of the government will be reduced toensuring environmental protection, productionsafety and fair competition in the market.

It must be emphasised, however, that the twoscenarios described above do not represent theonly possible outcomes. The natural gas industryis still at the initial stages of its development, andits future development is, therefore, very flexible.China is endowed with comparatively abundantgas resources, has a great development potential,and innovation—and especially structural reform—will allow China ample operational space toexpand its gas consumption and use global nat-ural gas resources. Therefore, if natural gas is tobecome a principal energy source, the crux of thematter is the strategy and policy choices thatChina makes.

Different development strategies do not onlyhave a deep effect on the future development ofChina’s natural gas industry and energy resourcestructure. Robustly developing the natural gassector would also be an important method toincrease effective investment and promote eco-nomic growth.

Robust Development of the NaturalGas Industry Stimulates EconomicGrowth and Plays a Role in Protectingthe EnvironmentThere is great opportunity for natural gasindustry growth in China. Currently,annual consumption of natural gas inChina does not exceed 200 billion m3,possibly rising to 350 billion m3 in 2020and rising further to 580 billion m3 by2030. The end market alone is expected todouble. Taking into account the potentialfor growth in the upstream, midstream anddownstream segments of the natural gasindustry, the investment demand is veryconsiderable. It is estimated that in theperiod between 2015 and 2060, cumulativetotal investment to the value of almostCNY 6 trillion will be created. Equivalentto CNY 400 billion a year, this can driveup the annual GDP growth by 0.6%.

Regarding the upstream production ofgas, China’s production potential mayreach 470 billion m3 in 2020, a figurewhich includes 280 billion m3 of conven-tional gas and 190 billion of shale and coalseam gas. To build these capacities willrequire cumulative investment of CNY1.6 trillion. Just one shale natural gas fieldproject in Sichuan basin with annualcapacity of over 100 billion m3 requires aninvestment of 0.8 to CNY 1 billion.

As regards midstream pipeline invest-ment, China needs to expand its pipelinenetwork to over 150,000 km by 2030, and,based on the investment budget of CNY10–15 million per km of pipeline, thiscould result in a total investment ofapproximately CNY 2 trillion. The total

12 1 General Summary

investment required for the construction ofnatural gas peak and reserve facilities andLNG terminals exceeds CNY 500 billion.

Regarding urban gas pipeline networks,here the total investment must be raised toCNY 1.2–1.6 trillion, based on previouscalculations of CNY 3–4 invested for eachadditional cubic metre of gas.

With regard to sources of investment,the Chinese natural gas industry is still atan early, fast-growth stage, and thereforeinvestment risks are low and returns arestable, making it very attractive to manydifferent types of capital. In recent years,after the launching of coastal LNG termi-nals, investment of over 50 billion fol-lowed within a short period of time, a verypositive market response. Even withoutgovernment funds, the deregulation of rel-evant areas brings a great deal of socialcapital.

There are also clear environmental andsocial benefits to actively developing thenatural gas industry. Estimates suggest thatby 2030 natural gas will replace the use of300–400 million tons of coal, and roughcalculations show that this will lead to a10% reduction in PM2.5 concentration,which will be of great benefit to the healthand the quality of life of China’s citizens.

1.3.2 Strategic Objectives of HighEfficiency, Safetyand Sustainability

Development of the natural gas industry must becarried out with a fundamental emphasis on highefficiency, safety and sustainability. The specificimplications are:

• Achieving efficiency means working to raiseefficiency at all stages of the process—ex-ploration and production, transport and utili-sation. Efficiency is the foundation of thedevelopment of natural gas industry in China.

China is endowed with gas resources, buttheir quality cannot compare with that in theMiddle East, Central Asia and Russia, and theconditions are unfavourable when comparedwith those in the United States. To make theextraction of natural gas economically viable,both extraction and transmissioncost-effectiveness must improve. Moreover,the end-user price for natural gas in China iskept high due to cheap alternative energysources and the long distances involved in gasimports. To make gas competitive, therefore,it must be used with greater efficiency so thatits qualities of being an efficient and cleanfuel can be fully realised.

• Safety, both natural gas resource security andproduction safety, is a prerequisite fordevelopment. The importance of energysecurity is self-evident as far as leadingnations are concerned; the energy security ofa leading nation starts within its borders, andis based on robust regulation. It is on thisbasis that resource security can be achievedunder the open economic conditions of globalresource allocation. In order to strengthenresource and energy security, domestic sup-ply must be boosted, and gas import sourcesand import mechanisms diversified. At theproduction and operation level, the peak andtrough differences in the demand for naturalgas are very large, and we must strengthen thenational natural gas network and boostnational gas storage reserves in order toensure the security of supply of natural gas.Moreover, the safety of gas usage remainsimportant, as it is used by a great number ofhouseholds nationwide.

• Sustainability is the relationship between theeffective management of the development ofnatural gas industry and the environment andecology, and is a goal of natural gas industrydevelopment. First, in order to improve theenvironment rather than damage it, the naturalgas industry must emphasise environmentalprotection at production, transmission andusage stages, and also pay attention to thesustainability of resource supply. Second, theconcept of sustainable development must be

1.3 China’s Natural Gas Industry Development Strategy for the Next 15 Years 13

used throughout the natural resources indus-try. In order to protect the environment, theexternal cost of pollution must be fullyreflected, and enlarging the usage of naturalgas will raise the efficiency of naturalresource industry, lowering the environmentalpollution caused by the utilisation of naturalresources.

1.3.3 Clearly Defined Channelsand Targetsof the Natural GasIndustry

China’s target for the next 15 years is to vigor-ously develop the natural gas industry. Effortsmust be made for natural gas to reach 10% of allprimary energy source consumption by 2020,increasing consumption to 350 billion m3, andmore than 15% and 580 billion m3 respectivelyby 2030. The main channels to achieve this areoutlined below.

First, end consumer markets must be devel-oped. In order to turn natural gas into a principalenergy source, multiple measures must beapplied simultaneously to enlarge natural gasconsumption:

• Environmental regulation must be strength-ened, and there must be an emphasis on usingnatural gas a substitute for coal, including inrural/urban residential heating and fuel usagein light industries such as textiles and papermills. This will be critical in reducing smogand improving the environment.

• Natural gas transport must be developed. Theemphasis here will fall onto road passengertransport and waterway freight transport. Thepromotion of gas as a replacement for oilmust be achieved by strengthening infras-tructure and perfecting the relevant techno-logical standards.

• In electricity generation and heavy industry,relying on competitive markets for energyresources, green finance and taxation reformmust ensure that the environmental and

economic benefits of using natural gas (suchas energy saving and peak storage capacity)are valued and realised. We must raise theeconomic benefits generated by, and thus thecompetitive power of, natural gas in peakelectricity reserves, trigeneration and thenatural gas chemical industry.

Second, the upstream natural gas supply mustbe diversified. Using a two-pronged approachinvolving increasing domestic production andusing foreign trade, relying on the dynamic com-plementarity and boosting the competitionbetween the two can raise the efficiency ofresource allocation, and achieve market liberali-sation and diversification of the natural gas supply.Domestic production of natural gas resourcesmustbe strengthened, and the following three-stepstrategy regarding conventional gas, tight naturalgas and shale coal seam bed gas promoted:

• In the near term, growth must be centred onthe technological reserves for the productionof conventional gas and tight natural gas,shale and coal seam gas.

• The medium-term aim is to simultaneouslyadvance conventional gas, tight and shalenatural gas industry. China must also activelyparticipate in foreign markets, and, usingcommercial principles, promote natural gastrade and investment, and strengthen controland bargaining power capacity for importscoming into China.

• Sustainable development of trade with Rus-sia, the Middle East, South East Asia(Myanmar) and the maritime trade must bepromoted, partnership with the ShanghaiCo-operation Organization, ASEAN andCanada must be enlarged further, and importmethods and pricing mechanisms must begradually diversified. China must combine its“One Belt, One Road” strategy with theactive implementation of the “Go Out” pol-icy, and play an active role in the interna-tional markets by means of long-termagreements, equity investment, joint devel-opment, pipeline network construction andocean shipping.

14 1 General Summary

Third, a gas pipeline and storage networkmust be constructed consistent with the princi-ples of safety, fairness and transparency.

• The system must have unified planning, beinterconnected and integrate the national gasproducers, imports and consumption. Thetop-level design of the pipeline network mustbe carried out using a scientific approach,ensuring the interconnectivity of differentgas-producing areas and markets in variouslocations.

• There must be a focus on diversifyinginvestment in the construction of the pipelinenetwork, encouraging the entry ofnon-state-owned enterprises and capital. Thesecurity risk issues can be avoided bydemarcating pipeline hierarchy and differen-tiating the investment accordingly.Long-distance pipeline must be constructed incombination with national-level planning;construction of provincial-level trunk linesmust be performed under the guidance oflocal government, using both state-ownedenterprises and social capital. The city- andregional-level pipeline construction marketmust be gradually liberalised.

• Access to the pipeline network must be fair.National pipeline access standards must beunified. In order for gas from different loca-tions to have access to the pipeline networkand reach the end customers, the onlyrequirement must be that the correct safetystandards are complied with.

• The reserve capacity must be strengthened,and the obligation to maintain reservecapacity must be backed up by legislation.The gas reserve price must be fixed, and allparties must be mobilised to boost nationalpeak regulation reserves and the emergencycapacity.

Fourth, innovation must be applied to raise thetechnological levels in the industry. Vigorousefforts must be made to promote technologicalinnovation at each segment of the industrialchain, from exploration and production,

transmission and distribution to conversion andutilisation, allowing the technological revolutionto achieve technological and economic efficiencyat every stage.

• The strategic layout of natural gas productionand conversion key technology will be laun-ched in advance: exploitation of shale, deepsea, coal seam bed and methane hydratereserves launched, key problems in areas suchas gas engines and combined cycle electricitygeneration facilities tackled, both human tal-ent and financial investment boosted, andtechnological innovation in institutionalmechanisms activated.

• Research and development and application ofcomplete technological sets and solutionsmustbe explored in depth, focusing on the integra-tion of the equipment systems, reduction ofcosts, environmental protection and greendevelopment. Efforts must be made to ensurethat, by 2020, China achieves a clear increasein the technological level of the equipment, thatgreat strides forward are achieved in technicalautonomy and domesticising of shale and seagas prospecting and exploitation technology,and that the efficiency of the industry’s func-tioning, production and operation is raised. By2030, the industry’s technological level andproduction and operation efficiency willachieve leading international standards, anddomestic technological innovation capacity beraised greatly.

Fifth, natural gas price reform must be vig-orously promoted. As gas markets and infras-tructure in different locations mature,liberalisation of gas price setting must be pushedon in waves, gradually reducing the directintervention by the government, actively per-fecting the pricing mechanism and market envi-ronment, and finally realising a completeliberalisation of natural gas prices. Full advan-tage must be taken of the multiple import chan-nels and mature infrastructure in South-Easterncoastal locations such as Shanghai, Guangdongand Zhejiang.

1.3 China’s Natural Gas Industry Development Strategy for the Next 15 Years 15

• Take the initiative in upstream market diver-sification, abolishing price setting at gas ter-minals, and promoting independent pricing atupstream markets.

• Building on this, the separation of the mid-stream pipeline transmission and downstreamsales must be pushed on, third-party access topipeline network transmission allowed, directaccess provided to large customers and lib-eralisation of the end market gradually pro-moted. In central and western China, whereinfrastructure is not yet mature, an upper capmust be placed on gate price and transmissionand distribution, and the end-market pricingmechanism must be further improved, withprice adjustment frequency increased. Pricesfor transmission and distribution and storagemust be formulated rationally, and measuresimplemented to improve the situation asregards the seasonal price gap, the peak andtrough price gap and the end price. By 2020,the situation will be ripe for gradually push-ing for cross-regional price merger usingmethods such as third-party access to thepipeline network, and finally achieving lib-eralisation of the prices of natural gas.

Sixth, a natural gas industry system and agovernment regulatory system must be built. Inorder to have a healthy, sustainable modernnatural gas industry, we need to allow the marketto play a decisive role in resource allocation, andat the same time take advantage of the role of thegovernment. When designing the system, wemust:

• completely understand the crucial junctions inthe reform of the natural resources system;

• promote the liberalisation of the natural gasindustry;

• design the organisation and modes of opera-tion in upstream, midstream and downstreamsegments of the production chain;

• diversify resources and subjects;• create standardised, legitimate competition

and co-operation; and• apply the utmost effort to building an effi-

cient, open, orderly market.

Regarding government regulation, it is nec-essary to carry out, as soon as possible, top-leveldesign and division of responsibility in naturalgas market regulation; regulation must place anemphasis on environmental protection, fairaccess to the pipeline network and low-streamseparation of pipeline network transmission andsales. Also, unified pipeline transmission pricecontrol measures must be formulated. The aim isto achieve, by 2020, multifaceted competition inChinese natural gas market, breakthroughs inexploration and production and imports, priceliberalisation in some regions, an efficient gov-ernment regulation system, and industry growththat shows greater vitality and efficiency. By2030, the aim is to have a system of robust, fairmarkets with multiple players, where the marketitself plays the decisive role in price setting.Also, by the same year, a unified, independent,professional regulatory system should be inplace. The dynamic, efficient new industry willenjoy much greater influence internationally, andits output will be internationally competitive.

1.4 Raising Efficiencyand Supporting ImprovedPolicies to Expand Natural GasUse

In order for natural gas to become a main energysource, natural gas use must be expanded, andraising its competitiveness is the key. Natural gasprice sensitivity for residential use, industrialservices, vehicular transport and hydrogen pro-duction is low, while that of central heating,electricity generation, usage for industrial fuel,production of synthetic ammonia and methanol ishigher, and under current pricing conditionsnatural gas lacks competitiveness. One way ofraising this competitiveness is to internalise theexternal costs, reflecting the impact that resourceutilisation has on the environment and people’shealth, and this will enable us to express theadvantage of natural gas as a clean resource.Another way is to raise the efficiency of naturalgas utilisation, and this higher efficiency willprevent the end cost of using the expensive

16 1 General Summary

natural gas from increasing markedly. Specificareas and policies are as follows (Fig. 1.4).

1.4.1 Strengthen EnvironmentalRegulation, ImproveResource UtilisationEfficiency, SubstituteNatural Gas for Coal

Substituting natural gas for the coal used indecentralised energy generation is one of thepriorities in the development of the natural gasindustry, and there is a great potential fordevelopment in this area. Decentralised use ofcoal is inefficient and highly polluting, leading tohigh pollution control costs. Currently approxi-mately half of the coal in China is used forcentralised electricity generation, and the otherhalf is used in a decentralised manner. Half of thelatter is accounted for by areas such as metal-lurgy and cement firing, and the rest is made upof public heating, textiles, ceramics, glass and

paper production. In all these areas there ispotential to substitute gas for coal. Looking at theexperience of developed countries, the propor-tion of coal used for electricity generation standsat 78% in OECD countries, and the same figureexceeds 90% in the United States. There is alsovery little use of coal for decentralised electricitygeneration.

There are three main channels for coal to gassubstitution:

• Catering for heating users in small andmedium-sized northern cities and someindustry clients located in the industrial zone,coal-fired boilers can be replaced withcoal-fired CHP plants. This is aneconomy-based, environmentally friendlysubstitution route.

• The same approach (replacement of coalburning with CHP plants in public heating) isdifficult to implement for large and very largenorthern cities due to limited environmentalcapacity, the existing limitations on the land

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1.4 Raising Efficiency and Supporting Improved Policies… 17

available for power plants and problems withcoal transportation. Moreover, it is very dif-ficult, using coal-powered CHP plants, tosatisfy the requirements of industrial clientswho require extremely high temperatures andthose users whose locations are widely dis-persed. Their energy requirements can onlybe satisfied by using natural gas andexpanding natural-gas fired CHP.

• For the urban fringe and in the countryside,where coal is used in decentralised mannerfor heating and cooking purposes, apart fromsubstituting LPG and LNG for coal, there isalso an option of using biogas produced fromthe organic waste generated in the villages.The expectation is that, using the abovemethods, by 2030 the use of gas will rise inthe areas where it is most used—to 160 bil-lion m3 among the industrial users, and toapproximately 120 billion in urban heating,and residential and commercial use.

Regarding policy, one option is to strengthenenvironmental regulations, increasing the cost ofcoal when used in decentralised energy genera-tion. For example, an onlinemonitoring system forreduction of atmospheric pollution produced bycoal-burning boilers could be set up, as well asemissions monitoring systems. Second,energy-saving reform could be strengthened inorder to improve energy resource usage efficiency,for example boosting the construction ofenergy-saving buildings, and optimising industrialprocesses and their methods of using energy. Forhigh-quality, expensive energy resources, theeconomic burden must not be passed down to theend user, and the government can providefinancialsupport for the replacement of the energy facilitiesand to aid with energy-saving reform. Third, toaddress the addition of new coal-burning boilers inareas such as northern and central China whereatmospheric pollution management comes underthe greatest pressure, enforcing compulsory usageof natural gas can be considered, to avoid addingnew boilers in the future.

1.4.2 Improve Planningand TechnologicalStandards, and Promotethe Developmentof Natural GasTransportation

Expanding the use of natural gas in transportwould be a highly significant move and haveimportant implications for safeguarding nationalenergy security. Natural gas is a clean and effi-cient fuel, but using it as a substitute fuel hasseveral specific economic and technologicalimplications. Pollution and carbon dioxideemissions from gas-powered vehicles are onaverage lower than those from traditional internalcombustion vehicles. From the economic pointof view, over the past few years, the large dif-ference in price between gas and oil, as well assales tax exemption, has made gas-poweredvehicles economically viable and propelled fastgrowth in their use, especially as CNG urban taxifleets and public buses.

There is enormous potential for the growth anddevelopment of gas-fuelled transport. In China thetotal gas volume used by vehicles reachedapproximately 12 billion m3 in 2013, of whichCNG vehicles contributed 10 billion m3 and LNGvehicles 2 billion. The CNGmarket for vehicles isgradually entering a period of fast growth. It isexpected that by 2020 annual consumption willreach 20 billion m3, then 23 billion in 2025, andthat this will be followed by a slowdown. Themarket for LNG vehicles is expected to maintainfast growth in the future; the forecast is that in 2020the LNG market will exceed 20 billion m3, withexpectations of exceeding 40 billion by 2030. Theuse of LNG as ship fuel is another importantpotential market, but, due to the more rigorousenvironmental policies, growth here is expected tobe slow initially, and changes in environmentalpolicy will dictate the outcome of the later stagesof development. According to optimistic calcula-tions, the market for LNG as ship fuel may exceed2 billion m3 in 2020 and 10 billion in 2030.

18 1 General Summary

However, there are barriers obstructing thedevelopment of the natural gas transport fuelindustry. Unlike the fixed-source users in powergeneration, and residential and industrial users,transport users are mobile, and need an externalnetwork. While the change from coal to gas inelectric power generation can be called a “point”substitution, the change from petrol or diesel togas in transport is more of a “network” or “sys-tem” substitution. Large-scale development ofthe industry does not just depend on the technicaland economic qualities of one segment of theindustrial chain or a certain industry, but ratheron the network effect of the entire system. Only ifa sufficient number of service facilities, such asrefuelling stations and repair shops, join thenetwork can the customers’ mobile,network-based demand be satisfied. The networkcan then reach a tipping point, and the old“chicken and egg” problem can be solved. Thisprocess of establishing a network will require agreat deal of time if left to the market’s “invisiblehand”. Markets can also malfunction from timeto time, so the government can be extremelyhelpful here. These are the recommendations forpromoting gas for petrol substitution:

• The construction of filling station infrastruc-ture must be accelerated. The first step is toformulate a filling station network construc-tion plan for China’s important freight trans-port road routes, water transport routes andkey areas. In order to benefit vehicle users,conflicts, fragmentation, duplicate construc-tion and harmful competition must be avoi-ded. Second, suitable tax reduction andexemption policies must be formulated tomake investment in gas fuelling facilities atfilling stations attractive, thus accelerating theavailability of gas at filling stations until atipping point is reached. Having reached thetipping point, a gradual withdrawal of theincentives may be considered. Moreover, anyobsolete regulations must be identified andamended, for example any regulations basedon the premise of using gasoline fuels must

be revised, the approval process for fillingstations must be simplified, and the ban onLNG transport on the railways must be lifted.

• Industrial standards must be formulated asquickly as possible for the entire industrialchain, for example regarding fuel quality,measuring fuel calorific value, construction offilling stations and gas vehicles’ componentparts. Accelerating the standardisation of theentire industrial chain will allow economiesof scale to be achieved.

• The government must take the lead, with theindustry associations playing the role ofco-ordinators. Full advantage must be takenof the government’s leading role in procure-ment; funds for gas-fuelled vehicles must beallocated a clear proportion in the financialsupport and subsidies issued by the municipaladministration, public transport and govern-ment departments for vehicle procurement. Inaddition, the co-ordinating role of the indus-try associations must be given free rein.Co-ordination is particularly necessary inbuilding the natural gas transport industrynetwork, and, since transportation has alreadybeen fully liberalised, the government mustnot interfere directly in the markets, and sothe role of associations as co-ordinatingintermediaries is vital.

1.4.3 Improve the PricingMechanism, Makingthe Developmentof Natural Gas ElectricalPower GenerationJustifiable

Using natural gas to generate electricity hasmany benefits compared with coal. It is cleaner,provides flexibility to respond to demand peaksand requires a much smaller land area. It ishighly suitable for peak-time electricity genera-tion and CCHP usage, and these qualities makenatural gas indispensable in electricity

1.4 Raising Efficiency and Supporting Improved Policies… 19

generation. Looking at the international experi-ence, in 2010 the global contribution of naturalgas to electric power generation stood at 30% ofall fossil fuels, and in 2030 it is estimated to riseto 37%. In developed countries, electricity gen-eration is a major portion of natural gas usage,accounting for 30–40% of total natural gas use.

China has abundant coal resources andcoal-based electricity generation can be easilymade clean and efficient. Coal is an excellent,competitive fuel when used for baseline elec-tricity generation. For this reason, in China, theuse of natural gas to generate electricity shouldcentre on peak-time electricity generation andCHP generation as well as decentralisedpower-generating, heating and cooling. In thedecentralised electricity generation sector, wemust take into account the economies of scale inasset utilisation and assign priority in the order:region, building, household. The liberalisation ofthe electricity market, especially in electricitysales, provides an important opportunity to pro-mote the development of the decentralisedenergy sources. It is estimated that by 2030 thevolume of gas used in peak and baseline elec-tricity generation will reach 60–70 billion m3,whereas CHP generation and decentralisedresource electricity generation will use approxi-mately 100 billion m3. The key measures to beimplemented in order to boost the competitivepower of electricity generation from natural gasare as follows:

• Peak and trough electricity and gas pricesmust be set. As regards electricity generation,gas is a flexible energy source for this pur-pose, and has high peak regulation andreserve values. Its value for peak generation iseven more significant against the backgroundof the increased use of renewable and inter-mittent energy sources. Looking at the naturalgas part of the system, there is seasonalvariation in the use of electricity and gas. Forexample, during winter a lot of gas is used forheating, but electricity is used relatively little,while in summer a great deal of electricity isused for refrigeration, but there is little heat-ing being used. The use of natural gas in

electricity generation, therefore, can reducethe difference between the peaks and thetroughs in natural gas demand. Using cheapgas to produce expensive electricity is acompetitive advantage of electricity genera-tion using natural gas. Currently the gridtariffs are higher for electricity generatedusing gas than for electricity generated usingcoal, which to a certain extent reflects its peakregulation and reserve usage value. The nextstep may be to introduce time-of-use pricingto further express the benefits of using naturalgas for peak shaving. Time-of-use pricing fornatural gas should be formulated in such away as to fully express the competitive powerof gas-generated electricity.

• The external environmental cost must bereflected. The external cost of electricitygeneration can be separated into two cate-gories. The first is the costs of normal pollu-tion such as dust and sulphur and nitrogenoxides. Increasing investment can lead theemissions produced by coal-based electricitygeneration to approach the levels produced bygas-based electricity generation, as the newcoal electricity generating units now basicallyhave the same pollutant concentration limitsas gas units (using 6% oxygen content asreference, the concentration of dust, sulphurdioxide and nitrogen oxide emissions doesnot exceed 10, 35 and 50 mg per m3 respec-tively). Boosting investment in environmen-tally friendly facilities and equipment andfactoring this into the budget increases thecost of electricity produced by large generatorunits by 0.01–0.02 CNY/kWh, and this figureis slightly higher for older, smaller generatorswhich use inferior-quality coal. Overall, themeasures to control general pollution docontribute to the gap in the cost of electricityproduction between gas and coal, but thiseffect is not large. The other aspect, a keyone, is the cost of coal emissions. Using coalfor generating electricity produces0.8 kg/kWh of emissions, while using gasproduces only 0.37 kg/kWh. As the price ofcoal increases, the corresponding costs ofpollution from generating electricity using

20 1 General Summary

coal are also showing an upward tendency.According to an example from the ShenzhenEmissions Exchange, on June 18, 2013 theonline opening price for one ton of coal stoodat CNY 30 per tonne, and the cost ofcoal-produced electricity at 0.013 CNY/kWh.When the coal price peaked at143.99 CNY/tonne on October 18, 2013, thecost of coal-produced electricity rose to0.06 CNY/kWh.

• The core equipment and facilities must beproduced domestically. Currently, core tech-nology such as turbines and computerisedturbine equipment is a monopoly of foreigncompanies, which creates high long-termcosts and keeps transportation and long-termpreventive maintenance fees high. Solvingthis problem will lower the fixed costs ofgas-generated electricity. Lowering invest-ment per unit by 15% can lower the electricitycost by approximately 0.014 CNY/kWh. Atthe same time, changing to the domesticproduction of key equipment can lower totallifecycle costs. If the total repair fees arelowered by 50%, then the correspondingreduction in electricity costs will be reducedby approximately 0.01 CNY/kWh. Changingto the domestic production of key equipmentcan lower the electricity cost to the approxi-mately 0.024 CNY/kWh.

1.4.4 Adjust Gas Pricesfor Residentialand Chemical IndustryUse, and ReduceCross-Subsidiesfor Different Users

There are large subsidies in place to providelow-cost natural gas to residential and chemicalindustry customers in the long term. For exam-ple, in 2013, the average price of gas for endurban residential users nationwide was2.15 CNY/m3, which was 1.5 CNY/m3 lowerthan the national average marginal residentialsupply cost. The volume of gas used by

residential users is approximately 18 billion m3,which means that the subsidy from the gas sup-pliers to urban residents reached approximatelyCNY 27 billion. For fertiliser producers, the gasprice is now 1.80 CNY/m3 on average, which is1.10 CNY/m3 lower than the national averagemarginal commercial supply cost. The volume ofgas used by the fertiliser industry is approxi-mately 20 billion m3, implying that the subsidyby the gas suppliers for this industry’s users isapproximately CNY 22 billion. It appears on thesurface that these large subsidies are provided bythe gas suppliers, but, in actual fact, it is otherusers that bear the cost. The resulting higherprice for these users is detrimental to theexpansion of natural gas use in their sectors.

The price for the residential users must begradually raised until it exceeds the cost for thegas suppliers. The first reason is that the volumeof gas consumed by residential users (includingfor heating purposes) is expected to grow greatly,from 28.8 billion m3 in 2012 to 54.8 billion in2020 and 73.4 billion in 2030. Such increaseswill make the continuation of subsidies highlyproblematic. The second reason is that the priceadaptability of residential users is high, and theycan be regarded as top-quality downstream cus-tomers. Looking at the competition, and com-paring with oil, LPG or electricity, as long as gasprices remain below 4 CNY/m3, gas remainscompetitive. Regarding the adaptability of theconsumer, the average amount of gas used byone person each year is approximately 60 cu-bic m, and a hypothetical price increase of1 CNY/m3 results in additional CNY 60 peryear spent on gas. In 2013 the disposable incomeof the low-income stratum (the bottom 20%) ofthe rural/urban population stood at CNY 11,434,which means that the increased spending on gasamounts to a mere 0.5% of that figure. Moreover,the price of heating must also be adjusted,otherwise it will be difficult to continue with theuse of natural gas for this purpose. Naturally, theuse of gas for cooking and heating is absolutelyessential in people’s lives, and for this reason asubsidy can be given to the part of the populationliving in poverty when the prices are adjusted.Choosing the right opportunity and the right

1.4 Raising Efficiency and Supporting Improved Policies… 21

method to raise the prices for the residential usersis crucial, as is the importance of communicationwith the public. Leaving the decision-makingregarding the extent of the price adjustment rangeto the lower levels of authority, such as localgovernment, can also be considered.

For chemical industry users, certain discountsmay be given using market measures, such assetting peak and trough prices and interruptibleprices, but the situation so far, with prices belowcost, can no longer continue. The chemicalindustry must no longer rely on cheap gas, buthas to optimise its industrial process andstrengthen its production management to be ableto fully take advantage of time of day prices anddiscounts for interruptible prices. In addition, itmust continue with industrial upgrading anddevelop high value-added industries. Regardingpolicy, a clear timeline must be set for the pricemerger between residential users, the chemicalindustry and other users, to provide local gov-ernment with ample room for adjustment.

1.5 Measures to Ensure a Safeand Efficient Gas Supply

At the same time as expanding the use of naturalgas, we must also raise gas supply capacity, aswell as ensuring the safety and efficiency of thegas supply. The key to ensuring a safe and effi-cient gas supply is attracting new players to theexploration and exploitation of gas resources,thus greatly boosting the national supply capac-ity. In addition, import sources and methods mustbe diversified further, to ensure the security ofnatural gas imports. The advance of pipelinenetwork construction must be moderated, and theinterconnectivity of the pipeline network boos-ted. Construction of gas reserve facilities andreform of the relevant institutional mechanismsmust both be consolidated to ensure the smoothoperation of natural gas industry. We must alsoraise the technological level of the equipmentand facilities and of the innovation capacity of

the industry, strengthening the very foundationof its long-term development.

1.5.1 Attracting New Playersto Resource Exploitationto Expand Natural GasProduction

China is richly endowed with gas resources andhas the fundamental technology it needs toexploit them. Priority is given to conventionalgas, tight natural gas, shale and coal seam gas,and to the appropriate development of coal gasindustry. The key problems lie with the organi-sation of the industry. As mentioned above,under the current system, the output volume ofnatural gas in China will reach 230 billion m3,possibly reaching 380 billion in 2030. If thesystem is reformed, the same figures may rise to270 and 470 billion m3 respectively. This sec-tions outlines the measures that should be takenin order to attract new players to resourceexploitation and thus expand national natural gasproduction volume.

1. Development model

A new model of development must beapplied. Exploration and production and thepipeline transmission of natural gas are subject tothe regulations of the State Council, and areoperated by the state-owned oil companies. Theadvantage of this system is that it allows inten-sive development of the natural gas industry, andmakes it convenient to undertake large-scaleexploitation, but it also faces the problem of highcosts. The other development route is to reformthe current monopolised control system andstrengthen the role of market forces, attractingbusinesses with different models of ownership tothe exploration and production of natural gas,and achieving diversified development. Theresulting market competition, “the survival of thefittest”, will create a new structure of exploration

22 1 General Summary

and production in the natural gas industry. It isrecommended that the current institutionalmechanisms be adjusted appropriately, and con-ventional oil and gas operational authority bemoderately liberalised. Before anything else,though, conventional oil and gas mining rightsmust be opened up to the state-owned energyenterprises which have already obtained shalenatural gas mining rights, as well as to thoseenergy enterprises which are engaged in overseasimports. This change will attract these enterprisesto the domestic exploration and production ofconventional resources.

2. Minimum investment level

The minimum exploration investment must beadjusted. The 1996 Chinese Mining Law and thefollow-up supporting laws and regulations statethat the minimum investment for oil and gasprospecting rights is 5000 CNY/km2 in the firstyear, CNY 7000 in the second and CNY 10,000in the third. However, it fails to consider otherfactors, such as currency inflation. Due to thecosts having risen greatly and the fixed-pricebudget, these unchanged minimum prospectingand surveying investment regulations have led toa decrease, year after year, in the explorationworkload per unit area. In the past, three explo-ration wells could be completed with a budget ofCNY 100 million, but currently it is only possi-ble to complete one. Physical explorationinvestment per unit area has is currently barelybetween one third and one fifth of its level15 years ago and there is a severe lack of phys-ical exploration work done in the regionsfavourable to gas production. According to theinvestment standards and regulatory require-ments for shale natural gas block tenders, thebasic exploration investment required for con-ventional oil and gas blocks is 3–5 times greaterthan the current levels, with a minimum invest-ment of 30–50,000 CNY/km2. Raising minimumexploration investment, raising the prospectingefficiency of the blocks, encouraging blockwithdrawal and reducing the surface area of theblocks will transform the current prospectingstalemate. At the same time, the current advanced

block application system must be reformed, and,as with shale natural gas block sales, it should bepossible to sell conventional oil and gas blocksthrough a competitive process. In addition,mechanisms for block exit that are widely prac-tised internationally can be used. Monitoringteams must also be set up to oversee the imple-mentation of all the rules and regulations.

3. Trading mechanism for reserves

Trading mechanisms and platforms for provennatural gas reserves need to be established. Inrecent years, the average annual increase inproven geological natural gas reserves hasexceeded 600 billion m3, and this tendency tofast growth is expected to continue in the comingyears. However, there is investment and openingup of the newly proven reserves is not promptlyachieved, with parts of the reserves remainingunexploited for prolonged periods of time. Thereason for this is the difficulty of making theexploitation of some of these reserves economi-cally viable. The recommendation, therefore, isto establish a trading mechanism for thehard-to-exploit proven reserves, allowing them toenter the market, where they can be transferred toa different party, and can eventually come intopossession of an enterprise capable of conductingmore expeditious exploitation and making iteconomically viable. The exploration enterprisescan thus recover their exploration costs and theproducer enterprises, by purchasing thesereserves, gain a production opportunity. Toensure that these reserves are developedpromptly, the situation where rights transfer isnot followed by development must be avoided.

Recommendations for Setting up a100 billion m3 Annual Capacity ShaleNatural Gas Integrated ExperimentalArea in Sichuan BasinThe development of the shale natural gasindustry touches upon many areas—theconditions of the natural resources, tech-nology, equipment, construction, invest-ment, utilisation and environmental costs,

1.5 Measures to Ensure a Safe and Efficient Gas Supply 23

for example—and these must all be con-sidered. We estimate that with appropriateorganisation and policy support, SichuanBasin can become a leader and focal pointfor shale natural gas development in China,and the potential production of shale nat-ural gas in this region could be as high as100 billion m3 by 2025. The reasons forthis are as follows:

1. Guaranteed resource base: Accordingto PetroChina evaluation data, the totalreserves of shale natural gas in theLongmaxi and Qiongzhusi formationsapproach 40 trillion m3. These includeLongmaxi marine facies shale naturalgas, where production breakthroughshave already been made, with a totalarea of 75,000 km2, containing reservesof 25 trillion m3 of shale natural gas,with recoverable resources of 3.7 tril-lion m3. Of these 75,000 km2, 35,000have been found to have conditions thatare especially favourable to shale nat-ural gas extraction, containing almost14 trillion m3 of shale natural gas, ofwhich 2.8 billion m3 is recoverable. Ina scenario where the 20,000 km2 areaof Longmaxi shale coal formation isused, development is started in 2015,then the exploration and well distribu-tion can be completed and 10,000 wellscan be drilled by 2025, with thepotential production of shale natural gasreaching 100 billion m3 in 2025. Fol-lowing that, drilling approximately 800wells annually, production can remainstable for 20 years.

2. Mining technology and equipment:Currently China is at already in theinitial stages of mastering shale naturalgas geophysics, well drilling and com-pletion, and fracturing technology.China currently possesses 3500 mcapability of horizontal drilling andstage fracturing. Chinese non-seismicgeophysical prediction and

identification technology, fully mobiletracked drilling rigs, large fracturingvehicles and construction environmen-tal protection technology all complywith advanced international standards,and there has also been a breakthroughin domestic bridge plug production.Currently the only fields where there isa gap between Chinese technology andadvanced foreign technology are welldrilling geological guidance, measure-ment while drilling (MWD), micro- andnano-structures and component analy-sis. However, there are already manyforeign shale oil companies in Chinataking part in shale natural gas devel-opment, and these can supply the keytechnology required. The fact thatSinopec’s Chongqing Fooling shalenatural gas field has already entered thecommercial exploitation phase provesthat the development of Chinese shaleoil industry has passed an importantbenchmark.

3. Exploitation is productive and eco-nomic viability guaranteed: ByNovember 30, 2014 (when the researchgroup was on-site), Sinopec, in Fool-ing, Sichuan, completed 69 fracturingtest wells, all of which produced med-ium and high shale natural gas flow.The average flow at a single well wasmeasured at 32,000 m3 per day. Onaverage, a single well, under conditionsof uninterrupted flow, can produce over21.6 million m3 of gas, with the aver-age cost of single well standing at CNY80 million (including exploration, pro-duction and transmission costs). Add-ing taxes and other simple managementfees, the well cost is below 1.5CNY/m3. Currently the wellhead priceof shale natural gas stands at2.78 CNY/m3, and adding the0.5 CNY/m3 national financial subsidygives us the actual gas price of3.18 CNY/m3, and a single well can,

24 1 General Summary

therefore, dependably generate anannual income of up to CNY68.69 million. Other areas in Sichuan,such as Changning and Weyuan, alsohave shale deposits, situated at greatdepth, but here shale natural gas fieldsare layered with conventional gasdeposits and the economic value lies intheir combined extraction, while shalenatural gas production in Exi, in theeast of Chongqing, is made highlyeconomically viable due to the presenceof associated light oil. These factsconfirm the assured economic viabilityof shale natural gas production inSichuan Basin.

4. Existing environmental protectionprecedents to draw lessons from andguaranteed water resources requiredfor gas extraction: The United Statescurrently has over 100,000 shale naturalgas wells, and under effective govern-ment supervision and public scrutiny,there have so far been no environmentalaccidents which might have beendetrimental to society. In SichuanBasin, the extractable layers of shalenatural gas are situated at the depths ofover 2000 m, and measures such asadequate well casing and increasedsafeguards (adding an extra casing) caneffectively prevent the water used forfracturing from permeating to the sur-face. As far as water use is concerned,the production of 100 billion m3 of gasconsumes approximately 400 mil-lion m3 of water, which amounts to1.6% of the current water consumptionin Sichuan province. Therefore,Sichuan Province, richly endowed withwater resources, can guarantee suffi-cient water reserves for the industry.In order to meet the 100 billion m3

annual mark, CNY 800 billion of invest-ment is required to build the capacity (tocover the drilling and completion ofapproximately 10,000 wells between 2015

and 2025). Under the current system theproject would rely solely on PetroChinaSouthwest Oil and Gasfield Company.However, this company’s investment trackrecord is insufficiently dynamic—as evi-denced by the Laongangmiao gas field(with over 400 billion m3 of capacity),discovered by PetroChina Southwest Oiland Gasfield Company in central Sichuan(these conventional gas fields also requirelarge exploration investment). Thus a newway of thinking is needed to develop theshale natural gas industry, and we proposeestablishing an integrated shale natural gasexploitation experimental zone in SichuanBasin and its periphery. First, preliminarytesting will be conducted under safe con-ditions and strict environmental manage-ment, and the consequent exploitation mustthen proceed using new, remodelledmethods, mechanisms and regulations. Aswell as playing a role in bolstering shalenatural gas exploitation, it will become atrailblazer for China’s oil and gas reform,and the experience gained from it can bereplicated and promoted. Important initia-tives include:

1. Innovative mining rights manage-ment and market access manage-ment: A unified tender can be put outfor resources, with the exception ofthose areas where the three mainenterprises have started already pro-duction, are verifying resources or arecarrying out exploration. Market accessmust not be restricted to otherstate-owned enterprises but must alsobe opened to privately run companiesand foreign-owned enterprises. It is notonly the large transnational foreignenterprises that need to be attracted totake part, but also small andmedium-sized companies with exten-sive experience and strong capacity forinnovation. It is these companies thatplayed a key role in shale oil and gas

1.5 Measures to Ensure a Safe and Efficient Gas Supply 25

revolution in the United States. If theenvironmental targets for technologyare met and national security clearanceis obtained, foreign enterprises canenter the Chinese market as whollyforeign-owned enterprises.

2. The full benefits of the mixed own-ership system must be obtained: Thispractice has already been implementedby PetroChina and Sinopec. In theChangning block PetroChina has set upSichuan Changning Gas DevelopmentCo., Ltd., while Sinopec establishedChongqing Shalegas Exploration andDevelopment Co., Ltd. in Chongqing,both of which are under mixed owner-ship. A mixed system of ownership notonly grants an investment opportunityto local state capital, private capital andforeign capital to invest, but is alsoconducive for central enterprises’ usageof social capital in order to bolsterresource exploitation. The presence oflocal state capital is beneficial withregard to demolition and resettlement,road building and the immediate usageof natural gas. The participation ofprivate and foreign capital is beneficialin reforming corporate governance andraising extraction efficiency and thelevel of services. In order to deepen themixed ownership reform in shale natu-ral gas industry, it is necessary to applygreat effort in the areas of corporategovernance, strategic synergy and thedivision of labour. We must maintainthe initiative across the board, andavoid misappropriation of funds or sit-uations where the mixed system ofownership exists only on paper, and theexternal investors are denied participa-tion in management and operations.

3. Effective regulation methods forshale natural gas industry: Appropri-ate policy system, management stan-dards, regulation system and rules forshale natural gas prospecting and

exploitation, as well a platform togather and share information, can be setup and applied for a period of 3–4 yearsin the experimental area. Regarding theenvironmental regulations, the envi-ronmental regulation will be organisedand implemented locally following thestandards and policies set by the centralgovernment. The Environment Ministryis currently researching and formulatingthe environmental impact assessmentguidelines for the shale natural gasindustry, and these can be put to a pilottest in the experimental area, bringingout and implementing, for the first time,the national standards and regulationsregarding land use, vegetation restora-tion, water resource utilisation, wastewater treatment, waste disposal, gasemissions, exploratory well drilling andwell completion. Regarding sharinggeological data and information, it ispossible to follow the American exam-ple and introduce legislation to enforcethe obligatory compilation of geologi-cal shale natural gas data, building it upinto a geological engineering informa-tion management platform, with thegovernment controlling the naturalresources information, which will thenbe shared, boosting the efficiency ofshale natural gas exploitation.

4. Fiscal and taxation policy

Fiscal and taxation policy regarding naturalresource extraction must be improved. Conven-tional gas projects generate high income afterprice liberalisation, and the natural resourcetaxation rate should be raised. However, for tightnatural gas, shale natural gas and coal seam gas,in order to encourage development of theunconventional gas industry, it is necessary toconsider reforming the financial and taxationsystem, adjusting the relationship between local

26 1 General Summary

and central taxation, lowering the naturalresource tax rate and mobilising the role of localgovernment. Regarding shale natural gas, duringthe 2012–2015 period, the central financialadministration provided a subsidy of0.4 CNY/m3 to shale natural gas-producingenterprises meeting the relevant conditions. The13th Five-Year Plan period is a crucial time inthe development of China’s shale natural gasindustry, as it moves from the investment stage togrowth stage. Even in the current situation ofvery low international oil prices, with theexpectation that the price of a barrel of oil is toremain around the 60–80 $/bbl in the next 3–5 years, and with global investment in shalenatural gas shrinking, it is especially important toencourage active exploration and production ofshale natural gas. For this reason, the subsidiesfor shale natural gas industry must be extendedand continued. Currently the Finance Ministryand the Natural Resources Ministry have alreadydecided that the subsidies will be fixed at thelevel of 0.3 CNY/m3 for the period of 2016–2018 and 0.2 CNY/m3 for 2019–2020.

Coalbed gas exploration must also be sup-ported. First, in coal seam gas exploitation, wemust, with safety and environmental protectionas guiding principles, closely integrate thedevelopment of mines and wells within coalmining areas. Ground drainage must be per-formed five years in advance, pumping waterfrom the well must be advanced moderately, andold reservoir coal seam gas (methane) must beactively extracted. Independent enterprises mustbe encouraged to purchase coal seam gas(methane) from different mine and well locations,large-scale usage must be realised, and subsidiesextended to the enterprises directly or partiallyusing this gas. Second, commercial exploitationof non-coal mine coal seam gas should be pro-moted using targeted policy. Coal seam bed gasproduction must be commercialised in partiallyexploited coal bed gas areas situated in thelocations outside the regions with coal miningprogrammes, as well as in those mines which for10 or 20 years have not engaged in coal pro-duction. The current categorised incentive policydoes not allow the extension of these incentives

to the coal mining locations which do not addressthe safety and environmental issues.

1.5.2 Achieving ImportDiversification,Safeguarding the Securityof Natural Gas Imports

The general orientation of support and encour-agement for natural gas imports is as follows.With regard to natural gas import policy, Chinaneeds to reconcile the conflict between the fol-lowing three aspects: the need to address theproblem of environmental pollution, a continu-ous increase of natural gas consumption causedby economic development and a rise in people’sincomes, and the need to ensure the security ofnatural gas supply. The domestic consumption ofnatural gas must be expanded both as a propor-tion of the total energy resource consumption(currently at 5.8%) and as regards the penetrationrate in residential use (16%). Preventing airpollution has already become urgently necessaryand is a strong motivating factor in the expansionof the use of natural gas. In summary, to solvethe fundamental contradictions facing the issueof how to expand domestic natural gas con-sumption, the formulation and issuing of all therelevant natural gas policies and regulations inChina must be subordinate to the need to effec-tively resolve these contradictions. The orienta-tion of China’s import policy in the near future(from the present day to 2020 and then 2030) isas follows: imports must be cautiously encour-aged, but at the same time efforts must be madeto achieve diversification of the import sourcesand import partners, as well as of contracts andpricing methods, in order to guarantee overallcontrol of natural gas imports.

Analysis of Chinese Natural Gas Sup-ply SecurityThe degree of dependence of China onforeign natural gas is rising fast, reaching32% in 2013. For this reason, some takethe view that restrictions should be placed

1.5 Measures to Ensure a Safe and Efficient Gas Supply 27

on the proportion of natural gas imports.Our analysis shows that China is capableof maintaining overall control of thesecurity of natural gas supply, without theneed for restrictions being placed on theproportion of natural gas imports. Thereasons for this are as follows:

• Natural gas is a substitutable resourceand can be easily substituted using oil,coal or renewable energy sources,which makes the problem of its supplysecurity easily solvable.

• The security of natural gas supply inChina is markedly better than that ofoil. One reason is the diversity ofsources of natural gas imports—fromCentral Asia in the North West, Russiafrom the North East, Myanmar in theSouth West, and on the Eastern sea-board the LNG arriving via maritimeroutes from different countries. Thesituation is clearly different from oil,which relies on the supplies from theMiddle East, and over-relies on thesupplies delivered via the Strait ofMalacca. The second reason is that,compared with other countries, thecurrent ratio of natural gas in its energystructure and the ratio of its imports,make China’s diversified imports com-parable with the European Union, andin the future will be comparable withJapan and South Korea.

• The national reserves of conventionalgas, shale natural gas and coal seam gashave very large development potential,and, provided the institutional mecha-nisms are rationalised and enough timeis allowed, production output can beincreased greatly.It could be said that the key and the

incentive to achieve national gas supplysecurity are firmly in China’s own hands.For this reason, in the context of China’sample global natural gas supply and itspressing need to control emissions,

increasing gas imports will allow China tosimultaneously increase natural gas usageand reduce emissions. Naturally, whileencouraging imports, the operation of gasstocks and reserves as well as the inter-connectivity of the pipeline network mustbe increased, in order to mitigate againstpotential short-term market fluctuations(Fig. 1.5).

First, the sources of imports must be diversi-fied. According to the current LNG and pipelinecontracts signed by China, in the coming yearsnatural gas imports are expected to undergo fastgrowth, from 53 billion m3 in 2013 to approxi-mately 192–230 billion m3 in 2020. Generallyspeaking, the diversification of China’s naturalgas imports is growing. The main importers intoChina are Turkmenistan and Russia, with eachcountry accounting for roughly 30% of the total,while Australia’s imports come second, at 12%.The remaining 30% or so is contributed by eightdifferent countries—including Myanmar, Qatar,Uzbekistan and Papua New Guinea—and also bycentralised natural gas buyers. These figuresrepresent a significant change from the propor-tion of natural gas imports in 2013: the importsfrom the Middle East into China fell the most,from 17.7% in 2013 to just 3%, Turkmenistan’sfell from 47 to 30%, but imports from Russiagrew from zero to 32%, with a slight increase inAustralian imports also.

Second, the import methods must be diversi-fied. Regarding contracts and price setting:

• The contracts must include long-, medium-and short-term ones, as well as merchandiseon hand contracts, in order to facilitate greaterflexibility and also to better respond to andcontrol market changes.

• When setting prices, the oil price index aswell as the standard diversified price indexmust be included.

• When estimating the competitiveness of theprice, it is necessary to consider factors suchas the risks involved in the project and the

28 1 General Summary

commercial structure; risks can be mitigatedby using rolling contracts for purchasingnatural gas, which are also suitable for bal-ancing domestic supply and demand.

The natural gas supply structure must involvediverse geographic sources. Also we must attractnew participants in the import industry, encour-aging more large-scale end users to purchasenatural gas on the international LNG market.Such new customers, both electricity companiesand large-scale urban heating enterprises, willbring great benefits to the market, and byreducing the intermediate links this can improvethe efficiency of the natural gas value chain.Supervision and regulations must be strength-ened, and access by third parties to the relevantfacilities, such as receiving stations and thepipeline network, must be effectively promotedto ensure an efficient, unimpeded flow of naturalgas imports into the country.

Third, natural gas trade and foreign invest-ment must be bolstered using commercial prin-ciples. Encouraging foreign investment in naturalgas, especially in the “One Belt, One Road”region and by the major gas-producing countries,

is particularly beneficial for safeguarding thesecurity of natural gas supply, as well as beingbeneficial to extending the commercial cover tomore segments in the natural gas value chain. Italso helps the chain to withstand the risks ofprice fluctuations. When developing foreigntrade and investment in natural gas, in order toconsistently maintain commercial principles, wemust not adhere only to national strategic guid-ance, but must also make the utmost effort toobtain commercial benefits, and make economicviability a foundation of project partner-ship. Naturally, in order to realistically tackle theproblem of contracts signed at the time of highprices, a new mechanism of sharing the historicalcost between enterprises and the state can beexplored.

1.5.3 Accelerating the Constructionof Pipeline Network,Promoting NetworkInterconnectivity

Pipeline network is key infrastructure and itsconstruction must be advanced moderately, and

Share of gas from imports

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Fig. 1.5 Proportion of natural gas imports and import diversity in selected countries. Note The Herfindahl index isused to measure and describe varied indicators. The lower the value, the higher the diversification

1.5 Measures to Ensure a Safe and Efficient Gas Supply 29

its unified planning, interconnectivity and dis-patch flexibility strengthened. Specific measuresare outlined below.

First, the construction of pipeline networkinfrastructure must be accelerated and transmis-sion capacity increased. China’s 2020 natural gasmarket demand will be approximately 350 bil-lion m3, and 580 billion in 2030. Knowing thatresource supply to demand ratio must be 1:1.1and the transfer capability to demand ratio 1:1.15in order to ensure proper distribution and allo-cation within the market, we can see that thecapacity of the pipeline network must reach400 billion m3/year in 2020, and 670 billion in2030. At the end of 2014 the transmissioncapacity of China’s pipeline network stood at240 billion m3, capable of satisfying just 60% ofthe 2020 transmission demand and 36% of the2030 transmission demand. Therefore, the con-struction of pipeline network infrastructure mustbe accelerated in order to meet the demands ofthe growing market. Efforts must be made toextend the total pipeline network length to15,000 km by 2020, achieving transmissioncapability of over 400 billion m3, and 26,000 kmand 690 billion m3 respectively by 2030. Theaim is to achieve a pattern of “western gas to theEast, northern gas goes South, eastern gas arrivesby sea, using the nearest supply”. In other words,Central Asia imports of gas supply the NorthWest of China, Myanmar supplies gas to theSouth West, the North of China will be suppliedby Russia, and Eastern China by maritimeimports of LNG, forming four great importpathways. Between 2020 and 2030 Lines A, B,C, and D of the Central Asia–China Gas Pipelinewill achieve transmission capacity of 85 bil-lion m3, the Myanmar–China Pipeline a mini-mum capacity of 10 billion, the Russia–Chinapipeline 68–69 billion, while LNG imports areexpected to realise a reception capability of100 million tons.

Second, the construction of pipeline networkmust achieve optimal layout and interconnectiv-ity. The fundamental idea is to create intercon-nectivity by constructing a backbone trunk of thelong-distance national pipeline, equipped withhubs and tie-lines. The flexibility of allocation

control will be achieved by provincial-levelbackbone pipeline trunks running through dif-ferent hubs. Underground reservoirs and LNGreception terminals will be connected to thenational pipeline network and the adjacentprovincial and metropolitan markets will form aregional network. Specific measures required are:

• Achieve interconnectivity of the main trunkof the national pipeline network. The inter-connectivity of the main trunk relies first onthe key hubs at the junctions of the network.Such hubs have been formed in Zhongwei inNingxia, Yongqing in Hebei and also inShanghai and Guangdong. Among these,Ninxia’s Zhongwei is the junction on theroute connecting Western China to the East,and is connected to the system transportingWestern gas eastwards, linking up the Xin-jiang coal methane pipeline, the Shaanxi–Beijing pipeline, the Zhongwei–Jingbianpipeline and the Zhongwei–Guizhou pipeline.Zhongwei brings together the gas from Cen-tral Asia, from Xinjiang’s and Changqing’sgas fields as well as the Xinjiang coalmethane. Yongqing in Hebei is northernChina’s regional hub; it connects theShaanxi–Beijing Pipeline, the Russia–ChinaNatural Gas Pipeline, the gas storage reser-voirs in northern China and the Tianjin–Hebeiresources pipeline. It is the northern region’scentre for the regulation of the natural gasflow, it optimises natural gas allocation andmitigates peak demand. Many lines of thebackbone national pipeline traverse HubeiProvince, which is a key hub in South CentralChina, a key junction connecting the suppliesof conventional gas and coal methane fromXinjiang, the imported gas from Central Asiaand Russia, as well as shale natural gas fromSichuan and Chongqing. Shanghai, animportant natural gas market centre, is notonly an important hub for China’s West toEast Pipeline’s Pipelines 1 and 2, and theSichuan to East Pipeline, it also receives gasfrom the Sea of Japan (East Sea) and also alarge quantity of LNG imports. Shanghai is agas trading hub and is also a national pricing

30 1 General Summary

benchmark, and the city is destined to becomea national hub in the future. GuangdongProvince is an important natural resourceshub, and in the future will form a staging areafor different types of gas. Its supply structureis varied, with pipeline gas, sea gas and LNG,and its supply pipelines include China’s Westto East Pipeline’s Pipelines 2 and 3, theXinjiang–Guangdong–Zhejiang pipeline, seagas and also LNG terminals. Guangdong isthe most diversified province as far as sourcesof gas are concerned, and several differentcategories of gas resources are pooled here,including conventional gas, coal methane, seagas and LNG (Fig. 1.6).

• Unified planning, interconnectedness andflexible deployment of resources ofprovincial-level pipelines are a priority—inorder to avoid replication of infrastructure andloss of efficiency, the infrastructure con-struction must take place under a unifiedplanning programme and proceed step by stepaccording to the degree of market develop-ment. The provincial natural gas companiesmust be in charge of the construction and

operation of the provincial pipelines and peakregulation facilities. However, provincial gascompanies must not purchase natural resour-ces. This is done by the downstream cus-tomers negotiating directly with upstreamsuppliers.

• Because of factors such as administrativedivisions and examination and approval redtape, the structure and development ofregional pipeline networks, apart from thetrans-provincial long-distance pipeline and itstie-lines, is largely concentrated within theborders of provinces, creating large naturalgas consumption gaps between neighbouringprovinces or economically similar provinces.In the future, relying on government guidanceand support, pipeline network tie-lines mustbe built to connect the backbone provincialpipelines, achieving resource complementar-ity, bolstering regional natural gas industrydevelopment and improving the regionalpipeline network system.

Third, overall planning of infrastructure con-struction is necessary, strengthening the

Coastal transportation arteryShanghai

HubHubeiHub

YongqingHub

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ZhongweiHub

Legend

LNG Terminal

Station

Existing provincial pipeline

Existing long-distance pipeline networkPlanned long-distance pipeline network

Planned provincial pipeline

Fig. 1.6 National natural gas pipeline concept

1.5 Measures to Ensure a Safe and Efficient Gas Supply 31

supervision of the schedules of planned projects.Currently, infrastructure construction in China ismainly carried out by the three major oil and gascompanies, with no effective links between them.As the infrastructure keeps improving, the inter-connectedness of the infrastructure layout willbecome crucial in ensuring the security and sta-bility of the functioning of China’s natural gasindustry. This will become especially significantin the future following the construction of theXinjiang–Guangdong–Zhejiang Pipeline, Westto East Pipeline Lines 4 and 5, and the Russia–China Pipeline, as well as of coastal terminalsand underground storage reserves. Effectiveinfrastructure interconnection can only beachieved if effective co-ordination is included inthe planning stage. For this reason, the govern-ment departments must become involved ininfrastructure construction, carrying out com-prehensive co-ordination and strengthening thesupervision, regulation and control of the con-struction projects. In order for the planning tar-gets to be implemented, the progress and theactual status of the projects must also be tracked.

Fourth, we must diversify the investors. Chinaencourages and supports all categories of capitalto participate in investment into the constructionof infrastructure under the umbrella of unifiedplanning. The three major oil and gas companiesmust open up their investment rights for theconstruction of the national backbone pipeline,and private capital must be attracted to this area.The monopoly of the provincial gas companieson infrastructure construction must be broken.By attracting private capital to participate in theinfrastructure construction, we will bolsterinfrastructure construction and raise constructioncapacity. Attracting new shareholders, such asthe National Council for Social Security Fund,urban infrastructure industrial investment fundsand Baosteel, will break the established patternof 100% investment by the three major oil andgas companies, and establish private capital inthe construction of the national backbonelong-distance natural gas pipeline. The plannedWest to East Pipeline Lines 4 and 5 and theXinjiang–Guangdong–Zhejiang Pipeline must,using the method applied for West to East

Pipeline Line 3, create a joint capital ventureusing private capital. Investor diversification inlong-distance pipeline infrastructure will beachieved by bringing in investors other than oneof the three major oil and gas companies. Toaccelerate provincial infrastructure construction,those provinces with their own gas companiesmust attract private capital with a desire forinvestment and the necessary investment eligi-bility to form investment partnerships. The con-struction rights for the provincial branches of themain pipeline network must be completely lib-eralised and the eligible enterprises will beallowed to take part in infrastructure constructionand operation, in accordance with national andlocal government’s planning.

1.5.4 Accelerate the Constructionof Natural Gas ReserveFacilities and ImplementCorrespondingInstitutional Reform

Natural gas storage and peak regulation areextremely important in ensuring the smoothoperation of natural gas supply. Currently, Chi-na’s effective storage capacity stands at approx-imately 4 billion m3, merely 2.2% of theconsumption volume, very different to the 15–20% observed in developed countries. The sys-tems of organisation are also inadequate. Thespecific recommendations are as follows.

• Clear targets must be set for the constructionof gas storage facilities. Natural gas storagefacilities in China must be built in accordancewith the scale of China’s future natural gasconsumption, taking into account the currentpeak regulation capacity, the conditions of theunderground storage reservoirs and theadvancements in the construction of LNGterminals, as well as drawing on the experi-ence of major foreign gas consumer countries.The integrated system of the undergroundstorage facilities and LNG storage facilitieswill, by 2020, have a storage capacityof 30 billion m3 of natural gas and

32 1 General Summary

5–10 billion m3 of LNG. With a workingstorage capacity of 35–40 billion m3, thisprovides a storage equal to 10–11% of thetotal demand and will transform the currentpeak regulation method of reducing customerdemand. At the same time, in order to guar-antee supply security of key regions, thenational natural gas emergency responsesystem must be set up as quickly as possible,specific emergency plans perfected, and anearly warming emergency response systembuilt. During the period leading up 2030, thescale and capacity of the storage system forpeak regulation must continue to be graduallyexpanded, and the working capacity of stor-age facilities expanded to 65 billion m3, or12% of the total demand, converging with theglobal average. Around 2030, the strategicstorage capacity must reach approximately5% of the import volume in order to create anemergency reserve storage system that iscapable of dealing effectively with demandand supply fluctuations and able to cover thefull national demand.

• Emergency peak regulation reserves storageconstruction must be accelerated and its lay-out optimised. The first step is to boost thepace of the construction of large-scale naturalgas storage reservoirs and LNG tanks forwinter peak emergency. In northern,north-eastern and north-western regions ofChina, where the seasonal peak/trough dif-ference in gas consumption is very large, andwhere there is no shortage of locations tobuild the storage facilities, priority must begiven to the construction of undergroundstorage facilities, as well as supplementarysmall and medium-scale liquefying facilitiesand LNG terminal tanks. For peak regulationin Central and South Western China, with itsspecific geological conditions and the prox-imity of oil- and gas-producing areas, it ispossible to use depleted oil and gas pools toconstruct underground storage reservoirs, andat the same time use the upstream gas fields,supplementing this with small andmedium-sized LNG installations. In easternand southern China and other regions with

rather inadequate conditions for the con-struction of underground storage reservoirs,priority must be given to the construction ofLNG tanks, while underground reservoirs andsmall and medium-sized tanks can be used asa supplementary system for peak regulation.The second step is to prioritise the construc-tion of small-scale gas storage facilities inorder to satisfy daily peak regulation needs.In cities with high natural gas consumption,in order to solve the important problem ofdaily peak time demand, free hand must begiven to gas companies, and the constructionof small-scale LNG tanks and CNG sphericalstorage vessels must be accelerated. Further-more, it is worth considering using the newlydiscovered large-scale gas fields as storagefacilities (with strong regulation capacity),but the relevant technology and incentivemeasures must be researched first.

• Formulating the laws and regulations on gasreserve storage facilities, and thus clearlydefining the obligations of the operating nat-ural gas companies, is of critical importance.The national policies and regulations must beimproved as quickly as possible so as toensure the optimal external policy environ-ment for both the structure and the institu-tional framework. Enterprises must receiveencouragement to become engaged in theconstruction of storage facilities and researchmust be launched into innovative storagefacility operational models. National rulesand laws on the management of natural gasstorage facilities must draw on internationalexperience, and clearly state the organisa-tional and managerial roles and their dutiesand obligations, as well as create a gradedmanagement system for storage facilities.While strategic gas storage reserves remain aresponsibility of the state, the responsibilityand duty for the daily and hourly peak regu-lation must be shouldered by the provincialand municipal gas companies, together withthe operation of, and all the investmentrequired by, the regulation storage facilities.

• Pricing and taxation policy for gas storagemust be improved. The gap between the peak

1.5 Measures to Ensure a Safe and Efficient Gas Supply 33

and the trough prices is a reflection of thevalue of the natural gas at peak hours. Werecommend that China introducespeak-trough price differences for all types ofcustomers, which will lead to rational con-sumption, and the reduction in peak andtrough differences this causes will the raisethe operating efficiency of the system. In theUnited States and France, the differencebetween peak and trough prices is usually afactor between 1.2 and 1.5. January–Februaryand November–December will be designatedas peak gas usage season, when peak pricingwill be implemented, with the price risingabove the gas prices at that time, establishinga rational mechanism for pricing. The tariffscan then be calculated on the basis of theoperating costs of storage reservoirs andstorage facilities, and on the basis of theinternal return rate approved by the govern-ment. The government approves the pricelevel, but periodic evaluation and adjustmentof storage reservoir prices must be carriedout. The formulation of preferential policiesand measures will further encourage enter-prises to become involved in the constructionof storage facilities. The recommendation isfor the government to apply preferentialpolicies to the costs of the construction ofstorage facilities. Here the government canuse the law regarding commercial oil reservesas a reference, where the upstream suppliercan offset 30% of the cost of LNG used instorage and of the total cost of the investmentinto the construction of LNG emergency peakregulation storage faculties against tax. Thiswill encourage upstream suppliers to set up anappropriate amount of LNG storage, enablingthem to counter the problem of temporarysupply disruptions or excessive peak demand.

• Reform of the management system of gasstorage must be accelerated. Taking intoaccount the Chinese gas industry’s specialcharacteristics, future gas storage operationsin China may at first adopt an operatingmodel that is not fully market-based, withindependent storage operating companies setup within companies managing pipeline

transmission. Gas storage facilities will thusbecome independent profit-making bodies,which will not only help the gas storageindustry to operate in a more professional andmarket-oriented way, but will also supportindependent market price setting. As China’sgas storage services industry develops at greatspeed, there will be a developing tendency forstorage services to separate from pipelinetransmission services, becoming an indepen-dently operating link. The diversification ofpeak regulation storage facilities constructionmust be encouraged. For this purpose, anindependent state-owned enterprise, munici-pal gas companies and independent storageoperating companies must be formed to createa diversified system, which will help toensure natural gas supply security and fastgrowth in gas storage capacity.

• An effective early warning emergencyresponse system must be set up. The first stepwill be to establish a forecasting and earlywarning system. Statistical data monitoringand evaluation and information disseminationmechanisms must be established as soon aspossible, communication channels must befully integrated, and the system responsiblefor information and natural resources statis-tics collection must be continuously upgra-ded. Next, an emergency response systemcovering all the aspects of the natural gasindustrial chain—production, transportationand sales—must be set up. Different levels ofcontingency plans must be decided upon inaccordance with the specific enterprise andregional characteristics. In order to guaranteetimely, rigorous and authoritative emergencyresponse, overall co-ordination must beentrusted to the National Energy Commis-sion, establishing an assessment system and adecision-making mechanism capable of han-dling major events in the natural resourcesphere, as well as providing feedback andinformation disclosure.

• Finally, research must be conducted into theappropriate scale of strategic natural gasreserves. On a global perspective, the gasindustry has not yet seen an international

34 1 General Summary

supply crisis like the oil industry has, andthere are no prominent security issues. How-ever, compared to the oil industry, the gasindustry harbours a great potential risk—ithas a high degree of integration between thedownstream, midstream and upstream.A problem at any of these points can have aneffect on supply security. The Russia–Ukrainegas war of 2009 is one such example. For thisreason, China must, as soon as possible, onthe basis of its commercial reserves, startresearching the issue of strategic gas storagereserves, evaluating the future mid- andlong-term trends in national and internationalnatural gas security, commencing preliminaryplanning, and formulating a strategic reservesscope and model suitable for China.

1.5.5 Improve Technology Capacityand Strengthenthe Long-TermDevelopment Capability

By expanding joint research and co-operationwith foreign partners in science and technology,innovative, advanced technology must bedeveloped and deployed. The technology ofexploration, extraction and production of shalenatural gas, suitable for the specific nature ofChinese geology and subterranean structure,must be clearly understood, and a China-specific,cost-effective, environmentally friendly andscalable solution developed:

• Equipment: To begin with, there should be aswitch to more powerful equipment, to reducethe quantity of equipment and the scale ofwell sites and to facilitate operations inmountainous terrain. Following that, a switchshould be made to module-based,smaller-sized, portable equipment for thoseoperations in areas with geologically complexterrain.

• Cost reduction: In order to achievelarge-scale cost reduction, we must activelywork on research on the crucial and

complementary areas of technologicallyoptimal design and low-cost fracturing fluids.

• Environmental protection: The safety andenvironment-friendliness of the additivesused must be guaranteed. In the next three tofive years, the aim is to achieve, throughinnovation and the introduction of advancedtechnology, an economically viable systemfor shale natural gas that addresses China’sspecific needs.

We must strive to achieve, after 2020, amature and complementary shale natural gasindustry capable of developing its own technol-ogy. We must bolster research into shale naturalgas geology, and explore advanced yet workablemethods for shale natural gas exploration andcommercialisation.

The intensity of technological innovationmust be increased. There must be a focus onmaking key technological breakthroughs, andgreater input must be applied to the research inkey common technology in areas such asunconventional gas extraction, deep sea gasindustry development, and LNG storage andtransportation facilities. Strategic planning mustbe carried out, as soon as possible, with regard toresearch and development of key technologies ineight major areas—shale natural gas extraction,sea gas exploitation, coal seam gas extraction,methane hydrate extraction, coal gas,gas-powered vehicles (ships) engine manufac-turing, combined cycle gas turbine generatorunits, and carbon capture and storage. Whilefocusing on achieving breakthroughs in keytechnologies, we must also carry out, in advance,fundamental research in the relevant fields.

Finally, innovative energy technologiesrequire an innovative management system. Thenational energy authorities must take the lead,and organise and co-ordinate the work of theministries of technology, national resources,industry and information technology, finance,environmental protection and of the Standard-ization Administration. Every organisation’s roleand responsibility in supporting natural gastechnological innovation should be clearlydefined. The supporting policies must be

1.5 Measures to Ensure a Safe and Efficient Gas Supply 35

formulated according to the special characteris-tics of generic technologies in order to strengthenthe support system for innovative natural gastechnologies. A national unconventional naturalgas research laboratory must be set up, bringingtogether human, material and financial resourcesto achieve breakthroughs in the key areas oftechnology.

1.6 Constructing a Modern NaturalGas Market Mechanismand Management System

Expanding supply and demand, raising efficiencyand safeguarding supply safety all require areform of the institutional mechanisms. The ori-entation of such reforms is identical with thereform spirit and the orientation of the ThirdPlenary Session of the 18th Central Committeeof the Communist Party of China. Namely, whilethe decisive role must be given to market andresource allocation, the government role mustalso be applied to the greatest possible extent. Inorder to rationalise the comparative prices fornatural gas and alternative energy sources, apricing system and a green finance system mustbe set up which reflect the degree of scarcity ofnatural resources, the supply and demand rela-tionship, and the external cost of environmentaldamage. Diversified competition and greateropenness to foreign involvement must be boostedat all the stages of the natural gas industrialchain, but we must also at the same timestrengthen the regulations regarding marketaccess fairness and general services in order toestablish a diversified, opened, orderly andmodern market system. Specific measures are asfollows.

1.6.1 Liberalisation of the UpstreamSector and True ImportLiberalisation

In order to have competition in the natural gasmarket, it must have a certain number of partic-ipants. The United States and Europe are

examples of classic competitive markets, withmany players and vigorous competition at everystage, from exploration and production, andstorage and transportation, to wholesale andretail and market hubs. Resource acquisition isthe prerequisite of natural gas usage, but in thisindustry it is often the upstream producers thatcontrol the operations and the profit allocationalong the entire industrial chain. For this reason,the liberalisation of access to upstream explo-ration and development is crucial for the growthof the natural gas market.

Market Characteristics of MajorCountriesThe characteristics of a competitive,responsive, fluid natural gas market are:

• The number of participants in the mar-ket must exceed a certain number: agreater variety of services is madeavailable to consumers by greater mar-ket participation and midstreamcompetition.

• Competitive prices at wholesale andretail levels.

• Non-discriminating liberalised marketaccess, including access to infrastruc-ture facilities such as pipeline network,storage reservoirs and LNG terminals(Table 1.2).

Currently the oil and gas concessions in Chinaare almost entirely concentrated in the hands oflarge oil companies. Nationwide, the total area ofregistered oil and gas exploration concessionsstands at 4 million km2, and the area granted tothe three main oil companies—Sinopec, Petro-China and China National Offshore Oil Corpo-ration—stands at 3.9 million km2 or 97% of thetotal. The area of registered mining concession isapproximately 118,000 km2, of which117,000 km2 (99%) belongs to the three main oilcompanies. Exploration and development ofunconventional gas resources, such as shale and

36 1 General Summary

coal bed gas, has already been opened up to avariety of different enterprises, but the number ofexploration blocks is limited. Furthermore, thethree main oil companies still enjoy the leadingpositions in the development of the unconven-tional gas resources due to the fact that undermany circumstances the degree of the overlapbetween non-conventional gas (mainly shalenatural gas) and conventional gas blocks is veryhigh. Moreover, in the import segment of theindustrial chain, even though policy allows agreater number of enterprises to participate in thenatural gas import trade, currently, because of thelimiting factors such as reception terminals, thenumber of players in the domestic natural gastrade market is still very limited, being restrictedto a few enterprises such Huadian Group, JiufengEnergy and ENN Energy.

Solving the problems which plague the issue ofmining concessions, such as over-concentration,“enclosure without prospecting” and “controlwithout development” is a crucial part of the

comprehensive, deep upstream reform of theindustry. For this reason, starting with the existinglaws, regulations and management methods, themaximum effort must be exerted to promoteinvestment diversification, and improve marketaccess standards. The tender bid system must becomprehensively applied to natural gas conces-sions, and we must push forward, in an orderlyand efficient manner, the construction of primaryand secondary prospecting and mining rightsmarkets, while at the same time putting funda-mental natural gas resource data to work for thepublic benefit.

Regarding imports, we must, on the one hand,expand the standardisation, public disclosure andtransparency of the approval process for builtfacilities, such as receiving terminals, and, on theother hand, draw on the international experience,producing detailed policy regarding third-partyaccess, and effectively strengthening the neces-sary regulation. We must compel those enter-prises that meet the necessary conditions to turn

Table 1.2 Natural gas market characteristics of major countries and regions

Natural gas indicators Category USA EU UK Japan SouthKorea

China

Supply(billion m3/year)

Nationalproduction

689 269 38 3 0.5 115

Imports 37 231 39 123 53 49

Consumption (percentageof total amount)

Electricalpower

40 30 30 65 50 15

Industry 20 20 10 5 20 45

Pipeline (km) 500k 200k 8k 5k 4k 50k

Wholesale market competition ✓ Constrained(oligopoly)

✓ Constrained(oligopoly)

X X

Access openness Upstream ✓ ✓ ✓ ✓ X X

Transmission ✓ ✓ ✓ ✓ X X

Allocation diversified diversified ✓ X X X

Unbundling of transportationand sales rights

✓ diversified ✓ X X X

Independent (federal)market power

✓ ✓ ✓ X X X

Liquidity market centres ✓ ✓ ✓ X X X

Note The above data is from 2013, but the data for China’s natural gas consumption for electricity generation and byindustry is given at 2011 levelsSource Vivid Economics, and based on IEA, EIA, Chinese Government and ENTSOG data

1.6 Constructing a Modern Natural Gas Market Mechanism and Management System 37

towards the natural gas import industry (pipelinetransmission and LNG) and make independentchoices to engage in natural gas imports.

1.6.2 Step-by-Step Natural Gas PriceReform, AcceleratedConstruction of NaturalGas Trade Hubs

Natural gas reform is key to resolving thenumerous conflicts in the natural gas sector. Suchreform must not only focus on adjusting naturalgas price levels. The focus must also be on thereform of the pricing mechanism.

1. The netback method must be improved fur-ther, as quickly as possible. First, price reg-ulation frequency must be adjusted, andefforts must be made to achieve seasonalregulation as soon as possible. Second, the oilprice levels and depreciation indices used as areference for price adjustment must, to thegreatest possible extent, reflect the changes inthe price of alternative energy sources, ratherthan be based on the high-price import costspaid previously by the three large gas and oilcompanies.

2. The cost and the prices for gas transmissionusing long-distance pipelines, pipeline bran-ches, provincial and metropolitan pipelines,and distribution pipelines must be determinedon a scientific and rational basis. In addition,the regulation in this sector must bestrengthened and the return on pipelineinvestment rate adjusted from 12% down to8–10%. The current situation of inflatedtransmission and distribution prices must bereformed in order to create a more optimalenvironment for price reform and for thedevelopment of the natural gas reformindustry.

3. Improvements must be made in the imple-mentation of seasonal price differences, the

peak and trough price differences, intermittentsupply prices and storage prices. Measure-ment standards and valuation methods mustbe revised (from being based on flow rate orquality, to a valuation based on calorificvalue) and at the same time we muststrengthen, both in technological and admin-istrative areas, the supervision and checks ofpricing violations. The problem of the lack oforganisation in tax collection by local gov-ernments must be solved as quickly as pos-sible. Currently, as part of the natural gasprice adjustment fund, the local governmentlevies a fee of between 0.3 and 1 CNY/m3 ofnatural gas sold, which adds to the burden onthe consumer. This practice must be abol-ished. The aim is to gradually rationalise theprice of natural gas for residential use.

4. Price liberalisation must be carried out inareas which comply with the necessary con-ditions. In areas with multiple sources ofnatural gas and abundant supply, such as theeastern regions of Shanghai, Guangdong,Zhejiang and Jiangsu, the imports of naturalgas must be liberalised by allowingthird-party access to infrastructure; liberali-sation must also extend to the gate price ofevery province, with prices decided directlyby the up- and downstream users.

5. The construction of regional trading hubsshould be promoted. The construction of theShanghai and Guangdong hubs can be pushedforward in the near future. In the medium andlong term, new regional hubs can be set up inBeijing, Sichuan, Hubei, Ningxia and Xin-jiang. Efforts must also be made to make theShanghai hub into an Asian, and even inter-national, natural gas trade hub. Eventually,the Shanghai hub will develop into a tradinghub system where its international pricinghub capability can interact with that of amulti-regional hub, acting as a link andcomprehensively connecting the domesticand the foreign demand and supply. The

38 1 General Summary

trading hubs must first engage in spot trading,then expand its trade volume and scope, andonly then commence developing trading infutures, increasing the market depth.

The Function, the Conditions and theImplementation Phases of TradingHubsSpot trading provides greater flexibilityand fluidity to long-term contracts, and itsrole in international natural gas trade iscontinuing to grow. Trading hubs have twoimportant roles. The first is to physicallybring together the sellers and the buyers,and the second is to allow for the compe-tition to decide the prices. For this reason,as the signal of market-oriented pricingraises the economic efficiency of the trad-ing and investment decisions, correspond-ingly lowering trading costs, marketparticipants will benefit. Moreover, thetrading hubs can, by using the pricingmechanisms, also solve the problem ofsupply and demand imbalance, safeguard-ing the security of gas supply. The poten-tial shortcomings are that the prices mightexperience intense short-term fluctuations,since they are decided entirely by compe-tition, and led entirely bynon-governmental market forces. The datashows that price fluctuations are oftengreater when prices are set using the tradehub method than when set using oil priceas a standard.

The success of trading hubs depends onthree prerequisites. First, there must benon-discriminatory access to an improvedand open natural gas transmission pipelinenetwork for the market participants tooperate in. Liberalisation of the pipelinenetwork is the key to successfully liberal-ising prices, and failure to meet this con-dition can cause the natural gas supply,regardless of whether the gas is domesti-cally produced or imported, or transportedby pipeline or as LNG, to be unable to link

up with local demand. Second, many of theindependent buyers and sellers activelytake part in arbitrage trade, and none havestrong market allocation capacity. For thisreason, the trading hubs must be guided bycompetitive prices, thereby avoiding theproblem of the market forces influencingand distorting prices and trade volume.Third, the government must support theliberalisation of prices on the wholesalegas market, along with providing stable,transparent and reliable regulations. Thetrading hubs must place priority on arbi-trage trade, which will raise market oper-ational efficiency, but the arbitration trademust rely on accurate and highly trans-parent reports of natural gas prices.

China has many of the conditions nec-essary to become Asia’s regional naturalgas trading hub: the scale of its natural gasproduction, the growth of its pipeline net-work and the volume of its LNG imports.Moreover, other Asian countries cannotmatch China on the Asian natural resourcesmarket. However, the Chinese market isstill comparatively centralised, third-partyaccess to the pipeline network is still sub-standard, and the prices remain under thegovernment control. These factors willhinder the establishment of trading hubs.A roadmap for the next 5–10 year devel-opment of China’s natural gas trading hubsmust be formulated. First, pilot projectsmust be launched. A mechanism compris-ing third-party access to pipeline networkand transparent prices can be set up in theShanghai region, creating the conditions ofcompetitive natural gas demand and sup-ply. Then the area allocated to pilot pro-jects can be expanded, new categories ofsellers and buyers added, while at the sametime strengthening market supervision.Gradually, as the effectiveness of the pilotproject grows, it will attract a growingnumber of producers and consumers. Asmore and more different organisations jointhe hub trade, the network effect can be

1.6 Constructing a Modern Natural Gas Market Mechanism and Management System 39

achieved, increasing the advantages of thehub. Both the hub’s scale and its role insetting prices will continue to grow untilthe hub becomes limited by the size of theland area allocated to it.

With price liberalisation action as a founda-tion, it is also necessary to use the regulatory roleof taxation policy, and to establish and improvethe policy system of environmental taxation andcarbon trading. Environmental tax and carbon taxcan be used as an incentive mechanism to expandthe natural gas industry, and will also send out apowerful signal to the investors. The period ofthe 13th Five-Year Plan must witness the for-mulation and appearance of the environmentaltax, the expansion of carbon trading and theestablishment of a robust national market,expanding across the entire economy, includingprimary, secondary and tertiary markets, andintegrated into the global market.

1.6.3 Clear Allocation of Functionsand Robust Supervisionto Support Unbundlingand Third-Party Access

In order to ensure the fairness of market trans-actions, we must, in accordance with thedemands of the Third Plenum, push forward withthe separation of pipeline network from naturalgas transmission services. The detailed methodsare outlined below.

First, we must push forward with the separa-tion of pipeline network from natural gas trans-mission services. Both international experienceand the practices established in China indicatethat unbundling of services, accounting and legalaffairs alone is not sufficient; the key is to achievethe unbundling of functions and structure. If it issuccessful, and is backed up with robust regula-tion, the splitting of ownership rights is notrequired. More specifically, in order to completethese three tasks, we must first, as fast as possi-ble, push forward the unbundling of services,

accounting and legal affairs; pipelines alreadybuilt can remain in the possession of the threemain oil and gas companies, but their companybranches must be turned into subsidiaries. As forthe newly built pipelines, here the three maincompanies can take the lead, but a diversity ofinvestors must be brought in. The three majorcompanies must be encouraged to form consor-tiums with up- and downstream enterprises,especially those engaged in natural gas services,for joint investment, construction and operations.Even more important is to provide the gastransportation companies with business scope,cost regulations, operational methods and infor-mation disclosure methods. The transportationcompanies must have independent managementrights, and the information disclosure by theparent company, the affiliated companies andother companies must be synchronised.

Unbundling of the Natural Gas Pipe-line Network and Natural GasTransmissionThe unbundling of services in itself is notvery effective. In the United Kingdom, inthe early stages of this process, the domi-nant position of the established brand,British Gas, hindered competition. InJapan, where the degree of unbundling ofaccounting and functioning was not strongenough at the early stages, the unbundlingof services did not have much value. TheEuropean experience also shows that theunbundling of legal affairs on its own doesnot have much use either, and must besupplemented by deeper structuralunbundling using measures such as func-tional unbundling.

Functional unbundling is a crucial fac-tor in the entire unbundling process.Functional unbundling often involves aseries of restrictions and requirementswhich affect the operations of midstreamservices (regardless of whether or not theyare an independent legal entity). Unbund-ling includes the following: establishmentof an independent trademark and brand;

40 1 General Summary

data processing restrictions; unbundling ofauxiliary services such as legal affairs,accounting and IT; management unbund-ling; and compliance and reporting plan-ning (Table 1.3).

If the regulatory mechanism is suffi-ciently robust, there is no need for owner-ship rights to be unbundled. Only the UKand The Netherlands have carried outownership rights unbundling. The Frenchand German policy makers advocatestructural unbundling without the unbund-ling of ownership rights, and the latestEuropean Union natural gas directives

have stipulated robust regulatory measuresin order to boost structural unbundling.According to this new reform plan, thelarge-scale electricity and gas enterprisesmust choose one of the following threereform programmes:

• unbundling of ownership rights andsale of the pipeline transportation net-work, achieving a complete separationof pipeline network and transmission;

• unbundling of operational rights whilepreserving the pipeline network own-ership rights, but with the establishment

Table 1.3 Five methods for the unbundling natural gas pipeline network and natural gas transmission

Method Changes Aim Comparison with prior tounbundling

Servicesunbundling

Midstream business (mostimportantly pipeline services)are separated from the gasretail businesses, becomingindependent suppliers

If transmission businesses donot independently supplynatural gas retailers, thecompetition becomesdistorted as the supplier is notable to sell the natural gas tothe pipeline users apart fromthe pipeline company

N/A

Accountingunbundling

Midstream businesses mustindependently consider theirprofits and costs, and beseparated from the up- anddownstream services

Prevention of midstreamcross-subsidies or creation offavourable conditions for therelevant up- or downstreambusiness

If midstream businessescollect tariffs independentlywithout being a separateservice, it makes separatebookkeeping impossible

Legal affairsunbundling

Midstream business become aseparate legal entity, butremain vertically integratedinto the company structure,for example as awholly-owned subsidiary

A legal duty for the subsidiarycompany to become creditedas a legal person.Management unbundling canbe more effective if done as anindependent legal entity

A separate legal entity mustmanage separate accounts andsupply independent services

Structuralunbundling

Effective and extensiveseparation of the midstreambusiness operations policyincentive mechanism from theincentive mechanism of up-and downstream enterprises

Separation of the midstreambusiness operations incentivemechanism from the relevantentities, creation of a moreeffective market byeliminating the motivation foranti-competitive behaviour

Midstream business must be alegal entity with clearlydefined actions and duties

Ownershipunbundling

All the midstream businessesmust be separated from thevertically integrated company,and transferred to entities withindependent ownership rights

Comprehensive unbundling ofownership rights must achievethe fullest possible separationof midstream business fromthe benefits of low andupstream sector participants

The independently ownedcompanies must beindependent legal entities,with separate accounts andservices

1.6 Constructing a Modern Natural Gas Market Mechanism and Management System 41

of an independent company (indepen-dent system operator) to run the pipe-line network transmission operations;

• management rights unbundling whileretaining the possession and operationof pipeline transmission, but the man-agement of the pipeline transmissionmust be handed over to an independentsubsidiary endowed with managementand decision-making rights (indepen-dent transmission operator).The reform programme also requires all

member states to set up an independentregulatory mechanism in order to ensurethat the large enterprises carry out effective“separation of production and supply” andtruly implement the principles of freecompetition in the energy market. TheAmerican experience also shows that acompetitive gas market can be sustainedwithout the compulsory unbundling ofownership rights, provided that strict reg-ulations are imposed on the operations oftransmission and supply companies. Undernormal circumstances a robust regulatorysystem on its own is sufficient to achieveeffective structural unbundling.

Third-party access services must be providedas soon as possible. Robust regulation must beapplied to the terms of access, service prices andservice quality, ensuring that the main operatorsprovide fair, impartial services, and creating theconditions to cultivate a competitive market. Inorder to establish detailed regulations regardingthird-party access, and thus ensure third-partyparticipation, we need to promote informationdisclosure and strengthen the regulatory capacity.An open and transparent oil and gas managementand operations information platform is required,covering all the information relevant to industrialoperators, such as current excess production

capacity infrastructure and the conditions andcosts of third-party access.

Moreover, the unbundling of the pipelinetransmission business and sales business andthird-party access reform are complementarywhen it comes to liberalising the free choices ofdownstream users. The graded (according to thevolume of annual natural gas consumption) lib-eralisation of large users’ direct choice of gassuppliers must be pushed forward as soon aspossible. For this purpose, large users includeurban gas companies, electricity generating sta-tions and CCHP stations with 20,000 kWcapacity, large enterprises (including raw mate-rials and fuels) and LNG/CNG suppliers. Thestorage and city distribution link of the naturalgas industrial chain must also gradually intro-duce the third-party access mechanism for cus-tomers at different consumption scales. Startingwith the largest annual non-residential users, anannual schedule and the list of gas consumptionvolume must be made, and the largenon-residential users can be presented with sup-plier choices based on their own time scheduleand operations. The users may also choose toavoid the urban gas distribution networks com-pletely or chose solely the services of the citydistribution networks where the price is fixed bythe government.

1.6.4 Strengthen Energy ResourceManagement, Establisha Regulatory Systemand Build RegulatoryCapacity

When promoting marked-oriented reform of thenatural gas market, we need to strengthen com-prehensive energy resource management andprofessional regulation. The component parts ofthis are: building a comprehensive energy man-agement regulatory system; formulating a natural

42 1 General Summary

resource strategy, regulations and policies; con-trolling and regulating the overall balance ofenergy resources; ensuring energy resourcesecurity; adjusting the energy resource structure;adopting energy-saving and efficient manage-ment practices; strengthening information col-lection and analysis; supporting technologicalinnovation and international co-operation inenergy; and ensuring co-ordination with the rel-evant departments.

We must strengthen the energy resource reg-ulatory mechanism and maintain order in theenergy market, promote market competition inthe industry, and solve market disputes. Theauthority and the position of the regulators mustbe independent, and the regulators must makecorrect decisions while extending equal treatmentto all players in the markets. The specific stepsare as follows:

• In the near future, we must further improvethe regulatory and co-ordinating mechanism.The relevant departments must exercise bettercommunication, co-ordination andco-operation when formulating regulatorylaws, rules and standards, national energydevelopment planning and strategies andenergy industry policies. The departmentsmust also improve their information sharingand co-ordination during regulatory opera-tions. On the local level, purelyprovincial-level energy regulation depart-ments must be established which will directlysend out professional regulation teams to anylocations required. Moreover, the centralregulatory authorities must carry out robustinspection and supervision of the local regu-latory departments.

• In the medium and long term, we need to setup a unified energy regulatory mechanism.This mechanism, apart from monitoring theenvironment and national resources, must begradually given an economic and social reg-ulatory function across the entire energy

industry chain. It will explicitly co-ordinateits work with the relevant departments, with adetailed breakdown of its duties and respon-sibilities, and gradually become an indepen-dent regulatory body. The final outcome mustbe an independent, unified and professionalenergy regulation mechanism, and atop-down regulatory organisation system.According to the convention of Chineseadministrative reform, in 2018 the adminis-trative system will enter into an adjustmentphase and at that point these plans to build aunified integrated energy managementmechanism and an energy regulation mecha-nism can be considered.

1.6.5 Support the Developmentof Professional Servicesand TechnologicalCompanies; Use MarketForces to Promotethe Expansionof the Division of Labour

The experience of the American shale revolutiondemonstrates that a development style thatinvolves diverse participants and the division oflabour can mobilise progress in many areas,including venture capital, research and develop-ment, upstream resource extraction, infrastruc-ture, market development and terminalapplications. In a free competition environment,highly specialised, technologically advancedtechnical services companies can provide engi-neering services such as horizontal drilling, wellcompletion, well cementing and multi-stagefracturing, as well as technological services,such as well logging and experimental testing, tomining rights holders. Some companies cansimply withdraw after having completed theirservices at a certain stage of the industrial chain,and then be replaced by an enterprise from the

1.6 Constructing a Modern Natural Gas Market Mechanism and Management System 43

next stage of the chain. High division of labourhas therefore turned the extraction of shale nat-ural gas, at each stage, into a low-investment,short-operating-cycle process with fast invest-ment return. It has also attracted a great deal ofventure capital and private capital into theextraction of shale natural gas. We must there-fore exploit the role of market forces to the fulland strongly encourage the development of spe-cialised technological services companies andadvanced technology companies in the oil andgas industry. In accordance with the principle of“demand for production, advances in technology,excellence in reputation”, we should use methodssuch as market forces and quality control toregulate these service enterprises and their oper-ations. We must organise specialised construc-tion teams, and establish the system of rules foreach segment, including exploration, production,cost, safety and environmental protection, withthe aim of achieving an orderly, standardisedoperation of the production process, as well asensuring orderly exploration and production.

The policy measures needed to encourage thedevelopment of specialised companies mayinclude tax breaks in the first instance. Anothermethod is to split off smaller auxiliary companiesfrom the large state-owned enterprises as part ofthe reform of state-owned enterprises. Theseventure exploration, oilfield and engineeringtechnology auxiliaries can, after becoming inde-pendent, form specialised companies and inde-pendently enter the market. There are severaladvantages to this. First, the burden on the maincompany will be lowered and operational effi-ciency improved. Second, the development andgrowth of the service companies will beaccelerated.

Despite the concerns expressed by some overthe survival of such auxiliary companies afterseparation, experience has shown that many suchauxiliary companies have demonstrated excellentgrowth as specialised operations. For example,

Bureau of Geophysical Prospecting Inc., ChinaNational Petroleum Corporation, after leaving themanagement of CNPCC and forming a spe-cialised company, grew rapidly and becamestrongly competitive internationally. It is nowranked third globally in overall strength, and is ina firm first place for ground operations. Aftersuccessful example is that of the subsidiaries ofChina National Offshore Oil Corporation—ChinaNational Oilfield Services and Offshore OilEngineering Company—which have shownexcellent progress.

A third possibility is to form a rational andscientifically-based oil industrial chain—after thesplit off the auxiliaries, the main company willhave a greater choice of specialist companies thatcan provide services, and the auxiliaries will alsohave more choices over their co-operation withthe main companies. In addition, expansion intothe international market can also follow. Evenmore important is that specialised companies canprovide technology services to the new entrantsinto the competitive market, which can break thecurrent technology monopoly.

1.7 Deepen the Lawsand Regulations Systemof the Gas Sector, and Establisha Sound Legal System

Although the formulation of the legal frameworkfor the gas sector in China is already in its initialstages, the problems of lack of co-ordination andsystematisation and of inconsistency persist. Forexample, China still lacks a specialised, com-prehensive Oil and Gas Law to cover all the linkson the industrial chain. In the area of explorationand production there is a legislation base fromthe Mineral Resources Law and Solid Ore Min-ing Law, and there is a common problem withspecification of mining resources, but it fails toaddress the issues specific to the special

44 1 General Summary

properties of gas as a gaseous mining resource.A great deal of the current legislation retains theparticularities of a command economy, withrestrictions on the acquisition and transfer ofmining rights. As a result, such legislation isunsuitable for the requirements of market reformand the special characteristics of natural gas. Theregulatory legislation and rules covering gastransmission, storage and distribution at eachsegment of the industrial chain from pipelinenetwork to end consumption, as well as thosecovering environmental protection and otheraspects, remain unsound. The duties and theobligations of the local government and the rel-evant enterprises are not clearly defined. Thetechnology specifications and standards for amodern natural gas industry require improvementand standardisation, and the legal framework ofthe natural gas sector must be overhauled as soonas possible.

The key measure necessary is the establish-ment of a sound Natural Gas Law, using a spe-cialised gas law to support for the entire legalframework. The laws and regulations must bemade more practical, adapting them to the specialcharacteristics of natural gas exploration, pro-duction, transmission, storage and distribution,and usage, and improving the drafting of thespecific rules and supporting regulations that areneeded. The natural gas-specific laws and regu-

lations must be formulated as quickly as possible.When formulating and revising the Oil and GasMining Rights Regulations, the Mid–andDownstream Natural Gas Management Regula-tions, the Natural Gas Extraction EnvironmentalProtection Regulations, the Sea Oil and GasPipeline Management and Protection Regula-tions, the Natural Gas Storage Regulations andother such administrative regulations, the focusmust be on the legal system of the resources’property rights, exploration and developmentcontracts, infrastructure construction, operationalmanagement, storage, sales and usage, safety andemergency warning and response system, pro-duction safety and ecological benefit compensa-tion, cross-border investment and imports,exports and trade.

Conflicts between the Oil and Natural GasPipeline Management and Protection Regulationsand other laws must be solved by resorting to thejudiciary. There is an urgent need to clarify manyareas: the co-ordination of pipeline developmentplanning and other specialised programmes, theconvergence of pipeline construction planningand urban-rural planning, the legal definition ofthe pipeline underground rights of passage, therestrictions imposed by pipeline safety on landuse, and the conflict between pipeline safety andthe safety requirements of highways andrailways.

Open Access This chapter is licensed under the terms ofthe Creative Commons Attribution 4.0 InternationalLicense (http://creativecommons.org/licenses/by/4.0/),which permits use, sharing, adaptation, distribution andreproduction in any medium or format, as long as yougive appropriate credit to the original author(s) and thesource, provide a link to the Creative Commons licenseand indicate if changes were made.

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1.7 Deepen the Laws and Regulations System of the Gas Sector… 45

PART I

Analysis of Natural Gas Demand

2Developments in Global Natural GasConsumption

China is a country rich in coal but lacking in oil.For many years, coal has held the leading posi-tion in the country’s energy mix, while petroleumand natural gas consumption has been low.Recently, with economic growth and increasingenergy consumption, the increasing pressure onthe environment brought about by the extensiveuse of coal has led to unprecedented attentionbeing paid to the development of clean energy bythe state. On the supply side, the development ofshale natural gas, coalbed methane and otherunconventional gas sources has also beenaccompanied by greater development of con-ventional gas sources. Natural gas import vol-umes are also expected to grow. If China’snatural gas supply capabilities continue to growat the current rapid rates, then in the future sup-ply will no longer be the primary obstacle to thedevelopment of natural gas. Given these cir-cumstances, research into applications for naturalgas and its development potential, allowing tar-geted measures to support the growth of naturalgas consumption, is of major significance in thepromotion of the adoption of natural gas.

2.1 Major Factors Affecting NaturalGas Consumption Growthin Other Countries

In recent years, natural gas consumption grownrapidly in many countries, so that it accounts foran increasing proportion of energy used. Chinacan learn crucial lessons by analysing natural gasconsumption growth in these countries.

2.1.1 Proportion of EnergyConsumption of NaturalGas in Various Countries

The horizontal axis in Fig. 2.1 indicates theproportion of energy consumption represented bynatural gas (0–100%, divided equally into10 groups) while the vertical axis indicates theproportion of natural gas consumption of eachcountry compared to global natural gas con-sumption. It is clear that, out of 103 countries (orregions), there are 29 countries whose naturalgas proportion is between 0–10% of total energyconsumption and these 29 countries account for8.34% of global natural gas consumption. Thereare 14 countries whose natural gas consumptionis between 20–30% of total energy consumptionand these 14 countries account for around 32.7%of global natural gas consumption. There areanother 19 countries whose natural gas con-sumption is between 30–40% of total energyconsumption, accounting for around 19.64% of

* This chapter was overseen by Zhaoyuan Xu from theDevelopment Research Center of the State Council andMartin Haigh from Shell International, withcontributions from Baosheng Zhang and Shouhai Chenfrom the China University of Petroleum, Lianzeng Zhaofrom the China Petroleum Planning Research Institute,Linji Qiao from ENN and Juan Han from Shell China.Other members of the research group participated indiscussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_2

49

global natural gas consumption. There are fewcountries where natural gas usage accounts for aproportion greater than 40%, and these countriesoften possess large quantities of natural gasreserves. However, with the exception of Iranand Russia, these countries are not major naturalgas consumers in terms of quantity. The majorityof global natural gas demand comes from coun-tries where natural gas usage accounts forbetween 20–30% and 30–40% of total energystructure.

In order to analyse the prospective growth ofChina’s natural gas consumption, we choseseven countries to act as “benchmark countries”for China, and carried out detailed analysis of thegrowth in consumption of natural gas in theseseven countries. Each of these seven countries isa major consumer of natural gas, and the pro-portion of energy consumption accounted for bynatural gas has increased relatively quickly ineach case. Of these, four countries are developedcountries: the United States, Japan, Germany and

the United Kingdom. There are also threeemerging countries: Malaysia, Turkey andEgypt. There are other major naturalgas-consuming nations where the proportion ofenergy usage accounted for by natural gas isquite high, but these have large natural gasreserves, excluding them from the comparisondue to China’s relatively small reserves. Inaddition, there are countries where growth innatural gas consumption has been slow over anumber of decades, which are therefore notsuitable for adoption as “benchmarks” for theanalysis of China’s future natural gas demand(Fig. 2.2).

Since 1982, the proportion of natural gasconsumption of these benchmark countriesexhibited major increases, especially in the threeemerging countries of Turkey, Malaysia andEgypt, where natural gas proportions have risenfrom very low levels to extremely high levelsover the past 30 years. During this same period,the proportion of energy sources that natural gas

The majority of gas demandoccurs within 33 countriesthat use gas for 20–40% oftheir primary energy

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

30%

20%

10%

0%

Percentage of gas in the energy mix

Perc

enta

ge o

f glo

bal g

as

Russia and Iran are major consumers with high gas penetration

29

19

14

19

7

44 2

23

Fig. 2.1 Proportion of energy consumption of each country accounted for by natural gas and proportion of globalnatural gas consumption of each country. Source Formulated by Vivid Economics based on IEA and EIA data

50 2 Developments in Global Natural Gas Consumption

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

30%

20%

10%

0%

Percentage of gas in the energy mix

Per

cent

age

of g

loba

l gas

China

China

United States

Japan

Germany

United Kingdom

Malaysia

Turkey

Egypt

China

United States

Japan

Germany

United Kingdom

Malaysia

Turkey

Egypt

29

19

14

19

7

44 2

23

Fig. 2.2 Natural gas consumption in seven benchmark countries. Source Formulated by Vivid Economics based onIEA and EIA data

Pro

porti

on o

f prim

ary

ener

gy s

ourc

es a

ccou

nted

for b

y na

tura

l gas

0%

10%

20%

30%

40%

50%

60%

70%

China Germany Japan USA Turkey UK Malaysia Egypt

1982 2012

Fig. 2.3 Changes between 1982 and 2012 in the proportion of natural gas consumption of seven benchmark countries.Source Formulated by Vivid Economics based on IEA data

2.1 Major Factors Affecting Natural Gas Consumption Growth in Other Countries 51

accounted for in China rose from 2% in 1982 to4% in 2012 (Fig. 2.3). This indicates that anincrease in the proportion of energy sourcesaccounted for by natural gas could occur.

2.1.2 Breakdown of Natural GasConsumption Growthin Seven BenchmarkCountries

To carry out analysis of the natural gas con-sumption growth in these seven benchmarkcountries, we used index breakdown analysismethods, carrying out quantified analysis of themost important factors driving natural gasdemand, allowing the degree to which variousfactors contributed to the growth in natural gasdemand to be calculated. The main factorsinclude economic activity, energy density andfuel conversion.

1. Method of analysis

In different economic sectors, natural gasdemand changes are related to changes in eco-nomic activity, energy density and proportion ofnatural gas usage. Each economic sector’s natu-ral gas demand can be expressed as a functionthat includes a series of drivers (namely, eco-nomic activity, energy density and proportion ofenergy usage represented by natural gas), asshown in the equation below:

Gasdemand

¼Xsectors

i

economicactivity i

� energyintensity i

� share of energyfrom gas i

In the equation above, the total natural gasdemand G is broken down into the sums of thenatural gas demand of various sectors Gi (i = 1,…,n). The natural gas demand of each sector isthen broken down into three parts, namely eachsector’s economic total GVAi, energy intensityEi

GVAiand natural gas share of total energy con-

sumption in the sector GiEi. Based on natural gas

demand functions, indexes can be set for eachdriver, and these indexes can be broken downagain to quantify the change that occurs to nat-ural gas demand due to changes in each driverover a period of time. This kind of indexbreakdown approach is called a logarithmicmean Divisia index (LMDI). LMDI is a commonanalytical method found in energy literature.Based on the relative changes of each variabledriving factor, it breaks changes in overall nat-ural gas demand into the effects of three factors.This allows the analysis of natural gas growthprospects from the perspective of each factor’sdevelopment trends. Due to the limitations in thedata, the influence of fuel price changes has notbeen eliminated from the LMDI used in thisanalysis.

Theoretically speaking, these three drivingfactors will affect natural gas demand in differentways:

• Economic activity: As economic activitygrows, the energy input required by sucheconomic activity grows as well, so if all otherfactors remain equal, natural gas demand willalso exhibit a corresponding increase.

• Energy intensity: When the level of eco-nomic activity remains unchanged, then asenergy consumption intensity drops, theamount of energy required to create the sameamount of economic activity is reduced, andthus energy demand will drop. If all otherfactors remain equal, total natural gas demandwill exhibit a corresponding drop.

• Conversion to natural gas: If a given eco-nomic sector converts from coal or other fuelsto natural gas, then natural gas demand willincrease.

2. Breakdown of factors affecting interna-tional natural gas demand

This section presents a breakdown of naturalgas demand changes in the seven benchmark

52 2 Developments in Global Natural Gas Consumption

countries between 1982 and 2012, and for Chinabetween 2005 and 2012, based on LMDI.1

(I) Influence of economic growth on naturalgas consumption

As economic activity increases, each sector’snatural gas demand will increase. Figure 2.4shows the proportion that the increase in naturalgas demand as a result of economic growthencountered in the seven benchmark countriesbetween 1982 and 2012 represents in terms ofactual growth in demand (treating actual totalnatural gas growth in consumption as 100%). Itis clear that in these seven benchmark countriesthe economic activities in all economic sectorsgrew, and each sector’s natural gas demand alsorose. However, the most notable increases werein the residential and public utility sectors. The

possible cause of this may have been that asincomes increased, household heating expendi-ture rose, and this was accompanied by increasedusage of natural gas in power systems to satisfythe increased power demands. In addition, therewas a growth in natural gas demand for manu-facturing in each country. This is an indicationthat as economic activity increases, more naturalgas is needed to satisfy the ever-growing demandfor energy.

(II) Influence of energy intensity on naturalgas consumption

Reduced economic sector energy intensityimplies that the amount of natural gas required togenerate the same output has dropped. Naturalgas demand in China, the United States, Germanyand the United Kingdom has seen a net reduction,which is primarily due to a decline in residentialand manufacturing energy intensity (Fig. 2.5).There are also some countries, such as the UnitedStates, Japan and Egypt, where the miningindustry and public utility sector energy intensity

China

Germany

Japan

USA

Turkey

UK

Malaysia

Egypt

0% 50% 100%

Residential

Mining and utilities

Manufacturing

Services

Fig. 2.4 Contribution of increased economic activity in increasing demand for natural gas. Source Formulated byVivid Economics based on UN and IEA data

1The period over which analysis is possible for China isrelatively short, mainly due to the difficulties encounteredin obtaining the pre-2005 data required to carry out thisanalysis.

2.1 Major Factors Affecting Natural Gas Consumption Growth in Other Countries 53

have seen increases. However, since it is notpossible to break down mining industry, publicutility and heating plant data, the underlyingcauses of these increases is difficult to analyse. Inaddition, over the same period of time, thenon-gas-consuming sectors of the economy ofany particular country (such as economic activitythat requires electrical power) may also exhibitreduced energy intensity, resulting in an overallimprovement in total energy intensity of thesecountries, such as that encountered in Japan. Theresults of this breakdown indicate that China, theUnited States, Germany and the United Kingdomall show reduced demand for natural gas as aresult of reduced energy intensity.

(III) Influence of fuel conversion on naturalgas consumption

Among the seven benchmark countries, all eco-nomic sectors chose to reduce usage of otherfuels and to increase the proportion of naturalgas. In other words, they achieved fuel

switching. This is a major factor behind theincrease in natural gas demand (Fig. 2.6). Theeffect was particularly marked in the mining andpublic utility sectors, and their fuel conversionand the corresponding natural gas demandincrease accounted for a large proportion ofgrowth in consumption. In addition, China,Germany, the United Kingdom and Turkey,among other countries, also saw residential usagefuel conversion, which resulted in an increase indemand for natural gas. In the United States andMalaysia, manufacturing exhibited a relativelylarge-scale transition towards natural gas. InJapan, Germany and the United Kingdom, theservice industry also showed similar trends.

2.1.3 The Importance of FuelSwitching in Natural GasDemand Growth

Figure 2.7 is a summary of each country’snatural gas consumption growth factors for

-50% 0%-100%-150% 50%

China

Germany

Japan

USA

Turkey

UK

Malaysia

Egypt

Residential

Mining and public utilities

Manufacturing

Services

In all countries manufacturinghas become less energy-intensive, reducing gas demand

Improved residential gas efficiencyin the UK has resulted in a majorreduction in the demand for gas

Fig. 2.5 Influence of energy intensity changes on natural gas demand. Source Formulated by Vivid Economics basedon UN and IEA data

54 2 Developments in Global Natural Gas Consumption

50% 100%0%-50% 150%

China

Germany

Japan

USA

Turkey

UK

Malaysia

Egypt

Residential

Mining and public utilities

Manufacturing

Services

Significant increase innatural gas demand dueto power sector fuel conversion

Fig. 2.6 Influence of fuel switching on natural gas demand. Source Formulated by Vivid Economics based on UN andIEA data

The UK experienced a “dash for gas”,deindustrialisation and rising incomes

These emerging marketshave not reduced energyintensity in gas-consumingsectors

0% 50%-50%-100% 150% 200%

Gas switching effect

Economic activity effect

Energy intensity effect

China

Germany

Japan

USA

Turkey

UK

Malaysia

Egypt

Fig. 2.7 Factor breakdown of benchmark country natural gas demand: overall results. Source Formulated by VividEconomics based on UN and IEA data

2.1 Major Factors Affecting Natural Gas Consumption Growth in Other Countries 55

1982–2012 (China 2005–2012) (each country’snatural gas demand total change is set at 100%),giving an indication of the relative importance ofeach factor. From Fig. 2.7 we can see that, apartfrom the United States, in all other countries theinfluence of switching from other fuels to naturalgas on natural gas demand was greater than thatof economic activity. This shows that the maindriver behind natural gas demand increases is thechoice to adopt natural gas as a replacement forother fuels.

Analysis of this breakdown found that thenature of natural gas demand in the UnitedKingdom was different from other countries. Infact, all three drivers have a major influence inthe United Kingdom. Between 1982 and 2012the United Kingdom was primarily influenced bythree major development trends:

• the “dash for gas”—many people convertedfrom coal to natural gas, which played amajor role in the overall fuel conversionfigures;

• growth in GDP, which made the effects ofeconomic activity more apparent;

• de-industrialisation and schemes to improvehousehold energy efficiency, which resultedin a major increase in energy efficiency andhad an opposite effect on natural gas demand.

Even though energy intensity factors cancause demand for natural gas to decline, the othertwo factors caused natural gas demand toincrease. Each of these factors had a very sig-nificant result, equivalent to the total change innatural gas demand during the same period. Theexperience of the United Kingdom shows that,given the circumstances soon to be faced byChina, for instance rapid development ofdomestic natural gas resources, high rates ofeconomic growth and the economy becomingmore service industry-oriented, factors that driveup natural gas demand will continue to be verysignificant.

Generally speaking, the seven benchmarkcountries analysed each experienced a largeincrease in natural gas demand. A detailedanalysis of the results based on economic sector

shows that each of the three factors has the effectof influencing demand for natural gas as follows:

• Increased economic activity will cause naturalgas demand in all economic sectors toincrease, especially the power-hungry sectorsof housing, mining and public utilities.

• Reduced energy intensity in residentialhousing and manufacturing will causereduced natural gas demand.

• Fuel conversion is an important driver, inwhich the primary driver is the conversion ofpower plants and heating facilities to naturalgas, while residential housing and manufac-turing sector fuel conversion was also a majorfactor in most countries.

2.2 Primary Factors MotivatingSwitching from Other Fuelsto Natural Gas

Based on international experience, natural gas isgenerally uncompetitive on pricing alone, com-pared to other fuels. It follows that there are otherfactors that contribute to the decision to switchfrom other fuels to natural gas and it is thereforenecessary to explore these less-obvious factorsmore deeply.

This research employs two methods toexplore the motivating factors behind fuelswitching. The first consists of cross-sectionalregression analysis conducted on the 2012 datafor OECD countries, focusing on factorsincluding: the share of the economy accountedfor by the service industry; whether or not thereare natural gas reserves; total natural gas reserves(adjusted by GDP); and degree of openness totrade. The second involves a descriptive analysisof the majority of the world’s countries from1980–2013 in terms of natural gas share of theenergy mix and data on motivating factorstowards natural gas, with a focus on severalvariables, including service industry proportion,manufacturing industry proportion, urbanisationand atmospheric pollution (including PM10 andSO2).

56 2 Developments in Global Natural Gas Consumption

2.2.1 Various Approaches to NaturalGas Replacement

1. The seven benchmark countries primarilyswitched from oil to natural gas

Each country uses oil, natural gas and coal invarious proportions to satisfy its fossil fuel needs.As time passes, energy source structures gradu-ally adjust. Figure 2.8 shows the fossil fuelenergy mix changes over time in China and thebenchmark countries. Each country’s energysource structure change is shown as a pathway.The thin end represents the 1980 energy mix, andthe thick end represents the 2012 energy mix.The energy mix change path follows the timelinefrom the thin end to the thick end.

If a country’s path moves to the top of thetriangle, this indicates that the share of naturalgas increased in that country. If a country’s curvemoves away from “Oil” in the bottom lefttowards the top of the triangle, this indicates thatnatural gas replaced oil, as in Egypt (pink),

Turkey (purple) and Japan (green). If a country’spath moves from away from “Coal” in the bot-tom right towards the top of the triangle, thisindicates that coal had been replaced with naturalgas in that country, as in United States (yellow)and the United Kingdom (blue). If the country’scurve goes straight up toward the top of the tri-angle, then this indicates that natural gas hasreplaced both oil and coal in that country, such asin Germany over the past few years (grey).China’s energy mix (red) has always beenfocused on coal, with only slight changes so far.

From Fig. 2.8 it is apparent that the countrieswith the fastest growth in demand for natural gasare those switching from oil to natural gas,whereas China is switching from coal to naturalgas. To allow a conclusion to be reached that isof relevance to China, a large range of countriesis required for comparison, in particular thosethat have converted from coal to natural gas,even if the scope of conversion to natural gas inthese countries is smaller than that encounteredin the seven benchmark countries.

Gas

Oilproducts

0%

0% 100%

0%

20%1980

more gas, equal decline in oil and coal

more gas, less coal,

constant oil

constant coal,more gas,

less oil

201280%

40%60%

60%40%

80%20%

20% 40% 60% 80% 100%100% Coal

China

United States

Japan

Germany

United Kingdom

Malaysia

Turkey

Egypt

Other than the UK, there has been little movement ‘north-west’: switching from coal to gas

The UK’s “dash for gas” in the 1990s rapidly changed its energy mix

China’s energy mix continues to be dominated by coal

Fig. 2.8 Natural gas replacement pathways in China and benchmark countries (1980–2012). Source Formulated byVivid Economics based on IEA data

2.2 Primary Factors Motivating Switching from Other Fuels to Natural Gas 57

2. Main replacement pathways in countriestransitioning from coal to gas

Conversion from coal to gas is mainlyencountered in Europe, Australia and the UnitedStates. Figure 2.9 shows the changes in energystructure in terms of coal and natural gas for majorcountries that have transitioned from coal to gas.Curves running from the bottom right-hand cornerrepresent a high percentage of coal, while move-ment toward the top left corner is toward a highpercentage of natural gas. Developed countries,primarily in Europe, and especially the UnitedKingdom, have seen a high proportion of coalusage transition toward a high proportion of nat-ural gas. From the perspective of overall globaltrends (orange pathway) in recent years relating tofossil fuels, coal proportions have seen someincrease, primarily due to declines in oil ratherthan natural gas. The motivating factors forEuropean countries to switch to natural gas may

also be of relevance when considering switchingfrom coal to gas in China.

2.2.2 Analysis of Driving Factorsin OECD MemberCountries Switchingto Natural Gas

We conducted regression analysis on natural gasconsumption proportions and other factors forOECD countries for 2012. The aim of thisanalysis was to identify the primary motivatingfactors behind OECD countries switching tonatural gas.

Based on the regression results, there werefour factors—service industry share, normalisedGDP-adjusted total natural gas reserves, degreeof openness to trade (a ratio between theimport/export totals and GDP) and current natu-ral gas reserves—that acted as major variables in

1980 2011

China

United States

Europe

Australia

United Kingdom

World

China

United States

Europe

Australia

United Kingdom

World

Gas

%

Share of coal in primary energy (%)

00

10

20

30

40

50

20 40 60 0

China has made asmall move to gasChina has made asmall move to gas

European countrieshave made the biggest coal to gas switches

European countrieshave made the biggest coal to gas switches

The global trend has been to switch to coal, but from fuels other than gas

The global trend has been to switch to coal, but from fuels other than gas

Countries moving in thedirection of the arrow areswitching from coal to gas

Countries moving in thedirection of the arrow areswitching from coal to gas

Fig. 2.9 Changes in energy usage from coal to natural gas. Note The data represents non-renewable energy sourcepercentage; the data only shows countries that have experienced major transitions to gas. Source Formulated by VividEconomics based on IEA data

58 2 Developments in Global Natural Gas Consumption

natural gas share in OECD countries. Changes inthese four variables have a pronounced influenceon natural gas share. For example, if a membercountry’s service industry share changes by 1%,then that country’s natural gas proportion willchange by 0.86% (Table 2.1). By conductingfurther computation, it can be deduced that thesefour variables are responsible for 53% of thechanges in OECD member country natural gasshare. That is to say, differences in OECDmember countries’ natural gas shares can mainlybe traced back to these four variables.

When all factors are considered, serviceindustry share is the factor that has the greatesteffect on proportion of natural gas in OECDmember countries. Figure 2.10 shows standardvalues for regression coefficients. By employingstandard regression coefficients, one can comparethe importance of such variables. The higherthe standard value, the greater the importance.

Service industry share is the most importantvariable, followed by GDP-adjusted natural gasreserve levels. Based on these results, it is clearthat service industry share is not only the mostimportant variable, but is also an index that canbe used as a yardstick for other driving factors.For example, countries with a larger serviceindustry share could be at the stage of introduc-ing increasingly strict controls on air quality, andthis will further increase the market share ofnatural gas. However, this research does notincorporate air quality monitoring data; othervariable factors that could explain natural gasshare, such as urbanisation, were incorporatedinto the factors we considered, but did not affectthe results. This is because by 2012 the majorityof OECD member countries had alreadyachieved a high degree of urbanisation, and thusthere were no significant differences in urbani-sation between them.

Table 2.1 Role of four variables in OECD country natural gas share

Variable An increase of 1% of any variable will cause:

Share of service industryGross value added in services sector (GVAservices/GVA)

Natural gas share rises by 0.86%

Natural gas reserve levels (adjusted for normalisedGDP)Reserve levels/GDP

Natural gas share rises by 0.49%

Degree of openness to trade(Imports + Exports)/GDP

Natural gas share rises by 0.09%

Whether there are natural gas reserves or not1 represents entirely no reserves, 0 represents theexistence of reserves

If a country does not have natural gas reserves, then naturalgas share drops 0.15%

Note This cross-sectional regression analysis uses 2012 dataSource Vivid Economics

Stan

dard

ised

regr

essi

on c

o-ef

ficie

nt

Share ofservices

Gas reserves/GDP

Presence ofgas reserve

Opennessto trade

0

0.2

0.4

0.6

Fig. 2.10 Regression results for 2012 natural gas share in OECD countries

2.2 Primary Factors Motivating Switching from Other Fuels to Natural Gas 59

The OECD country analysis results show thatwhen a country has natural gas reserves and hasalready entered the stage of development inwhich services are the primary focus, natural gasaccounts for a very large share of the energy mix.Domestic reserves are undoubtedly important,because those reserves are often a country’scheapest source of natural gas and, regardless ofhow extensive they are, they will influence thenatural gas share. This implies that countrieswithout natural gas reserves might not makenatural gas a primary energy source, that naturalgas would not be used for infrastructure and byinstitutions, and that the import of natural gaswould not be encouraged. The OECD countriesSouth Korea and Japan are an exception to this,though; their domestic natural gas reserves arenegligible, they have a high degree of opennessto trade and they restrict other energy sources,which results in natural gas having a relativelyhigh share in their energy structures.

The analytical data shows the influence offactors driving changes in the use of natural gasin developed countries, but does not consider theeffects of urbanisation and atmospheric pollution.These factors are of major relevance in China,but they are less influential in OECD membercountries. The next section will therefore expandthe range of countries looked at so that a morecomprehensive range of driving factors can beexamined.

2.2.3 Further Analysis of MotivatingFactors for a Countryto Switch to Natural Gas

To further analyse the factors motivating acountry to switch to natural gas, we carried out acomparison of data on natural gas share andnatural gas motivating factors for most of theworld’s countries for the period 1980–2013. Thispermitted a more comprehensive analysis of howchanges in each country’s natural gas share cor-related with changes in the variables. A globaldataset was built for the years 1980–2013,

including natural gas share, service industryshare, manufacturing share, urbanisation andatmospheric pollution including PM10, and SO2

for each country. The changing trends are out-lined in Figs. 2.11, 2.12, 2.13, 2.14, 2.15 and2.16.

1. Apart from China, service industry shareis often closely connected to natural gasshare

Changes in service industry share and naturalgas share exhibit the same trends. In other words,when one variable changes, the other variablechanges along with it. This kind of commontrend suggests that a connection exists betweenthe two and all that remains is for it to be con-firmed by statistical analysis. There is a pro-nounced pattern in the United Kingdom, Japanand South Korea, and many other countries alsoexhibit such characteristics. In Fig. 2.11, only thedata from China fails to demonstrate a relation-ship between service industry share and naturalgas share. Nonetheless, China’s service industryshare is similar to levels in Japan and SouthKorea in 1980, so it is likely that this trend willmanifest in the future.

2. The relationship between the manufactur-ing industry share and natural gas share isnot pronounced

Only in a minority of countries is there aconnection between manufacturing share andnatural gas share; in the majority of countries thetwo do not have a pronounced relationship. Fig-ure 2.12 shows that, with the exception of China,Asia’s emerging markets all use natural gas todevelop their manufacturing industries. In Eur-ope, the natural gas share continues to rise asdeindustrialisation proceeds. This implies that therelationship between manufacturing industryshare and natural gas share could changedepending on industrial and energy mix policies,as well as changing as a result of economicdevelopment.

60 2 Developments in Global Natural Gas Consumption

CHINA INDIA

UNITED KINGDOM SOUTH KOREA

Fig. 2.11 Size of service industry and natural gas share of energy mix, 1980–2010. Note Natural gas share refers to theshare of natural gas within total non-renewable energy sources. Source Vivid Economics, based on EIA and WorldBank data

CHINA MALAYSIA

UNITED KINGDOM SOUTH KOREA

Fig. 2.12 Size of manufacturing industry and natural gas share of energy mix, 1980–2010. Note Data is for share ofgas in primary energy. Source Vivid Economics, based on EIA and World Bank data

2.2 Primary Factors Motivating Switching from Other Fuels to Natural Gas 61

CHINA INDIA

ARGENTINA SOUTH KOREA

Fig. 2.13 Urbanisation and natural gas share of energy mix, 1980–2010. Note Data is for share of gas in primaryenergy. Source Vivid Economics, based on EIA and World Bank data

Relative to coal, gas significantlyreduces SOx, NOx, PM10 andPM2.5, which are the mostharmful air pollutants

~x3,000 more SOx fromcoal relative to gas

Coal more polluting than gas

Coal less polluting than gas

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l of p

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Fig. 2.14 Comparison of pollution resulting from natural gas power generation and from coal power generation, perunit calorific value. Source Formulated by Vivid Economics based on EEA and UNFCCC data

62 2 Developments in Global Natural Gas Consumption

CHINA JAPAN

UNITED KINGDOM POLAND

Pollution limits imposed, with entryof gas in following years

Fig. 2.15 PM10 emission levels and natural gas share of heat and power generation, 1970–2010. Source Formulatedby Vivid Economics based on EEA and UNFCCC data

CHINA UNITED STATES

UNITED KINGDOM POLAND

Fig. 2.16 Relation between power generation, SO2 emission levels and natural gas share of heat and power generation,1970–2010. Source Formulated by Vivid Economics based on EEA and UNFCCC data

2.2 Primary Factors Motivating Switching from Other Fuels to Natural Gas 63

3. Urbanisation and natural gas share areclosely related

Urbanisation is closely related to natural gasusage, and China is now in the early stages ofurbanisation. From Fig. 2.13 it can be seen thaturbanisation and natural gas share are closelyrelated inmany countries. This is very likely due tothe fact that natural gas is particularly well suitedto use as a fuel in urban environments, since it iseasily transported via networks of pipes, its com-bustion is easily controlled and it generates mini-mal atmospheric pollution. This is very importantto an area with a high population density. So far,China does not exhibit this trend in the same wayas other countries, but because China is in the earlystages of urbanisation, greater demand for naturalgas may result as urbanisation progresses.

4. Many countries switch from coal to naturalgas after enacting air quality legislation

Compared to coal, natural gas is a compara-tively clean fuel. For example, when powergeneration with natural gas is compared to powergeneration with coal, natural gas only results insmall amounts of the most harmful air pollutants(Fig. 2.14). Many countries have therefore swit-ched from coal to gas after air quality legislationis introduced.

5. In countries where there are competitivepower markets, the natural gas powergeneration share increases after PM10 re-strictions are put in place

Figure 2.15 shows that in the United Kingdomand Poland, PM10 emissions generated by powergeneration dropped significantly in the year inwhich air quality legislation was introduced.Furthermore, the share of natural gas powergeneration then increased rapidly. This showsthat in the completely competitive power marketsof the United Kingdom and Poland, even thoughefforts were made to restrict PM10 emissions byother courses of action, the cost of coal powergeneration eventually became prohibitive andpower generation began its transition to natural

gas. Figure 2.15 also shows that in Japan, wherethe power generation market is more regulated,the increase in the share of natural gas powergeneration has not lagged behind changes inPM10, though there was also a marked directeffect in the 1970s, which shows that natural gascan be used directly to control atmospheric pol-lution. In China, even though the share of naturalgas power generation is increasing, the totalremains relatively small, and coal power gener-ation’s overwhelming growth suggests that thePM10 levels are set to remain elevated.

Figure 2.16 shows that in the United King-dom, the United States, Poland and other coun-tries, SO2 emission levels improved significantlyafter air quality legislation was enacted. Thedirection taken by changes to SO2 emissions maybe similar to that for PM10 emissions, but the rateof reduction is slower. For coal-fired power sta-tions, compared to satisfying the restrictions onPM10, SO2 restrictions will only be met suc-cessfully if they are adopted at a more gradualpace. In China, the enormous expansion ofcoal-fired power stations means that SO2 levelsare set to remain high.

Many countries have implemented strategies toimprove air quality by switching to natural gas.Analysis reveals that the approaches to imple-menting such strategies differ from country tocountry. Some countries rely on market forces andpollution control measures which force up the costof coal, causing a transition to gas. Other countriesadopt natural gas development planning. Theultimate result of these different approaches tocontrolling air quality is essentially the same, butthe results in terms of controlling atmosphericpollution become apparent at different stages.

2.2.4 Summary

The main conclusions that can be drawn from ouranalysis of the drivers for transition to natural gasare that, in the course of development, anincrease in the size of the service sector, thepressures of urbanisation and an urgent need tocontrol atmospheric pollution result in all coun-tries switching gradually to natural gas. Major

64 2 Developments in Global Natural Gas Consumption

adjustments have been made in Europe, theUnited States and Australia in switching fromcoal to natural gas—and this now also needs tooccur in China. At first glance, these adjustmentsare a result of a growing service sector sharedriving an increase in demand for natural gas, butthere is also evidence that other trends drivedemand for natural gas, such as urbanisation anddemands for cleaner air. These two factors play amajor role in the motivating the transition inmany countries. As urbanisation in China pro-ceeds, an increasing amount of attention is beingpaid to air quality, and this is likely to encouragegreater use of natural gas.

2.3 The Influence of Natural GasPrice on Demand

As well as factors such as service sector growth,urbanisation and air quality controls, natural gasprice also has a direct effect on energy costs, andcan play an important role in affecting demand.This section carries out an in-depth analysis ofthe relationship between natural gas price anddemand. The analysis mainly concentrates on theexperiences of OECD countries, because as theyare the primary natural gas-consuming countries,there is relatively good data available. Further-more, in the majority of cases, these countrieshave liberalised energy price markets, making iteasier to follow the changes in natural gas pric-ing, and easier to analyse the relationshipbetween pricing and demand.

2.3.1 The Relationship BetweenNatural Gas PriceChanges and Changesin Demand in OECDCountries Isnot Pronounced

1. Natural gas demand in OECD countriesgrew rapidly from relatively low levelsbetween 1987 and 2000

Figures 2.17, 2.18, 2.19 and 2.20 show theevolutionary progress of natural gas prices and

the demand of main sectors in the United King-dom, the United States, Japan and Germany.Each point represents data for a year. The coloursof the points represent annual rates of change innatural gas demand. The vertical axis plots thenatural gas price to industry, with pricesexpressed as 2010 PPP (purchasing power parity—that is, including inflation and relative pricechange adjustments). This price thus representschanges in natural gas affordability. There is aclear increase in natural gas prices during theearly 1980s, with a drop in 1987. Since then theyhave remained fairly stable until 2000. Subse-quently, and in particular from 2005 until theGlobal Financial Crisis and the shale natural gasrevolution in the United States, prices have risencontinuously. Although industry sector gas pricesare considered, it seems that they have increasedat the same rate—the price of residential gas ishigher than that used by industry.

Based on the experience of four countries,natural gas prices between 1987 and 2000 werelow and stable and yet, compared to other peri-ods, natural gas demand continued to growrapidly. During this period, the number of yearswhen there was higher growth in sector demandfor natural gas was greater than in the periodwhen the price was higher. For example, Japanand the United Kingdom saw more years withincreased demand during this period than at othertimes (tending towards red on the scale).

2. Natural gas demand rose in many coun-tries when natural gas prices were high

Even though natural gas prices began to risein 2000, in the United Kingdom, Japan andGermany, demand for natural gas remainedconsistently steady or grew. From 2000 to 2008,natural gas prices in OECD countries actuallyrose by 60%. Despite this, during the overlappingperiod of 2000–2012, industrial and residentialnatural gas demand in OECD countries onlydropped by 8%. This indicates that, once demandstabilises, it is capable of withstanding wideeconomic fluctuations. This could be due to thefact that natural gas demand is not sensitive toprice changes (i.e. it is non-elastic), at least in

2.2 Primary Factors Motivating Switching from Other Fuels to Natural Gas 65

terms of residential usage. Moreover, once nat-ural gas is adopted, residents are not willing togive up natural gas for other fuels. As a cleanfuel, allowing controllable heating and with

easily accessible exothermic properties, whennatural gas is compared to other fuel types, suchas coal, it becomes apparent that due to itsindividual properties, as soon as the necessary

1985

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UNITED STATESResidential

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Electricity

Fig. 2.17 Relationship between growth in demand for natural gas and pricing in three sectors in the United States.Source Vivid Economics based on IEA data

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Fig. 2.18 Relationship between growth in demand for natural gas and pricing in three sectors in the United Kingdom.Source Vivid Economics, based on IEA data

66 2 Developments in Global Natural Gas Consumption

1985

Gas price$2010 PPPper MMBtu

Annual percentagechange in sector

gas demand

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Continued increase in gas demand even as prices increase

JAPANIndustrial

Fig. 2.19 Relationship between growth in demand for natural gas and pricing in industry in Japan. Source VividEconomics, based on IEA data

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Residential gas useincreasing fasterthan industrial

GERMANYResidential

Industrial

Fig. 2.20 Relationship between growth in demand for natural gas and pricing in the residential and industrial sectorsin Germany. Source Vivid Economics, based on IEA data

2.3 The Influence of Natural Gas Price on Demand 67

infrastructure is in place, residents and manu-facturers are less concerned about price. Fromthese observations we can see a kind of “ratcheteffect”: once natural gas demand reaches a cer-tain level, the likelihood of switching to anotherenergy source is lower, therefore there is lesslikely to be a reduction in demand. Only scien-tific innovations such as electric heat pumps, thatmay be capable of offering even higher-qualityheat and efficiency, will change the current“non-elastic” state of affairs.

On the whole, during periods when naturalgas prices are rising, increases in demand fornatural gas from manufacturing, residential andpower generation sectors seem to keepstep. Despite a lack of data covering all industriesin all countries, the data that is available showsthat demand for natural gas generally increasesacross the board in all sectors. Although this isnot applicable to the United States, the UnitedKingdom, Japan and Germany, it is still appli-cable to other major natural gas-consumingcountries such as The Netherlands and Spain.

3. No pronounced relationship between sec-tor gas price and demand share

Figure 2.21 shows natural gas PPP price againstoverall demand share in various sectors for OECDcountries in 2012. This shows that there is no pro-nounced relationship between sector gas price and

demand share in each country; although theindustrial sector gas price in someof these countriesis relatively low, the industrial sector gas demandshare in those countries is not necessarily high.

From Fig. 2.21 it is also possible to see that theprice of residential sector gas in OECD countries isrelatively high, with residents willing to pay highergas charges. This could be because residentialnatural gas usage requires the economies of scale,since the transportation and delivery costs aremuchhigher. Practically speaking, there is no pro-nounced relationship between residential demandandgas price, since the primary replacement energysource for residential usage is electricity. Electricityis relatively more expensive, and natural gas ismore convenient. In fact, the high price of naturalgas doesn’t seem to have had a negative impact onresidential demand for natural gas. Over recentyears there has been a greater increase in demandfor gas for residential use than for industrial use inOECD countries.

2.3.2 Limited Effect on Demandof Difference in PriceBetween Natural Gasand Other Energy Sources

Economically speaking, the demand for a partic-ular item is not only determined by its price, butalso by the price of alternatives. This suggests that

0% 10% 20% 30% 40% 50% 60% 70%

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)

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10

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Fig. 2.21 Relationship between sector gas price and share in OECD countries (2012). Source Vivid Economics, basedon IEA data

68 2 Developments in Global Natural Gas Consumption

natural gas demand will also be affected by thedifference in price between natural gas and otherenergy sources.

1. The difference in price between natural gasand electricity in OECD countries has notaffected the demand for gas in the indus-trial and residential sectors

In OECD countries, the natural gas price islower than that of electricity in both residentialand manufacturing sectors. Compared to coun-tries where the price of electricity is lower thanthat of natural gas, natural gas has a slightlyhigher share of primary energy sources, thoughthis effect is still not all that pronounced. Fig-ures 2.22 and 2.23 show the relationshipbetween the pricing of natural gas and electricityin different countries and the natural gas share inthe industrial and residential sectors. The dots inthe diagram represent different countries, whilethe colour of the dots indicates natural gas share.

Figure 2.22 shows the residential sector,while Fig. 2.23 shows the manufacturing sector.These two diagrams demonstrate that pricingcompetition between the residential and

manufacturing sectors has very little influence ondemand for natural gas or electricity.

2. Rate of growth in demand for natural gasin OECD countries was especially rapidduring a period of stable relative energysource prices

From 1987 to 2000, demand for natural gas inOECD countries grew rapidly. However, duringthat period the prices of natural gas, electricityand coal remained relatively stable. Figures 2.24and 2.25 both indicate this situation. For exam-ple, during this period, looking at the actual unitprice of energy in the manufacturing sector, themean gas price was only 22% of the electricityprice, or around one quarter. However, comparedto the price of coal, the price of natural gas wasover three times higher, at around 320%. Whenrelative prices remain stable, the competitivenessof each energy source remains unchanged, andthus demand will not change as a result of pricingcompetition between energy sources. However, itwas under precisely such circumstances thatnatural gas demand nevertheless grew steeply, anindication that factors other than price play a

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NLDESP

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Countries with highershares of gas

Fig. 2.22 Residential gas share and pricing differences between gas and electricity. Note Data is for 2012, electricalunits have been converted from MWh to MMBtu. Source Vivid Economics, based on IEA data

2.3 The Influence of Natural Gas Price on Demand 69

$ pe

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Fig. 2.23 Industrial sector natural gas proportion and variance in natural gas and electricity price. Note Data is for2012, electrical units have been converted from MWh to MMBtu. Source Vivid Economics, based on IEA data

Gasdemand isconstant

Gas demand increasesby 27%

Gas demand decreasesby 8%

0%

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Gas demand increased significantlywhen the competitiveness of gasrelative to electricity was stable

Fig. 2.24 Natural gas and electricity price difference and demand growth. Data source Vivid Economics quoting theIEA

70 2 Developments in Global Natural Gas Consumption

significant role. Another conclusion that can bedrawn is that pricing competition between energysources is not actually all that pronounced.

Among OECD countries, competitionbetween oil and natural gas is only on a smallscale. In OECD countries, natural gas is gener-ally not used as a transportation fuel, so it rarelycompetes with oil. In addition, oil is now lesslikely to be used for power generation in OECDcountries. Due to this, competition between oiland natural gas is not pronounced in thesecountries.

In summary, natural gas demand seems tohave no pronounced relationship to the price ofnatural gas. So, even if the price of natural gas inChina remained high, it is not that likely toreduce demand for gas. Even though in OECDcountries the price of gas is more competitiveand gas has a higher overall share, these coun-tries have not seen an increased demand fornatural gas due to pricing competition betweendifferent energy sources. This is a direct result of

the important non-pricing-related characteristicsof gas. These results show that even though gasprices in China have been high in the past, otherfactors such as urbanisation and atmosphericpollution that are now confronting China willmost likely result in major growth in demand fornatural gas.

2.4 Current State of Natural GasUse in China and Future Trends

2.4.1 Sector Distribution and TotalGas Consumptionin China Since 2000

1. China’s natural gas industry has grownrapidly, but overall share is still low

Due to its relative abundance, coal has alwaysplayed a major role in China’s energy mix—itsshare of total energy consumption has never been

Gasdemand isconstant

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Gas demand decreasesby 8%

0%

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The relative competitiveness of gasversus coal has remained relativelystable over long periods of time Industrial gas prices

increased, then declined rapidly due to the financial crisis

Fig. 2.25 Natural gas and coal price difference and demand growth. Note Natural gas demand is for industrial andresidential usage. The red dotted line is the average level during the same period of time. Data source Vivid Economicsquoting the IEA

2.3 The Influence of Natural Gas Price on Demand 71

less than 65%. After coal, oil is the second mostimportant energy source, accounting for around20% of total energy consumption. Natural gasconsumption is the lowest, with a share notexceeding 6%, and the low amount of cleanenergy in the overall mix is a major deficiency.In 2000, China’s natural gas consumption wasonly 24.5 billion m3, with 2.2% of total energysource consumption. This had risen to106.9 billion m3 by 2010, having tripled in size.However, the total energy source share onlyreached 4.4%. In 2013, China’s natural gasconsumption had reached 166.0 billion m3,accounting for 5.8% of total energy consumption(Fig. 2.26).

By looking at production and consumption,we can arrive at the following conclusions: first,an energy source structure focused on coal andoil will be hard-pressed to achieve fundamentalchange over a long period of time. Second, theimportance of natural gas in China’s energysource system is continually rising, but it is farfrom occupying a central position. To increasenatural gas production and consumption wouldstill require major government policy support.

2. Natural gas is primarily used in manufac-turing, power generation and residential

In terms of sector distribution in China, themanufacturing industry has always been the mainuser of natural gas. In 2000, the manufacturingindustry consumed 11.8 billion m3 of naturalgas, accounting for 48.5% of China’s total nat-ural gas consumption. In 2003, this figurereached 50%, the highest ever. Subsequently, theshare began to decrease, and 2010 consumptionwas 57.3 billion m3 (33.4% of total natural gasconsumption).

Power generation is the sector with the fastestgrowth in natural gas consumption. In 2000, thepower industry consumed 800 million cubicmetres of natural gas, only 3.3% of total naturalgas consumption. By 2006, this had doubled to7.0%, and in 2012 it reached 23.5 billion m3,16.0% of China’s total natural gas consumption.

Transport and residential are two other majorsectors using gas. In 2000, transport and shippingused 880 million m3, accounting for 3.6% oftotal consumption. By 2012, this had risen to15.5 billion m3, or 10.6% of consumption.

0.0

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Fig. 2.26 Chinese energy source consumption structure (%)

72 2 Developments in Global Natural Gas Consumption

Relatively speaking, the residential natural gasconsumption share has been relatively stable. In2000, residential consumption accounted for13.2% of overall consumption, and this had risento 19.7% by 2012 (Fig. 2.27).

3. Compared to other countries, China’snatural gas prices are relatively high

In recent years, China’s natural gas priceshave increased relatively quickly. In the late1980s, China’s natural gas price was relativelylow and stable. However, since 2000 the price ofChina’s imported natural gas has risen, just as ithas in the United Kingdom and Japan, as can beseen in Fig. 2.28. There was a decline in 2008 asa result of the Global Financial Crisis, but the risecontinued after 2009.

Compared to other countries, at the same timeas China experienced rapid growth in demand fornatural gas it also had a relatively high naturalgas price. Figure 2.29 shows rapid growth in

demand for natural gas in OECD countries in the1990s, but at that time prices were relatively low.China now experiences relatively high prices, apronounced characteristic of the development ofnatural gas. In addition, China’s natural gasmarket also exhibits problems, including pricedifferences between users: compared with thesituation elsewhere in the world, in China naturalgas production prices are lower, residential nat-ural gas prices are lower, but natural gas pricesfor industrial use are higher.

2.4.2 Mid- to Long-Term Energyand Natural GasDevelopment Plansin China

In 2013, the State Council published the EnergySource Development 12th Five-Year Plan. InJune 2014, the State Council issued the EnergySource Development Strategy Action Plan

0

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Domestic useOther industriesWholesale, retail, accommodationand catering

Transport, warehousing andpostal servicesConstruction

Power generation, gas and watersupplies and public utilities

ManufacturingMining

Fig. 2.27 Natural gas consumption in China by sector

2.4 Current State of Natural Gas Use in China and Future Trends 73

0

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Fig. 2.28 Natural gas prices in China and other countries. Data source Vivid Economics

Gasdemand isconstant

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Fig. 2.29 Long-term movements in natural gas price and demand in OECD countries

74 2 Developments in Global Natural Gas Consumption

(2014–2020) and in November 2014 China andthe United States published the Sino-AmericanJoint Declaration on Climate Change. Theseimportant documents laid out planning and out-lines for China’s energy source development upto 2030. Based on these documents, China’senergy source development plan includes severalimportant landmark tasks.

1. Overall energy consumption and energysupply capabilities

Prior to updating its energy statistical data,China set objectives for total volume of energydevelopment.

In 2015, China’s energy consumption willreach 4 billion tons of standard coal. By 2020,non-renewable energy consumption will becontrolled at around 4.8 billion tons of standardcoal, with total standard coal consumption con-trolled at around 3.0 billion tons, a drop of62.5% in the proportion of total energyconsumption.

By 2020, a relatively comprehensive energysecurity system will have been established.Domestic non-renewable energy source outputwill have reached 4.2 billion tons of standardcoal, with energy self-sufficiency maintained ataround 85%. In addition, the oil production tostorage ratio will have increased to 14–15. By2020, installed generating capacity of nuclearenergy will have reached 58 GW, with another30 GW of capacity under construction.

2. Energy source structure

By 2015, non-fossil fuel’s share of energysource consumption will have risen to 11.4%,and non-fossil fuel’s share of installed powergeneration capacity will have reached 30%. Thenatural gas primary energy source consumptionshare will have risen to 7.5%, while coal’s shareof consumption will have dropped to around65%. By 2020, non-fossil fuel energy sourceswill account for 15% of primary energy con-sumption, natural gas’s share will have reached10% and coal’s share will be controlled to within62%. Newly added natural gas will be earmarked

to support residential usage and replace dispersedcoal usage, while a programme will be intro-duced to encourage urban residents to adoptclean energy sources. By 2020, urban residentswill essentially be using natural gas. By 2020, anattempt will have been made to ensure thatstandard hydroelectric power reaches around350 million kW of installed capacity, while windpower will reach 200 million kW of installedcapacity. The feed-in price of wind-generatedand coal-generated electricity should be thesame. Photovoltaic installed capacity will reacharound 100 million kW. The price of photo-voltaic electricity should be the same as thepower grid electricity sale price.

By 2020, accumulated newly added provenreserves of conventional gas will be 0.55 tril-lion m3, with annual production of standard nat-ural gas of 185 billion m3. By 2020, shale naturalgas production will aim to exceed 30 billion m3,while coalbed methane production volumes willaim to reach 30 billion m3.

3. Long-term objectives of the Chinesegovernment to be achieved by 2030

In November 2014, during the APEC summit,China and the United States released theirSino-American Joint Declaration on ClimateChange, which revealed the long-term objectivesof China up to 2030. China’s intentions are thatCO2 emissions should peak by around 2030 andwork should be carried out to try to achieve thispeak sooner. Planning outlines include 2030non-fossil fuel energy sources rising to accountfor around 20% of primary energy sourceconsumption.

2.4.3 Mid- to Long-Term Natural GasDevelopment Trendsfor China Basedon InternationalExperiences

Compared to other countries, the share of Chi-na’s current energy source consumptionaccounted for by natural gas is at a relatively low

2.4 Current State of Natural Gas Use in China and Future Trends 75

level. This is partly due to the available naturalresources, but as the economy and societydevelop, the effects of conflicts in supply anddemand and of environmental restrictions onresources in relation to energy consumption willalter. As a result, the overall structure of China’snatural gas consumption will differ from thatseen in the past.

Based on the experiences of seven countrieswith similar natural environments and availabil-ity of natural gas resources, natural gas devel-opment is primarily influenced by growth in theservice sector as a share of economic activity,degree of urbanisation and the urgency of con-trolling atmospheric pollution. Europe, theUnited States and Australia have all made sig-nificant adjustments to allow for the transitionfrom coal to natural gas.

China has a potentially enormous demand fornatural gas. With suitable policies, the natural gasshare of energy consumption will rise consider-ably. As China’s current economic developmententers a “new normal”, especially with the

service sector share already exceeding that ofsecondary industry, and as further urbanisationcontinues to take place, and in recent years muchgreater attention has been paid to air quality, itcan be predicted that China’s natural gas con-sumption will see increasingly rapid growth.

In 2000, China’s natural gas consumption wasonly 24.5 billion m3, accounting for 2.2% oftotal energy consumption. In 2014, China’s nat-ural gas consumption was 183 billion m3, 5.8%of total energy consumption. Looking at thebreakdown of consumption, the manufacturingindustry is showing a declining trend, droppingfrom a high of 50% of total natural gas con-sumption down to 33.4% currently. Power gen-eration has risen from its 2000 share of 3.3% upto the current 16.0%. Transport and residentialusage of natural gas have grown relativelyrapidly, with shares rising from 3.6 and 13.2% in2000 to 10.6 and 19.7% respectively in 2012.Looking at the long term, demand for natural gasin China will continue to show a trend for rapidgrowth.

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76 2 Developments in Global Natural Gas Consumption

3Potential for Natural Gas to Actas a Substitute Fuel in China

Unlike coal and oil, natural gas does not have anexclusive niche. Analysis of international expe-riences has found that growth in natural gasconsumption in other countries has come aboutlargely as a result of substituting gas for otherfuels. It is only substituted for other fuels whenits price is competitive compared to other energysources, incentivising users to adopt it. Thecompetitive forces that drive such changes derivefrom users’ desire to have their requirements forenergy services met while reducing their energysource costs to a minimum.

This section therefore examines the price ofnatural gas that would make it competitive indifferent application sectors, relative to the cur-rently preferred fuel used in that sector.

The primary application sectors for naturalgas are power generation, transport and shipping,urban gas, industrial fuel and natural gas chem-ical engineering. In the power generation sector,natural gas competes primarily with coal. In thetransport and shipping industry, it primarilycompetes with diesel. In the urban fuels gassector, competition in residential usage is

primarily with liquefied gas, artificial gas andelectricity. In the heating and small-scale boilersector, natural gas primarily competes with coal.In the industrial fuel sector, competition is pri-marily with fuel oil, artificial coal gas and coal.In the field of natural gas chemical engineering,competition is mainly with coal and naphtha.This section mostly consists of an analysis ofprice tolerance in these primary markets.

3.1 Power Generation: CostComparison of Gas as aSubstitute for Coal in PowerGeneration

International experiences of development suggestthat power generation is an important sector fornatural gas. Natural gas power generationaccounts for 39.4% of total installed capacity inthe United States and 29% in Japan, whereas thisnumber is only about 3% in China. China’snatural gas power generation therefore has plentyof space to grow. In terms of its specific char-acteristics as a commodity, electricity is a classichomogenised product. Whether it is coal,hydroelectric, gas, wind or photovoltaic power,once it enters the grid, from the point of view ofthe end user it is essentially the same. It is pri-marily cost that affects the competitiveness ofsuch commodities.

* This chapter was overseen by Zhaoyuan Xu from theDevelopment Research Center of the State Council andMartin Haigh from Shell International, withcontributions from Baosheng Zhang and Shouhai Chenfrom the China University of Petroleum, Lianzeng Zhaofrom the China Petroleum Planning Research Institute,Linji Qiao from ENN and Juan Han from Shell China.Other members of the research group participated indiscussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_3

77

3.1.1 Direct Cost ComparisonBetween Gas Generationand Coal Generation

In order to better compare and analyse gas powergeneration competitiveness and other factorsaffecting it, we adopted base-load coal powergeneration as the object of reference. Based on this,coal-fired units rely on the currently widely adop-ted ultra-super critical unit, with an installed scaleof 600,000/1,000,000 kW. For gas-fired units, thewidely adopted 9F-grade CCGT unit was adopted,with an installed scale of 400,000 kW. Coal powergeneration baseline price was set at 550 CNY/ton(price of 5500 kilocalorie power coal delivered topower station), which converts to a standard coalprice of 700 CNY/ton.

1. Coal-fired power generation kWh totalcost calculation

The coal-fired power generation 1 kWh costprimarily includes capital costs, non-fuel opera-tional costs and fuel costs. Referring to nationalenergy department reports and coal-fired powerstation feasibility reports, and supposing that acoal-fired power generating unit operating cycleis 20 years, the discount rate would be 9%.Coal-fired generating units initially require a unitinvestment of 3900 CNY/kW, with annual oper-ating hours of 5000. Therefore, the capital cost of

1 kWh is 0.085 CNY/kWh. Other costs of a kWhcome to around 0.045 CNY/kWh. When theseare combined, the total is 0.13 CNY/kWh, a fig-ure close to the fixed cost of a kWh. As far as fuelcosts are concerned, 300 g of standard power coalis consumed on average, therefore the fuel cost ofa kWh is around 0.21 CNY/kWh. Combiningthese three together, the overall cost of a kWh is0.34 CNY/kWh (see Fig. 3.1).

2. Gas-fired power generation kWh total cost

Combining research data and feasibilityresearch report data, the initial unit investmentfor a gas-fired power unit was established to be3000 CNY/kW. Assuming that annual operatinghours are 3500 h (at peak load and intermediateload), after conversion the capital cost of 1 kWhis 0.094 CNY/kWh. Based on research data,other operating costs for 1 kWh are0.065 CNY/kWh. As regards fuel cost, depend-ing on region and construction date, the price ofgas supplied to power stations can differ signifi-cantly. This report uses south-eastern coastalareas as the main reference region, and adopts aprice of 2.8 CNY/m3 as the basis for calculation.In terms of the gas required to generate 1 kWh,in actual gas-fired generation the differences ingas source result in fuels having differentcalorific values. There is quite a wide variation inthe amount of gas consumed in power

Yuan/kmh

Fuel cost

Coal power Gas 3500 hours Gas 5000 hours

Other fixed costs

Investment costs

0

0.1

0.2

0.3

0.4

0.6

0.7

0.5

0.085

0.045

0.210

0.094

0.065

0.504

0.066

0.046

0.504

Fig. 3.1 Preliminary comparison of coal power generation and natural gas power generation costs

78 3 Potential for Natural Gas to Act as a Substitute Fuel in China

generation. By combining research data, a figurefor gas consumption related to power generationcan be set at 0.18 m3/kWh, which converts to akWh fuel cost of 0.504 CNY/kWh. Combiningthese three together, the overall cost of a kWh is0.663 CNY/kWh. If annual operating hours wereraised to 5000 h, the 1 kWh fixed cost includingcapital costs and non-fuel related operating costswould drop, causing the cost of 1 kWh to bereduced to 0.615 CNY/kWh.

It is apparent from this comparison that, basedon current energy source prices, the 1 kWh costfor gas power generation is still far greater thancoal, regardless of whether 3500-h or 5000-hoperations are concerned. Looking at the directcosts, gas-fired generating units are not compet-itive. Even the fuel cost of gas-fired power gen-eration alone (that is, the variable cost, ormarginal cost) is much higher than totalcoal-fired power generation costs. This makesgas-fired generating units uncompetitive com-pared with coal-fired power generation, even ifone ignores the fixed costs or where fixed costshave been covered by subsidies.

3. Price tolerance calculations for gas-firedpower generation

Without considering changes to other factors,if gas-fired generating units were competitivewith coal-fired power generation, then what levelof gas price would we be talking about? Sensi-tivity analysis shows that when the gas kWh fuelcost is equivalent to the total cost of coal fuel, thenatural gas price would drop to around1.9 CNY/m3, which is equivalent to Europeangas price levels. At this price level, due to theexternal benefits of gas-fired power generation,the fixed cost would attract a subsidy and gaswould become competitive with coal. The sen-sitivity analysis shows that if the total fuel gascost for 1 kWh was required to be the same asthe total cost of 1 kWh generated with coal, thenfor an annual operation of 5000 h, natural gasprices would need to drop to around1.3 CNY/m3, while for 3500 h of operations itwould need to drop to around 1.0 CNY/m3,which is trending closer to US gas prices.

3.1.2 Other Factors Influencingthe Competitivenessof Gas-Fired PowerGeneration

Apart from the actual gas price, there are otherfactors that affect the competitiveness of gas-firedpower generation, including those that have aneffect on the internal costs of gas power gener-ation and its associated external benefits.

1. Localised production of core equipmentfor natural gas power generation

In terms of core equipment, the overseasmonopolies in turbine equipment and processcontrol have led to long-term elevated equipmentcosts, while LTP, operating and maintenancefees are very high. An improvement in this sit-uation would help to reduce the fixed kWh costsfor gas power generation. If unit investmentcould be reduced by 15%, it would also bepossible to reduce the kWh cost by around0.014 CNY/kWh. At the same time, localisationof manufacture would reduce long-term mainte-nance and inspection costs. If overall mainte-nance fees could be reduced by 50%, this wouldalso bring about a reduction in the kWh cost ofaround 0.01 CNY/kWh. By localising the man-ufacture of core equipment, the associated kWhcost could be reduced to a level around the0.024 CNY/kWh mark.

2. Operating hours

By increasing the annual operating hours ofgenerating units, it is possible to reduce the kWhfixed costs that need to be absorbed, therebyreducing gas power generation costs to a certaindegree. However, the benefits of this decreaseprogressively. Based on the configuration data inthis report, and by adopting sensitivity calcula-tions, when generating unit operating times arerespectively increased from 3500 h to 4000, 4500and 5000 h, the respective cost reduction will be0.02, 0.035 and 0.048 CNY/kWh (see Fig. 3.2).

There are many factors restricting natural gasinstallation operating hour increases. The first is a

3.1 Power Generation: Cost Comparison of Gas … 79

-0.09

-0.08

-0.07

-0.06

-0.05

-0.04

-0.03

-0.02

-0.01

0.00 3500 4000 4500 5000 5500 6000 6500 7000

kWh fixed costs variation (Yuan)

kWh fixed costs accumulative variation (Yuan)

Fig. 3.2 Power generation cost analysis

high natural gas price and limited governmentsubsidies, which greatly shorten the hours ofpower generation. Some new generating units thatform part of this research were only capable ofannual power generation of 1000 h. In somelocations, in order to cope with high gas prices, anapproach had been adopted whereby coal-firedpower stations were used as a proxy in powergeneration, but no solution was sought to resolvethe fundamental issue of gas power generationfacilities sitting idle. The second is that insouth-eastern coastal areas, due to the lack ofhydroelectric and other externally generatedpower for use in peak regulation, when majorfluctuations in power demand occur, the effect ofthis is also felt on the operating hours of gas powergeneration. At the same time, frequent starting andstopping of operations also shortens the useful lifeof generating units and increases maintenancecosts, none of which is beneficial to the long-termoperation of gas power generating units.

3. Emissions standards

China has introduced relatively strict emis-sions standards with regard to coal-fired powergeneration. In September 2014, the three com-mittees forming the National Development andReform Commission issued the Coal PowerEnergy Savings and Emissions ReductionsUpgrade and Reconditioning Action Plan (2014–2020), which makes clear pronouncements

concerning strict control over emissions ofatmospheric pollutants and which requires theatmospheric pollutant emissions concentrationsratings of newly built coal-fired generating unitsin eastern regions to conform to the restrictionsapplicable to gas turbine emissions (namely thatwith a baseline oxygen content of 6%, smoke anddust, SO2 and nitrogen oxide concentration maynot exceed 10, 35 and 50 mg/m3). Emissionsratings of newly built coal-fired generating unitsin central regions must approach or achieve therestrictions applied to gas turbine emissions,while emissions ratings of newly built coal-firedgenerating units in western regions are encour-aged to approach or achieve the restrictionsapplied to gas turbine emissions. Apart from theaddition of environmental installations, the plantoperating modes were not changed. With regardto additional investment and the operational costsof such environmental installations, pricing con-versions can be made with reference to theupgrades and modifications applied to the instal-lations of certain current power stations andadditional environmental investment encounteredin new projects. After conversion, it was discov-ered that in order to comply with the strictestemissions standards, coal-fired power generationkWh costs rise by between around 0.01 and0.02 CNY/kWh. Large-scale generating unitcosts increase slightly less, while cost increasesare slightly higher for older and smaller units orwhere coal quality is poorer.

80 3 Potential for Natural Gas to Act as a Substitute Fuel in China

4. Carbon tax

The high carbon emissions of coal powerrepresent an important advantage for gas power.The price of carbon or the level of carbon tax is acritical factor influencing the competitiveness ofgas power costs. Collection of carbon taxes willcause coal power and gas power kWh absolutecosts to both rise. However, because coal powerabsolute cost increases will be greater, the dif-ference in costs will result in the relative cost ofcarbon emissions associated with 1 kWh for coalpower being greater than for gas power. Basedon various energy source emission productcoefficients provided by the Shenzhen CarbonExchange as well as IPCC report coefficients, itis possible to calculate the coal power carbonemissions as 0.8 kg/kWh and gas power carbonemissions as 0.37 kg/kWh. As carbon pricesrises, so does the carbon emission cost for coalpower (Fig. 3.3). Taking as an example theShenzhen Carbon Exchange June 18, 2013online trading opening price of 30 CNY/ton, thetotal increase in the relative cost of coal powerwas around 0.013 CNY/kWh. Taking as anexample the highest price listed on October 18,2013 of 143.99 CNY/ton, this affects the relativecost by around 0.06 CNY/kWh.

5. Auxiliary services

Gas power auxiliary services refer to thesystem value of gas power in terms of adjust-ments during peak periods and as a back-up. Theterm also highlights the advantages of gas powerover coal power as regards energy quality. Cur-rently, with there being no auxiliary servicesmarket and no time-based power pricing mech-anisms, capacity pricing based on a two-tierelectricity price would take advantage of thebenefits of auxiliary services. The determinationof the capacity electricity price takes into con-sideration all aspects covered by gas power fixedcosts, and can also be understood as includingthe additional investment in power capacityrequired to guarantee the reliability and stabilityof power supplies. Shanghai currently has powerstations that implement a two-tier system forelectricity pricing, with a gas power capacityprice of 45.83 CNY/kW/month. In large citiessuch as Shanghai, Beijing and Shenzhen, where atwo-tier system has been implemented, theindustrial power price is between 40–44 CNY/kW/month. In overall terms, the influ-ence of auxiliary services on competitiveness isfairly small.

Coal power emissions relative cost Yuan/kWh

Carbon cost Yuan/ton

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

20 40 60 80 100 120 140 160 180 200 220 240 260 280 300

Fig. 3.3 Coal power emissions relative cost (CNY/kWh)

3.1 Power Generation: Cost Comparison of Gas … 81

3.1.3 Conclusions Regardingthe Prospects of GasReplacing Coal in PowerGeneration

Natural gas power generation competitiveness isdetermined by various relative costs. Here, thecoal price adopted is 550 CNY/ton. Based on theoverall trends in coal prices since 2014, this isunlikely to increase in the short term. Regardingthe natural gas price, considering that natural gaswill gradually form a globalised market, withrelatively large amounts of natural gas beingimported by China, China’s natural gas price willbe inseparable from international gas prices. Asthings stand, increased marginal supply affectingthe international natural gas market primarilycomes from North American LNG, while EastAsia is mainly responsible for marginal increasesin consumption. Therefore, North Americannatural gas prices will have the greatest influenceon LNG prices in East Asia. In fact, the biggestinfluence will be felt in China’s south-easterncoastal regions, where there has been the greatestgrowth in natural gas power generation. Sum-marising forecast data from various researchinstitutions, assuming a future US Henry Hubnatural gas price of 5 $/MMBtu, total LNGtransportation fees of 5 $/MMBtu and a CIFprice in China of 10 $/MMBtu, it would benecessary to reduce or exempt import duty onLNG. At the same time, for large power plantusers near LNG receiving stations, the gasreception and piping costs can be estimated at0.2 CNY/m3. This would result in the price ofnatural gas delivered to the power plant being2.39 CNY, which can be converted to a kWhcost of 0.43 CNY/kWh.

1. Comprehensive cost comparison for baseloading power generation

For a base loading generating unit (5000 h),the fuel cost based on an international gas priceof 5 $/MMBtu would be 0.43 CNY/kWh, givinga kWh total cost of 0.541 CNY. By introducinglocalisation of equipment manufacturing, itwould be possible to reduce kWh costs by0.024 CNY. By increasing annual use to 6000 h,

costs could be reduced by 0.0185 CNY/kWh,reducing the kWh cost of gas power to0.499 CNY/kWh. After the cost of emissionstreatment has been applied to coal, the cost is stillonly 0.36 CNY/kWh. If the carbon tax price is120 CNY/ton, then the cost of coal power wouldrise by 0.05 CNY/kWh, reaching an overall costof 0.41 CNY/kWh. Therefore, gas power costswould still be higher than coal power by around0.088 CNY/kWh. As a result of this, gas powerwould not be competitive in China.

2. General cost comparison of peak regulation

When gas-fired peak regulation (annual oper-ation of 3500 h) is compared to base loadingpower generation, the greatest difference is that itallows the advantages of auxiliary generationservices to be exploited. For example, by adopt-ing capacity power pricing, once localised man-ufacturing has been taken intoaccount, the compensatory level is around39 CNY/kW/month, which converts to an elec-tricity price of 0.134 CNY/kWh. At the sametime, if coal power emissions standards were verystrict, the additional pollution processing costswould rise by 0.02 CNY/kWh. Coal power kWhtotal costs would rise from 0.34 CNY/kWh to0.36 CNY/kWh. If the carbon tax rate was 120CNY/ton, then coal power costs would rise by afurther 0.05 CNY/kWh. This would result in totalcoal power costs of 0.41 CNY/kWh, while thegas power total cost would be 0.43 CNY/kWh.Unless the carbon tax price is increased further, orgovernment subsidies are increased, gas powerwill continue to lack a competitive advantage.

In overall terms, gas power lacks competi-tiveness with coal, not only at current gas pricelevels and in the current market environment, buteven when the CIF price of international LNG isat the $10 levels, under which circumstances gaspower would still need a series of combinedmeasures in order to achieve market competi-tiveness. Due to this, for a market to arise wheregas power was able to develop would not onlyrequire changes in the global natural gas market,but also require the implementation of a series ofwider-reaching policy measures. This wouldinclude providing encouragement for major

82 3 Potential for Natural Gas to Act as a Substitute Fuel in China

scientific breakthroughs, gaining control over gaspricing mechanisms, streamlining the adminis-tration of the natural gas industry, the creation ofliberalised gas and electricity pricing mecha-nisms and the internalisation of environmentalcosts and effects, particularly in terms of sensiblecarbon emissions pricing. Only then wouldgrowth in gas power generation become possible.

3.2 Transport: Analysis of NaturalGas as a Substitute for Diesel

Starting in the 1930s, when Italy promoted usageof natural gas in cars due to the petrol shortage atthat time, there have been over 70 years of his-tory of gas being used as vehicle fuel. However,transport is different from power generation inthat its use in transport relies to some extent onuser perception, energy source availability andtransportation safety, while also being affectedby external networks. The replacement of dieselby natural gas in the field of transportation wouldrequire system-wide adjustments and involve arelatively complex process.

3.2.1 Primary Motivators for NaturalGas to Replace Diesel

Looking at the development history of naturalgas vehicles, safety, cleanliness and economyhave all been primary motivators in promotingthe development of natural gas cars. After the1973 oil crisis, national worries about the safetyof oil supplies resulted in greater attention beingpaid to the development of natural gas cars. Inthe 1980s, urban air quality problems resultingfrom vehicle exhaust pollution attracted increas-ing attention in Europe and North America, whilethe fact that levels of gas and emissions weremuch lower than petrol or diesel led to westerncountries, led by Italy, paying more attention tothe promotion of natural gas cars. However,since the 1990s, as oil product quality andemissions control technology have improved,petrol and diesel vehicle pollution emissionshave been greatly reduced and the advantages of

natural gas in terms of cleanliness are no longerso pronounced. The pace of development ofnatural gas-powered vehicles in Europe andNorth America has now slowed. At the sametime, up until around 2005, as international oilprices rose, the economic attraction of natural gasbecame more pronounced, and there was a rapidgrowth in the use of natural gas-powered cars indeveloping countries with relatively abundantgas resources.

Currently, in developed countries, oil suppliesare relatively stable and there are fairly good oilreserves. Unless a major incident occurs, oilsecurity has long since stopped being a drivingfactor for the development of natural gas vehi-cles. Moreover, with advances in engine tech-nology, the advantages of natural gas cars asregards cleanliness have been reduced, reducinginterest in the development of natural gas cars indeveloped countries. As regards economic fac-tors, the energy consumption cost expenditure ofEuropean and North American users is relativelylow, with more attention being paid to the driv-ing experience, therefore without enhancedpolicies to drive forward the transition, the dif-ference in price between diesel and gas wouldhave no effect in terms of encouraging users toswitch.

These factors exist to some extent in China aswell, and in particular cleanliness and economystill play a major role in the rapid developmentand adoption of natural gas-powered vehicles. Interms of cleanliness, natural gas has the advan-tage of having a single component ingredient,allowing the easy removal of impurities, inaddition to being of stable quality and havingexcellent physical characteristics, making it easierto improve cleanliness and meet emissionsrequirements. Of course, in developed countries,where oil quality is satisfactory and emissionscontrol technologies are in place, petrol and dieselvehicles can meet the emissions levels of naturalgas vehicles. Aside from this, vehicle emissionscontrol requires the integration of fuel processing,engines controls, exhaust handling and otherrelated technological systems and appropriatelyenhanced emissions standards. In China, due tothe supply network and its locked-in nature, high

3.1 Power Generation: Cost Comparison of Gas … 83

levels of new investment in systems improve-ments and upgrades with a long-term strategywould be necessary to resolve problems relatingto crude oil quality, refining processes, the vehi-cle industry and industrial standards that currentlyexist; natural gas, however, offers many advan-tages due to its cleanliness, as well as a goodtolerance towards it in petrol engines, so itsadoption would show quicker results in terms ofenvironmental requirements.

The fact that China is a developing countrymeans that economical fuel is still a major driverbehind the development of natural gas as atransportation fuel. Fuel costs account for around40% of operating costs, so reducing fuel costs is amajor factor in making transport businesses morecompetitive. In the past few years, the significantdifference in the price of diesel and gas andexemption from consumer taxes has resulted inthe rapid development of natural gas vehicles inChina. Taking CNG in taxis as an example, for aperiod of time the CNG price was just half that ofpetrol, meaning that the conversion cost could berecovered within a few months, resulting in rapidgrowth in the market for CNG in cars.

3.2.2 Natural Gas Oil ReplacementPrice Tolerance in theUrban Transport Sector

1. Taxi natural gas petrol replacement pricetolerance

Urban CNG taxis and public transport arecurrently the largest markets for natural gas. CNG

taxis are mainly being adopted in second- andthird-tier cities, as well as in first-tier cities wherenatural gas was introduced relatively early, suchas the cities in the Sichuan-Chongqing basin andin Chengdu. In some cities, adoption of naturalgas fuel is almost universal. However, after rapiddevelopment in the past, this market has slowedin recent years. In first-tier cities where taxis didnot invest in CNG early on, the high demand forland for urban development has made it difficultto site natural gas filling stations, which restrictsthe development of CNG taxis.

City taxis can use CNG to replace petrol, thecost of taxi conversion being around CNY 5000.Based on average distances travelled of100,000 km, and the cost of conversion beingabsorbed over a year, the conversion cost is5 CNY/100 km. The price tolerance of gas usedas a replacement, based on the running costs forgas taxis being the same as for petrol taxis, is5.58 CNY/m3 for an international crude oil priceof 100 $/bbl, and 4.34 CNY/m3 when the inter-national crude oil price is 60 $/bbl (Table 3.1).

2. Bus natural gas diesel replacement pricetolerance

Urban public transport is also an importantsubmarket for CNG and LNG applications.Because public transport companies normallyhave their own bus stations, it is possible forthem to construct LNG/CNG stations even infirst-tier cities. As a result, there is greaterpotential for development.

Urban public transport vehicles can use CNGto replace diesel, and vehicle conversion costsaround CNY 12,000. Basing calculations on

Table 3.1 Taxi price tolerance of natural gas as replacement for petrol

International priceof crude oil ($/bbl)

Petrol Fuel cost(CNY/100 km)

Natural gas

Price(CNY/L)

Oilconsumption(L/100 km)

Gasconsumption(m3/100 km)

Conversioncost(CNY/100 km)

Pricetolerance(CNY/m3)

100 6.77 8 54 8.8 5 5.58

80 6.08 49 4.96

60 5.39 43 4.34

Data source Results of calculation

84 3 Potential for Natural Gas to Act as a Substitute Fuel in China

recovering the cost of conversion over a year,with a distance travelled of 80,000 km, the cost isthe equivalent of an additional 15 CNY/100 km.The price tolerance of gas used as a replacement,based on the running costs for gas buses being thesame as for diesel buses, is 5.80 CNY/m3 whenthe international crude oil price is 100 $/bbl, and4.28 CNY/m3 when the international crude oilprice is 60 $/bbl (Table 3.2).

CNG private cars and light commercial vehi-cles also account for a share of the market, pri-marily concentrated in second- and third-tiercities where natural gas taxis are relatively welldeveloped. Private cars are normally relativelyeconomical low-end compact cars, such as thosecosting less than CNY 100,000. In the next10 years, the market will remain relatively stable,and as income levels rise, new users will con-tinue to enter the economy car market. However,at the same time, some of the original economyvehicle users will upgrade to mid-range andhigh-end vehicles. As for penetration of electricprivate vehicles, it is mainly in first-tier citiesaffected by vehicle policies, and especially incities where license plate restrictions are in place,that there is a considerable variance in terms ofmarket share when compared to CNG privatevehicles, and as far as overall numbers go, thisdoes not represent a major influence on the CNGprivate vehicle market at the present time. Therehas been relatively rapid growth in light com-mercial vehicles in the past two years, butnumbers still remain low, as conversion of dieselengines presents problems, resulting in lowlevels of interest and indicating minimal marketgrowth in the future.

3.2.3 Commercial Vehicle Natural GasDiesel Replacement PriceTolerance

The commercial vehicle LNG market is the sub-market with the greatest growth, and is primarilycomposed of heavy lorries, inter-city buses,medium-sized lorries, works vehicles and othervehicles. In terms of economic incentives ormarket scale, heavy lorries are the applicationmarket with the greatest growth potential. More-over, long-distance inter-city buses, if travellingover 400 km, also have a marked economiceffect, but are affected in turn by the rapiddevelopment of high-speed rail and the quicknessof air travel. It is expected that this market willtend to shrink. However, medium-sized lorries,works vehicles and other vehicles only makeeconomic sense in regions where gas sources arerelatively inexpensive, due to their relatively lowfuel consumption. Since 2011, there has been arapid increase in the construction of LNG fillingstations, and the expectation is that by 2020 fillingstation coverage will include major ports, indus-trial parks and main logistics routes. Moreover, asnetworks are optimised, the growth in numbers ofLNG vehicles will outrun the increase in LNGfilling stations, resulting in increased operationalefficiency and profitability of LNG filling sta-tions, and the emergence of a self-sustainingcycle in this industry.

We calculated the commercial vehicle pricetolerance taking inter-city long-distance heavylorries as an example. Inter-city long-distancelorries can use liquefied natural gas (LNG) insteadof diesel. The purchase price of LNG vehicles is

Table 3.2 Bus price tolerance of natural gas as replacement for diesel

International price ofcrude oil ($/bbl)

Diesel Fuel cost(CNY/km)

Natural gas

Price(CNY/L)

Oilconsumption(L/100 km)

Gasconsumption(m3/100 km)

Conversioncost (CNY/L)

Pricetolerance(CNY/m3)

100 6.72 35 235 38 15 5.80

80 5.90 206 5.04

60 5.08 178 4.28

Data source Results of calculation

3.2 Transport: Analysis of Natural Gas as … 85

higher by roughly CNY 90,000 than that of dieselvehicles. Basing calculations on annual travel of100,000 km, and recovering the cost of conver-sion over 50% of the vehicle scrapping distance,the calculated cost is the equivalent of an addi-tional 45 (37.5) CNY/100 km. The price toler-ance of gas used as a replacement for diesel, basedon the running costs for gas commercial vehiclesbeing the same as for diesel commercial vehicles,is 5.15 CNY/m3 when the international crude oilprice is 100 $/bbl, and 3.67 CNY/m3 when theinternational crude oil price is 60 $/bbl(Table 3.3).

3.2.4 Ship Transport Natural GasDiesel Replacement PriceTolerance

Waterborne transport relying on LNG is a sub-market that is just starting to develop. Shipsconsume considerable amounts of fuel, andshipping routes are relatively fixed and generallylinear in their distribution. There are low externalrequirements for filling station networks, andwith mature technology and commercial models,rapid development is likely. Currently, ship fuelsare divided into light oil and heavy oil. Becauseheavy oil prices are low, LNG is not competitive.The main market for LNG is as a replacement forlight oil. Light oil use is primarily concentratedin interior river systems and used in river trans-port, dredging and works vessels, as well asbeing used by some coastal fishing boats. Interiorriver goods vessels have stable annual oil con-sumption, have fixed routes and can normally fill

up at service areas. There are not that manydredgers, but they have high fuel consumption,refill frequently, have stable fuel consumptionand have relatively dense concentrations, makingit possible to construct dedicated filling stations.These two types of user are submarkets thatcould be reasonably easily developed. Eventhough coastal fishing boats are numerous, theyare affected by factors such as the fishing seasonand have some seasonal variances with non-fixedroutes and irregular operation, accompanied byrapid deterioration, therefore short-term devel-opment will be slow. Currently, LNG shippingapplications are being promoted heavily bycentral and local government. Because singleunit fuel consumption is considerable, economyof scale is particularly pronounced. Compared toconstructing an LNG filling station network,adding filling stations along shipping routes ismuch simpler and more convenient. Once con-ditions develop, this market will easily pick up,and it requires only a short development cycle.

Price tolerance for shipping to use LNGinstead of oil is relatively high. Basing calcula-tions on a 2000 ton grade dual-fuel (30% die-sel + 70% LNG) powered ship, the conversioncost is CNY 750,000. Based on 10 journeys peryear, each voyage being 1250 km, and offsettingthe conversion costs over 5 years of voyages, theconversion cost works out at 1200 CNY/100 km.The price tolerance of gas used as a replacementfor diesel, based on the running costs forgas-powered vessels being the same as for dieselvessels, is 4.96 CNY/m3 when the internationalcrude oil price is 100 $/bbl, and the price toler-ance is 3.47 CNY/m3 when the international

Table 3.3 Transport lorry price tolerance of natural gas as replacement for diesel

Internationalprice of crude oil($/bbl)

Diesel Fuel cost(CNY/100 km)

Natural gas

Price(CNY/L)

Oilconsumption(L/100 km)

Gasconsumption(m3/100 km)

Price(CNY/L)

Pricetolerance(CNY/m3)

100 6.72 45 302 50 45 5.15

80 5.90 265 4.41

60 5.08 229 3.67

Data source Results of calculation

86 3 Potential for Natural Gas to Act as a Substitute Fuel in China

crude oil price is 60 $/bbl. Pricing parity fornatural gas versus diesel is around 0.70(Table 3.4).

3.2.5 General Factorsin the TransportationMarket Relating to GasReplacement of Diesel

Even though natural gas is currently the mostrealistic alternative transportation fuel, and itsclean, low-carbon and economical qualities meanthat it has great potential in China, the realisationof this presents many challenges. In addition toeconomy, factors affecting the switch from oil tonatural gas include natural gas supply, develop-ment of natural gas transport modes, natural gasfilling stations, consumer expectations and thedevelopment of electrically powered cars.

1. Assurances related to natural gasand transportation usage

In terms of natural gas fuel, users primarilyfocus on assurances concerning gas supplies,price and quality. Currently, as transitions takeplace in the layout of global natural gas suppliesand demand, and China’s natural gas suppliesdiversify, it can be expected that natural gassupplies will be fully guaranteed in the future. Itis therefore to be expected that concerns aboutnatural gas supply guarantees will no longer playa major role. Natural gas prices, pricing mecha-nisms and price development trends play a moresignificant role. In terms of quality, unlike in

power generation, consumers focus more on thecalorific value of natural gas.

2. Extent of deployment of natural gas fillingstations

The extent of deployment of natural gas fillingstations is an important factor affecting the con-venience of vehicle operation. Transportation isaffected by network externalities, and as morefilling stations come on line, this will attract newusers and create wider network benefits. Thiswill, in turn, increase the value of new andexisting filling stations, creating a virtuous circlethat increases the use of gas in transport.

3. Development of natural gas transportation

Transportation using natural gas currentlyincludes CNG vehicles, LNG vehicles and LNGshipping, and involves manufacturing or con-version, operation, maintenance and scrapping.CNG vehicles are primarily compact cars, lightgoods vehicles and buses. Because CNG andpetrol both use a combustion engine, the manu-facture, conversion and maintenance processesare simple. Currently the main problem encoun-tered is that public transport departments areworried that converted vehicles present a safetyhazard. LNG vehicles are primarily used asheavy lorries, light commercial vehicles,inter-city passenger vehicles and in otherlong-distance uses where vehicles consume largequantities of fuel. They can also be used inmining, engineering and other sectors. Vehicleconversion requires return to the factory, but the

Table 3.4 Shipping price tolerance of natural gas as replacement for diesel

Internationalprice of crude oil($/bbl)

Diesel Fuel cost(CNY/100 km)

Natural gas

Price(CNY/L)

Oilconsumption(L/100 km)

Gasconsumption(m3/100 km)

Price(CNY/L)

Pricetolerance(CNY/m3)

100 6.72 950 6384 1045 1200 4.96

80 5.90 5605 4.21

60 5.08 4825 3.47

Data source Results of calculation

3.2 Transport: Analysis of Natural Gas as … 87

technology is mature. The cost of switching fromdiesel to LNG is relatively high due to the smallscale on which it occurs. In addition, LNGvehicle repair shops are few and far between. If amalfunction occurs, it is often necessary to returnthe vehicle to the factory for repair, resulting ininconvenience and financial losses being incur-red by the user. LNG ships are currently in thetrial adoption stage. Depending on the type ofcombustion engine that vessels rely on, conver-sion to LNG may require a return to the factoryin order to convert the engine to the spark igni-tion type. Alternatively, conversion may be to amixed diesel/LNG type engine, and appropriateconversion schemes still require improvementthrough further trials.

4. User perception also influences replace-ment of oil-based fuels with natural gas

User perception is the subjective experienceof the user relating to the use of natural gas intransportation, and this has an important influ-ence on the development of natural gas trans-portation and in the analysis of submarkets. Userperception includes three aspects: performance,user sensitivity and usage environment.

In terms of performance, natural gas vehiclesvary somewhat from petrol vehicles. Comparedto petrol, the burn rate of natural gas is slower,the theoretical highest burn temperature is lower,and the amount of air required during the burnprocess is greater. At the same time, to accom-modate burning of both fuels, the engine is oftennot configured to the optimal state to use naturalgas. These factors each influence the drive outputof natural gas engines, fuel efficiency and otheraspects. In terms of user sensitivity, this involvesfuel economy, power output, usage space, con-venience and many other factors. For example,commercial vehicles focus more on economy andfactors related to economy, whereas privatevehicles focus more on output, usage space,cleanliness etc. In terms of usage environment,electric cars have also been labelled as innova-tive, technologically advanced, fashionable andenvironmentally friendly alternatives to both gasand petrol vehicles, whereas gas-fuelled private

vehicles tend to have an image of being moreaffordable.

5. Other threats posed by replacementwith electric cars

Compared to natural gas vehicles, electric carsoffer some competitive advantages, and thereforecould present fierce competition to natural gasvehicles. First, electric motor efficiency is inher-ently higher than that of the internal combustionengine, there being less mechanical wear in theelectric car drive mechanism; as a result of this, lessenergy is consumed than with internal combustionengine cars. Moreover, electric motors emit essen-tially zero emissions. Second, in terms of output andperformance, output in electric cars can beincreased through simple changes to voltage, cur-rent and frequency. Their structure is more com-pact, while they have a flexible driving dynamic.Finally, in terms of economy, even though currentpurchase costs are high, they become more eco-nomical as driving distance increases.

Currently, the greatest obstacle to the devel-opment of electric vehicles comes from insuffi-cient battery recharging facilities, in addition towhich battery costs are high and there are chal-lenges when it comes to extending voyage dis-tances. The potential threat that electric cars poseto natural gas-powered cars and the space theirdevelopment occupies depends on the techno-logical development of electric vehicles, and thespeed at which battery exchange and chargingfacilities can be extended.

3.2.6 Potential Prospectsfor Transportation MarketNatural Gas Demand

In 2013, natural gas vehicles used around12 billion m3 nationally. Of this, CNG vehiclesused around 10 billion m3, and LNG vehiclesused 2 billion m3. Because natural gas is still themost practical alternative fuel for transportationcompared to other alternative fuels, it has a rel-atively large potential for development.

88 3 Potential for Natural Gas to Act as a Substitute Fuel in China

Looking at the larger picture, markets forvehicles using CNG will gradually enter a periodof slower development, with expectations thatthis growth will be slightly higher or equivalentto natural gas consumption market growth rates.By 2020, consumption will reach 20 billion m3,and by 2025 it will reach 25 billion m3, afterwhich growth will stagnate.

LNG vehicle markets in the next 10 years willmaintain high rates of growth, with expectationsthat in 2020 vehicular use of LNG will exceed20 billion m3. By 2030, that number is expectedto reach 40 billion m3.

Shipping LNG is also an important potentialmarket, but conversion schemes and commercialmodels have yet to be further optimised. More-over, interior river system markets using light oilonly have small capacity, whereas coastal ship-ping still depends on the degree of implementationof environmental policy. Early development istherefore expected to be slow, with later devel-opment depending on changes in environmentalprotection policies. Optimistic projections for shipusage of LNG envisage usage exceeding 2 bil-lion m3 by 2020, and over 10 billion m3 by 2030.

3.3 Urban Use: Assessment of PriceTolerance for Natural Gasto Replace Other Fuels

3.3.1 Price Tolerance is RelativelyHigh for ResidentialUsage of Natural Gas

Urban residential usage of natural gas is pri-marily for cooking, hot water and heating sys-tems. Gas use indices are affected largely bylifestyle, infrastructure and price. Based on cal-culations in the Urban and Rural ConstructionStatistical Yearbook 2012, per capita natural gasusage across China in 2012 was 73 m3. How-ever, in regions such as Sichuan and Chongqing,where there are more abundant resources, theprice is lower, and where urban introductionoccurred early on, this figure reaches 120 m3. Inmajor cities there is a high quality of life required

and they exhibit a higher range of 70–80 m3.Other cities generally have a range of 50–60 m3.

Residential options for energy sources includeelectricity, bottled liquefied gas and natural gas.Therefore, natural gas, liquefied gas and electricitycompete to replace each other in urban residentialusage. Since electricity replaced coal, urban resi-dential usage of natural gas has an indirect rela-tionship of acting as a substitute for coal.

1. Price tolerance for natural gas to replaceliquefied gas

Liquefied gas is a by-product of the oilrefining process, and its price is very muchrelated to the price of crude oil. When theinternational price of crude oil is 100 $/bbl,household bottled liquefied gas costs8.23 CNY/kg, and when the international priceof crude oil is 60 $/bbl, household bottled liq-uefied gas costs 6.64 CNY/kg.

The heat efficiency of urban residential pipednatural gas and bottled liquefied gas is around60%. Basing calculations on the principle ofequivalent effective calorific value costs, theprice tolerance for natural gas as a replacementfor liquefied gas can be calculated as5.62 CNY/m3 when the international price ofcrude oil is 100 $/bbl and 4.54 CNY/m3 whenthe international price of crude oil is 60 $/bbl(Table 3.5).

2. Price tolerance for natural gas to replaceelectricity

Electricity is a clean and efficient householdenergy source. When natural gas prices are notcompetitive with those of electricity, residents willswitch to using electrical appliances, for exampleswitching from a natural gas hot water heater to anelectrical hot water heater. Based on the availableinformation, residential natural gas heat efficiencyis around 75%, whereas electric hot water heatefficiency is around 98%. Calculating the pricetolerance of natural gas to replace electricity basedon the principle of equivalent effective calorificvalue cost, with current residential electricity

3.2 Transport: Analysis of Natural Gas as … 89

prices being 0.40–0.60 CNY/kWh, natural gasprice tolerance as a replacement for electricity is2.92–4.38 CNY/m3 (Table 3.6).

3. Natural gas price tolerance in terms ofdisposable income of urban residents

Compared to liquefied gas, natural gas isconvenient, does not require bottling or transportand avoids the inconvenience of frequentreplacement. It is symbolic of quality of life, andthus even if natural gas use has a higher cost thanliquefied gas, residents will still opt to use natural

gas, so long as the cost is within the range tol-erable to their income level.

According to Price Law, residential use nat-ural gas is a public commodity and is included inthe scope of government price setting. Govern-ment procedures must be followed, and the mostimportant factor from the point of view of gov-ernment price setting is the disposable incomelevel of urban residents. A level of average res-idential usage of 3% of the disposable income oflow-income residents is used as a reference,resulting in an acceptable residential natural gasprice of 5.7 CNY/m3 (Table 3.7).

Table 3.5 Price tolerance for residential usage natural gas replacement of liquefied gas

Internationalcrude oilprice ($/bbl)

Small bottle liquefied gas Effectivecalorificvalue cost(CNY/GJ)

Natural gas

Price(CNY/kg)

Calorificvalue(MJ/kg)

Calorificefficiency

Calorificefficiency

Calorificvalue(MJ/m3)

Pricetolerance(CNY/m3)

100 8.23 50.25 60% 273 60% 34.34 5.62

80 7.43 246 5.08

60 6.64 220 4.54

Data source Results of calculation

Table 3.6 Price tolerance for residential usage natural gas replacement of electricity

Residential electricity Effective calorificvalue cost(CNY/GJ)

Natural gas

Price(CNY/kWh)

Calorificvalue(MJ/kWh)

Calorificefficiency

Calorificefficiency

Calorificvalue(MJ/m3)

Pricetolerance(CNY/m3)

0.6 3.60 98% 170 75% 34.34 4.38

0.5 142 3.65

0.4 113 2.92

Data source Results of calculation

Table 3.7 Residential disposable income price tolerance for natural gas

Income group Per-capita disposableincome (CNY/year)

Upper limit of residentialfuel expenditure (CNY/year)

Resident averagegas usage (m3/year)

Acceptable naturalgas price (CNY/m3)

High income 56,389 1692 60 28.2

Mid- to highincome

32,415 972 16.2

Middle income 24,518 736 12.3

Mid- to lowincome

18,483 554 9.2

Low income 11,434 343 5.7

Data source Results of calculation

90 3 Potential for Natural Gas to Act as a Substitute Fuel in China

3.3.2 Price Tolerance is also QuiteResilient in CommercialService Natural Gas Use

Commercial service natural gas users primarilyinclude airports, government institutions,employee canteens, kindergartens, schools,hotels, restaurants, the catering industry, shop-ping centres and office buildings. Individual unitusage is far higher than that of residential users,with usage primarily for cooking and for coolingand heating systems. Alternatives include lique-fied gas and electricity.

1. Price tolerance of natural gas replacingliquefied gas

Unlike residential users of liquefied gas,commercial service users generally use largetanks of liquefied gas, the price of which is lowerthan that of the smaller bottles of liquefied gasused residentially. Basing calculations on theprinciple of equivalent effective calorific valuecosts, the price tolerance for natural gas replacingliquefied gas can be calculated as 5.34 CNY/m3

when the international price of crude oil is

100 $/bbl and 4.31 CNY/m3 when the interna-tional price of crude oil is 60 $/bbl (Table 3.8).

2. Price tolerance of natural gas replacingelectricity

Among commercial service and institutionalusers, there is a competitive alternative relation-ship between natural gas and electricity in thepromotion of natural gas direct combustion airconditioning units (Table 3.9). Basing calcula-tions on the principle of equivalent effectivecalorific value costs, the price tolerance for nat-ural gas replacing electricity can be calculated as4.52 CNY/m3 when the international price ofcrude oil is 100 $/bbl and 3.01 CNY/m3 whenthe international price of crude oil is 60 $/bbl.

3.3.3 Price Tolerance is Weakfor Centralised UrbanHeating Using Natural Gas

China’s centralised heating is primarily focused inthe northern regions. The traditional areas relyingonwinter season heating are the three north-eastern

Table 3.8 Price tolerance for commercial service usage of natural gas as replacement for liquefied gas

Internationalcrude oilprice ($/bbl)

Large tank liquefied gas Effectivecalorificvalue cost(CNY/GJ)

Natural gas

Price(CNY/kg)

Calorificvalue(MJ/kg)

Calorificefficiency

Calorificefficiency

Calorificvalue(MJ/m3)

Pricetolerance(CNY/m3)

100 7.82 50.25 50% 311 50% 34.34 5.34

80 7.06 281 4.82

60 6.31 251 4.31

Data source Results of calculation

Table 3.9 Price tolerance for commercial service usage of natural gas as a replacement for electricity

Commercial usage of electricity Effectivecalorific valuecost (CNY/GJ)

Natural gas

Price(CNY/kWh)

Calorificvalue(MJ/kWh)

Conversionefficiency

Conversioncost(CNY/GJ)

Conversioncost(CNY/GJ)

Conversionefficiency

Calorificvalue(MJ/m3)

Pricetolerance(CNY/m3)

0.6 3.60 95% 300 475 320 75% 34.34 4.00

0.5 446 3.25

0.4 417 2.50

Data source Results of calculation

3.3 Urban Use: Assessment of Price Tolerance for … 91

provinces, five north-western provinces, five northChina provinces and Shandong and Henan, givinga total of 15 provinces (regions, cities), most ofwhich rely on coal-fired boilers. Conversion fromcoal to natural gas has been carried out based onlocal environmental policy requirements. Basingcalculations on the equivalent unit cost per heatedarea, when the coal price is 600 CNY/ton, naturalgas price tolerance as a replacement for coal is1.75 CNY/m3 (Table 3.10).

3.4 Industrial Use: Cost Comparisonof Natural Gas Replacing OtherEnergy Sources

Natural gas as an industrial fuel is primarily usedin smelting furnaces, heating furnaces, hottreatment furnaces, roasting furnaces, dryingfurnaces and other industrial furnaces (construc-tion materials, electromechanical, metals andother industries) and industrial furnaces used togenerate steam for process requirements, and isused to replace fuel oil, coal gas and coal.

3.4.1 Price Tolerance is Very Lowfor Replacement of FuelOil by Natural Gasin the Glass Industry

Glass is primarily divided into flat panel glassand special type glass. Flat panel glass is dividedinto general flat panel glass and floating glass.The general process for the production of glassis: raw material–melting–forming–cooling–cut-ting–packing–placement into inventory–sale.Natural gas is primarily used at the melting stage,the main natural gas-consuming equipment beinga glass furnace. Based on glass raw materialmelting principles, glass enterprises generally usehigh calorific value fuels such as fuel oil. Naturalgas may therefore act as a substitute for fuel oilin the glass industry.

Basing calculations on the principle ofequivalent effective calorific value costs, theprice tolerance for natural gas replacing fuel oilcan be calculated as 3.25 CNY/m3 when theinternational price of crude oil is 100 $/bbl and1.94 CNY/m3 when the international price ofcrude oil is 60 $/bbl (Table 3.11).

Table 3.10 Urban centralised heating price tolerance of natural gas as a replacement for coal

Coal Heatingcost(CNY/m2)

Natural gas

Price(CNY/ton)

Calorificvalue(MJ/kg)

Consumedamount(kg/m2)

Conversioncost(CNY/m2)

Conversioncost(CNY/m2)

Consumedamount(m3/m2)

Calorificvalue(MJ/m3)

Pricetolerance(CNY/m3)

800 20.94 30 12 36 9 12 34.34 2.25

600 30 1.75

400 24 35

Data source Results of calculation

Table 3.11 Glass industry price tolerance of natural gas as replacement for fuel oil

Internationalcrude oilprice ($/bbl)

Fuel oil Effectivecalorificvalue cost(CNY/GJ)

Natural gas

Price(CNY/kg)

Calorificvalue(MJ/kg)

Heatingefficiency

Heatingefficiency

Calorificvalue(MJ/m3)

Pricetolerance(CNY/m3)

100 3.74 41.88 85% 105 90% 34.34 3.25

80 2.98 84 2.59

60 2.24 63 1.94

Data source Results of calculation

92 3 Potential for Natural Gas to Act as a Substitute Fuel in China

3.4.2 Price Tolerance is RelativelyWeak for the CeramicsIndustry for Replacementof Coal Gas by Natural Gas

The ceramics industry can be broken down intofour sub-industries: hygiene ceramics, articlesfor everyday use, art and other ceramics.According to the production processes forceramic products, the overall process is: rawmaterial moulding and forming—firing—cool-ing and application of enamel—re-firing andother steps, with natural gas primarily used inkiln heating.

In order to guarantee the quality of the cera-mic products, the fuel needs to be pure andwithout contaminating matter and the supplymust be stable. Normally coal gas is used, butnatural gas has the potential to be a substitute.Basing calculations on the principle of equivalenteffective calorific value costs, the price tolerance

for natural gas replacing coal gas can be calcu-lated as 2.46 CNY/m3 when the price of coal is600 CNY/ton (Table 3.12).

3.4.3 Natural Gas Price Tolerance isRelatively Poor for SteamProduction as a Replacement for Coal

Steam is broadly used in industrial manufactur-ing processes, with steam generated by industrialboilers. Industrial boiler steam production doesrequire much fuel, and normally low-priced coalis used. Therefore, in the industrial production ofsteam, natural gas has the potential to compete asa substitute for coal. Basing calculations on theprinciple of equivalent effective calorific valuecosts, the price tolerance for natural gas replacingcoal can be calculated as 1.92 CNY/m3 when theprice of coal is 600 CNY/ton (Table 3.13).

Table 3.12 Ceramics industry natural gas price tolerance as a replacement for coal gas

Coal Coal gascalorificvalue(MJ/m3)

Effectivecalorificvalue cost(CNY/GJ)

Natural gas

Price(CNY/ton)

Calorificvalue(MJ/kg)

Conversionefficiency(m3/kg)

Conversioncost(CNY/m3)

Calorificvalue(MJ/m3)

Pricetolerance(CNY/m3)

800 20.94 3 0.7 16.75 82 34.34 2.80

600 72 2.46

400 62 2.12

Data source Results of calculation

Table 3.13 Industrial boiler steam production price tolerance of natural gas as a replacement for coal

Coal Steamcost(CNY/ton)

Natural gas

Price(CNY/ton)

Calorificvalue(MJ/kg)

Consumedamount(kg/ton)

Conversioncost (CNY/ton)

Conversioncost(CNY/ton)

Consumedamount(m3/ton)

Calorificvalue(MJ/m3)

Pricetolerance(CNY/m3)

800 20.94 200 80 240 50 78 34.34 2.44

600 200 1.92

400 160 1.41

Data source Results of calculation

3.4 Industrial Use: Cost Comparison of Natural Gas … 93

3.5 Chemicals: Potentialfor Increased Natural Gas Usein the Production Process

Natural gas chemical engineering refers to theuse of methane, the primary component of nat-ural gas, in manufacturing processes, the prod-ucts of which are primarily synthetic ammonia,methanol and hydrogen.

3.5.1 Price Tolerance of NaturalGas is Extremely Low forthe Manufactureof Synthetic Ammonia

Production capacity and production volume inChina’s synthetic ammonia industry are thehighest in the world, and coal and natural gas arethe main raw materials, accounting for 76 and22% respectively. The price of the final ureaproduct is essentially guided by the productioncost of the coal raw material. Thus, from theperspective of industry development, natural gascompetes as an alternative to coal in the manu-facture of synthetic ammonia.

Basing calculations on the principle ofequivalent finished product costs, the price tol-erance for natural gas replacing coal in themanufacture of synthetic ammonia can be cal-culated as 1.42 CNY/m3 when the price of coalis 600 CNY/ton (Table 3.14).

3.5.2 Price Tolerance of NaturalGas is Very Weak for theManufacture of Methanol

Production of methanol in China relies on coaland natural gas as the main raw materials,accounting for 63 and 28%, respectively. Theprice of the urea end product is essentially guidedby the cost of the coal raw material. Thus, fromthe perspective of sector development, naturalgas has a relationship as a substitute for coal inthe manufacture of methanol.

Basing calculations on the principle ofequivalent finished product costs, the price tol-erance for natural gas replacing coal in themanufacture of methanol can be calculated as1.71 CNY/m3 when the price of coal is600 CNY/ton (Table 3.15).

Table 3.14 Natural gas tolerance in production of synthetic ammonia as replacement for coal

Coal Urea finishedproduct cost(CNY/ton)

Natural gas

Price(CNY/ton)

Consumedamount(kg/t)

Conversioncost(CNY/ton)

Conversioncost(CNY/ton)

Consumedamount(m3/ton)

Pricetolerance(CNY/m3)

800 1080 1000 1738 800 600 1.77

600 1554 1.42

400 1369 1.07

Data source Results of calculation

Table 3.15 Methanol production price tolerance of natural gas as replacement for coal-based production

Coal Methanol finishedproduct cost(CNY/ton)

Natural gas

Price(CNY/ton)

Consumedamount(kg/ton)

Conversioncost(CNY/ton)

Conversioncost(CNY/ton)

Consumedamount(m3/ton)

Pricetolerance(CNY/m3)

800 1400 1500 2457 900 870 2.02

600 2218 1.71

400 1979 1.40

Data source Results of calculation

94 3 Potential for Natural Gas to Act as a Substitute Fuel in China

3.5.3 Price Tolerance of NaturalGas is Very Strong for theManufacture of Hydrogen

Natural gas has a high methane content, and whenused as the raw material in the production ofhydrogen it results in a high hydrogen yield inaddition to reducing fuel consumption, making itthe ideal raw material. The majority of theworld’s hydrogen is manufactured using naturalgas as a raw material. However, in China the rawmaterial most used in the manufacture of hydro-gen is coal, although petrochemical enterprisesmanufacture hydrogen using mainly naphtha.Natural gas is primarily used in the manufactureof hydrogen by petrochemical enterprises as analternative to naphtha. Basing calculations on theprinciple of equivalent finished product costs, theprice tolerance for natural gas replacing naphthacan be calculated as 7.19 CNY/m3 when theinternational price of crude oil is 100 $/bbl and4.34 CNY/m3 when the international price ofcrude oil is 60 $/bbl (Table 3.16).

3.6 China’s Natural Gas DemandCurve and Ways to IncreaseNatural Gas Consumption

3.6.1 China’s Natural Gas Pricesin 2013

1. Shanghai as the baseline

In July 2013, the National Development andReform Commission issued the Notice

Regarding Natural Gas Prices (FGJG 2013,No. 1246), in which a reform plan was proposedfor natural gas prices. Considering China’s nat-ural gas market resource trends, consumption andmanagement distribution as a whole, Shanghaiwas chosen as the pricing baseline location.Station prices across the country in all provincesas well as all user terminal natural gas priceswere tied to the Shanghai station price.

2. Individual subsidies for each provincialstation

The price difference between each province’sstation price and the pricing baseline of theShanghai station price was the subsidy. The mainfactor affecting provincial subsidies was trans-portation cost (Table 3.17).

3. End price calculations for provincial users

Provincial station price = Shanghai station price- subsidyCity station price = provincial stationprice + provincial pipeline network pipelinetransport feeCity natural gas user terminal price = city stationprice + city distribution feeLarge industrial user delivery price = city stationprice + provincial pipeline network pipelinetransport feeCNG filling sales price = city station price +CNG compression and distribution feeLNG filling sales price = city station price +LNG liquid filling feeDepending on the provincial pipeline networkpipeline transport fee for each province, the city

Table 3.16 Hydrogen production price tolerance of natural gas as replacement for coal-based production

Internationalcrude oilprice ($/bbl)

Naphtha Hydrogenfinishedproduct cost(CNY/ton)

Natural gas

Price(CNY/kg)

Consumedamount(kg/ton)

Conversioncost (CNY/ton)

Conversioncost(CNY/ton)

Consumedamount(m3/ton)

Pricetolerance(CNY/m3)

100 10.64 3600 1000 33,731 650 5200 7.19

80 8.51 27,185 5.77

60 6.38 20,638 4.34

Data source Results of calculation

3.5 Chemicals: Potential for Increased Natural Gas … 95

Table 3.17 Station price subsidies in each province

No. Province Subsidy No. Province Subsidy No. Province Subsidy

1 Shanghai 0.00 11 Shandong 0.20 21 Sichuan 0.53

2 Guangdong 0.00 12 Liaoning 0.20 22 Chongqing 0.54

3 Zhejiang 0.01 13 Hubei 0.22 23 Hainan 0.54

4 Jiangsu 0.02 14 Jiangxi 0.22 24 Ningxia 0.67

5 Anhui 0.09 15 Hunan 0.22 25 Gansu 0.75

6 Henan 0.17 16 Shanxi 0.27 26 Shaanxi 0.84

7 Guangxi 0.17 17 Heilongjiang 0.42 27 Inner Mongolia 0.84

8 Beijing 0.18 18 Jilin 0.42 28 Qinghai 0.91

9 Tianjin 0.18 19 Yunnan 0.47 29 Xinjiang 1.03

10 Hebei 0.20 20 Guizhou 0.47 30 Tibet 1.50

distribution fee, CNG compression and distribu-tion fee and LNG liquid filling fee, the averagevalues are 0.2 , 0.75 , 1.5 and 2.0 CNY/m3,respectively.

3.6.2 Natural Gas Demand Curvefor China in 2013

1. Summary of price tolerance for differentusers

Based on the calculations in this chapter, whenthe international price of crude oil is 80 $/bbl, andwhen raw coal price is 600 CNY/ton, the terminalprice tolerance for natural gas usage by users invarious sectors is 1.4–5.77 CNY/m3. Within thisrange, the price tolerance is relatively high forresidential, commercial services, vehicle and shiptransport, and natural gas manufacturing ofhydrogen, but relatively low for centralised heat-ing, natural gas power generation, industrial fuels,synthetic ammonia and methanol (Fig. 3.4).

During the optimisation of primary energyconsumption structures, for natural gas replace-ment of oil as the fuel in industrial processes, thenatural gas price tolerance is 2.59 CNY/m3,while for natural gas chemicals, the price toler-ance of natural gas for use in the production ofhydrogen as a replacement for naphtha is highest,with a maximum natural gas price tolerance of5.77 CNY/m3.

In terms of natural gas as a replacement sec-ondary energy source for electricity in residentialand commercial use, natural gas price tolerance

ranks only second to natural gas substitutingpetroleum, at around 3.7 CNY/m3 (Fig. 3.5).

During the process of natural gas replacingcoal, natural gas price tolerance is generally low,and only when it is used as a substitute forsyngas is the natural gas price tolerance relativelyhigh at 2.46 CNY/m3. Price tolerance for othercoal use, whether for heating, synthetic ammo-nia, methanol production, steam boilers or powergeneration, is only around 1.5 CNY/m3.

2. Construction of the natural gas demandcurve

Step 1: The total consumption of natural gas inChina of 166 billion m3 was dividedbetween 30 provinces, 5 categories and16 types of user.

Step 2: The prices of alternative energies suchas coal, fuel oil, naphtha, #93 petrol, #0diesel, LPG, electric power and data onurban residents’ disposable income wascollated, and an evaluation of the ter-minal price tolerance of 16 kinds ofnatural gas user carried out.

Step 3: Terminal price tolerance of natural gasusers was normalised using natural gaspricing mechanisms based on theShanghai natural gas benchmark price.

Step 4: The tolerance for the Shanghai bench-mark price of the 30 provinces, 5 cate-gories and 16 types of user was organisedfrom high to low, yielding the effectiveChina natural gas market demand curve.

96 3 Potential for Natural Gas to Act as a Substitute Fuel in China

5.725.08

3.65

4.82

3.25

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4.96 5.044.41 4.21

1.40 1.47 1.54

2.59 2.461.92

1.421.71

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Fig. 3.4 Terminal price tolerance for users in various natural gas sectors

5.77

5.08 5.04 4.96 4.824.41 4.21

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g

Ste

am b

oile

rs

Syn

thet

ic a

mm

onia

Pow

er g

ener

atio

n

Substitute for oil Substitutefor electricity

Com

mer

cial

veh

icle

s

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

Fig. 3.5 Terminal price tolerance of main gas market users in terms of energy substitution

3.6 China’s Natural Gas Demand Curve and Ways … 97

This finally yielded the 2013 China naturalgas demand curve, as shown in Fig. 3.6.

3.6.3 Implementation Modelof Effective Demandand Actual Natural GasConsumption Basedon Natural Gas PriceReform Targets

In 2013, China proposed a natural gas price reformscheme, which set the Shanghai benchmark priceof natural gas at 3.32 CNY/m3. From the effectivedemand curve of the natural gas market it can beseen that, in 2013, China’s actual consumptionof natural gas reached 167.6 billion m3, and,based on the Shanghai benchmark price of3.32 CNY/m3, the corresponding effective demandreaches 50 billion m3, which only accounts for30% of actual consumption. The natural gas con-sumption in urban centralised heating, powergeneration, ammonia and methanol synthesis andfor most industrial fuels cannot be the effectivedemand based on the Shanghai benchmark price of3.32 CNY/m3 (Table 3.18).

In 2013, China’s actual natural gas con-sumption reached 166 billion m3, which sub-stantially exceeds the effective demandcalculated based on price tolerance, being a resultof various natural gas supportive policies.

1. Natural gas price reform transitional pol-icy—gas suppliers providing subsidies ofnearly 150 billion CNY to users

The natural gas price reform scheme imple-mented by the state specified that the civil naturalgas price would not be changed, the fertilisernatural gas price would be slightly adjusted, andnon-residential use natural gas prices would havea stored gas and reserve gas two-tier systemapplied to them. During the natural gas pricereform transitional period, an unsatisfactory lowprice policy was applied to natural gas, withnatural gas suppliers providing subsidies to nat-ural gas consumer enterprises to ensure that userscould afford gas and that natural gas consump-tion reached a certain level.

In 2013, the national average urban residentterminal natural gas price was 2.15 CNY/m3 andthe average resident natural gas provincial gateprice was 1.37 CNY/m3, which was1.50 CNY/m3 lower than the average nationalincremental natural gas price. Natural gas sup-pliers granted around 27 billion CNY of subsidiesto urban residential users based on a residentialnatural gas consumption of 18 billion m3.

The average fertiliser natural gas consumptionprice was adjusted slightly to around1.80 CNY/m3, being 1.10 CNY/m3 lower than theaverage national incremental natural gas price.

0 200 400 600 800 1000 1200 1400 1600 1800

7.0

6.5

6.0

5.5

5.0

4.5

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

Shan

ghai

ben

chm

ark

pric

e (Y

uan/

m3 )

Quantity consumed (108 x m3)Natural gas chemicals Urban fuel Vehicular and waterborne Industrial fuel Natural gas power generation

Fig. 3.6 Effective 2013 China natural gas market demand curve

98 3 Potential for Natural Gas to Act as a Substitute Fuel in China

Natural gas suppliers granted around 22 billionCNY of subsidies to fertiliser users based on afertiliser natural gas consumption of 20 billion m3.

In 2013, the stored natural gas price in variousprovinces in China was 0.88 CNY/m3 lower thanthe incremental natural gas. Natural gas supplierssubsidised non-residential stored natural gasusers to the tune of around 100 billion CNYbased on a non-residential stored natural gasvolume of 110 billion m3.

2. Special pricing policy for natural gas gen-eration electricity prices

The Notice on Relevant Matters for AdjustingGrid Purchase Price of Power GenerationEnterprises issued by the National Developmentand Reform Commission on September 30, 2013,besides reducing the desulphurised coal power

electricity grid price for all provinces (regions andcities), required that the gas-fired power electricitygrid price in provinces (regions and cities) suchas Shanghai, Jiangsu, Zhejiang, Guangdong,Hainan, Henan, Hubei and Ningxia should beincreased, thus easing slightly the conflictinginfluences on the natural gas price. In China,the grid price of gas power electricity is 40%higher than that of coal power electricity (around0.20 CNY/kWh). Based on 28.5 billion m3 resi-dential natural gas consumption, around570 million CNY of the cost of gas generatedelectricity is transferred from power suppliers tothe user.

3. Supportive policy for natural gas use

Generous fiscal subsidies are granted in manylocations to encourage the adoption of natural

Table 3.18 Effective demand of natural gas in China based on the Shanghai benchmark price in 2013

Main purpose Actual consumption Effective demand Growthrate (%)Quantity Proportion (%) Consumption Proportion (%)

Urban fuel gas Residential 181 10.95 147 30.95 81

Commercialservice

104 6.29 84 17.61 80

Centralised heating 97 5.87

Vehicular andwaterbornetransportation

CNG taxi 59 3.57 59 12.43 100

CNG bus 32 1.94 32 6.74 100

LNG lorry 33 2.00 24 4.96 71

LNG shipping

Gas-fired powergeneration

Peak-loadregulation powerplant

157 9.50

Thermal powerplant

126 7.62

Distributed energyresources

4 0.24

Industrial fuels 606 36.66 88 17.45 15

Natural gaschemical industry

Synthetic ammonia 152 9.20

Methanol 61 3.69

Hydrogenproduction, etc.

41 2.48 41 8.28 100

Total 1653 100 475 100 29

Data source Calculation results(Units of 100 million m3)

3.6 China’s Natural Gas Demand Curve and Ways … 99

gas centralised heating. Compared withcoal-fired centralised heating, the natural gasprice tolerance for gas-fired centralised heatingonly reached 1.75 CNY/m3. After deductingurban natural gas distribution costs, the provin-cial gate natural gas price tolerance reachedaround 1.00 CNY/m3. If the unit price chargedfor centralised heating is not adjusted, the eco-nomic benefits of gas-fired centralised heatingwould be almost the same as those of coal-firedcentral heating. Based on the stored natural gasprice of 2.2 CNY/m3 and a heating natural gasconsumption of 10 billion m3, the fiscal subsidygranted by local government for gas-fired cen-tralised heating reached around CNY 12 billion.

4. Coercive policy for natural gas use

In September 2013, the State Council pub-lished the Action Plan for Atmospheric Con-tamination Prevention, which requires theacceleration of coal to gas conversions, with the

aim of eliminating small urban coal-fired boilers,establishing coal-free zones etc. to speed up theadoption of natural gas in heating boilers,industrial boilers and thermoelectric projects.Cities at all levels were required to rid them-selves of coal-fired boilers with capacity less than10 tons of steam per hour, and the construction ofcoal-fired boilers with capacity of 20 tons ofsteam or less per hour was forbidden. Mostindustrial fuel users have a low tolerance fornatural gas prices, but based on policy require-ments, they are now required to absorb the costsof natural gas themselves.

Judging from the natural gas effective demandcurve, the demand for stored natural gas thatcould be supported by industrial fuel usersreached 30 billion m3, while the increased costof CNY 27 billion associated with the other30 billion m3 of industrial fuel consumption hadto be absorbed by the enterprises themselves,posing challenges for the sustainable develop-ment of natural gas-consuming enterprises.

Open Access This chapter is licensed under the terms ofthe Creative Commons Attribution 4.0 InternationalLicense (http://creativecommons.org/licenses/by/4.0/),which permits use, sharing, adaptation, distribution andreproduction in any medium or format, as long as yougive appropriate credit to the original author(s) and thesource, provide a link to the Creative Commons licenseand indicate if changes were made.

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100 3 Potential for Natural Gas to Act as a Substitute Fuel in China

4Environmental and Social Valueof Natural Gas

Natural gas, as a clean energy source, can reducethe economic losses caused by environmentalpollution from coal and petroleum. Based oninternational experience of natural gas con-sumption development, it is clear that, whilenatural gas lacks an obvious price advantage andhas even higher direct costs, it is still an effectivesubstitute for other energy sources. The key tothis is that restricting pollution reduces the eco-nomic and social losses associated withpollution.

4.1 Losses Caused by AtmosphericPollution in China

4.1.1 Atmospheric Pollution is a KeyCause of Death in China

Based on World Health Organization figures, in2010 there were 1.2 million people who diedprematurely as a result of air pollution, repre-senting a loss of over 25 million years of healthyliving. Atmospheric pollution includes indoorand outdoor pollution, among which outdoor

pollution is mainly caused by discharge of pol-lutants through the use of fossil fuels, includingcoal burning, automobile emissions, dust, etc.,while indoor atmospheric pollution is caused byleakage of hazardous substances generated dur-ing finishing, and the lack of affordable and cleanfuels for residential use; an example of this is theuse of direct combustion of large quantities ofcoal briquettes, which cause significant pollution.In 2010, outdoor atmospheric pollution wasranked fourth as a cause of death for residents inChina, while indoor atmospheric pollution wasranked fifth.

From a historical point of view, prevention ofindoor atmospheric pollution in China hasimproved a great deal, but outdoor atmosphericpollution still presents serious challenges. In1990, indoor atmospheric pollution was rankedsecond as a cause of death in China. Subse-quently, its importance dropped rapidly, and in2010, it was ranked fifth. However, in recentyears, with rapid economic development inChina, and a lack of strict energy conservationand emission reduction measures in many energyproduction and consumption enterprises, the airquality in China has failed to improve signifi-cantly, and the threat of atmospheric pollution tohealth remains significant. During the period1990–2010, an average of 80–90 persons per10,000 died of various diseases caused byatmospheric pollution (Fig. 4.1).

* This chapter was overseen by Zhaoyuan Xu from theDevelopment Research Center of the State Council andMartin Haigh from Shell International, withcontributions from Baosheng Zhang and Shouhai Chenfrom the China University of Petroleum, Lianzeng Zhaofrom the China Petroleum Planning Research Institute,Linji Qiao from ENN and Juan Han from Shell China.Other members of the research group participated indiscussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_4

101

4.1.2 Losses from Injury to HealthCaused by AtmosphericPollution in ChinaAccount for 3–12%of GDP

Economic activity can improve citizens’ incomeand increase well-being, but the associated atmo-spheric pollution causes losses in terms of qualityof life. A balance must be reached between eco-nomic benefits and losses. However, health lossescannot be directly measured in the same way aseconomic output if there is no quantification of lossof health. Previous experience shows that, if healtheffects can be economically quantified in a finan-cial index that represents losses caused by thedeath of a person, this reflects the true cost ofeconomic development, and can act to promoteimprovements in air quality.1

1. Atmospheric pollution losses in theEuropean Union

Based on international standards, the airquality in EU countries is excellent. However, in2012, the losses from primary pollutants gener-ated by industry and energy generation stillaccounted for between 0.3% and 1% of GDP

(European Environment Agency, 2014). Figure 4.2shows estimated hazard costs per ton of pollutantsin Europe. In Europe, the hazards of CO2 cost9.8–38.1 €/t (2005 prices), while the hazards ofPM10 cost 23,000–67,000 €/t. Other pollutantsbesides particulate matter also need to be noted; inparticular, the hazard cost of heavy metal andorganic pollutants per unit weight far exceeds thatof particulate matter pollution, though the quantityof these pollutants is less. The hazard that theyrepresent overall is therefore less than that pre-sented by particulate matter.

2. Estimate of health-related losses caused byatmospheric pollution in China

China faces worse pollution than other coun-tries. In the main cities in China, the averageconcentration of PM10 and sulphur dioxide isrespectively 5 times and 12 times the referencevalue (Nielson and Ho 2013) issued by the WHOin 2009. Significant research has shown that airpollution and energy structure have a directrelationship. In recent years, various methodshave been adopted in many studies to assesshealth-related losses in China.

The China 2030 Report, jointly issued by theDevelopment Research Center of the StateCouncil and the World Bank in 2013, estimatedthat the health-related losses caused by PM10

were equivalent to 2.8% of the GNI in 2009,

1990 1995 2000 2005 2010

250

200

150

100

50

0

Dea

ths

per 1

0,00

0

Risks due to diet

High blood pressure

Smoking

Atmospheric particulate pollution

Indoor atmospheric pollution dueto solid fuels

Fig. 4.1 Top five causes of death of residents in China. Data source Vivid Economics, referred from Institute forHealth Metrics and Evaluation (2014)

1There are also many people who object to using moneyto measure the value of life, but for the purpose ofbalancing interests, this measure is still necessary.

102 4 Environmental and Social Value of Natural Gas

calculated based on the two basic parameters ofdeaths caused by particulate matter discharge andthe amount of money that people are willing topay to reduce the risk of disease.

The New Climate Economy Report issued bythe Global Commission on Economy and Cli-mate in 2014 estimated that the economic losscaused by deaths of people due to PM2.5 in Chinain 2010 was equivalent to 9.7–13.2% of GDP,with a median value of around 12% of GDP. Thisresult was obtained by multiplying three values:deaths caused by PM2.5, economic value ofdeaths and per capita GDP. The economic valueof deaths was obtained by converting the value ofstatistical life (VSL) used in the European Union,adjusted for per capita income. In other words,the economic value of deaths will grow togetherwith the growth of per capita GDP. Data fordeaths caused by PM2.5 was sourced from theWHO’s 2010 Global Burden of Disease Study.

Matus et al. (2011) estimated the economicloss caused by atmospheric pollution. This papercalculated the health hazard caused by PM10 andozone, and the results show that in 2005 theeconomic losses caused by health hazards due to

PM10 accounted for around 6% of GDP. Thispaper adopted the multi-department CGE modelto calculate the losses due to atmospheric pollu-tion health damage between 1970 and 2005,taking into account the cost of related treatment,reduced working capacity and extra holidaystaken. In 2005, around 60% of the losses weredue to death, 10% due to the cost of treatmentand 30% from other economic losses.

If other pollutants are brought into the equa-tion, the economic losses of atmospheric pollu-tion in China become even higher. These studiesonly consider particulate matter (PM), includingthe larger PM10 with a diameter of 10 micronsand the smaller but more harmful PM2.5. In fact,the hazards of other pollutants such as sulphurdioxide and nitrogen dioxide are also severe.

In general, the difficulties encountered inresearch into the economic quantification of thelosses caused by atmospheric pollution in Chinacause a lot of variation: the research methods,concerns and assessment standards are different,and the research results are also uncertain. Gen-erally speaking, the economic loss caused byatmospheric pollution in China is massive,

Main atmospheric pollutants (VOLY method)

Main atmospheric pollutants (VSL method)

Heavy metals

Organic pollutants

1

10

100

1,000

10,000

100,000

1,000,000

10,000,000

Eur

opea

n da

mag

e co

st p

er to

n of

pol

luta

nts

(200

5 no

n-va

riabl

e E

uro

pric

e/to

n)

CO

2

CO2 low hazard

CO2 high hazard

Am

mon

ia

NM

VO

C

Hyd

roca

rbon

s

PM

10

Sul

phur

dio

xide

Ars

enic

Cad

miu

m

Chr

omiu

m

Lead

Mer

cury

Nic

kel

Ben

zene

PA

H

Dio

xins

and

Fur

ans

Fig. 4.2 Hazard cost estimation for main pollutants in Europe. Note Damage calculations apply for Europe only. Datasource Vivid Economics, referred from (European Environment Agency, 2014)

4.1 Losses Caused by Atmospheric Pollution in China 103

equivalent to between 3% and 12% ofGDP. Based on the results of these studies, in2014, atmospheric pollution caused a loss ofbetween $300 billion and $1200 billion inChina. Given that the International EnergyAgency estimated that China’s energy supplyneeded $300 billion of investment annually up to2035, this gives a clear indication that improvingair quality would pay for itself (Fig. 4.3).

3. Other unfavourable effects of atmosphericpollution

Atmospheric pollution not only causes directharm to health and economic losses, it alsoreduces China’s capital labour reserves andreduces productivity. This results in a “haircut”being applied in terms of the actual economicbenefits of the particularly labour-centredapproach to economic activities that China relieson. In addition, the investment attracted by the12th Five-Year Plan and the political targets putforward during the 3rd Plenary Session of the18th CPC Central Committee will also be affec-ted. The implementation of policies for expandingurbanisation, developing the service industry,reducing inequality, improving social insurance,etc. will become harder to achieve, as shown inFig. 4.4.

4.2 The Environmental Valueof Natural Gas as a Substitutefor Coal

The environmental value of natural gas stemsfrom the fact that it is a clean energy substitutefor coal. Coal production, transportation andusage cause serious environmental pollution, andresult in tremendous direct and indirect externaleconomic losses. However, as the costs of envi-ronmental pollution in China are accounted for asexternal economic losses, market entities causingenvironmental pollution consistently fail to paythe price of environmental pollution themselves.Similarly, the environmental benefits of replacingcoal and oil with natural gas are not reflected innatural gas’s market value, since the costs offailing to make the replacement are not beinginternalised.

4.2.1 Environmental Pollutionand Economic LossesIncurred During CoalProduction

Environmental pollution generated during coalproduction manifests as damage to and

0%

3%

6%

9%

12%

State Council DevelopmentResearch Center and

the World Bank (2012)

Matu, et al.(2012)

New Climate Economy(20140 D

amag

e to

hea

lth c

ause

d by

atm

osph

eric

pol

lutio

nas

a p

erce

ntag

e of

GD

P/G

NI

6.0%

2.8%

11.8%

Fig. 4.3 Economic loss caused by atmospheric pollution as a percentage of GDP. Data source The State CouncilDevelopment Research Center and the World Bank 2012, Matus et al. 2012; Global Economy and ClimateCommission, 2014

104 4 Environmental and Social Value of Natural Gas

appropriation of land, and pollution of waterresources and the atmosphere.

Underground mining causes surface subsi-dence; mining areas suffer from ponding, floodingand salinisation, which accelerate water and soilerosion; and desertification causes damage to sur-face infrastructure to differing degrees. Open coalmining peels off the topsoil and rock stratumcovering the coal bed, destroying land resources,and discharges spoil onto adjoining land. Coalspoil piles up and buries land resources. Based onrelevant data, extraction of 10,000 tons of coal willcause surface subsidence of an area of 0.2 hec-tares, requiring relocation of two residents, whileassociated spoil occupies 0.01 hectares. The eco-nomic losses caused by land resource damage dueto extraction of one ton of coal are thus CNY 65.

During the mining process, the scale ofextraction grows and even larger quantitiesof mine water are discharged, causing pollution ofthe aquatic environment around mines; mean-while, the water table drops, causing subsidence.The commonly used coal washing process resultsin large quantities of water that contains highconcentrations of sludge, silt and harmful heavymetal ions. Large amounts of harmful substances(especially heavy metal ions) contained in the coalspoil heaps leach out due to rainfall and enter theecosystem. Based on relevant data, extraction ofone ton of coal results in the discharge of 2.3 tonsof mine water, 0.35 tons of industrial waste water,0.05 tons of coal washing water, and 0.04 tons ofother waste water, resulting in economic lossesestimated at CNY 10 per ton of coal.

The greenhouse effect of marsh gas (the mainingredient of which is CH4) released during coalextraction is 21 times that of CO2, making this

one of the main gases responsible for globalwarming. Large quantities of hazardous gasessuch as SO2, CO2, CO etc. produced by spon-taneous combustion of coal spoil also affect theatmospheric environment. Based on relevantdata, extraction of one ton of coal on averageresults in the discharge of 10 m3 of gas, equiv-alent to a discharge of 138 kg of CO2, and theestimated economic loss caused by atmosphericpollution produced by extraction of one ton ofcoal is CNY 15.

Economic losses caused by environmentalpollution during coal production per ton of coalextracted are around CNY 90.

4.2.2 Environmental Pollutionand Economic LossDuring CoalTransportation

The geographical distribution of coal productionand consumption in China is highly unbalanced,with coal production bases being distributedmainly in the northern and western regions, whilecoal consumption is mainly distributed in easternand coastal areas, determining the basic patternof transportation: northern coal to the south, andwestern coal to the east. The average distancecoal is transported by rail is 552 km.

Coal in China is transported over long dis-tances, and passes from the coal stores or coalyards of mines to trains (or vehicles or vessels)and then reaches large thermal power generationcoal yards, industrial coal consumption enter-prise coal yards and fuel company coal yards ofvarious sizes. As coal storage, loading and

Urbanisationincreases exposure

Increased servicesrequire healthyhuman capital

Poor health places aburden on new

social security

Localised pollutioncan affect inequality

Air quality

Fig. 4.4 Further effects of atmospheric pollution

4.2 The Environmental Value of Natural Gas as a Substitute for Coal 105

transportation facilities are usually not integrated,the lack of flow regulation exacerbated by poormanagement results in serious pollution of thesurroundings at all stages of coal storage, han-dling and transportation.

The spontaneous combustion of mined coalnot only happens in coal yards, but also afterloading on lorries or vessels. During openstacking, handling and transportation of coal, thecoal dust contaminates wide areas and causesserious pollution. Spraying in open coal yardsduring loading and unloading to cause coal dustto settle results in pollution of bodies of water.

Based on relevant data, there is an annualdischarge of between 200,000–300,000 tons ofharmful gas due to spontaneous combustion ofcoal in China, while 10 million tons of coal dustis produced during coal storage and 11 milliontons of coal dust is generated during coal trans-portation. The estimated economic losses causedby pollution from transportation of each ton ofcoal are thus CNY 20.

4.2.3 Estimates of EnvironmentalPollution and EconomicLosses Arising fromCoal Use

Direct combustion of large amounts of coal hascaused serious damage to the environment inChina, while it is also the main cause of envi-ronmental pollution.

SO2 discharge and acid rain have seriouseffects on human health and vegetation, and causedeforestation, damage to buildings and metalcorrosion. Based on calculations made by variousinstitutions, the economic loss caused by the dis-charge of one ton of SO2 is as high as CNY 7000.

CO2 discharge and the greenhouse effectseriously threaten global ecosystems and thesurvival of mankind, causing shrinking forests,land salinisation, desertification, extreme weatherevents, etc. Based on the cost of carbon seques-tration, the estimated economic loss caused bythe discharge of one ton of CO2 is CNY 110.

NOX discharges have serious effects on humanhealth and cause a series of diseases and

photochemical reactions, in addition to damagingecosystems. Based on calculations made by vari-ous institutions, the economic loss caused by dis-charge of one ton of NOX is as high as CNY 5000.

Dust emissions have an effect on humanhealth and discharge of dust into the atmospherewill reduce atmospheric cleanliness and affectplant photosynthesis etc. Based on calculationsmade by various institutions, the economic losscaused by discharge of one ton of dust is as highas CNY 200,000.

Based on calculations of coal combustionpollutant discharge quantities, the economic losscaused by the pollution produced by one ton ofraw coal is CNY 830 (Table 4.1).

4.2.4 Environmental ValueAssessment for NaturalGas Substituting Coal

The process of coal production, transportation anduse results in serious environmental pollution.The estimated economic loss incurred is 380–940 CNY/t, of which production accounts for90 CNY/t, transportation accounts for 20 CNY/tand usage accounts for 295–830 CNY/t.

CO2 and other micro pollutants are dischargedduring the natural gas usage process. Calculatedbased on a discharge of 2.5 kg CO2 per m

3 nat-ural gas, the economic loss caused by the pol-lution due to natural gas is 0.3 CNY/m3.

Based on calorific value and efficiency of coaland natural gas, and calculated for 550 m3 nat-ural gas replacing one ton of coal, the natural gasenvironmental value compared to coal which issubjected to similar emissions restrictions is 0.4–1.4 CNY/m3 and 1.4 CNY/m3 under conditionsof dispersed coal use.

4.3 Social Value of Natural Gasas a Substitute for Coal

Besides environmental losses, coal production,transportation and consumption processes allcause non-economic losses to the population, forinstance non-economic losses involving mental

106 4 Environmental and Social Value of Natural Gas

and physical suffering, such as that due to thepain caused by disease suffered by the victim,and the pain caused to the relatives due to thedeath of a loved one.

Social losses are calculated based on differ-ence in willingness to pay and human capital.Willingness to pay refers to readiness to pay or adesire for compensation ascertained throughresearch, the calculation of which includes bid-ding gaming methods, comparison gamingmethods and the Delphi method. Human capitalrefers to the monetary loss connected with health,including increased losses and medical expensesdue to premature death, illness or medical leaveand other factors.

4.3.1 Social Loss of Coal Production

The coal industry is the industry with the greatestnumber of fatal accidents in China—annual coalmine fatalities had reached around 6000–7000, butdropped to nearly 4000 by 2007. Accidents in coalmines account for 85% of workplace fatalities inChina’s mining industry, and coal mining accountsfor 50% of all mining fatalities, the highest rate inthe country. Apart from this, pneumoconiosis, anoccupational disease related to coal production,has very serious consequences on health.

4.3.2 Social Loss of Coal Use

Environmental pollution caused by coal use seri-ously affects people’s health. SO2 emissions have

obvious effects on the respiratory system, irritat-ing the respiratory mucosa, resulting in acute andchronic inflammation of the respiratory tract.Long-term inhalation of SO2 will lead to fibrehyperplasia of lung tissue cell walls as well asemphysema and bronchial asthma. Smoke dustdischarge is a serious problem too. The dustconsists of particulates which can become sus-pended in the atmosphere for a long time, and atany time it can be directly inhaled into the res-piratory tract. These small particulates are a car-rier of bacteria, viruses and metallic particles, andbring harmful pathogenic bacteria and toxic par-ticles into the human respiratory system and thealveoli, inducing allergic rhinitis, bronchitis andbronchial asthma, and even malignant tumours.

4.3.3 Social Value Assessmentof Natural Gasas a Substitute for Coal

Based on the functional relationships betweendeath rate and the incidence (dose-responsefunction) of certain diseases outlined in Atmo-spheric Pollution in Large and Medium-SizedCities of China issued by the World Bank, thecontribution of coal and natural gas use toatmospheric pollution was evaluated, whileconsidering the loss of life caused by miningaccidents and the social losses associated withoccupational diseases encountered in the coalproduction process, providing an estimatedexternal environmental benefit to society of nat-ural gas of around 0.4 CNY/m3 (Table 4.2).

Table 4.1 Calculation table for the economic loss caused by pollution produced by one ton of raw coal

Emission Discharge quantity (kg) Unit loss(CNY/kg)

Economic loss (CNY) Remarks

Near zeroemissions

Distributedcombustion

Concentratedcombustion

Distributedcombustion

CO2 2455 2455 0.11 270 270 Calculated based on carbonexchange value

NOX 5.40 5 27 Calculated based on pollution loss

SO2 10.40 7 73 Calculated based on pollution loss

Dust 2.30 200 460 Calculated based on pollution loss

Total 295 830

4.3 Social Value of Natural Gas as a Substitute for Coal 107

4.4 China’s Achievementsin Energy Conservationand Emissions Reduction

Thanks to technical progress and greater socialawareness, China has significantly enhanced itsenergy conservation and emissions reductionwork in recent years. The results show thatenergy conservation and emissions reductionresulted in significant direct and indirect benefitsbeing achieved with limited input, providingempirical support for the further development ofclean energy in China.

4.4.1 Targets and Main Measures forSulphur Dioxide EmissionReduction During thePeriod of the 12thFive-Year Plan

In recent years, China has attached great impor-tance to energy conservation and emissionsreduction, and has strengthened the intensity ofenergy conservation and emissions reductionwork, with stated targets becoming bindingindexes listed in the Five-Year Plan and gov-ernment planning. For example, the 11thFive-Year Plan specified that sulphur dioxideemissions between 2006 and 2010 should be

10% lower than those in 2005. Judging from theactual achievements, the implementation of theseemission reduction works has seen good results.

In order to achieve the sulphur dioxide emis-sions reduction targets during the 11th Five-YearPlan period, two main policies were adopted bythe Chinese government.

• All newly-built coal-fired power generationplants were required to be fitted with flue gasdesulphurisation facilities conforming tospecific standards, while most of the oldpower generation plants were required toundergo retrofitting to meet desulphurisationstandards. After the reforms, the coal-firedpower station flue gas desulphurisationcapacity was enhanced to 83% in 2010 fromthe 12% adopted in 2005. Flue gas desul-phurisation conversion costs are low. The fluegas desulphurisation cost of a 6 million-wattpower plant is only around 3.8% of the con-struction cost, and operational costs areincreased by 2.4%—costs that are offset bygovernment subsidies.

• Small, inefficient power generation plantswere to be shut down. At the end of 2005,low-use and highly polluting small powerplants accounted for one third of nationalenergy production. By replacing these withlarge power generation plants, costs werereduced by a factor of 2 or 3 per million

Table 4.2 Dosage-effect function of inhalable particulate matter PM10

Item Unit Value Unit value orientation (CNY)

Human capitalmethod

Willingness to pay(WTP) method

Mortality Person 6 100,000 500,000

Respiratory disease outpatient rate Case 12 4000 5200

Emergency cases Case 235 400 520

Restricted activity days Day 57,500 40 52

Lower respiratory tract infection/paediatric asthma

Case 23 200 260

Asthma Case 2068 60 78

Chronic bronchitis Case 61 80,000 104,000

Respiratory disease symptoms Case 183,000 10 13

Note The values are the numbers of additional deaths, cases, or days for each increase of 1 lg/m3 in PM10

108 4 Environmental and Social Value of Natural Gas

watts. Since 2004, the average coverage ofnew power generation plants has doubled. Atthe same time, most of the large new powergeneration plants have adopted more efficienttechnology, as shown in Fig. 4.5. Based onthe shutdown policy for small power plants,59 billion watts of small power plants wereclosed during the 11th Five-Year Plan periodand replaced by larger power plants.

4.4.2 Emissions Reduction ResultsAchieved During the 11thFive-Year Plan Period

The goals of reducing sulphur dioxide emissionswere achieved. The power sector accounted for54% and 28% of the total sulphur dioxideemissions respectively in 2005 and in 2011,growth in sulphur dioxide emissions being muchslower than that of other pollutants, such asnitrogen oxides and particulate matter. A studyconducted by Harvard University and TsinghuaUniversity shows that the sulphur dioxide emis-sion reduction policy achieved a major effectwith a low macroeconomic cost, and is expected

to save between 12,000 and 74,000 lives everyyear, which is equivalent to CNY 8–400 billion(Nielson and Ho, 2013). This policy shows thatChina can achieve greater benefits (synergicallyspeaking) by improving atmospheric quality,while greater losses result if atmospheric pollu-tion is not controlled (Fig. 4.6).

4.4.3 Enormous Potential for NaturalGas to Substitute for Coalin Industrial Fueland Residential Heating

Considered from the point of view of pollutantsource, industrial and domestic coal use are nowmajor contributors. In recent years, the level ofpollution prevention and control technology incoal-fired power generation plants in China hasimproved significantly, with the proportion ofpollution produced during power generationsharply dropping, the proportion of pollutionproduced by transportation being relatively low,and emissions improving year by year. This isprimarily as a result of improved vehicles. Forexample, new urban vehicles in China mustcomply with the Europe IV standard, which

0%

20%

40%

60%

80%

100%

1995 1998 2001 2004 2007 2010

Per

cent

age

of n

ew c

oal p

lant

s in

yea

rby

tech

nolo

gy ty

pe

Ultra-supercritical

Supercritical Subcritical

Fig. 4.5 Proportion of new technology use in newly built coal-fired power stations in China. Source Vivid Economics,based on PIRA database

4.4 China’s Achievements in Energy Conservation and Emissions Reduction 109

greatly reduces automobile exhaust pollutantemissions. In terms of main pollutant sourcessuch as sulphur dioxide, nitrogen oxides, PM2.5

and organic carbon (OC), etc., industrial andresidential use are the main sources of emissions(Fig. 4.7).

Conversion from coal to natural gas in indus-trial and residential use is a feasible pollutionprevention and control measure. Different meth-ods have been adopted for the control ofproduction-related and residential pollutant emis-sions and the control of sulphur dioxide emissionsduring the 11th Five-Year Plan. This is because the

dispersal of industrial and residential users andtheir relatively small scale restricts their ability toadopt the same end technology on a significantscale. In contrast, the average scale of new powergeneration stations inChina has tripled since 2004,and there are now 1425 new power stations.Despite the quantity being significant, it is stillsmall compared to the quantity of industrial andresidential user locations in China. Natural gas issuitable for small-scale applications, and thisrepresents an economically valuable approach toreducing coal pollutant emissions from industrialproduction and residential heating.

-

5,000

10,000

15,000

20,000

25,000 tons

Open burning

Sulphurdioxide2005

Sulphurdioxide2011

Nitrousoxide2005

Nitrousoxides2011

Indoor burning Transport and logistics Industry Power generation

Fig. 4.6 Reduction of sulphur dioxide and nitrogen oxides emission during the 11th Five-Year Plan period. Datasource: Vivid Economics, referred from Nelson and Ho (2013)

-

2,000

4,000

6,000

8,000

10,000

12,000 tons

Open burning

OC2005

OC2011

PM2.52005

PM2.52011

Indoor burning

Transport and logistics

Industry

Power generation

Fig. 4.7 Change in the sources of PM2.5 and OC (organic carbon) during the 11th Five-year Plan

110 4 Environmental and Social Value of Natural Gas

Open Access This chapter is licensed under the terms ofthe Creative Commons Attribution 4.0 InternationalLicense (http://creativecommons.org/licenses/by/4.0/)),which permits use, sharing, adaptation, distribution andreproduction in any medium or format, as long as yougive appropriate credit to the original author(s) and thesource, provide a link to the Creative Commons licenseand indicate if changes were made.

The images or other third party material in this chapter areincluded in the chapter’s Creative Commons license,unless indicated otherwise in a credit line to the material. Ifmaterial is not included in the chapter’s Creative Commonslicense and your intended use is not permitted by statutoryregulation or exceeds the permitted use, you will need toobtain permission directly from the copyright holder.

4.4 China’s Achievements in Energy Conservation and Emissions Reduction 111

5Analysis of Medium- to Long-TermNatural Gas Demand and Supply

This section explores various aspects of thedevelopment of industry and the economy, andthe changes in supply and demand of differentenergy sources, considered in combination withprojected changes in economic growth, advancesin technology and shifts in industrial structure.The aim is to determine the medium- tolong-term demand and supply of natural gas andother energy sources in China.

5.1 The Natural GasSupply-Demand Model

In order to analyse and predict the future ofnatural gas demand, a Computable GeneralEquilibrium (CGE) model was devised to reflectmedium- to long-term economic growth andchanges in industrial structure, in terms of totaldemand for energy sources and the interchange-ability between natural gas and other energysources. The CGE model relies on generalequilibrium theory, using actual economic dataas the initial equilibrium, and reflects optimiseddecision-making by the market components

(manufacturers, consumers, government depart-ments). Compared to general economic models,CGE models are more often used for simulatingthe effect that policies have on the economy,whether direct or indirect, making them aneffective tool for analysing policies. The CGEmodel used in this study is based on the Com-putable General Equilibrium model developedand maintained over time by China’s StateCouncil’s Development Research Center(DRC-CGE) for dynamically simulating theeconomy of China. The development of themodel began in 1997; it has been perfected overthe years and applied to studies of the effects ofChina joining the World Trade Organization,infrastructure construction, energy conservation,emission reduction, urbanisation and otherpolicies.

5.1.1 Basic Characteristicsof the Model

The model uses 2010 as the base year and,adopting the Social Accounting Matrix based on2010 input-output tables of China for basic data,simulates the economy from 2010 to 2025. itincludes economic activities from various sec-tors, reflecting five aspects in particular:

• the manufacturing activities of various busi-ness sectors in the economy, and the demandsstemming from such manufacturing activities;

* This chapter was overseen by Zhaoyuan Xu from theDevelopment Research Center of the State Council andMartin Haigh from Shell International, withcontributions from Baosheng Zhang and Shouhai Chenfrom the China University of Petroleum, Lianzeng Zhaofrom the China Petroleum Planning Research Institute,Linji Qiao from ENN and Juan Han from Shell China.Other members of the research group participated indiscussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_5

113

• the economy’s demand for products: the totaldemand coming from the everyday activitiesof the citizens, the government and busi-nesses, as well as from other countries (re-gions), including the three major demands ofconsumption, investment and exports;

• the income, consumption and reserves of eachmajor economic body;

• foreign trade; and• dynamic economic growth and development.

The relationships of these factors are shown inFig. 5.1.

In this study, the model includes all of the 46production industries (as seen in Table 5.1),specifically 1 from agriculture, 5 from mining, 22from manufacturing, 3 from public works andconstruction, and 14 from the service sector.These industries illustrate the production activi-ties of various business categories.

5.1.2 Main Intensificationsand Adjustments MadeTowards Studiesof Natural Gas in ThisModel

Compared to typical CGE models, the one usedin this study made the following major changesto reflect influences on the supply and demandequilibrium of natural gas.

1. Detailed representation of primary energyproduction

To better reflect the input-output and inter-changeability of various energy sources, thisstudy takes into account coal mining and pro-cessing, oil drilling, natural gas extraction, oilrefining, coking, coal power, natural gas power,hydroelectricity, wind power, solar power,

PRODUCTIVE SECTORN

ON

-PR

OD

UC

TIV

ES

EC

TOR

Output

Value added

Total supply

Labour

Capital

Land FAC

TOR

S

DEMAND SECTOR

Intermediate input/demand

Balance of supply and demand

Government consumption

Household consumption

Investment demand

Government income

Household income

Deposit/Investment

TRADE

Export

Import

Fig. 5.1 Main structures of the CGE model used in this study

114 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

Table 5.1 Subdivision of industries in the model of this study

Number Industry Number Industry Number Industry

1 Agriculture, forestryand fishing industry

25 Non-metal mineral productindustry

49 Heat production andsupply industry

2 Coal mining andpreparation industry

26 Ferrous metals smeltingindustry

50 Natural gas productionand supply industry

3 Petroleum industry 27 Steel rolling industry 51 Water supply industry

4 Natural gas drillingindustry

28 Non-ferrous metals smeltingand rolling industry

52 Construction industry

5 Ferrous metals miningindustry

29 Metal products industry 53 Logistics industry

6 Non-ferrous metalsmining industry

30 Equipment manufacturingindustry

54 Urban publictransportation industry

7 Non-metal and othermining industry

31 Special equipmentmanufacturing industry

55 Other transportation andwarehouse industry

8 Food and alcoholicbeverage industry

32 Railway transportation andequipment manufacturingindustry

56 Postal industry

9 Tobacco industry 33 Car manufacturing industry 57 Information transmission,computer and softwareindustry

10 Textiles processingindustry

34 Ship and flotation devicemanufacturing industry

58 Distribution and retailindustry

11 Textiles, knitting andmanufacturing industry

35 Other transportationequipment manufacturingindustry

59 Hospitality industry

12 Clothing, shoe and hatmanufacturing industry

36 Electrical appliancesindustry

60 Financial industry

13 Leather, fur, feathers(down) and relatedproducts industry

37 Electricity supply anddistribution and controlequipment manufacturingindustry

61 Real estate industry

14 Carpentry and furnituremanufacturing industry

38 Household electrical andnon-electrical equipmentmanufacturing industry

62 Rental and commercialservices industry

15 Paper making andprinting industry

39 Other electrical machineryand equipmentmanufacturing industry

63 Research, testing anddevelopment industry

16 Education and physicaleducation equipmentmanufacturing industry

40 Communication equipmentand radar manufacturingindustry

64 Integrated technicalservices industry

17 Oil refinery and nuclearfuel processing industry

41 Computer manufacturingindustry

65 Water conservancy,environment and publicfacilities managementindustry

18 Coking industry 42 Electronic componentmanufacturing industry

66 Personal and otherservices industry

19 Chemical industry 43 Home audio-visualequipment manufacturingindustry

67 Education

20 Fertilisers andagricultural chemicals

44 Other electronicsmanufacturing industry

68 Health, social security andbenefits industry

(continued)

5.1 The Natural Gas Supply-Demand Model 115

Table 5.1 (continued)

Number Industry Number Industry Number Industry

21 Synthesised materialmanufacturing industry

45 Measuring instruments anddevices manufacturingindustry

69 Cultural, physicaleducation andentertainment industry

22 Special chemicalproducts manufacturingindustry

46 Cultural, office machinerymanufacturing industry

70 Public management andsocial organisation

23 Other chemicalproducts

47 Handicrafts and otherproducts (including wasteproducts) industry

24 Plastics and rubberproducts

48 Power generation andsupply industry

nuclear power, natural gas heating, coal heatingand natural gas processing, giving a total of 14types of energy source, thus better reflecting theinterchangeability of energy sources, especiallythe potential of natural gas to replace otherenergy sources.

Based on the national energy policy, thismodel separately configured production func-tions and development scales of different energysources, such as installed capacity of nuclearenergy, hydroelectricity, solar power and others,in order to ensure that they are in accordancewith national planned goals.

2. Detailed representation of characteristicsof the demands of the various sectorstowards natural gas

To examine natural gas demand in detail, thisstudy subdivided industries, in particular indus-tries with higher demand for natural gas. Forexample, the chemical industry was subdividedin order to reflect its demand for natural gas as araw material and the transportation industry wassubdivided in order to reflect its demand fornatural gas.

5.2 Simulation Scenariosfor Analysis Simulationsof Natural Gas Demand

To carry out the simulated analysis of natural gassupply and demand, and to compare variouspolicies, this study has devised two different

scenarios: one is the standard scenario, where thecurrent basic trends of economic growth arereflected, the other is the policy-driven scenario,which includes the effects of government policiesfavourable towards natural gas demand.

5.2.1 Key Assumptionsof the Standard Scenario

In the standard scenario, backed by clearlydesigned policies, relatively assertive growthfactors are observed in the Chinese economy. Onthe other hand, under the influence of ambitiousgovernment policies regarding environmentallyfriendly development and innovation, there arethe following significant changes to the growthfactors:

• Changes in total population and age structurereflecting the influence of the newest popu-lation policy adjustments (one-child policy,two-child policy) in terms of medium- tolong-term total population and workforce.The population of China peaks at around2032, when it will be around 1.463 billion,with the workforce peaking between 2017and 2027, at around 1 billion.

• Growth in personal consumption expenditure,brought about by an increase in incomelevels. Particularly remarkable is the reduc-tion in the percentage of expenditure taken upby food and other consumable goods, whiletravel, leisure, education and expenditure forother services continue to increase.

116 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

• Policies promoting energy conservation andemission reduction, influenced by the attemptto bring about a “new normal” and a varietyof activities targeted at alleviating atmo-spheric pollution, where the governmentcontinues to push for energy conservation andconsumption reduction, raising energy effi-ciency by between 3 and 2% points each year(a higher rate of increase at first, followed bya lower one).

• The new urbanisation policies progresssmoothly, and more of the rural population arenow living in cities. The urbanisation rate willhopefully reach 70% in 2030 and 75% in 2050.

• Personal savings remain at high levels, butthis is expected to gradually reduce as per-sonal income and level of social securityprovision improve. By 2030, the personalsavings rate of urban populations should fallby 13%, from the current rate of 38% toaround 25%.

In addition to the above factors, optimisedpolicies include policies that concentrate in par-ticular on transformation of the mode of eco-nomic development:

• A more significant ratio of renewable energyusage, mainly represented by rapid develop-ments in non-fossil fuel energy sources suchas nuclear power, wind power and solarpower. For nuclear power, the installedcapacity of 14.61 million MW in 2013 willquickly grow to 58 million MW by 2020,reaching 150 million MW by 2030 and400 million MW by 2050. Installed capacityof hydroelectric power plants was 280 mil-lion MW in 2013, and will rise to 340 millionMW in 2020, 400 million MW by 2030 andaround 450 million MW by 2050. Otherenergy sources such as wind power and solarpower will also grow at similar speeds.

• The government places great importance oninnovation-driven development, enablingremarkable breakthroughs in improvingbusiness innovation, the results of which willcontribute to an increased significance ofimprovement in core areas driving economicgrowth, which will become evident by the

13th and 14th Five-Year Plans, at which stagesecondary industry in China will have a highsustainable all-factor growth rate of 4%.

• Mitigation of overcapacity is relativelysmooth, allowing industry to grow continu-ously. This can be observed in the slowinggrowth in investment in heavy and chemicalsindustry while output growth stabilises, atrend that will benefit sustained developmentof the industry.

• The nurturing of tertiary industries, in par-ticular the hastening of the development ofproductive service industries and tertiaryindustries, which will be beneficial in bring-ing in new investment to monopolisticindustries previously difficult to access, suchas finance, logistics, education and health.

• As a result of financial reforms, the proportionof the national economy accounted for byprivate income increases; this is advantageousbecause of raised income levels and theimproved ratio of consumption and invest-ment in the economy.

5.2.2 Key Assumptionsof the Policy-DrivenScenario

In the policy-driven scenario, apart from makingthe same assumptions as the standard scenario,the government will also levy a carbon tax oncoal, oil and natural gas—fossil fuels that resultin greenhouse gas emissions. Pricing for thiscarbon tax collected through carbon trading willbe implemented in 2015 for coal. The carbonprice (or tax rate) for the first year will be 10% ofprice, rising to 20% in the second year, thenremaining at 30% thereafter. The tax rate forpetroleum (including both crude oils and refinedoils) is the tax rate for coal multiplied by thedifference in carbon emission rates, which worksout at 0.64 times the tax rate for carbon price forcoal, while the rate for natural gas is 0.2 timesthe rate for coal, converted based on a coal priceof 500 CNY/ton once the rate reaches 30% (advalorem). This is equivalent to a carbon emis-sions tax (or achieving a carbon price through

5.2 Simulation Scenarios for Analysis Simulations of Natural Gas Demand 117

carbon trading of an equivalent amount) of CNY60 for every ton of carbon dioxide where coal isconcerned.

5.3 Natural Gas Supplyand Demand in the StandardScenario

5.3.1 Speed of Economic Growthand InternationalComparison

Under the assumptions of the standard scenario,China will retain a relatively fast growth rate inthe future. In the two years after the 12thFive-Year Plan, the average economic growthrate is expected to be around 7.3%, with GDP

growth during the 13th Five-Year Plan at around6.66 and 5.56% from 2021 to 2025. In the periodbetween 2026 and 2030, economic growth isexpected to be around 4.64%, around 3.47%from 2031 to 2040 and around 2.73% from 2041to 2050 (Table 5.2).

Based on simulation results, the per capitaGDP of China will continue rising at a relativelyfast rate. For example, by around 2020, percapita GDP in China is hoped to reach $10,000(in 2013 figures, and taking into account anaverage annual 0.5% appreciation of the CNY),while by 2030 per capita GDP in China couldreach $20,000, and $40,000 by 2050, thusachieving a similar level to that current in Japan.If the comparison is made using purchasingpower parity, China’s development level will beeven higher (Fig. 5.2).

Table 5.2 Growth speed and growth momentum in the standard scenario

Year 2013 2014–2015 2016–2020 2021–2025 2026–2030 2031–2040 2041–2050

GDP 7.68 7.31 6.65 5.55 4.63 3.46 2.73

Speed of growthin workforce

0.3 0.1 −0.2 −0.3 −0.5 −0.7 −0.4

Speed of growthin capital deposit

11.6 10.9 9.3 7.7 6.5 4.8 3.2

Data source Based on calculation results

. 0

10000

20000

30000

400000

500000

600000

1960 1970 1980 1990 2000 2010 2020 2030 2040 2050

US

$ (a

ppre

ciat

ion)

China Japan Korea USA

Fig. 5.2 Development levels in China and international comparisons in the standard scenario. Data source Figures forChina after 2013 based on model calculation results, other figures from Wind data

118 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

In the standard scenario, the speed of growthof China’s economy is still higher than the his-torical speed of other “catch-up economies”,while also exhibiting the usual sustained growthcharacteristics encountered with “catch-up”economies. For example, before 2020, there is apossibility that per capita GDP growth in Chinacan be kept above 6%, exceeding the historicalfigures for Japan, Taiwan and the United States,only being lower than historical figures forspecific years in South Korea. The same goes forthe period from 2020 to 2030, when growthspeed in China will far exceed historical figuresfor other countries.

Similar results were obtained from long-termpurchasing power parity calculations using theWorld Bank’s International Comparison Pro-gram. Using this programme, per capita GDP inChina will reach the level of South Korean percapita GDP by 2030 and by 2035 it will be on apar with Japanese per capita GDP, exceedingper capita GDP in the USA in 2050 (Figs. 5.3and 5.4).

5.3.2 Mid- to Long-Term Changesin Industrial Structures

The simulation shows that the tertiary industryratio will continue to rise. In 2013, the tertiaryindustry ratio was 46.1%, which is significantlylower than the level of most countries at a similarlevel of development. In 2015, it rises to around48.1%, and from 2015 to 2020 it will rise by4.9%, possibly exceeding 60% by 2030, reachingaround 65% in 2050 (Table 5.3).

From experience gained with economicgrowth in other countries, as the level of devel-opment rises, the ratio of non-agriculturalindustries also goes up, especially the tertiaryindustry ratio, which seems to be a general norm.Major factors pushing the tertiary industry ratiohigher are the changes in people’s consumerstyles, increased services export ratio and risingdemand for services in various sectors, as well asgovernment spending. Deceleration of exportgrowth also holds sway over tertiary industrialstructure, since the main exports are

14.0

12.0

10.0

8.0

6.0

4.0

2.0

0

-2.0

-4.0

5000 10000 15000 20000 25000 30000 35000 40000 45000 50000

2013

Per

-cap

ita G

DP

gro

wth

rate

(3 y

ear a

vera

ge)

and

econ

omic

dev

elop

men

t lev

el

China Japan S. Korea Taiwan USA

1990 International round (G-Kdollar)

Fig. 5.3 Growth speed in China and international comparisons in the standard scenario. Description Data for Japan,South Korea, Taiwan and USA drawn from historical growth figures; horizontal axis is the international dollarcalculation based on 1990 purchasing power parity calculated using Maddison’s method. Data source Figures for Chinaafter 2013 based on model calculation results, other figures from Maddison

5.3 Natural Gas Supply and Demand in the Standard Scenario 119

manufactured goods and therefore, when otherconditions remain unchanged, a faster growth inexports will most likely lead to a larger corre-sponding secondary industry ratio (Fig. 5.5).

In the period from 2020 to 2025, China willessentially complete the industrialisation process,entering the post-industrialisation era. Looking atthe progress of industrialisation in China, thedemand for heavy industries such as steel andconcrete is approaching its peak, while the east-ern coastal regions are on their way into thepost-industrialisation stage. This developmenttrend conforms to the strategic plans of the 18thNational Congress of the Communist Party ofChina. This is based on two indicators: per capitaGDP (which will exceed $10,000 in 2020 (at

2013 prices) and $14,000 in 2025, achieving thedevelopment standard for post-industrialisation)and secondary industry’s contribution to growth(which will be above 40% before 2020, but willgo through a period of significant decrease after2020). This is similar to the situation in SouthKorea in the 1990s (Table 5.4).

The proportion of high energy consumptionindustries will begin to fall. High energy con-sumption industries are a major factor affectingeconomic structures, and if the proportion ofthem is high, then economic growth requiresmore environmental resources, leading to moreserious pollution. Under optimised policies,towards the end of the 12th Five-Year Plan, it ishoped that the ratio of high energy consumption

14.0

12.0

10.0

8.0

6.0

4.0

2.0

0

-2.0

-4.0

5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

Per

-cap

ita G

DP

gro

wth

rate

(3 y

ear a

vera

ge)

and

econ

omic

dev

elop

men

t lev

el IC

P

China Japan S. Korea Taiwan USA

1990 International round (G-Kdollar)

Fig. 5.4 Growth speed in China and international comparisons in the standard scenario. Data source Figures for Chinaafter 2013 based on model calculation results, other figures from Maddison

Table 5.3 Industry structures in the standard scenario

Year 2010 2015 2020 2025 2030 2035 2040 2045 2050

Primary industries 10.0 9.0 7.1 6.2 5.4 5.0 4.8 4.8 5.1

Secondary industries 48.2 43.0 39.8 35.7 33.4 32.1 30.8 30.0 29.3

Tertiary industries 41.8 48.0 53.1 58.1 61.2 62.9 64.4 65.2 65.6

Data source Results from model calculation

120 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

industries will begin a continual descent, fromaccounting for 32.4% of all industries toaccounting for 28.5% by 2030 and 24.5% by2050 (Fig. 5.6).

5.3.3 Energy Consumptionand Structural Change

Even though China’s national industries showsignificant optimisation in the standard scenario,industry still accounts for a considerable pro-portion of the economy, and along with the risein personal income also comes higher personalenergy use. China’s national energy consumptionis therefore expected to increase greatly in thefuture. It is estimated that by 2020 total nationalenergy source consumption will reach 5 billiontons, an annual increase of 3.4% from 2010 to

2020. The rise should slow between 2020 and2030 to a 1.3% annual increase, reaching around5.68 billion tons, and between 2030 and 2040 therise will be further reined into 0.8% per year, butby 2040 the total national energy consumptionwill still reach 6.06 billion tons. Around 2045,total national energy source consumption inChina will peak and in 2050 it will stabilise ataround 6.1 billion tons (Fig. 5.7).

Even though total energy consumption willcontinue to rise, energy use per unit GDP willdecline considerably, falling from 0.89 tons ofcoal per CNY 10,000 GDP in 2010 to 0.62 tonsof coal per CNY 10,000 GDP in 2020, and thento 0.43 and 0.25 tons of coal per CNY 10,000GDP in 2030 and 2050, respectively (Figs. 5.8and 5.9).

There will also be great structural changes inmedium- to long-term energy source production.

0

20.0

40.0

60.0

80.0

100.0

0 5000 10000 15000 20000 25000 30000 35000 40000 45000

Tertiary industry proportion and economic development level

China Japan

S. Korea

Taiwan

USA

Fig. 5.5 Primary, secondary and tertiary industries in China and international comparisons in the standard scenario.Data source Results from model calculation

Table 5.4 Developedcountries in thepost-industrialisation era

Country Industrialisation stage Post-industrialisation stage

United Kingdom 1760–1870 1950–

United States of America 1790–1900 1950–

Germany 1830–1913 1970–

Japan 1885–1973 1973–

South Korea 1960–1995 1995–

5.3 Natural Gas Supply and Demand in the Standard Scenario 121

0%

5%

10%

20%

30%

40%

15%

25%

35%

2010 2015 2020 2025 2030 2035 2040 2045 2050

Proportion of high energyconsumption industryadded value (current price)

High energy consumptionindustry added valueproportion of GDP(calculated at current price)

Fig. 5.6 Change in high energy consumption industry ratio under baseline scenario. Data source Results from modelcalculation (%)

20

25

30

40

50

65

100

mill

ion

ton

stan

dard

coa

l

Energy Twelfth Five-Year Plan, 2015 energy 400 million tons, 2020 controlled to 480 million tons

60

35

45

55

2010 2015 2020 2025 2030 2035 2040 2045 2050

State of transition of energy consumption volume

State of transition of energy production volume

44.0

50.0

53.3

56.8 59.2

60.5 61.0 60.6

Fig. 5.7 Total energy consumption in standard scenario. Data source Results from model calculation

122 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

Production of the most important primary energysource, coal, will peak in around 2020 at3.07 billion tons of standard coal, or a total of4.3 billion tons of coal. From then onwards, coalproduction will fall annually, dropping to below3 billion tons of standard coal by 2030, below2.5 billion tons by 2040 and around 2.26 billiontons by 2050. As for clean energy, there will begreater development of nuclear power andhydroelectricity; hydroelectricity will grow from230 to 380 million TSCE in 2020, and hope-fully will have reached 460 million TSCE in2030. From that point onwards, however, growthwill slow to a crawl due to limitations inhydroelectric resources, reaching around500 million TSCE by 2050.

Nuclear power appears to have better devel-opment potential. Based on current plans, ifprogress is smooth, nuclear power output inChina will grow from 20 to 130 million TSCEby 2020, and then rise to 320, 550 and760 million TSCE by 2030, 2040 and 2050,respectively.

Looking at the final energy production struc-ture, electricity will see the biggest expansion inmedium- to long-term energy consumption. In2010 electricity consumption was 1.22 billionTSCE, which is anticipated to rise to 2.65 billionTSCE into 2030 and 2.9 billion TSCE in 2050.Consumption of refined oil will also see furtherincreases, from 520 million TSCE in 2010 to850 million TSCE in 2030 and 940 millionTSCE in 2050.

5.3.4 Demand for Natural Gasand Main Increasesin Consumption

In the standard scenario, demand for natural gasis expected to grow rapidly. It is expected toapproach 200 billion m3 in 2015, and exceed300 billion m3 by 2020. By 2030 it may exceed450 billion m3, and exceed 600 billion m3 by2050. Limited by domestic production growth,imports of natural gas (including liquid natural

0

10.0

20.0

30.0

40.0

50.0

60.010

0 m

illio

n to

n st

anda

rd c

oal

2010 2015 2020 2025 2030 2035 2040 2045 2050

24.5

28.6 30.6 30.4 29.8 29.0 27.3 25.2

1.3

2.0

2.8 3.4 4.1 4.7

5.2 5.4

5.5 2.3

3.1

3.8 4.2 4.6 4.9

5.1 5.1

5.0 0.2

0.7

1.3 2.1 3.2 4.2 5.5

6.5 7.6

0.1

0.4

0.7 1.0

1.4 1.8 2.2 2.4

2.7

22.6

Coal

Photovoltaic power

Natural gas Hydro power Nuclear power

Wind power Crude oil

Fig. 5.8 Medium- to long-term energy production structure in China. Data source Results from model calculation

5.3 Natural Gas Supply and Demand in the Standard Scenario 123

gas) are expected to see a major increase, from50 billion m3 in 2015 to 100 billion m3 by 2020and 180 billion m3 by 2030, stabilising by 2040at around 200 billion m3 (Fig. 5.10).

Although fast growth is expected, growth inother energy sources, and in particular powergeneration, is rising, therefore the ratio of totalenergy sources accounted for by natural gas stilllags quite a long way behind target levels. It isexpected that natural gas will make up 6.0% oftotal energy sources by 2015, which is somewhatless than the goal of 7.15% set out in the 12thFive-Year Plan. In 2020 it will be 8.0%, which isstill lower than the planned goal of 10%(Fig. 5.11).

In terms of the main areas where natural gasconsumption is growing, the most important isgas use in power generation. If use of natural gasin power generation becomes economicallycompetitive, allied with strengthened attempts toimprove air quality, it is likely that natural gas usein power generation may rise from 25 billion m3

in 2015 to 50 billion m3 by 2020, and the figureshould then double and exceed 100 billion m3 by2030, finally stabilising after 2040 at around the160 billion m3 mark. Other than natural gas usein power generation, there are three other majornatural gas uses: central heating, transport and thechemical industry.

In the medium to long term, to achieve green,clean power generation it is essential that powersource structures are optimised. One majoraspect of the optimisation of generation would bea reduction in output of coal-based generationand a drop in the proportion of the total resourcesthat it accounts for. Based on simulation analysis,the standard scenario is that coal power genera-tion in China will peak at 5.1 trillion kWh inaround 2020 and then decline from there on, toaround 4.9 trillion kWh by 2030, going downfurther to 4.1 trillion kWh by 2040 and furtherstill to 3.2 trillion kWh in 2050.

The reduction in coal power generation mustbe based on rapid developments in clean power

0

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2010 2015 2020 2025 2030 2035 2040 2045 2050

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18.9 22.6 24.6 26.5 28.0 28.8 29.1 29.0

12.3

11.6

11.3 10.9

10.6 10.2 9.9 9.2 8.6

5.2

6.9

7.5 8.1

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3.6

2.7

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4.0 4.3 4.5 4.4 4.1

1.2

2.2

3.1 3.6

4.0 4.4

4.6 4.7 4.7

Power generation

Crude

Raw coal Coke Thermal power

Refined oil products Natural gas

Fig. 5.9 Medium- to long-term energy consumption structure in China. Data source Results from model calculation.Note Raw coal refers to coal used for purposes other than generating electricity or coke refining

124 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

generation. In the standard scenario, the biggestgrowth lies in nuclear power, while there is alsomuch room for growth for natural gas powergeneration. Natural gas power generation willrise quickly from 77 billion kWh in 2010 to

280 billion kWh by 2020, 620 billion kWh by2030 and around 920 billion kWh by 2050.Similarly, wind power, photovoltaic electricity,hydroelectricity and nuclear power will alsoundergo rapid development (Fig. 5.12).

20

1020

2020

4020

6020

702010

0 m

illion

cub

ic m

etre

s

3020

5020

2010 2015 2020 2025 2030 2035 2040 2045 2050

Natural gas consumptionNatural gas production

1067

1968

3005

3811

4678

5322

5786 5969 6012

Fig. 5.10 Natural gas production and consumption in the standard scenario. Data source Results from modelcalculation

0

2

4

8

12

14

Twelfth Five-Year Plan 2015 natural gasproportion reaches 7.15%, 2020 reaches 10%(sales volume reaches 350 billion cubic metres)

Natural gas consumption proportion of energy consumption

%

6

10

2010 2015 2020 2025 2030 2035 2040 2045 2050

3.9

6.0

8.0

9.5

10.9

11.9 12.7 13.0 13.2

Fig. 5.11 Medium- to long-term changes in ratio of natural gas consumption in China. Data source Results frommodel calculation

5.3 Natural Gas Supply and Demand in the Standard Scenario 125

5.4 Natural Gas Supplyand Demandin the Policy-Driven Scenario

In the standard scenario, even though natural gasconsumption in China will rise to 300 billion m3

by 2020, 450 billion m3 by 2030 and 600 billionm3 by 2050, it would still not reach the goals setout for natural gas development in the medium-to long-term energy development plan of the12th Five-Year Plan. This indicates that, in orderto achieve those goals, in addition to the currentarrangements for energy sources, policies that aremore effective must be put in place to boostnatural gas demand.

5.4.1 Total Natural Gas Supplyand Demand

Among the various possible economic measures,the most effective would be the much-vaunted

pricing policy based on carbon trading and otherways of realising a carbon price. Under thepressure of a global push for reduction ofgreenhouse gas emissions, the introduction of acarbon tax could help to encourage society toreduce its reliance on fossil fuels and reducegreenhouse gas emissions. The use of natural gasproduces much less carbon than coal or oil, andthus carbon pricing will help to further promotethe replacement of coal and oil with natural gas.

In the policy-driven scenario, the demand fornatural gas will increase, due to changes in rel-ative energy source prices that are advantageousto natural gas. Due to the sensitivity of naturalgas to pricing depending upon different uses, theincrease in demand encountered will vary. Someuses, such as household use of natural gas,already contribute a substantial proportion, andthus the increase would be limited in these areas.Other uses, such as power generation and heat-ing, which are more sensitive to pricing, will seea greater relative increase in demand (Fig. 5.13).

0

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trilli

on k

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att h

ours

2010 2015 2020 2025 2030 2035 2040 2045 2050

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4.9 4.6

4.1 3.7

3.2

0.1

0.1

0.3

0.4 0.6

0.8 0.9 0.9 0.9

Photovoltaic power

Wind power

Natural gas electricity production

Nuclear power

Hydro power

Coal

Fig. 5.12 Medium- to long-term power generation structural changes in China. Data source Results from modelcalculation

126 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

With the right policies in place, natural gasdemand in China could be expected to reach344.7 billion m3, achieving the planned goal of350 billion m3 stipulated in the 12th Five-YearPlan. By 2030, natural gas consumption mayapproach the level of 580 billion m3, and bearound 800 billion m3 by 2050.

5.4.2 Effects on Pollutant Dischargeof Natural Gas ConsumerDemand Growth

Under the influence of policy, demand for naturalgas will grow and will replace major coalapplications, so the use of natural gas will beeffective to some degree in restricting emissionsof various pollutants (Fig. 5.14).

Based on emissions of 2.46 tons of CO2,8.5 kg of SO2 and 7.4 kg of nitrogen oxides forevery one ton of standard coal burned (whenapproaching zero emissions, each one ton ofstandard coal burned results in 0.14 kg of SO2

and 1.12 kg of nitrogen oxides), under thepolicy-driven scenario, natural gas consumptionwill increase from 183 billion m3 in 2014 to575.6 billion m3 by 2030, equivalent to at least

522 million tons of standard coal based oncalorific value. Based on this, it would be pos-sible to reduce emissions to 418 million tons ofSO2 and 4.354 million tons of CO2 (replacing20% of near-zero emission coal-fired powergeneration and 80% of dispersed coal use) by2030. This is the equivalent of 21.3% of thenational SO2 emissions total of 20.439 milliontons in 2013. There will also be a reduction innitrogen oxides emissions of 2.339 million tons,which is the equivalent of 10.5% of the nationalnitrogen oxides emissions total of 22.274 milliontons in 2013. Moreover, by 2020 there will befurther reductions of CO2 emissions by172 million, of SO2 emissions by 1.794 milliontons and of nitrogen oxide emissions by964,000 tons.

In a policy-driven environment, it is possibleto markedly reduce greenhouse gas emissions. Ina baseline scenario, greenhouse fossil fuel energyconsumption in China is expected to continue togrow in terms of emissions in China each yearfrom the 13th Five-Year Plan to 2030. In 2015,greenhouse gas emissions caused by fossil fuelsare expected to reach 9.51 billion tons (due tocarbon exchange and other factors, greenhousegas emissions caused by fossil fuel consumption

20

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2020

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ion

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2010 2015 2020 2025 2030 2035 2040 2045 2050

Natural gas consumptionNatural gas production

1067

1985

3447

4531

5756

6715

7465 7828 7951

Fig. 5.13 Natural gas supply and demand in the policy-driven scenario. Data source Results from model calculation

5.4 Natural Gas Supply and Demand in the Policy-Driven Scenario 127

is not equivalent to the total national emissionstotal), and by 2020 will approach 10.5 billiontons, an annual increase of 1.93%. By 2030 itwill approach 11 billion, growing annually by0.95% from 2020 to 2030, peaking in 2033 atapproximately 11.08 billion tons. Subsequentlyit will gradually decline. In a policy-drivenenvironment, because overall fossil fuel energyconsumption will see a major reduction, theresulting greenhouse gas emissions also mark-edly drop. In 2015, there is expected to be areduction in emissions of approximately 400million tons compared to the baseline scenario.CO2 emissions reductions from 2020 to 2030will be approximately 1.7 billion tons.

5.4.3 Main Areas of Natural GasDemand

In the policy-driven scenario, areas where naturalgas demand would grow quickly are still the onesmore sensitive to costs and prices, namely naturalgas power generation, transport and the chemi-cals industry, while changes in demand remainrelatively small in other areas such as domestic

use. For example, with the policies in place,compared to the standard scenario, domestic usewould only rise by 5 billion m3 by 2050, whilefor natural gas power generation the consump-tion in 2030 would be 45 billion m3 highercompared to the standard scenario. Natural gasheating possesses tremendous potential and isvery sensitive to costs. With policies in place itcould be hoped that consumption might rise by30 billion m3 by 2030.

Based on the simulation results, in thepolicy-driven scenario natural gas consumptionin China reaches 600 billion m3 by 2030. Of thattotal, urban use (including vehicular and water-borne transport) accounts for 35%, while 32%goes to power generation, 27% to industrial fuelsand 6% is used in the chemicals industry. Urbanuse mainly consists of cooking, hot water foreveryday use, gas use in public utilities (airport,government departments, staff canteens, kinder-gartens, schools, hostels, hotels, restaurants,malls, offices etc.), centralised heating, cen-tralised air conditioning and being used byvehicles and ships. As for industrial use, naturalgas is used as fuel for equipment used in variousindustries, including pottery, glass, steel,

0

2

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Twelfth Five-Year Plan 2015 natural gasproportion reaches 7.15%, 2020 reaches 10%(sales volume reaches 350 billion cubic metres)

Natural gas consumption proportion of energy consumption

%

6

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18

10

2010 2015 2020 2025 2030 2035 2040 2045 2050

4.1

6.4

10.8

13.1

15.4

17.0

18.3 18.7 18.8

Fig. 5.14 Ratio of natural gas in total energy sources in the policy-driven scenario. Data source Results from modelcalculation

128 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

petrochemicals, textiles, aluminium oxide, tita-nium dioxide, fire-resistant materials, carbonresources and so on. In the chemicals industry,natural gas is mainly used as an ingredient for thesynthesis of ammonia and methanol and inhydrogen production. In power generation, nat-ural gas is used in peak regulation power sta-tions, thermal power stations and by distributedenergy source users. There is, therefore, massivepotential natural gas demand (Table 5.5).

5.4.4 Demand Curve for Natural Gasin China in 2030

1. Predicted replacement energy source priceseries

With consideration given to the long-termtrends in international oil prices, this analysis isbased on an international oil price of $80 perbarrel (Table 5.6).

2. Demand curve for natural gas in 2030

The demand for natural gas in China in 2030is expected to be 576.6 billion m3, subdividedbetween 31 provinces and 16 types of user.Assessment of terminal natural gas price toler-ance for all users in all provinces was carried outbased on the local price of replacement energysources. Conversion was then carried out basedon the Shanghai benchmark price conversion,with the natural gas price tolerance based on theShanghai benchmark being ranked from high to

Table 5.5 Natural gas consumption based on primary usage (100 million m3) according to use

Major fields of application 2013 2030 Growth(%)Consumption Proportion

(%)Consumption Proportion

(%)

Urban gas Residentialliving

181 11.0 520 9.03 187

Commercialservices

104 6.3 300 5.21 188

Centralisedheating

97 5.9 360 6.25 271

Vehicular andwaterbornetransport

CNG taxis 59 3.6 160 2.78 171

CNG buses 32 1.9 90 1.56 181

LNG lorries 33 2.0 550 9.56 1567

LNG vessels 45 0.78

Natural gaselectricityproduction

Peakregulationpower stations

157 9.5 640 11.12 308

Thermalpower stations

126 7.6 1060 18.42 741

Distributedenergy sources

4 0.2 130 2.26 3150

Industrial fuel 606 36.7 1540 26.75 154

Natural gaschemicalengineering

Ammonia 152 9.2 185 3.21 22

Methanol 61 3.7 106 1.84 74

Hydrogenproduction etc.

41 2.5 70 1.22 71

Total natural gas consumption 1653 100 5756 100 248

Data source Results from model calculation

5.4 Natural Gas Supply and Demand in the Policy-Driven Scenario 129

Table 5.6 Natural gas energy source replacement price list by province (calculated at the international oil price of $80per barrel)

No. Region Coalprice

Fueloilprice

Naphthaprice

93#petrolretailprice

0#dieselretailprice

SmallbottleLPGprice

LargebottleLPGprice

Industrialelectricityconsumptionprice

Householdelectricityconsumptionprice

(CNY/t) (CNY/L) (CNY/kg) (CNY/kWh)

1 Xinjiang 316 2553 7096 5.86 5.74 7.19 6.83 0.36 0.53

2 Gansu 507 2553 7155 6.01 5.85 7.24 6.88 0.46 0.51

3 Qinghai 519 2553 7252 6.00 5.86 7.24 6.88 0.36 0.45

4 Tibet 507 2727 7083 6.00 5.86 8.20 7.79 0.36 0.45

5 Ningxia 478 2553 6959 6.03 5.83 5.76 5.48 0.43 0.45

6 Shaanxi 450 2553 7126 6.01 5.83 6.30 5.98 0.55 0.50

7 Shanxi 460 2595 6988 6.08 5.88 7.62 7.24 0.50 0.48

8 InnerMongolia

444 2595 7080 6.04 5.83 7.62 7.24 0.48 0.47

9 Henan 565 2594 6990 6.04 5.85 6.86 6.52 0.60 0.56

10 Hubei 628 2594 6993 6.04 5.85 8.49 8.07 0.60 0.57

11 Hunan 606 2594 6997 6.08 5.90 8.03 7.63 0.65 0.59

12 Jiangxi 666 3722 6990 6.07 5.88 6.85 6.51 0.65 0.60

13 Anhui 674 3722 6985 6.06 5.87 6.93 6.58 0.65 0.57

14 Yunnan 539 2727 7018 6.18 5.98 7.62 7.24 0.48 0.48

15 Guizhou 506 2727 6991 6.16 5.95 8.20 7.79 0.51 0.46

16 Sichuan 561 2727 7028 6.19 6.02 7.28 6.91 0.58 0.47

17 Chongqing 534 2727 6974 6.19 6.01 6.98 6.64 0.63 0.52

18 Guangdong 675 3548 6992 6.09 5.89 8.23 7.82 0.69 0.61

19 Guangxi 677 3548 7000 6.14 5.94 8.44 8.02 0.59 0.53

20 Fujian 661 3722 6982 6.08 5.89 7.98 7.58 0.61 0.45

21 Hainan 678 3548 6960 6.14 5.94 8.19 7.78 0.66 0.61

22 Jiangsu 632 3722 6978 6.07 5.86 7.40 7.03 0.64 0.53

23 Zhejiang 701 3722 6978 6.07 5.88 8.14 7.73 0.65 0.54

24 Shanghai 615 3722 6946 6.35 6.24 7.20 6.84 0.69 0.62

25 Beijing 580 2595 6953 6.36 6.26 7.62 7.24 0.62 0.49

26 Tianjin 580 2595 6950 6.03 5.83 7.62 7.24 0.63 0.49

27 Hebei 596 2595 6993 6.03 5.83 7.02 6.67 0.56 0.52

28 Shandong 556 3722 6988 6.03 5.84 7.81 7.42 0.67 0.55

29 Liaoning 499 2891 7352 6.03 5.83 7.47 7.09 0.53 0.50

30 Jilin 645 2891 7320 6.03 5.83 6.51 6.18 0.58 0.53

31 Heilongjiang 623 2891 7394 6.03 5.83 6.33 6.01 0.58 0.51

130 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

low, yielding the demand curve for natural gas inChina in 2030 (Fig. 5.15).

3. Various integrated policies would berequired in order to achieve a 575.6 billionm3 natural gas consumption

If a pricing policy is not implemented,achieving a target of 575.6 billion m3 of naturalgas consumption by 2030 would require a seriesof alternative policies to be introduced. Based onthe national natural gas pricing reform plan of2013, with an international oil price of $80 perbarrel as the basis, it is calculated that thebenchmark Shanghai natural gas price would be2.6 CNY/m3. Looking at the effective demandcurve for natural gas, the planned natural gas

consumption in China by 2030 would be575.6 billion m3, and with reference to thebenchmark Shanghai natural gas price of2.6 CNY/m3 and effective consumption of206.7 billion m3, this would account for 32% ofestimated demand. Urban natural gas centralisedheating, power generation, synthesis of ammoniaand methanol, and the majority of usage as fuelin other industries would not satisfy the condi-tions for generation of effective demand capacitybased on the benchmark Shanghai natural gasprice of 2.6 CNY/m3 (Table 5.7).

At the current energy source pricing levels,market forces alone would not push demand fornatural gas up to the goal of 575.6 billion m3. Sys-tematic design of policy which reflects the environ-mental and social value of natural gas is necessary.

0 1000 2000 3000 4000 5000 6000

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ngha

i ben

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ark

pric

e (Y

uan/

m3 )

Demand (108 x m3)

Natural gas chemicals Urban fuel Vehicular and waterborne Industrial fuel Natural gas power generation

Fig. 5.15 Demand curve for natural gas in China in 2030

5.4 Natural Gas Supply and Demand in the Policy-Driven Scenario 131

Table 5.7 Market demand for natural gas in China in 2030 (100 million cubic metres)

Major fields of application 2030 2030 market demand (nopolicy measures)

Actualdegree(%)Consumption Proportion

(%)Consumption Proportion

(%)

Urban gas Residentialliving

520 9.03 516 28.30 99

Commercialservices

300 5.21 292 16.02 97

Centralisedheating

360 6.25

Vehicular andwaterbornetransport

CNG taxis 160 2.78 160 8.77 100

CNG buses 90 1.56 90 4.93 100

LNG lorries 550 9.56 366 20.09 67

LNG vessels 45 0.78 10 0.57 23

Natural gasgeneration

Peakregulationpower stations

640 11.12

Thermalpower stations

1060 18.42

Distributedenergy sources

130 2.26

Industrial fuels 1540 26.75 315 17.29 20

Natural gaschemicalengineering

Ammonia 185 3.21

Methanol 106 1.84 2 0.12 2

Hydrogenproduction etc.

70 1.22 70 3.84 100

Total natural gas consumption 5756 5756 100% 1824 100

Data source Results from model calculation

Open Access This chapter is licensed under the terms ofthe Creative Commons Attribution 4.0 InternationalLicense (http://creativecommons.org/licenses/by/4.0/),which permits use, sharing, adaptation, distribution andreproduction in any medium or format, as long as yougive appropriate credit to the original author(s) and thesource, provide a link to the Creative Commons licenseand indicate if changes were made.

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132 5 Analysis of Medium- to Long-Term Natural Gas Demand and Supply

6Analysis of China’s Natural Gas UsePolicies and Suggested Reforms

6.1 Development of China’sNatural Gas Use Policy

6.1.1 The Encouraging ConsumptionStage

Before the Shaan-Jing natural gas pipeline beganoperation in 1997, China’s only gas pipeline toreach a length of over 350 km was the HongKong offshore gas pipeline (Yacheng–HongKong, 778 km). Owing to the lack ofcross-regional gas pipelines, natural gas in Chinawas characterised by being produced in nearbyfields. At that time, the two most importantmarkets for natural gas were Sichuan and theNorth East. The Sichuan Basin has a long historyof developing natural gas and already has ahighly developed network of pipelines. TheNorth East gas fields can produce high-qualityoil-associated gas. The main uses of natural gasare primarily in the chemical industry, where it isused to produce methanol and fertilisers. Muchassociated gas is vented or consumed by oilcompanies during production. Urban gas andindustrial fuel usage is limited to areas adjacent

to sources, and only constitutes a fraction of totalnatural gas consumption (see Table 6.1).

China’s natural gas exploration in the 1990swas extremely fruitful. In total, nine large gasfields and 32 medium-sized gas fields were dis-covered. Taken together, these make up the sixmajor gas regions of Sichuan, Ordos, Tarim,Qaidam, the East China Sea and the Ying-Qiongarea, of which the Jingbian gas field is the largest,with proven reserves of 290.09 billion m3. Thediscovery of large natural gas reserves stimulatesthe construction of long-distance gas pipelines.These include the Shaanxi gas entry to Beijing,western gas being piped east, Sichuan gas beingpiped east and offshore gas terminals. In 2003the IEA noted that the development of China’snatural gas market had many obstacles to over-come, the first being increasing demand fornatural gas. At that time, the main problemsfacing the natural gas industry were competingwith cheap coal and creating demand for, ratherthan restricting use of, natural gas.

6.1.2 Restricted Usage Stage

With the completion of the western gas pipedeast project, a new era in the development ofChina’s natural gas markets commenced. Themarkets changed from being regional to beingnational, freeing up supply and leading to a sharpincrease in production. This brought about a shiftin market trends. There had previously beenworries that there were not enough consumers ofnatural gas, but suddenly there was not enoughsupply to meet the demand. In 2005, the National

* This chapter was overseen by Zhaoyuan Xu from theDevelopment Research Center of the State Council andMartin Haigh from Shell International, withcontributions from Baosheng Zhang and Shouhai Chenfrom the China University of Petroleum, Lianzeng Zhaofrom the China Petroleum Planning Research Institute,Linji Qiao from ENN and Juan Han from Shell China.Other members of the research group participated indiscussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_6

133

Development and Reform Commission tried toadjust prices in order to regulate the use of nat-ural gas. This led to the decision to revise themanufacturer’s natural gas pricing mechanism,raising the manufacturer’s natural gas price by anappropriate amount, encouraging gas use effi-ciency, optimising gas use structures and pro-moting healthy and sustainable development ofindustrial gas use, all in order to ensure suppliesto the Chinese natural gas market. It was madeknown that all oilfield gas not subject to planningwould be treated as second-grade gas and wouldbe priced based on the government guidelines at980 CNY/1000 m3. Price increases would belimited to 10%, but there would be no bottomlimit. The price of first-grade gas was raised byan appropriate amount, the government beingresponsible for price regulation, with upper andlower limits of 10% (see Table 6.2).

The 2005 natural gas price adjustment stillfailed to effectively curb the rapid growth indemand for natural gas. This was largely due tothe price of gas being relatively low, concentrateddevelopment of the gas-based chemicals industryin areas adjacent to gas production sources and amad rush to develop low added value, shortindustrial chain methanol and fertiliser plants in

various areas. In August 2007, in order to resolvethe conflicts arising in supply and demand, theNational Development and Reform Commissionissued a new natural gas use policy. The Com-mission divided natural gas use into four distinctcategories (priority, permitted, restricted andprohibited) and took an interventionist policytoward its use. Such measures prioritisedeco-friendly urban gas uses (see Table 6.3).

6.1.3 Flexible Restrictions Stage

The Chinese government has implemented manypolicies to meet the growing domestic demandfor natural gas. First, it aimed to limit large-scalenatural gas and chemical projects. Second, itraised gas prices to encourage natural gas pro-duction and imports. Between 2002 and 2012,China’s natural gas production more than dou-bled, from 32.7 to 107.2 billion m3. During thistime, China was also actively importing overseasresources. On May 25, 2006 the first shipment ofLNG entered Dapeng Bay in Shenzhen fromAustralia’s North West Shelf. This marked thebeginning of a new era for China’s imports ofnatural gas. In 2010, the Central Asian gas

Table 6.1 China’s natural gas consumption structure in 1998 (excluding Hong Kong)

Item Gas used in the chemicalsindustry

Industrialfuels

Urbangas

Oilproduction

Miscellaneous Total

Consumption(�108 m3)

89.64 18.53 24.12 56.68 13.6 202.57

Percentage 44.25 9.1 11.9 28 6.7 100

Data source National Bureau of Statistics

Table 6.2 Natural gas prices in 2005 after price adjustments (CNY/1000 m3)

Sichuan-Chongqinggas fields

Changqing gasfields

Qinghai oilfields

Xinjiang oilfields

Other oilfields

First-gradegas

Gas forfertiliser

690 710 660 560 660

Industrialgas

875 725 660 585 920

Urban gas 920 770 660 560 830

Second-gradegas

980

134 6 Analysis of China’s Natural Gas Use Policies …

pipeline began delivering gas to China and in2013 the China-Burma pipeline was broughtonline. Based on the Natural Gas DevelopmentPlan, China’s annual imports of natural gas willreach 93.5 billion m3 by 2015, which willaccount for one third of the entire gas supply.This increase in the supply of offshore gasresources, in conjunction with the rapid increaseand growth of domestic natural gas production,means that the hitherto problematic situation ofChina’s gas supply has been greatly eased.

In October 2012, the National Developmentand Reform Commission adapted its policy onnatural gas use (see Table 6.4) and relaxedrestrictions on a number of specific gas usefields:

• In terms of policy objectives, there was nolonger an emphasis on relieving conflictsbetween supply and demand. Encouragementof a low-carbon economy was added, as was

Table 6.3 2007 natural gas usage policy

Order ofpriority

Field of use

Highestpriority

Urban gas 1. Cities (especially medium-large cities), residential cooking, boiling water andother residential uses

2. Public service facilities (airports, government offices, canteens, nurseryschools, schools, hotels, restaurants, shopping centres, office buildings, etc.)

3. Natural gas vehicles (especially dual-fuel vehicles)4. Distributed co-generation and CCHP users

Permitted Urban gas 1. Centralised heating (in city centres)2. Individual household heating3. Central air conditioning

Industrial gas 4. Industrial fields in which natural gas may replace oil or LPG, such as forbuilding materials, machinery, textiles, petrochemicals and metallurgy

5. Industrial fields in which natural gas is a more sustainable substitute than coalgas, or is economically beneficial. Examples include building materials,machinery, textiles, petrochemicals and metallurgy and other industrial fieldswhere adoption of natural gas offers relatively high environmental andeconomic benefits

6. Building materials, machinery, textiles, petrochemicals, metallurgy

Natural gas powergeneration

7. Construction of natural gas peak regulation infrastructure for main powerloading centre(s) in regions with sufficient natural gas supplies

Gas chemicalindustry

8. Economically beneficial hydrogen gas projects that consume gas on a smallscale

9. Ammonia and fertiliser producers that would be incapable of moving orcategory 1 and 2 users to which the regulations do not apply

Restricted Natural gas powergeneration

1. Construction of natural gas power stations in non-crucial power loadingcentres

Gas chemicalindustry

2. Extension of pre-existing synthetic ammonia facilities relying on natural gas,conversion of synthetic ammonia facilities from coal to natural gas

3. Carbon 1 chemical engineering projects with primary methane-basedproducts, including acetylene and chloromethane

4. New synthetic ammonia projects relying on natural gas, other than thoseincluded in item 9 of category 2

Prohibited Natural gas powergeneration

1. Construction of base-load natural gas power stations in 13 large-scale coalmining regions including Shaanxi, Mongolia, Shanxi and Anhui

Gas chemicalindustry

1. New construction or extension of methanol production facilities relying onnatural gas

2. Projects for the replacement of coal with natural gas for the production ofmethanol

6.1 Development of China’s Natural Gas Use Policy 135

Table 6.4 2012 natural gas usage policy

Order ofpriority

Field of use

Highestpriority

Urban gas 1. Urban areas (especially medium-large cities), residential cooking, boilingwater and other residential usages

2. Gas used for public service facilities (airports, government offices, canteens,nursery schools, hospitals, hotels, bars, restaurants, department stores, officebuildings, stations, welfare offices, old people’s homes, harbours, pierterminals and bus stations)

3. Natural gas vehicles (especially dual-fuel and liquefied natural gas vehicles),including city buses, taxis, commercial vehicles, passenger vehicles,sanitation lorries and other transport vehicles that rely on natural gas as fuel

4. Centralised heating (in city centres)5. Gas air conditioning

Industrial gas 6. Building materials, machinery, textiles, petrochemicals, metallurgy7. Interruptible hydrogen manufacturing projects relying on natural gas

Other users 8. Natural gas distributed energy projects (comprehensive energy efficiencyabove 70%, including the use of renewable energy sources)

9. As fuel in sea-going, river-going and lake-going vessels (includinggas-fuelled and dual-fuelled vessels) that rely on natural gas (especially LNG)

10. Towns that have an emergency and peak regulation natural gas storagefacilities

11. Coalbed methane (marsh gas) power generation projects12. Natural gas co-generation projects

Permitted Urban gas 1. Individual household heating users

Industrial gas 2. Projects in which natural gas is used as a replacement for oil or LPG, such asbuilding materials, machinery, textiles, petrochemicals and metallurgy

3. New projects where natural gas is used as fuel, including building materials,machinery, textiles, petrochemicals and metallurgy

4. Projects where the adoption of natural gas as a replacement for coal offersenvironmental and economic benefits, including building materials,machinery, textiles, petrochemicals and metallurgy

5. Urban projects for conversion of industrial boilers to gas (especially inmedium-large cities)

Natural gas powergeneration

6. All natural gas power projects excluding item 12 in the first category and item1 in the fourth category

Gas chemicalindustry

7. Natural gas hydrogen production projects excluding item 7 in the firstcategory

8. Small natural gas liquefaction facilities for peak regulation and storage

Restricted Gas chemicalindustry

1. Extension of existing natural gas-based ammonia plants and conversion ofammonia plants from coal to natural gas

2. Carbon 1 chemical engineering projects with primary methane-basedproducts, including acetylene and chloromethane

3. New urea fertiliser projects that use natural gas as raw material

Prohibited Natural gas powergeneration

1. Base-load power generator construction projects in 13 large-scale coal miningregions including Shaanxi, Mongolia, Shanxi and Anhui (excluding coal bedmethane (marsh gas) power generation projects)

Gas chemicalindustry

2. New construction or extension of natural gas-based methanol plants anddownstream methanol production projects

3. Projects for methanol manufacturing using natural gas as replacement of coal

136 6 Analysis of China’s Natural Gas Use Policies …

increasing the proportion of primary energysources accounted for by natural gas.

• Restrictions applicable to natural gas powerwere relaxed, but the prohibition on gaspower construction projects (excluding coal-bed methane (marsh gas) power generationprojects) in 13 regions with large-scale coalbases continued, including Shaanxi, InnerMongolia, Shanxi and Anhui. The categoriesof other natural gas-based power generationprojects were changed from “permitted” or“prohibited” to “highest priority” and“permitted”.

• There was relaxation of restrictions on use ofnatural gas as an industrial fuel, in centralisedheating and by interruptible users in the fieldsof building materials, machinery and elec-tronics, textiles, the petrochemicals industry,metallurgy and other industrial fields, whohad their categories changed from being“permitted” to “highest priority”.

6.2 “Optimisation” of Natural GasUse Structures and Policies

China’s policy on natural gas use clearly statesthat one of its main goals is to optimise thestructure of natural gas use. So what exactly are“optimised” gas use structures, and how is their“optimisation” to be achieved?

6.2.1 China’s Natural Gas UseStructure

The structure of natural gas usage refers to theproportion of natural gas used in different areasrelative to overall consumption. Before 2000,due to a lack of inter-regional pipelines, oil fieldproduction self-usage and chemical engineeringadjacent to oil fields accounted for the vastmajority of China’s natural gas consumption.Urban gas and gas used for generating poweraccounted for a very small proportion (seeTable 6.5). Once long-distance pipelines werebrought online, the gas-using regions spreadfrom being concentrated around oil and gas fieldstowards the more economically advanced centraland eastern regions (see Table 6.5). In 2013, outof a total consumption of 166 billion m3 of nat-ural gas in China, urban gas (including gas usedin vehicular and waterborne transport) andindustrial fuel consumption together accountedfor 67% of total consumption.

6.2.2 Worldwide There Is no SuchThing as “Optimised” GasUse Structure

In 1998, the chemical industry accounted for44.5% of Chinese natural gas consumption. By2007, this proportion had dropped to 30%. In2007, when natural gas use policy was introduced,the structure of China’s natural gas use was far

Table 6.5 2003–2011 China natural gas use structure

2003 2004 2005 2006 2007 2008 2009 2010 2011

Oil field internal use 79.44 72.77 78.88 77.44 85.59 104.41 117.40 129.55 126.04

Power generation andheating

7.54 12.74 18.78 29.49 70.74 73.92 127.91 180.80 215.90

Industrial fuels 45.71 70.22 89.69 99.62 116.29 153.24 155.75 183.29 264.5

Chemical engineering rawmaterials

128.13 122.90 141.44 177.42 207.05 200.03 176.84 187.28 233.48

Transport and logistics 18.82 26.16 38.01 47.24 46.88 71.55 91.07 106.70 138.35

Commercial use gas 6.85 9.18 10.79 13.16 17.11 17.75 23.96 27.24 33.64

Residential 79.43 102.63 143.39 170.10 177.70 226.90 264.38

Other gas use 14.14 9.12 12.77 16.09 20.92 23.64 26.00 27.14

Total 286.49 328.11 466.14 559.77 703.14 811.92 894.27 1067.76 1303.46

Unit 108 m3

6.1 Development of China’s Natural Gas Use Policy 137

from ideal, mainly reflected by the chemicalindustry accounting for a disproportionately largeproportion of total natural gas consumption. Inlight of this, the natural gas chemicals industryshould have been classified as a restricted orprohibited gas use field. In 2011, gas use in thechemical industry dropped to 18%, then 15% in2013. In 2012, when the National Developmentand Reform Commission issued the gas use pol-icy, the main objectives were still optimising gasuse structure and restricting and prohibiting use ofnatural gas in chemical engineering.

Global natural gas use structures can be divi-ded into three types: a balanced structure type, amainly power generation type and an urban gasuse type. The United States is a typical balancedstructure, with urban gas, power generation andindustrial gas (including industrial fuels and gasfor use in chemical engineering) each constitutingroughly one third. Japan, South Korea and Russiause natural gas predominantly for power genera-tion. Japan, for example, used 94.5 billion m3 ofnatural gas in 2010, of which 60% was used toproduce electricity. After the Fukushima nuclearaccident in 2011, an even higher proportion ofnatural gas was used to generate electricity.Consumption of natural gas in The Netherlandsand the United Kingdom, two Western Europeancountries, is predominantly urban. In 2010, theDutch consumed 43.6 billion m3 of gas, of whichurban gas accounted for 56%, industrial fuels for33% and power generation usage for 11% (Canqi2014: 1–2). Looking at the historical develop-ment of China’s natural gas output in the light ofthe experiences of other countries, it is clear thatthere is no such thing as a standard optimisedstructure in terms of natural gas use.

Even though there is no standard optimisedstructure, it doesn’t mean that standards don’texist for the optimisation of natural gas use. TheNational Development and Reform Commissionin its policy on gas use proposed that the use ofnatural gas should be optimised according tothree criteria: social benefit, environmental ben-efit and economic benefit, though it does notdefine what is meant by social, environmentaland economic benefits. However, based on theorder in which they apply to gas use, “social

benefit” refers to living standards and the guar-antee of residential gas supplies, in order to avoidsocial unrest due to gas shortages. This is whythe domestic uses of cooking and boiling havebeen listed as prioritised areas of gas use. Envi-ronmental benefits include the reduction ofemissions. This is the reason for the inclusion ofgas-powered vehicles, centralised heating,industrial fuels, distributed energy resources andco-generation in the “permitted” and “top prior-ity” categories. Finally, economic benefits con-cern profits derived from market sales, andtherefore it is the overruling factor in decidingthe prioritisation of natural gas use. The “opti-misation” of natural gas use structures shouldtherefore seek to maximise social, environmentaland economic benefits.

6.2.3 Market Pricing AdjustmentsWould AutomaticallyResult in “Optimisation”of Natural Gas UseStructures

In order to “optimise” natural gas use structures,the National Development and Reform Com-mission developed a specific gas use policy. Thispolicy also classifies the use of gas as beingeither highest priority, permitted, restricted orprohibited, and thus established the order ofpriority. Chinese economist Hua Ben analysedthe capacity and affordability of five markets inthe lower reaches of the Yangtze in terms ofpower generation, urban gas, industrial andcommercial fuels, transportation fuels andchemical raw materials. He then performed afeasibility study on natural gas, concluding that,given that natural gas costs 2.5 times more forthe same calorific value when compared to coaland other fuels, a combined cycle power plantcannot compete with coal power generation interms of basic load and can only be used for peakregulation. Urban use of gas fuel is lessprice-sensitive, but the volume used is limited.Industrial and commercial gas use is the largestend user market for natural gas. CCHP systemsimprove natural gas pricing tolerance and are

138 6 Analysis of China’s Natural Gas Use Policies …

currently key to the efficient use of natural gas inChina. LNG has advantages as a vehicle gas fuel.Compared to coal, natural gas is not economi-cally viable for use as a raw material in thechemical engineering industry. Based on HuaBen’s theoretical results, there is absolutely noneed for the government to implement gas usepolicies, as price adjustments will automaticallyresult in “optimisation” of gas use structures andnatural gas is not economically viable for use inpower generation or as a raw material in chem-ical engineering.

Regarding the problem of the use of naturalgas in chemical engineering, however, it is likelythat natural gas producers and local governmentsin gas-producing areas may have applied differ-ent methods of calculation. Where natural gasproducers are concerned, due to the natural gasprice being controlled by the government, rev-enues from external sales of natural gas arelimited, while they are required to provide peakregulation and ensure supplies. However, devel-opment of industrial natural gas use near oil andgas fields is stable, since natural gas costs lesswhen the price doesn’t include a transport ele-ment. In addition, there is no regulation of theprice of chemical products, allowing higherlevels of income to be achieved. From the per-spective of local governments in naturalgas-producing regions, external sale of locallyproduced natural gas results in meagre earningsfrom resource tax (5% of the selling price).Therefore, local development of a natural gaschemical industry will not only help increaselocal tax revenue and provide employment, butcan also promote local economic development.When one does the math, this is an additionalimpetus for natural gas producers and govern-ments in gas-producing regions to develop thenatural gas chemicals industry.

A basic approach to “optimising” gas usestructure involves natural gas tax reform andenvironmentally-friendly policy, accompanied byreorganisation of the natural gas pricing mecha-nisms, all which should work together so thatnatural gas projects that bring greater social andenvironmental benefits have access to greatereconomic benefits as a result. It is preferable to

reduce the effects of government intervention inspecific markets to a minimum. Experience ofgovernment interference in natural gas marketsbetween the mid-1950s and the 1980s in theUnited States has already taught us the lessonthat, whether pricing controls or usage controlsare employed, neither are helpful in the devel-opment of a healthy natural gas industry.

6.3 Natural Gas Use and NaturalGas Price Controls

6.3.1 Natural Gas Price ControlPolicies in China

Due to the existence of a monopoly in the naturalgas market, it has been difficult for market pric-ing mechanisms to emerge, and thus natural gasprices have always been controlled by the gov-ernment in China. The prices at which upstreamcorporations sell natural gas are determined bythe National Development and Reform Com-mission, and the prices at which the downstreamcorporations sell natural gas are determined bypricing departments within local government.Before the natural gas price reforms of June2013, the National Development and ReformCommission set manufacturers’ natural gas pri-ces according to the price of alternative energysources (limiting increases to 10%, with no bot-tom limit), with gas being priced differently fordifferent uses. In the natural gas price reforms of2013, the National Development and ReformCommission decided to use alternative energysources as a pricing reference, and, based onconsiderations of the main directional flow ofnatural gas market resources and pipeline costs,established gate prices by the netback marketvalue method. The gate prices are set temporarilyand adjusted annually, and no further distinctionis made regarding different uses, while the goal isto merge stored gas and incremental gas priceswithin three years. In the second half of 2014,international oil prices fell drastically, based onthe price adjustment formula established in 2013,the National Development and Reform Com-mission then issued the Notice on Reorganising

6.2 “Optimisation” of Natural Gas Use Structures and Policies 139

the Price of Non-Residential Natural Gas onFebruary 28, 2015, merging the prices of storedgas and incremental gas, as well as partiallylifting the control over gate prices for commer-cial users. After adjustments, the maximum nat-ural gas gate price for each province was asshown in Table 6.6.

6.3.2 The Effect of PricingMechanisms in KeepingNatural Gas Prices Low

Prior to June 2013, the National Developmentand Reform Commission set different prices forvarious uses of natural gas (see Table 6.7), but toa certain degree this pricing scheme conflictedwith the natural gas use polices at the time. Forexample, gas use for chemicals was one of theareas prohibited by the policies, but in order tokeep the price of fertilisers low, a relatively lowprice was set for natural gas used in fertilisers,which then acted as a signal that such usage wasencouraged. Urban fuel gas use (non-industrial)was one of the natural gas use areas given

priority by gas use policy, resulting in a lowerprice for supplies. However, even though thelower prices were beneficial for increasing mar-ket demand, it did not encourage greater supply.Due to there being a shortfall between supply anddemand in the natural gas market, and forfinancial reasons, upstream enterprises prioritisedsupplies to higher priced users such as stableindustrial users, who could support a higherprice, which did not actually benefit the devel-opment of gas as an urban fuel.

Under strict government control, natural gasprices in China remained at a relatively low levelfor a long time. in 2012, the land-based naturalgas price (excluding tax) for domestic manufac-turers was 1.06 CNY/m3 (1.2 CNY/m3 with taxadded), which was equivalent to only a quarter ofthe WTI oil price at that time, a quarter of theCIF value of imported LPG, a third of the CIFvalue of imported fuel oil, half of the CIF valueof imported Central-Asian natural gas, or aquarter of the CIF value of imported Qatar LNG.In 2012, the average price of residential gas in 36major cities was 2.43 CNY/m3, while LPG waspriced at 7.65 CNY/kg and residential electricity

Table 6.6 Maximumnatural gas gate prices byprovince (region, city) after2015 price adjustments

Province Maximum gate price Province Maximum gate price

Beijing 2700 Hubei 2660

Tianjin 2700 Hunan 2660

Hebei 2680 Guangdong 2880

Shanxi 2610 Guangxi 2710

Inner Mongolia 2040 Hainan 2340

Liaoning 2680 Chongqing 2340

Jilin 2460 Sichuan 2350

Heilongjiang 2460 Guizhou 2410

Shanghai 2880 Yunnan 2410

Jiangsu 2860 Shaanxi 2040

Zhejiang 2870 Gansu 2130

Anhui 2790 Ningxia 2210

Jiangxi 2660 Qinghai 1970

Shandong 2680 Tibet 1850

Henan 2710

Unit CNY/103 m3 (including value added tax)Data source Pricing variation order (2015)351: Notice on reorganising the price ofnon-residential natural gas, issued by the National Development and ReformCommission

140 6 Analysis of China’s Natural Gas Use Policies …

Table 6.7 Baseline manufacturer’s prices (first-gate station) for domestic land-based natural gas after May 2010 priceadjustments

Name of oil/gas field Type of user Manufacturer’s baseline price(CNY/103 m3)

Chuan-yu oil-gas field Fertilisers 920

Direct supply toindustry

1505

Urban use (industrial) 1550

Urban use(non-industrial)

1150

Changqing oil field Fertilisers 940

Direct supply toindustry

1355

Urban use (industrial) 1400

Urban use(non-industrial)

1000

Qinghai gas field Fertilisers 890

Direct supply toindustry

1290

Urban use (industrial) 1290

Urban use(non-industrial)

890

Various oil fields in Xinjiang Fertilisers 790

Direct supply toindustry

1215

Urban use (industrial) 1190

Urban use(non-industrial)

790

Various oil fields in Tibet Fertilisers 790

Direct supply toindustry

1215

Urban use (industrial) 1190

Urban use(non-industrial)

790

Various oil fields in Dagang, Niaohe,Zhongyuan

Fertilisers 940

Direct supply toindustry

1570

Urban use (industrial) 1570

Urban use(non-industrial)

1170

Other oil fields Fertilisers 1210

Direct supply toindustry

1610

Urban use (industrial) 1610

Urban use(non-industrial)

1210

(continued)

6.3 Natural Gas Use and Natural Gas Price Controls 141

was priced at 0.53 CNY/kWh. The calorificvalue of natural gas is 8000 kcal/m3, for LPG itis 12,000 kcal/m3 and for electricity it is860 kcal/kWh. In other words, for the samecalorific value the price of natural gas was only48% of the price of LPG, and 49% of the elec-tricity price. Although a lower price for naturalgas is beneficial in the short term for promotinggas use, it does not reflect the market value ofclean and efficient energy sources, while alsocontributing to the conflicts between supply anddemand, thus affecting both the supply ofresources and sustainable healthy natural gasmarket development.

6.3.3 The Influence of a High FixedPrice for Natural Gas

In the 2013 natural gas price reform, the pricerestrictions on high-cost gas sources, such asLNG and unconventional natural gas, whichmake up a sixth of the entire market, were lifted,

allowing the market to determine prices instead.However, price controls were kept in place fordomestically produced and pipeline gases, whichaccount for the remaining five-sixths of themarket supply. Based on the 2013 natural gasprice reforms, incremental gas was adjusted to85% of the price of alternative energy in onemove, and classifications according to usagewere no longer applied. The price of stored gaswas raised by 400 CNY/1000 m3, while theprice of domestic gas was not adjusted (seeTable 6.8). Against the backdrop of insufficientoverall natural gas market supply, removal ofpricing restrictions on high-cost gas sources andadjusting the pricing mechanism for natural gasby a reasonable amount should have encouragedsupply and alleviated conflicts between supplyand demand. However, this was not a successfulmove as far as encouraging natural gas con-sumption, and resulted in a lack of marketdemand for natural gas.

In the 2013 price adjustments, the volume ofstored gas was 112.0 billion m3, but for

Table 6.7 (continued)

Name of oil/gas field Type of user Manufacturer’s baseline price(CNY/103 m3)

West-East Gas Pipeline Fertilisers 790

Direct supply toindustry

1190

Urban use (industrial) 1190

Urban use(non-industrial)

790

Zhong-Wu Line Fertilisers 1141

Direct supply toindustry

1541

Urban use (industrial) 1541

Urban use(non-industrial)

1141

Shaanxi Beijing Line Fertilisers 1060

Direct supply toindustry

1460

Urban use (industrial) 1460

Urban use(non-industrial)

1060

Sichuan going east pipeline 1510

Data source Circular (2010)211 of the NDRC “Increasing the base price of domestic on-shore natural gas”

142 6 Analysis of China’s Natural Gas Use Policies …

incremental gas it was only 11.0 billion m3,accounting for 91 and 9% respectively. Althoughincremental gas only accounts for a small share,its price rose more, directly affecting the growthof market demand for natural gas. Taking theBeijing gate price of 3.14 CNY/m3, for example,for the same calorific value it would cost 3.5times more than coal (calorific value of5500 kJ/kg, 620 CNY/ton), 0.87 times the priceof oil fuel (calorific value of 10,000 kJ/kg,4520 CNY/ton), and 0.70 times the price of LPG(calorific value of 12,000 kJ/kg, 6700 CNY/ton).Given the relatively high distribution costs, atthis price natural gas is less competitive. In 2014,economic development in China entered the“new norm” era, and economic growth began toslow, while dropping coal prices and abundanthydroelectricity resulted in reduced demand fornatural gas for power generation. The growth innatural gas consumption has been significantlylower than that predicted, with growth for lastyear of only 8.9%, which was considerablylower than the average of 17.4% over the last10 years.

6.3.4 Removal of Natural Gas PriceRestrictions Would Seethe Disappearanceof Natural Gas UsePolicies

Government natural gas price regulation, whe-ther it is set high or low, is detrimental to creatingequilibrium between supply and demand in themarket and encouraging sustainable developmentof the natural gas industry. The experiences ofthe United States and China in managing thenatural gas industry reveal that governmentrestrictions on natural gas prices tend to cause aserious imbalance of market supply and demand,resulting in the need for further direct govern-ment intervention. Moreover, experience in theUnited States also indicates that with the removalof price restrictions the market will activelyreallocate resources, and this automaticallyincreases social benefits and optimises the eco-nomic gains associated with natural gas to theirmaximum potential. The best method to ensurethe environmental benefits of natural gas is to

Table 6.8 Gate natural gas prices by province after the 2013 price reform

Province Stored gas Incremental gas Province Stored gas Incremental gas

Beijing 2260 3140 Hubei 2220 3100

Tianjin 2260 3140 Hunan 2220 3100

Hebei 2240 3120 Guangdong 2740 3320

Shanxi 2170 3050 Guangxi 2570 3150

Inner Mongolia 1600 2480 Hainan 1920 2780

Liaoning 2240 3120 Chongqing 1920 2780

Jilin 2020 2900 Sichuan 1930 2790

Heilongjiang 2020 2900 Guizhou 1970 2850

Shanghai 2440 3320 Yunnan 1970 2850

Jiangsu 2420 3300 Shaanxi 1600 2480

Zhejiang 2430 3310 Gansu 1690 2570

Anhui 2350 3230 Ningxia 1770 2650

Jiangxi 2220 3100 Qinghai 1530 2410

Shandong 2240 3120 Xinjiang 1410 2290

Henan 2270 3150

Unit (CNY/thousand m3)Data source Pricing Notice (2013)1246 of the National Development and Reform Commission concerning adjustmentof the natural gas price

6.3 Natural Gas Use and Natural Gas Price Controls 143

increase the cost of pollution abatement associ-ated with highly polluting fuels.

Among the different uses of natural gas,household use has the highest tolerance towardsrising prices, not being sensitive to changes ingas price. Based on statistics for 2012, thenational household use of natural gas was only17.85 m3/month per household, while in Beijinghouseholds it was 18.5 m3/month per household.Given the gate price of 3.14 CNY/m3, even afteradding the distribution and peak regulation costs,the price of natural gas for household use wouldnot exceed 5 CNY/m3. In terms of competitionbetween natural gas and electricity, with theprice for household electricity use being0.54 CNY/kWh, if the price of natural gas forhousehold use exceeds 5 CNY/m3, householdusers will stop using natural gas. Even if calcu-lated at 5 CNY/m3, the average natural gascost for each Beijing household isonly CNY 90/month. As the average annualdisposable income for Beijing citizens wasCNY 40,321 in 2013, natural gas consumptionaccounted for less than 1% of household income.

When compared to coal, natural gas hasadvantages as an industrial fuel. For example, ithas a better calorific value, is capable of raisingtemperatures more quickly, is clean andnon-polluting, and it can be easily switched onand off. It is also effective in tackling problemssuch as sulphur dioxide and phenol emissions,tarring and particulate pollution, thus improvingquality and economic effectiveness in industriessuch as pottery, glass and non-ferrous metals,which also increases its competitiveness. Whenconsidered from the point of view of China’soverall energy needs, China has only limitednatural gas supplies, therefore natural gas couldnever completely replace coal. From the point ofview of the atmosphere as a whole, “coal con-version to gas” does not completely overcomethis problem, the more important issue being toincrease clean coal use. The main uses for naturalgas in the chemical industry are the production ofammonia and methanol, and these are the mostsensitive to price changes in natural gas.Regardless of whether ammonia or methanol

production is concerned, coal is a serious com-petitor with natural gas for use as raw material inthe chemicals industry. At the same time as theratio of coal use in energy source structure isbeing reduced, coal prices are falling, thusoffering greater advantages to the coal chemicalsindustry than to the gas chemicals industry. Ifnatural gas pricing mechanisms were liberalised,this would result in a decline in natural gas’sshare of use in the chemicals industry, withoutthe need for government intervention.

6.4 The Relevance of the 1978 U.S.Natural Gas Policy Act for China

In 1978, during the international oil crisis, in theface of panic caused by lowering domestic pro-duction and natural gas reserves on the brink ofexhaustion, the United States Congress passedthe Fuel Use Act (FUA), restricting oil and nat-ural gas in power generation and for industrialpurposes. The legislative background and thecontents of the Fuel Use Act are similar to someextent to the “Natural Gas Use Policy” adoptedby the National Development and ReformCommission. The way in which the FUA affec-ted development of the natural gas industry in theUnited States provides a valuable reference forpolicies affecting China’s natural gas industry.

6.4.1 Legislative Background

In order to protect the interests of independentproducers and the end user, and prevent naturalgas manufacturers and pipeline operators fromcolluding in monopolistic profiteering, in 1954the Supreme Court of the United States gave itsdecision against Phillips Petroleum Co., autho-rising the Federal Power Commission (FPC) toregulate interstate natural gas wellhead prices.The FPC stipulated that wellhead prices must bedetermined “based on historical costs”, regard-less of stored amount, alternative energy sourceprices or changes in consumption. The maineffect of this was to protect the short-term

144 6 Analysis of China’s Natural Gas Use Policies …

interests of consumers. However, it interferedwith the investment necessary for manufacturersto increase future supply. In 1973, the productionof natural gas in the United States reached apeak, at an annual volume of 615.4 billion m3,and then began to fall. In 1978 production was at555.8 billion m3, and in 1986 it was as low as454.7 billion m3, dropping by a quarter frompeak levels (see Fig. 6.1).

In October 1973 the first oil crisis broke out,causing massive oil price inflation, and yet thenatural gas wellhead prices remained under reg-ulation, worsening the natural gas supply situa-tion. The price regulation caused an increase indemand and insufficient supply, and when com-bined with the effects of the oil crisis, this led tonatural gas supply shortages in the United Statesin the 1970s. Between 1976 and the winter of1977, at the worst point of the natural gasshortage, more than 9000 factories were forced tosuspend production, 750,000 people lost theirjobs and hundreds of schools in the Midwest andNortheast had to be closed, causing several bil-lion dollars of losses to the US manufacturingindustry. That period in the development of the

US natural gas industry is now referred to as the“era of failure”.

The catalyst for the Fuel Use Act was the peakgas theory, which predicts that natural gas willeventually be depleted after peak production isreached. In 1976, Exxon Oil published a reportsaid to be the result of research conducted byover a hundred top geologists and geophysicists.The report stated that the total remaining naturalgas resources in the United States were only287 � 1012 cf (around 8 � 1012 m3). In fact,from 1976 to 2012, the actual natural gas pro-duction in the United States was close to20 � 1012 m3, and at the end of 2012 there werestill discovered resources of 8.5 � 1012 m3.

6.4.2 Contents of the Legislation

Since the natural gas wellhead price restrictionsonly applied to interstate natural gas trade,pipeline companies buying natural gas within astate were not affected by the FPC price controls.As a result, there were no supply shortages in themajor natural gas exporting states. When winter

800.0

600.0

400.0

700.0

500.0

300.0

200.0

100.0

0

Uni

t: 10

x 1

08 m3

Output

Consumption

1970

19

72

1974

19

76

1978

19

80

1982

19

84

1986

19

88

1990

19

92

1994

19

96

1998

20

00

2002

20

04

2006

20

08

2010

20

12

Fig. 6.1 Changes in production and consumption of natural gas in the United States from 1970 to 2012

6.4 The Relevance of the 1978 U.S. Natural Gas Policy Act for China 145

approached, while the northern schools andcommercial establishments had to close becauseof the lack of natural gas supplies, Texas was stillusing natural gas as a replacement for oil andcoal in power generation, rather than shipping itup north. There were suggestions that the pricerestrictions should be lifted to let natural gas betraded at market prices. However, the publicutilities representatives of both the major partiesdecided to trust the “experts” and their theory ofresource depletion. They believed that the signsof depletion were already recognisable, and theyfelt that deregulation of natural gas prices was aselfish, short-sighted and idiotic solution. In theiropinion it was necessary to continue withresource protection subsidies, terminal usagecontrols and pricing control, which would raiseefficiency and ensure fairness all round.

In May 1978, the United States Congresspassed two acts: the Power Plant and IndustrialFuel Use Act (FUA) and the Natural Gas PolicyAct (NGPA). The NGPA was mainly a redesignof the regulatory regime and categorisation ofnatural gas well types, raising the price of naturalgas from “old wells”, and partially removingprice restrictions on “new wells”. The FUA is asupplementary act to the NGPA, authorising theDepartment of Energy (DOE) to issue ordersrestricting the use of natural gas to specificindustries, in an attempt to directly control theuse of natural gas. Apart from forbidding thebuilding of new natural gas power plants andindustrial boilers, the FUA further demanded thatfactories should abandon fuel switching capa-bilities, while encouraging factories using naturalgas to switch to using other fuels. After 1990, theuse of natural gas was banned in power plantsand industrial boilers. In the transitional period,use of natural gas in public works was restrictedto consumption volumes equivalent to thoseencountered during the energy crisis from 1974to 1976.

6.4.3 Implementation

In the process of setting out the FUA, the UnitedStates Congress firmly believed that natural gas

resources were in the process of being depleted,and could not possibly have predicted that anexcess of natural gas would arise. Yet, while theink was still wet on the FUA, Secretary ofEnergy James Schlesinger announced that therewere predicted natural gas reserves in excess ofthe 1 � 1012 ft3. He did state, however, that this“bubble” was only temporary. While the “bub-ble” lasted, the Department of Energy supporteda delay in switching to coal as demanded by theFUA, and encouraged industrial fuel users cap-able of switching energy sources to use “surplus”natural gas instead of oil.

The loosening of restrictions on wellheadprices increased the supply of natural gas, withhigh fixed prices limiting demand, and“take-or-pay” contracts locking up a large vol-ume of higher-priced natural gas, which caused a“bubble” to occur in the natural gas market, withsupply exceeding demand. As this bubble econ-omy persisted, the FUA’s restrictions on naturalgas use became a historically significant mistakeand resulted in the market imbalance worsening.In 1981, Congress overruled the FUA’s powerplant requirements and then in 1987 Congressrepealed the FUA and withdrew all the regula-tions responsible for restricting natural gasconsumption.

6.4.4 Lessons for Natural Gas UsagePolicy in China

The Natural Gas Use Policy, as adopted by theNational Development and Reform Commission,is not only similar in content to the 1978 FuelUse Act of the United States, they also share asimilar background, market environment andpolicy climate.

• The natural gas market in China has beengrowing rapidly since 2000; demand for nat-ural gas has been rising, but the growth indomestic production remains slow, leading toincreasing reliance on imported natural gas.This is similar to the uncertainties regardingfuture energy source supplies in the UnitedStates during the 1970s.

146 6 Analysis of China’s Natural Gas Use Policies …

• The United States had yet to carry out naturalgas industry reforms in the 1970s, and pipe-line transportation and sales of natural gaswere bundled together. The situation in whichnatural gas wellhead price restrictions wereput into place was therefore similar to thatwhen the Natural Gas Use Policy was enactedin China.

• Natural gas prices in China have been fre-quently adjusted since 2000, and from 2013onwards natural gas prices were pegged to oilprices and LPG prices. Lifting regulation ofunconventional natural gas and importedLNG prices would have the same effect aswhen the United States removed “new wells”pricing regulation in the FUA of 1978.

• Due to the higher value of natural gas, therehas been a great deal of activity in develop-ment of unconventional natural gas in China,while a large number of natural gas importcontracts have been signed with offshorepartners. This is also reminiscent of how,after “new well” price regulation was lifted inthe United States in 1978, there was extensivedevelopment of extraction of the moreexpensive “deep-level gas”.

• After suffering more than a decade of short-ages, United States pipeline companieseagerly signed long-term “take-or-pay” con-tracts with gas suppliers at high prices, inorder to ensure capacity to satisfy thedemands of users lower down on the supplychain, thus creating the conditions necessaryfor the “bubble” to occur. Contracts in thenatural gas market in China are also in theform of “take-or-pay”, and when suppliescome under pressure, local governments optfor a “give me gas, disregard the price”approach out of fear.

• Due to the effects of the long-term shortage inthe United States, in 1980, industrial andpublic power generation natural gas con-sumption was 20% lower than in the 1970s,with many industries having learned how toswitch fuels and save energy; nearly all newpower plants were coal- or nuclear-powered.As gas prices continue to rise, it will becomedifficult to continue using natural gas in

power generation in China, and enthusiasmfor natural gas in industrial uses will fall, withcoal-fired power stations preferring to adopt aclean coal use approach rather switching togas.

In a 2013 forecast, the gap between naturalgas supply and demand in China would be as bigas 22.0 billion m3. In fact, due to the NationalDevelopment and Reform Commission’s large-scale adjustment of pipeline gas prices in June,stored gas price went up by 400 CNY/103 m3,while the incremental gas price is now peggedagainst alternative energy sources, pushing itupwards to 1380 CNY/103 m3. This has resultedin many gas power stations adjusting their powergeneration plans and has resulted in a decline inindustrial gas use. In addition, with relativelywarm winters, China National Petroleum Cor-poration was actually able to put gas into storageduring the winter, all of which are signs of anexcess in supply. What we can learn from theFUA in the United States is that it is necessary tomake timely adjustments, and to repeal naturalgas use regulations when it becomes necessary.

6.5 Policy Recommendationsfor Encouraging Natural GasUse

The pressures of environmental protection andemission reduction mean that China needs to bemore active in developing natural gas andencouraging its use. The nature of current naturalgas use policies in China is such that, whendemand exceeds supply and pricing mechanismsare no longer effective, the government interfereswith supply and demand directly, mainly byapplying restrictions to gas use in specific sec-tors. In the past decade, with the widespreaddevelopment of natural gas sources, China hasreached a stage where a range of locally pro-duced gas, gas synthesised from coal, importedpipeline gas and imported LNG is available,greatly boosting the available quantity and sta-bility of natural gas supplies. The “shale naturalgas revolution” in the United States teaches us

6.4 The Relevance of the 1978 U.S. Natural Gas Policy Act for China 147

that as technology for natural gas extractiondevelops, the extent of natural gas reservesavailable for extraction will increase. As naturalgas prices in China are adjusted to moreacceptable levels, the scale of supply hasincreased, and there has been a reversal in theprevious supply-demand scenario, currentlymanifesting as a lack of demand. China musttherefore alter its current policy of restrictingnatural gas use, and instead promote andencourage a wider range of uses for natural gas.

6.5.1 Improve EnvironmentalSupervision, ReplacingDispersed Coal Usewith Natural Gas

The energy supply in China is said to be“coal-heavy, oil-deprived and short of gas”. Eventhough various sources of natural gas have beenintroduced in the last decade, vastly enhancingthe natural gas supply capacity, in the face of thetremendous demand for energy in China, thesupply of natural gas available to China is stilllimited. Natural gas is not likely to completelyreplace coal, although it could be prioritised toreplace dispersed coal use. In OECD countries,the ratio of coal used for power generation is78%, while 90% of coal consumed in the UnitedStates is for power generation. Dispersed coaluse is relatively concentrated in the steel andconcrete industries, but very dispersed coal use israre. In terms of total coal consumption in China,only half of it is used for power generation, theother half being used in dispersed coal burning.Of dispersed coal burning uses, half is used inmetal smelting and cement sintering and otherrelatively concentrated uses, for which coal isessential, the other half being used in heating,textiles, paper manufacturing and other verydispersed fields. When coal use is too dispersed,energy efficiency is low and large volumes ofpollutants result, resulting in increased pollutioncontrol costs. Natural gas substitution wouldtherefore apply mainly to the replacement of verydispersed coal use.

Since coal is relatively cheap, natural gas doesnot have a competitive advantage in terms ofprice, therefore businesses prefer coal basedpurely on economic considerations. Encourage-ment of the replacement of coal by natural gasmainly comes from environmental protectionpolicies.

• More rigid emission standards should bestipulated and, whether for concentrated ordispersed coal uses, all users should staywithin emissions targets. By internalisingwhat was originally an external cost of usingcoal, the competitiveness of natural gaswould improve.

• A new supervisory structure should bedevised, so that concentrated coal use can besupervised in real time and online, in order toprevent companies from installing but notusing emission reduction and pollution con-trol facilities, or only using them from time totime.

• In areas subject to urban planning or areasaffected by acid rain, coal burning should berestricted or prohibited.

• Where gas supplies allow, in facilities wherethe cost of restricting emissions is too high orwhere it would be impractical to introduceemissions restrictions, conversion to gascould be obligatory. For those in regionswhere conditions do not allow for gas sup-plies, construction of new installations whichrequire dispersed coal use which are notabsolutely necessary in terms of everyday lifeshould not be permitted. At the same time,more efforts should be put into building gasinfrastructure, so that more regions could optto use natural gas.

6.5.2 Optimise the Electricity PricingScheme, and Increasethe Economical NaturalGas Power Generation

The key to increasing the ratio of natural gas intotal energy source consumption structures is the

148 6 Analysis of China’s Natural Gas Use Policies …

development of natural gas power generation.Natural gas power generation is clean, occupiesless space and provides effective peak regulation.It is well suited for provision of supplementarypower to large cities or megacities. In developedcountries, natural gas power generation usuallytakes up around 40–60% of total natural gasconsumption. In China, on the other hand, only15% of total natural gas used is for power gen-eration. While there is much space for develop-ment, the biggest hurdle for expansion of naturalgas power generation is the relatively high costof natural gas power compared to coal power.Based on calculations, the cost of coal powergeneration is only 0.34 CNY/kWh, whereasnatural gas power generation costs as much as0.65 CNY/kWh (annual power generation of35,000 h), or 0.615 CNY/kWh (annual powergeneration of 5000 h). Under the current subsidyregime, natural gas-generated power is moreexpensive and there is no incentive for powergrid companies to buy natural gas-generatedpower. With a high natural gas price, there isnothing to be gained from natural gas powergeneration, and power generating companieshave shown little interest in it.

There are two ways to promote natural gaspower generation, both of which aim to improvethe economic benefits of natural gas powergeneration. The first method involves introducinglocal production of core technology, especiallythe manufacturing of gas turbines, so that unitinvestment costs and long-term maintenance andinspection costs can be lowered. The secondmethod is to increase power generation opera-tional cycles, lowering the fixed cost of eachkWh of electricity produced. However, theamount of leeway gained in terms of loweringcosts is very limited. Based on calculations,using locally manufactured core technologywould only bring the cost of power generationdown by 0.024 CNY/kWh. Increasing the lengthof the power generation operational cycles wouldmove natural gas power generation towardsplaying a base-loading role, lessening the gains itcan achieve as a supplementary power source inpeak generation. Currently there are no auxiliaryservice markets or peak/trough electricity pricing

mechanisms in China. The main policy adoptedhas been subsidising natural gas power genera-tion by setting a higher electricity price. In largecities such as Shanghai, Beijing and Shenzhen, atwo-part tariff is charged for electricity, thecapacity price being 40–46 CNY/kW month,basically covering the fixed costs of natural gaspower generation. On top of the two-part tariff,auxiliary service markets should also be devel-oped, switching from government regulation ofprices to market-regulated prices to provide suchsubsidies.

6.5.3 Strengthen Planned Guidanceto Promote Natural Gasin Transportation

For transportation, the gases used are mainlyCNG and LNG, which replaces petrol, diesel andship fuel. Based on data provided by the Envi-ronmental Protection Department, around aquarter of all atmospheric pollution in Chinacomes from exhaust gases. When natural gas isused as a replacement transportation fuel, vehi-cles emit less carbon dioxide compared tooil-burning vehicles, and they hardly emit anyother pollutants such as nitrogen oxide and sul-phides. Furthermore, the relatively large gapbetween natural gas and oil prices, and theabsence of goods and services tax, means thatnatural gas vehicles are more economical thanoil-burning vehicles. For example, in the case ofa taxi that runs on CNG, there was a period oftime when the price of CNG was half that ofpetrol, and hence the investment of severalthousand CNY required for conversion could berecovered in a matter of months. Backed byatmospheric pollution control measures and itseconomical characteristics, use of natural gas intransportation in China has been growingquickly, from 97,000 vehicles in 2005 to 2.3million natural gas-powered vehicles in 2014; theassociated annual gas consumption reached22.5 billion m3, making up 12.3% of total natu-ral gas consumption. LNG filling stationsincreased from 241 stations in 2011 to 2000stations in 2014.

6.5 Policy Recommendations for Encouraging Natural Gas Use 149

As natural gas transportation technologymatures, it brings more economic benefits, butthere are specific hindrances to the developmentof natural gas use in the transportation sector.Unlike household, industrial, power generationor other uses where the users stay in a fixedlocation, natural gas used in transportation issupplied to moving users and relies heavily onsupply networks. Natural gas fuel, filling stationsand transportation form the core of the naturalgas transport use value chain, each segmentaffecting the decision of a user on whether tochoose natural gas over all other alternatives; thisin turn may slow down or hamper the develop-ment of natural gas use in the transportationsector. As the natural gas supply situation inChina improves, the supply of natural gas fuel isassured for the foreseeable future. However, thegovernment still needs to strengthen planningand guidance and refine related policies andstandards, in order to increase the provision ofinfrastructure such as natural gas filling stationsand standardised filling services, thus ensuringthat the natural gas filling station network betterfulfils the mobile needs of transportation andlogistics users, thereby attracting users to adoptnatural gas, accelerating growth in the natural gastransport sector.

6.5.4 Reduce Cross-SubsidisationBetween Different Users,and Encourage Industrialand Commercial NaturalGas Use

In China, urban natural gas use is considered tobe one of the benefits of city life. Since resi-dential gas is associated with very low profitmargins, with supplies sometimes being providedat a loss, the financial shortfall due to cheaphousehold natural gas is made up by charging ahigher natural gas price to the industrial andcommercial sectors. For example, after theupstream natural gas prices were adjusted in2013, the Beijing gate price for stored gas was

2.26 CNY/m3 and for incremental gas was3.14 CNY/m3, but government pricing depart-ments set the price of residential use gas at2.28 CNY/m3. It is clear that sales to householdusers were made at a loss, compensated for byindustrial and commercial use. The subsidisationof household natural gas use by the industrial andcommercial sectors is in fact passed on to societyin its use of products and services. The higherhousehold income is, the more hot water andheating a household uses, and the more it benefitsfrom the natural gas subsidies. In contrast,households with lower incomes, or householdsthat are not natural gas users or that only use asmall amount of natural gas, would not benefitfrom, or only benefit slightly from, these subsi-dies. That households with higher incomesshould benefit more from such subsidies cannotbe seen as fulfilling the original objectives ofgovernment policy and is hardly fair.

Not only is an all-encompassing subsidy forhousehold natural gas use unfair, it is alsounsustainable and unnecessary. On the one hand,there is much room for growth in householdnatural gas use, and with volumes expected toincrease from the 2012 figure of 28.8 billion m3

to 54.8 billion m3 by 2020, the continuance ofsuch subsidies would be enormously difficult. Onthe other hand, household natural gas use is lessprice-sensitive, and hence there is no real needfor subsidies. From the point of view of eco-nomic competitiveness, as long as the price islower than 4 CNY/m3, natural gas will still becompetitive against oil fuel, LPG and electricity.City dwellers use an average of around 60 m3,and even if the price of each cubic metre goes upby CNY 1, the annual increase is still only CNY60. In 2013, low-income urban households (thelowest 20%) had a disposable income of CNY11,434, and an increase in natural gas expendi-ture of CNY 60 is equivalent to only 5% ofdisposable income. Therefore, the price of natu-ral gas for household users could definitely be setabove the cost of supplying the gas, cancellingthe cross-subsidising between household use andindustrial and commercial use, reducing the cost

150 6 Analysis of China’s Natural Gas Use Policies …

of using natural gas to the industrial and com-mercial sectors, and thus encouraging the growthof industrial and commercial natural gas use. Asfor the specifics of the price adjustments, localgovernments should decide the timing andmagnitude of them.

6.5.5 Extend Carbon EmissionTrading Rights,and Actualisethe Environmental Valueof Natural Gas

The key to encouraging the use of natural gas inpower generation as well as in the industrial andcommercial sectors is to improve the competi-tiveness of natural gas against coal. If consider-ing the price alone, natural gas cannot competeagainst coal, as the fuel cost per kWh of coalpower generation is a mere CNY 0.21, while thatof natural gas is CNY 0.50. As a clean energysource, natural gas has an environmental value,and when competing against coal this environ-mental value could be considered as the externalenvironmental cost of coal. The external cost ofcoal burning could be broken down into specificpollutant emissions costs, such as dust, nitrogenoxides and sulphur dioxide, in addition to acarbon emissions cost. With increased invest-ment, the pollutants released by coal burning canbe lowered to a level close to that encounteredwhere gas is used as the fuel. Newly constructedcoal-burning power stations can basicallyachieve the same level of atmospheric pollutantemissions as natural gas power stations (whenbaseline oxygen content is 6%, dust, sulphurdioxide, nitrogen oxides concentrations arerespectively above 10, 35 and 50 mg/m3), whilethe increase in investment cost for each kWh

is only CNY 0.01–0.02. Therefore, simply str-engthening enforcement of environmental regu-lations and restricting release of air pollutantswould not effectively increase the competitive-ness of natural gas against coal in the powergeneration sector.

Another method for boosting the competi-tiveness of natural gas is the levying of a carbontax, but while a carbon tax can narrow the gapbetween the costs of coal power generation andnatural gas power generation, thereby makingnatural gas comparatively more competitive, itwould nonetheless increase the absolute cost ofboth forms of power generation. A better way ofmaking natural gas more competitive is to set acarbon allowance for each kWh, and fully utilisetrading of carbon emission rights. For example, ifcoal power generation has a carbon emission of0.8 kg/kWh while gas power generation’s carbonemission is 0.37 kg/kWh and the governmentsets the carbon allowance at 0.7 kg/kWh, thencoal power stations have to purchase 0.1 kg/kWhof emission rights from the market, while naturalgas power stations have 0.33 kg/kWh of emis-sion rights for sale. If there are only coal andnatural gas power generation to choose from,then the electricity generated by coal cannotexceed 3.3 times the amount generated by naturalgas; in other words, the proportion of the quan-tity of natural gas power generation would be23% of total power generated, otherwise therewould be insufficient emissions rights availablefor purchase by coal power stations. This wouldallow the government greater flexibility to adjustthe natural gas power generation ratio, gettinggas power generators to directly subsidise naturalgas power generation, and forcing coal powergeneration to provide a direct subsidy to gaspower generation, thereby taking full advantageof the environmental value of natural gas.

6.5 Policy Recommendations for Encouraging Natural Gas Use 151

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152 6 Analysis of China’s Natural Gas Use Policies …

PART II

Analysis of Gas Supply for China

1. China’s natural gas resource volume is con-tinually growing. According to the latest surveyresults (2013), China’s conventional andlow-permeability natural gas geological resourcevolume is 52 trillion cubic metres, with techni-cally recoverable resource volume of 32 trillioncubic metres. In 2014, China’s conventionalnatural gas production volume was 128 billioncubic metres, with ground coalbed methaneproduction reaching 3.6 billion cubic metres andshale natural gas production reaching 1.3 billioncubic metres. It is expected that by 2020, China’snatural gas production volume will be approxi-mately 260–330 billion cubic metres, and by2030 that number will reach approximately 430–560 billion cubic metres. In order to accelerateChina’s natural gas development, the develop-ment path should be made clearer, by adjustingthe minimum exploration investment, maintain-ing reasonable prices, establishing tradingmechanisms and trading platforms for provennatural gas reserves and accelerating unconven-tional natural gas development. Small- andmedium-sized enterprises should be given specialencouragement to join the unconventional natu-ral gas development industry. In addition, basedon international experience, system reformsshould be extended to enhance the momentum ofnatural gas development and encourageinnovation.

2. In 1993, China changed to become animporter of crude oil. In 2007, China became anatural-gas-importing nation. In just 7 or 8 years,

by 2014, China’s natural gas import dependencyrate had exploded to 32%. This is a significantdevelopment. In future, the import status of nat-ural gas will have a marked influence on supplyand demand in China. Looking at natural gassupply and demand from a global perspective,natural gas resources are relatively plentiful, andnatural gas will account for a large proportion ofglobal energy consumption in future, playing alarger role than in the past. However, the drop ininternational oil prices has brought enormousuncertainty to the future development of theinternational natural gas market. It is expectedthat in the coming years imports of natural gasinto China will rapidly increase, growing from 53billion cubic metres in 2013 to 167 billion cubicmetres in 2020, including 70 billion cubic metresof LNG and 97 billion cubic metres of pipelinenatural gas. By 2030, imports of natural gas willhave grown further, to approximately 210–240billion cubic metres, with approximately 75 bil-lion cubic metres of LNG and 135–165 billioncubic metres of pipeline gas. If domestic naturalgas, especially shale natural gas, productionvolume achieves a market increase as a result ofbreakthroughs in technology and policy, then by2030 China’s natural gas import dependency canbe kept to below 40%.

3. Since the West–East Gas Pipeline com-menced operation in 2004, China’s natural gasinfrastructure has rapidly developed. As of theend of 2014, a pipeline distribution deploymentof nearby suppliers has been formed from west to

east and from offshore to onshore, providingcoverage to all provinces except Tibet. The twomajor import resource deployments of pipelinegas and LNG have also been completed, openingup access to Sino-Asian pipeline gas,Sino-Myanmar pipeline gas and LNG importchannels. There are also underground storage andLNG receiving stations to act as major peakshaving options, covering coastal regions, gasproduction regions and the area around the BohaiGulf. However, there are also shortages in pipe-line construction and in underground pipelinereserve peak shaving facilities. In order to guar-antee continued stable operation of China’s nat-ural gas infrastructure design, it is recommendedthat a safe and stable national natural gasinfrastructure operating system be built. Tostrengthen infrastructure construction capabili-ties, there should be unified infrastructure plan-ning, and construction investment should bediversified. To increase infrastructure usage effi-ciency, a fair third-party access (TPA) operationsand management platform should be created.

4. Constructing a robust natural gas reservepeak shaving system is an effective approach fordealing with mid-term natural gas supply inter-ruptions and ensuring stable operation of the

natural gas industry as well as stability within theeconomy and society. Currently, China’s naturalgas reserve construction is in its infancy, and thepeak shaving demands being faced are signifi-cant. The existing reserve peak adjustmentcapabilities are insufficient, and price and oper-ations mechanisms have obvious issues. Thepeak shaving and emergency response assurancemechanisms are both insufficiently robust andpresent problems and challenges. The securesupply of natural gas should be made an impor-tant component part of national security, accel-erating the construction of reasonable reservesystems suited to the scale of market demandwhile giving greater attention to the formulationof natural gas peak shaving emergency responsereserve planning, focusing on reserve facility lawand regulatory construction, and clarifying nat-ural gas business reserve obligations so as topromote natural gas peak shaving emergencyresponse reserve facility construction. Active taxand price policies should be released to reformreserve gas management regimes and constructprompt and flexible warning systems for emer-gency response, continually improving China’snatural gas supply assurance capabilities as wellas its risk mitigation capabilities.

154 Analysis of Gas Supply for China

7China’s Natural Gas ResourcePotential and Production Trends

7.1 Natural Gas Resource Potential

7.1.1 Resource Potential for ChineseConventionaland UnconventionalNatural Gas

According to estimates of China’s natural gasresources, China’s conventional andlow-permeability natural gas geological resourcevolume amounts to 68 trillion m3, of which40 trillion m3 is technically recoverable.Onshore conventional and low-permeability nat-ural gas resources are primarily distributed in thethree large basins of Sichuan, Erdos and Tarim.Marine natural gas resources are primarily dis-tributed in the Pearl River Estuary, theSouth-East Qiong and the East Sea Basin.

From a systematic appraisal of 121 regions in42 coal basins (groups), China’s onshore coalbedmethane resources located less than 2000 munderground amount to 36 trillion m3.

Technically recoverable resources less than1500 m underground total 11 trillion m3. Theseare primarily distributed in China’s northernQinshui Basin, Erdos Basin, the Yunnan-Guizhou-Guangxi area and the Eastern YunnanWestern Guizhou Area. In terms of geologicsequence, they are primarily from the Carbonif-erous, Permian and Jurassic. According to nationalshale natural gas resource potential surveyappraisals and the identification of the mostpromising regions, China’s onshore shale naturalgas geological resources located less than 4500 munderground total 134 trillion m3, with 25 tril-lion m3 of recoverable resources, primarily dis-tributed in the Sichuan Basin and surroundingareas (Table 7.1).

China’s gas hydrate resources are also veryabundant, and are primarily distributed in theSouth China Sea and East China Sea regions, aswell as in the permafrost of the Tibetan Plateau.Geological resources are approximately102 trillion m3, and this is currently one ofChina’s most abundant sources of clean energy,with the potential for large-scale developmentand the basic conditions in place to become amainstream clean energy source (Table 7.2).

7.1.2 Changes in Natural GasResource Assessments

China has conducted five rounds of systematicnational natural gas resource assessments. In1986 the first round found that China’s naturalgas geological resource volume was

* This chapter was overseen by Zhonghong Wang fromthe Development Research Center of the State Counciland Shangyou Nie from Shell International Explorationand Production. It was jointly completed by XiaoweiXuan, Yingxie Yang, Yongwei Zhang, Jiaofeng Guo,Weiming Li, Beiqing Yao, Tao Hong and Yuxi Li fromthe State Resource Department Oil and Gas Centre,Xiaoli Liu from the National Development and ReformCommission’s Energy Office, Guang Yang and JianhongYang from the China Energy Research Institute’sNatural Gas Centre, Xiaobo Ju and Beijing Yao fromShell China. Other members of the topic groupparticipated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_7

155

Table

7.1

Resou

rcepo

tentialandstateof

developm

entof

variou

snaturalgasresourcesin

China

Distributed

layer

Source

rock

Migratio

nlayer

Traplayer

Middle-shallow

layer

Resou

rcetype

Coalbed

methane

Shalenatural

gas

Water

soluble

gas

Tight

gas

Low

-permeability

gas

Con

ventional

Biogas

Recov

erable

resource

potential

11�

1012

m3

25�

1012

m3

Not

know

nDispu

ted

32�

1012

m3

Not

know

n

Stateof

developm

ent

International

Develop

edDevelop

edDevelop

edDevelop

edDevelop

edDevelop

ed

Dom

estic

Nodevelopm

ent

Materialsource

Ministryof

LandandResou

rces,revised

Table

7.2

China’s

naturalgasresource

volume

Typ

eGeologicalresource

volume

(trillion

cubicmetres)

Recov

erable

resource

volume(trillion

cubicmetres)

Rem

arks

Con

ventionalnaturalgas

6840

Shalenaturalgas

134

25In

caseswhere

developm

entfrom

explorationispo

ssible,

relativ

elyreliableresource

volumeis12

.85trillionm

3

Coalbed

methane

3711

1500

mshallow

coalbedmethane

recoverableresources

Gas

hydrate

102

Nolik

elycommercial

developm

entbefore

2030

Total

341

76

Source

Ministryof

LandandResou

rces

156 7 China’s Natural Gas Resource Potential and Production Trends

approximately 34 trillion m3. In 1994, the sec-ond round found that natural gas resources were38 m3. In 2007, the third round found that,spread over 115 land and near-shore regionscontaining oil and gas basins, China’s conven-tional natural gas resources were 35 trillion m3,with recoverable resources of 22 trillion m3. In2012, the fourth round found that natural gasgeological resources were 52 trillion m3, withrecoverable resource volume of 32 trillion m3.The fifth round, in 2013, found that natural gasgeological resources were further increased to68 trillion m3, with recoverable resources risingto 40 trillion m3. In short, China’s natural gasresource volume is continually increasing. This isespecially clear from the 2013 results, whichshowed a marked increase over 2012 (Table 7.3).

Looking back at the history of exploration anddevelopment, it is clear that natural gas resourcescontinually change along with the developmentof exploration. As demand continues to grow,natural gas exploration and development expandsto satisfy it, with ever-increasing resource types

and resource volumes. Progress in the develop-ment of oil and gas geological theory and tech-nology is continually expanding the types ofnatural gas and their scope, generally pushingnatural gas toward a trend of ever-expandingdevelopment. Also, the influence of price chan-ges will cause short-term fluctuations in theamount of natural gas that is judged economi-cally recoverable.

7.2 Proved Natural Gas Reserves

7.2.1 Conventional Natural Gas

China’s natural gas exploration and developmentlagged behind oil, with generally low levels ofexploration. According to BP’s annual statisticalreview, since 2006, proved natural gas reserveshave consistently maintained high rates of growth,with annual proved natural gas original reservevolumes of over 500 billion m3. Since 2010,annual proved conventional natural gas geological

Table 7.3 China’shistorical natural gasresource assessment results

Assessment time (years) 1986 1994 2007 2012

Geological resources (trillion cubic metres) 33.6 38.04 35 52

Recoverable resources (trillion cubic metres) 22 32

Source Ministry of Land and Resources, Crude Oil Department and Oil and Natural GasHeadquarters materials

100

milli

on c

ubic

met

res

0

2000

2010 2011 2012

4000

6000

8000

10000

12000

2013 2014

Geological Technically minable

Fig. 7.1 China’s annual increase in proved conventional natural gas reserves. Source Ministry of Land and Resourcesannual press conference materials

7.1 Natural Gas Resource Potential 157

reserves have exceeded 600 billion m3. Indeed, in2012 and 2014, proved geological reserves wereeach nearly 1 trillion m3 (Fig. 7.1). Conventionalproved natural gas reserves are primarily in theTarim Basin, Sichuan Basin and Erdos Basin. Inaddition, deep within the Songliao Basin there hasalso been rapid growth in proved reserves. As of2013, China’s proved natural gas geologicalreserves were 9.66 trillion m3, with technicallyrecoverable reserves of 5.54 trillion m3.

The basins in Sichuan, Erdos, Tarim, Son-gliao, Chaidamu and Zhungeer are now the sixmajor mainland natural gas exploration areas.Ying-Qiong and the East China Sea have becomethe two major near-shore exploration areas,forming a basic layout of eight large natural gasexploration areas. Erdos, Sichuan and Tarim arethe three major gas regions with reserves over1 trillion m3.

China’s proved natural gas reserve regions arerelatively concentrated, and are primarily dis-tributed in the western region, which accounts for83% of resources, while the east region andoffshore areas account for the other 17%.

From 1986 to 1990, proved natural gas sourcereserve growth was relatively small and less than40 billion m3. In 1991–1995, growth was closeto 100 billion m3, and in 1996–2000 growth was150 billion m3. In 2001–2005, growth roseconsiderably to approximately 300 billion m3,while during 2006–2010, the growth was over320 billion m3. In 2011–2013, conventionalproved natural gas resources growth exceeded600 billion m3 for three years in a row, with anadditional 616.4 billion m3 added in provedconventional natural gas reserves in 2013. In2014, newly added proved conventional geo-logical reserves reached 943.7 billion m3, mark-ing an increase of 53% year on year.Conventional proved natural gas volumeincreased consistently, setting a foundation forlarge natural gas production volumes.

7.2.2 Coalbed Methane

In 2012, national proved coalbed methanereserves added 134.4 billion m3, rising year onyear by 2.5%. In 2013, national proved coalbedmethane reserves added 23.6 billion m3

(Table 7.4). Proved coalbed methane geologicalreserves are 575.4 billion m3, with technicallyrecoverable reserves of 285.0 billion m3, showingrapid growth in proved coalbed methane reserves.Three-quarters of coalbed methane reserves orig-inate from Qinshui Basin, while one quarter isfrom the Erdos Basin, with proved reserves ofcoalbed methane relatively sparse in other areas.

In 2006, proved coalbed methane wells anddeveloped wells numbered 1373, a figure whichthen increased rapidly, so that by 2014 therewere 18,000 coalbed methane well drillings.

Over many years of exploration, the QinshuiBasin has become an especially large coalbedmethane region, with 400 billion m3 of geologi-cal reserves. The eastern edge of the Erdos Basinhas become a target gas region, with over100 billion m3 of geological reserves, and thecoalbed methane industry development has goodfoundations.

7.2.3 Shale Natural Gas

As of the end of 2013, China had not submittedproved reserves of shale natural gas. In June2014, China’s first proved shale natural gasreserves passed review and inspection by therelevant authorities. The proved reserve is locatedin Sinopec’s Fuling Gas Field Jiaoshiba RegionCoke-1 Well 3, over an area of 106.45 km2, andthe layers incorporating shale natural gas are aWufeng group within Longmaxi. Experts believethat the Lingpei Shale Gas Field is a typical shalenatural gas field. The gas field reservoir layer is amarine deep-shelf quality shale with significant

Table 7.4 Coalbedmethane newly addedproved reserve data table

Time (year) 2008 2009 2010 2011 2012 2013

Proved geological reserves(100 million m3)

225 244 1299 1311 1344 236

Source Ministry of Land and Resources annual press conference materials

158 7 China’s Natural Gas Resource Potential and Production Trends

thickness and very high abundance. Distributionis stable, depth is suitable, and there are nointervening layers in between, markedly differentfrom conventional gas deposits, and having thecharacteristics of typical shale natural gas, beingsimilar to North American typical marine-shelfshale natural gas indicators. The Peling Shale GasField is a high-quality marine-shelf shale naturalgas field that has excellent quality and quantity ofresources. There is a high formational pressure,the natural gas components are good, gas wellproduction volumes are high, and there have beengood results seen from mining attempts. Therehas been a high production volume from pilotwells, with long periods of stable production. Anexpert appraisal panel has determined provedshale natural gas volume to be 106.5 billion m3.

As of June 30 2014, the Jiaoshiba region’s 29wells with pilot mining recorded total daily gasproduction of 3.2 million m3, with accumulatedgas production of 611 million m3. As part ofthis, the first exploration well Coke IHF hasrecorded stable production for a year and a half at60,000 m3 per day, with an accumulated gasproduction of 37.69 million m3.

7.3 Growth of Natural GasProduction

7.3.1 Conventional Natural Gas

Prior to 1995, China’s natural gas productiongrowth was slow, rising from 14.3 billion m3 in

1980 to 17.4 billion m3 in 1995. From 1995 to2005, natural gas production accelerated, grow-ing from 17.4 billion m3 to nearly 50 billion m3,an average annual growth of 3.2 billion m3.Since production reached 50 billion m3, annualaverage growth has been approximately8 billion m3. By 2012 it had reached107.2 billion m3, 117.0 billion m3 in 2013 and128 billion m3 in 2014, with net annual growthof 9.4% (Fig. 7.2). Since 2000, China’s naturalgas production volume growth has beenapproximately 9.6%, and annual average growthfor natural gas over the next 10 years or so isexpected to be roughly 9–10%.

Since 2007, conventional natural gas con-sumption volume has exceeded natural gasproduction volume, and natural gas importshave continually increased. By 2013, China’sconventional natural gas consumption volumehad reached 166 billion m3 (see Fig. 7.3). Inrecent years, natural gas consumption volumehas grown by 12%, markedly higher thannatural gas production growth. Domestic natu-ral gas production volume is still unable tomeet the needs of domestic natural gasdemand, with imports of natural gas continu-ally increasing.

7.3.2 Coalbed Methane

China’s coalbed methane production volumeincludes both extraction and coal mine welldrainage. This research only deals with

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7.2 Proved Natural Gas Reserves 159

extraction-based coalbed methane, and does notconsider well drainage coalbed methane. As of2011, China’s ground extracted coalbedmethane was 2.3 billion m3, with 2012 groundextracted coalbed methane production volumeof 2.57 billion m3, a growth of 13% year onyear. Coal mine region coalbed methane pro-duction grew by 9.9% year on year, with therate of growth dropping during the same per-iod. By 2013, ground extracted coalbedmethane production volume was2.93 billion m3, growing by 13.7%. In 2014,ground extracted coalbed methane productionvolume was 3.6 billion, marking a large jumpupward (Table 7.5).

As of 2012, there were seven constructedcoalbed methane development projects, witheight development projects in progress. Grounddevelopment coalbed methane productioncapacity construction had reached 4.9 billion m3.In the past two years, new regions and newdevelopment projects have continually openedup, providing huge momentum for coalbedmethane industry development. For example, theBaode 1 billion m3 production capacity con-struction, the Yanchuan South 500 million m3

production capacity construction, the Mi’nanRegion East 1.5 billion m3 construction capacityconstruction and the Nanzhuang South 1 bil-lion m3 construction plans are all under way.

Moreover, total production capacity of approxi-mately 1.5 billion m3 will be developed throughprojects including Shouyang, Liulin, Changzi,Mabi and Shunan.

Coalbed methane exploration and develop-ment exhibits a marked trend toward newregions, new layers and new sectors:

• In recent years, coalbed methane explorationhas continually seen breakthroughs at depthslower than 800–1000 m, with coalbedmethane seeking relatively good single wellproduction volumes. For example, in theYanchuan Region at depths of 1497–1503 m,daily gas production has been relatively highat 3600 m3, while the Qinshui Basin inZhengzhuang at a depth of 1337 m hasachieved daily gas production of 2336 m3.Deep coalbed methane breakthroughs haveresulted in a marked expansion in the explo-ration and development of coalbed methane.

• In recent years there have also been significantbreakthroughs in low-rank coal exploration,for example, in Huainan single-well dailyproduction volumes at 660–880 m have been1000–2100 m3, Hui Chun has seen stablesingle-well production of 1500–2200 m3 at450–550 m and Yilan has seen stablesingle-well production of 1000–1200 m3 at700 m in depth. In addition, in Huolin River,

Table 7.5 China’scoalbed methaneproduction volume inrecent years

Time (year) 2011 2012 2013 2014

Production volume (100 million m3) 23 25.7 29.3 36

Data source Ministry of Land and Resources annual press conference materials

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160 7 China’s Natural Gas Resource Potential and Production Trends

Binchang and other places, low-rank coalregions have achieved production volumes ofover 1000 m3. Breakthroughs in low-rankcoal have opened up the door to develop-ment of coalbed methane in northern regions,where low-rank coal is distributed.

• Taking the Erdos Basin Hedong region as arepresentative of the North China Palaeozoiccoal stratum, there are typical coalbedmethane, tight natural gas and shale naturalgas characteristics between the layers. How-ever, comprehensive development of multipletypes of natural gas resources has not yet seena breakthrough. In recent years, the Hedongregion has increased exploration efforts withinthe coal stratum seeking tight sandstone gas,with marked breakthroughs already achievedand 6000–50,000 m3 of production volume oftight natural gas already achieved, and indi-vidual well production volumes also higher.

7.3.3 Shale Natural Gas

In 2012 China released the Shale Gas Develop-ment Plan (2011–2015), in which there wereplans that by 2015 proved shale natural gasreserve volumes would be 600 billion m3, with200 billion m3 recoverable. In 2015, shale natu-ral gas production was expected to be6.5 billion m3. Based on calculation of115 billion m3 of natural gas as 100 million tonsof oil, 6.5 billion m3 of shale natural gas isequivalent to 5.65 million tons of oil.

According to the latest information releasedby the Ministry of Land and Resources, in 2014China’s shale natural gas production volume was1.3 billion m3. As part of this, Jiaoshiba shalenatural gas production volume approached1.08 billion m3, and shale natural gas productionin Chuannan and other regions was200 million m3. The main natural gas productionlayers were in section 1 of the Wufeng-Longmaxi Formation.

From the perspective of exploration progress,China has achieved shale natural gas flowobjectives in formations including the

Qiongzhusi Formation, Wufeng-Longmaxi For-mation, Longtan-Dalong Formation, YanchangFormation, Xujiahe Formation, Ziliujing Forma-tion and others. Currently, only theWufeng-Longmaxi Formation has achieved suc-cessful large-scale development, with other targetformations still needing continual exploration.

7.4 Conventionaland Unconventional NaturalGas Production Forecasts

According to current natural gas increasetrends, forecasts for conventional and uncon-ventional natural gas production are asfollows.

7.4.1 2020 Production VolumeForecast

1. Forecasts based on the existing system

Based on the annual average growth of naturalgas production volume in the past several years of8–10 billion m3, conventional natural gas annualaverage production volume is forecasted to be8 billion m3. By 2020, conventional natural gasproduction volume will reach 180 billion m3.Based on target forecasts for shale natural gasproduction volumes from the Chongqing andSichuan regions, by 2020, shale natural gas pro-duction volume will be 40 billion m3. Coalbedmethane production volume data primarily showsa trend for growth in the extraction of coalbedmethane, and by 2020 this will reach around10 billion m3. Production volume total for natu-ral gas will be 230 billion m3 (not includingcoalbed methane) (Fig. 7.4).

2. Forecast in a partially changed existingsystem

With the system unchanged on the whole, andonly conducting new system explorations forshale natural gas in Chuannan and Chuandong,achieving shale natural gas development in

7.3 Growth of Natural Gas Production 161

general pilot regions for construction forecasts,conventional natural gas annual average growthwill remain unchanged at 8 billion m3, and by2020 will reach 180 billion m3. In Chuannan andChuandong, if new system trials for shale naturalgas development are conducted, by 2020 shalenatural gas production volumes will be60 billion m3. Coal formation coalbed methaneand tight natural gas general development effortswill be strengthened, with forecasts that by 2020,coalbed methane production volume will be15 billion m3 and tight gas and shale gas pro-duction volume within coalbed methane areaswill be 15 billion m3, for a total of270 billion m3 (not including coalbed methane)(Fig. 7.5).

7.4.2 2030 Annual ProductionForecast

1. Forecast in existing system

From 2020 to 2030, conventional natural gasproduction annual growth rate will remainunchanged and maintain at 8 billion m3. By2030, conventional natural gas production vol-ume will be 260 billion m3. In Chuannan andChuandong Longmaxi Formation, shale naturalgas production volume will rise, with other shalenatural gas formation production volumes alsoseeing breakthroughs. Shale natural gas produc-tion will rise from 40 billion m3 in 2020 to80 billion m3. Ground-extracted coalbed

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162 7 China’s Natural Gas Resource Potential and Production Trends

methane production volume will reach 20 bil-lion m3, while coal formation tight natural gasand shale natural gas production volume willreach 20 billion m3. Large-scale statistical coal-bed methane production will be 40 billion m3,for a total of 280 billion m3 (not includingcoalbed methane).

2. Forecast in a partially changed existingsystem

If oil prices remain at the current normal level,enterprise natural gas profitability will rise, andenterprises will be more motivated to producenatural gas. If conventional proved natural gasreserves remain at a high level from 2010 to2020, this will cause 2020–2030 annual pro-duction volume acceleration to rise slightly to10 billion m3, and reach 280 billion m3 by 2030.If Chuannan and Chuandong shale natural gasnew system pilots are particularly effective, andif they are expanded to achieve commercialbreakthroughs in other shale natural gas systems,then by 2030 shale natural gas production vol-ume will reach 150 billion m3. Coalbed methaneproduction volume will remain at 40 billion m3.Total natural gas production volume will be470 billion m3 (not including coalbed methane).

China’s natural gas production volumegrowth is controlled by myriad factors, includinggeological factors that can be resolved throughtechnological progress. However, system andmechanism factors are also ubiquitous, and clo-sely influence gains, and are difficult to resolvequickly. Cost factors in recent years have becomean important factor affecting natural gas industrydevelopment, and since 2003 exploration anddevelopment costs have continually risen. Ifthese cannot be effectively controlled, it willcause a marked influence on China’s natural gasindustry development and production volumegoals. As a result, China’s natural gas productionvolume increases could slow, and may behard-pressed to exhibit explosive growth.

7.5 Accelerating the Developmentof China’s Domestic NaturalGas Resources

7.5.1 Clarify Development Paths

Different paths of development require differentpolicy measures. Given a clear developmentpath, specific policy measures can be formulatedto promote natural gas development.

1. No change to the existing systems andmechanisms

This path of development is an extension ofthe existing development paths. Based on StateCouncil rules regarding oil and natural gaslicensing, natural gas exploration, developmentand pipeline shipping will all be operated byexisting state-owned oil companies. This busi-ness approach has the advantage of achievingintensive development of natural gas, and facil-itates large-scale development. However, costsare also very high, and overall prices are some-what excessive. This is especially true for pricesin natural gas production regions, and supplymarkedly lags behind demand. For example,Sichuan, Chongqing, and Xinjiang natural gasprices and supply volumes have no markedadvantage. Such a system causes cost increasesfor enterprises using natural gas as an energysource and source material.

2. Using change to strengthen market guid-ance and diversify development

Another path of development is to change theexisting licensed operation system, and to useenhancements to market mechanisms to intro-duce multiple ownership system enterprises todevelop natural gas and to carry out additionalexploration, thus realising diversified develop-ment. Through market competition, the strongestand most competitive survive, carrying out new

7.4 Conventional and Unconventional Natural Gas Production Forecasts 163

natural gas explorations, development projectsand supply investments. This developmentapproach requires that many issues are addres-sed, including high-quality preparation and fairallocation of mineral rights, the market liberali-sation of oil and gas project services, the inde-pendent operation of natural gas pipelines andfair access to them, marketing and trading ofproved reserves, and strong and effective over-sight. Otherwise, major problems will arise thatwill destroy the market reforms.

It is suggested that existing systems andmechanisms are suitably adjusted, appropriatelyopening up conventional oil and gas operatingrights by first opening up oil and gas mineralrights to large state-owned energy enterprises,such as state-owned energy enterprises thatalready hold shale natural gas mining rights, oropening up conventional oil and gas miningrights to energy enterprises that have alreadyentered the oil and gas sector overseas, guidingthese enterprises in their entry into domesticconventional and unconventional oil and gasexploration and development sectors.

7.5.2 Adjust Lowest ExplorationCommitments

In 1996, China’s Mine Law and subsequentaccompanying legislation prescribed that oil andgas mine exploration rights holders had to investat least 5000 CNY/km2 in the first year,7000 CNY/km2 in the second year and10,000 CNY/km2 in the third year. In the past,the low levels of exploration spending commit-ment did not take inflation into account. Becauseoil prices have gradually risen since 2003, oilcompany exploration and development costshave also seen constant increase. Thus 10 yearsago one exploration well only required CNY3000–5000, whereas now CNY 10,000–20,000might be needed to drill that same well, withsome well fees being even higher.

Because of the steep increase in costs,maintaining such low exploration spendingcommitments has essentially led to annualdeclines in investment because of the changed

price calculations. Previously, an CNY100 million exploration commitment could drillthree exploratory wells, whereas now only onecan be completed for the same outlay. Physicalexploration commitments by area are only onethird to one fifth of their level 15 years ago.A large area abundant in natural gas may thusbe seriously lacking in survey work, severelyimpacting natural gas discovery and reserveproduction growth.

Shale natural gas tender region bidding stan-dards and management requirements have raisedthe conventional oil and gas region lowestexploration commitment by a factor of 3–5 fromcurrent levels, with each square kilometre havinga lowest exploration commitment of CNY30,000–50,000. An increase in the lowestexploration commitment will increase surveyefficiency and promote prompt exits fromregions, thus reducing the occupied area of var-ious sectors and changing the current situation inwhich areas are marked out but not explored. Atthe same time, the current system of authorisa-tion through advance application could bechanged, following the example of the shalenatural gas region transfer approach, which usesa competitive mode to transfer existing conven-tional oil and gas blocks. International conven-tions provide examples of how to formulateeffective block exit mechanisms. A regulatoryteam should be set up to oversee implementationof legislation and systems.

7.5.3 Maintain Reasonable Prices

Currently, calls for natural gas price increases arevery loud, demanding that natural gas be pricedat 70% of oil prices according to heating value.As a basic energy and a source material foreconomic and social functioning, a natural gasprice that is too high or too low is not beneficialto overall development of the economy. Whenthe price is too low, producer investmentmomentum is insufficient and natural gas devel-opment is restricted. When natural gas prices aretoo high, this will keep a large quantity ofpotential consumers out of the market, which is

164 7 China’s Natural Gas Resource Potential and Production Trends

not beneficial to the economic development ofthe nation as a whole. In recent years, low naturalgas prices in the United States have played animportant role in economic recovery, and this isworth taking into consideration.

In the past 10 years, China’s natural gasreserve growth has been rapid, but productionvolume annual growth has been less than10 billion m3. The reason for this is the gapbetween oil and natural gas heating value prices,especially with the existing special licensedoperation system and high oil prices, which havemade enterprises more willing to invest in oilproduction. Recently, oil price drops have causedoil and natural gas heating value pricing tobecome equivalent, and given China’s relativelyhigh natural gas price, oil companies havebecome more enthusiastic about the production ofnatural gas. In order to reach a natural gas pricethat both providers and buyers can accept in themarket, the natural gas exploration and develop-ment market should be appropriately opened, andprices can then be formed through competitivemechanisms, thus establishing a relatively rea-sonable mechanism to set natural gas prices.

Different development mechanisms will resultin different price-forming mechanisms. Therefore,natural gas price problems must be resolved afterclarifying natural gas development mechanisms.

7.5.4 Establish Trade Mechanismsand Trade Platformsfor Proved Natural GasReserves

In recent years, China’s annual average provednatural gas geological reserves have consistentlyexceeded 500 billion m3, and it is expected thatthis will continue to grow fast for the next fewyears. However, proved reserves have not beenpromptly developed, and some have evenremained undeveloped for long periods of time.The reason for this is partly due to that portion ofproved reserves lacking effective economicmomentum.

It is recommended that a trade mechanism beestablished for proved and difficult-to-utilisereserves, permitting this portion of reserves toenter the market and be transferred. This willallow them to reach the hands of enterprises thatcan economically effectively develop suchresources and thus achieve prompt developmentand exploration. In such a system, enterprises cantransfer proved reserves to recover their explo-ration costs, while development enterprises canpurchase reserves to obtain development oppor-tunities. In order to guarantee the prompt devel-opment of these reserves, it is important to avoidsimple circulation and non-development ofreserves.

7.5.5 Accelerate Developmentof UnconventionalNatural Gas

China has abundant unconventional natural gasresources, of which shale natural gas and coalbedmethane are independent mine types, and are thefocus of unconventional natural gas develop-ment. Shale natural gas can be developed rapidly,and success has already been seen in ChongqingFuling Jiaoshiba, with a breakthrough also seenin Chuannan region, where success was realisedwithin a single year.

1. Pilot zones for shale natural gas develop-ment in Chuannan and Chuandong

Since 2009, when CNPC deployed andimplemented its Wei 201 Well and formallybegan shale natural gas exploration, shale naturalgas production volume reached 1.3 billion m3 by2014. This demonstrates that shale natural gas isquick to enter production, quick to achieve effi-ciency and quick to develop.

The shale natural gas formation in the south-ern and eastern portions of the Sichuan Basin isthe Longmaxi Formation. Based on CNPC andSinopec shale natural gas resource assessmentresults, this shale natural gas formation has shale

7.5 Accelerating the Development of China’s Domestic Natural Gas … 165

natural gas geological resource volume of1.9 billion m3 in Chuannan and Chuandong,with recoverable resources of 4.5 trillion m3.Shale natural gas presents relatively low devel-opment risks, and has resource foundations andtechnical foundations to carry out scaleddevelopment.

Chuannan and Chuandong Longmaxi For-mation are important areas when it comes toallowing shale natural gas to break through tolarge-scale production. Based on annual pro-duction of 60 billion m3 by 2020, and calculat-ing for stable production for 30 years,1.8 trillion m3 of shale natural gas recoverableresources are needed. It would only take a pro-portion of the 4.5 trillion m3 of recoverable shalenatural gas resources in Chuannan and Chuan-dong to achieve that goal. This means that bydeveloping the pilot construction in Chuannanand Chuandong, it will be possible to effectivelymobilise the Longmaxi Formation to providesufficient shale natural gas to meet the long-termgoal of 60–100 billion m3 of shale natural gasper annum by 2020. At the same time, it is alsopossible to explore the direction which oil andgas system reform should take in the future usingpilot regions here.

2. Additional support to coalbed methanedevelopment

Additional support for coalbed methanedevelopment could be provided with policies thatencourage profitability in the sector, with the aimof reaping benefits for energy security and theenvironment.

The first goal of enterprises when theydevelop coalbed methane is to obtain coalbedmethane commodities and to make profit. Thereis another major objective for surface andunderground extraction of coalbed methane incoal mining regions though: to ensure coal minesafety and to reduce gas emissions. In manyrespects, obtaining the coalbed methane

commodities is actually the secondary aim.These two different mindsets require corre-spondingly different policy measures.

• Coalbed methane development in coal miningareas is motivated by safety and environ-mental protection considerations. Workingclosely with coal mining and developers,plans need to be advanced by five years inorder to deploy surface extraction suitably farahead of well extraction, by deploying Lao-tang drainage and other coalbed methaneprojects.

• Policies that encourage and facilitate coalbedmethane can harness independent enterprisesto carry out coalbed methane extraction atscale across multiple mine sites. Policies,especially subsidies that promote coalbedmethane development, are primarily directedat enterprises that directly use this portion ofcoalbed methane (gas).

• When not involved with coal mining, coalbedmethane development is a commercial activ-ity, and can be promoted byincentive-focused industrial policy. Somecoalbed methane mining regions are notwithin coal planning regions and coal miningregions in the next 10–20 years. The coalmining in these regions is commercial coal-bed methane development, and coal miningsafety and environmental problems do notarise. Such activity should not enjoy thepreferential policies applied to coalbedmethane development in coal mining areas. Itis sufficient simply to use the current prefer-ential development policies in such cases.

It is worth noting that subsidy policies thatlack a time limit will cause enterprises to developa reliance on national subsidies, resulting in thecoalbed methane industry remaining in animmature state of development for longer thanwould otherwise be the case, rather than devel-oping healthily and robustly.

166 7 China’s Natural Gas Resource Potential and Production Trends

Case 1: Establishing a 100 billion m3

Shale Natural Gas General Pilot Regionin the Sichuan BasinThe current international oil price is low,and US shale oil and gas companies havesuffered the impact of this and even beenforced to apply for bankruptcy protection.Asian LNG spot prices are also trendinglower. However, looking to the long term,supply shortages and high import priceswill be the major problems faced byChina’s natural gas development. Shalenatural gas development is still a strategicchoice for China’s natural gas development.The Sichuan Basin’s abundant shale naturalgas resources and favourable developmentconditions make it possible to carry outpilots to test general reforms strategies. Byusing optimised systems and mechanisms, apreliminary shale natural gas developmentcan be scaled up and commercialised toachieve annual production of 100 billionm3

by 2025 in this large shale natural gasregion. This is not only a strategic choice toincrease secure domestic natural gas supply;it also represents an unusually attractiveinvestment opportunity.

1. Sichuan Basin has the basic condi-tions in place

During multiple surveys of Sichuan andChongqing, and after meetings with mul-tiple investors and engineering technicians,and collecting opinions from the relevantexperts regarding shale natural gas devel-opment resource conditions, technology,equipment, engineering, investments,applications, environmental loads andother factors, it is our opinion that with theappropriate system and policies, theSichuan Basin will become a leadingregion for shale natural gas development inChina. By 2025, this region could feasiblyachieve 100 billion m3 of shale natural gas

production volume. The reasons are out-lined below.

(I) Resource conditions are guaranteedThe Sichuan Basin’s shale natural gasresources are abundant, and there are widedistributions of two marine shelves ofsubstantially thick black shale. Accordingto Sinopec data, total shale natural gasresources in the entire Longmaxi Forma-tion and Qiongzhusi Formation amount to40 trillion m3. Of this, the Longmaxi For-mation marine shelf shale natural gas has apromising area of 75,000 km2 that hasalready seen development breakthroughs,with a shale natural gas resource volume of25 trillion m3 and recoverable resources of3.7 trillion m3. As part of this 75,000 km2,there are 35,000 km2 of shale natural gasresources whose conditions are superiorand geological resources of nearly 14 tril-lion m3, with recoverable resources of28 trillion m3. If development is onlypursued in the high-quality shale naturalgas area of 20,000 km2 of the LongmaxiFormation, beginning in 2015, the explo-ration and well layout planning could becompleted and approximately 10,000 wellscould be deployed within 2015–2025. By2025, annual production of 100 billion m3

could be achieved. Moving forward, activewells would number around 800, achievingstable production for 20 years. It could besaid that as far as resource volume isconcerned, Sichuan and Chongqingentirely satisfies the requirements toestablish a region with annual productionof 100 billion m3.

(II) Development technology andequipment is assured

Currently, China has preliminarily come toterms with shale natural gas geophysics,well drilling, well completion, pressure

7.5 Accelerating the Development of China’s Domestic Natural Gas … 167

fracturing and other technologies, giving itthe ability to drill shallow water wells of3500 m as well as staged fracturing.Non-seismic geophysical prospectingidentification and forecasting technology,wholly-mobile rail drills, large-scale frac-turing vehicles (3000 model, 3500 model),construction environment protection tech-nology and other factors are now at similarlevels of advancement to those seen inter-nationally, and breakthroughs have alsobeen achieved in domestic bridge plugmanufacture. Compared to internationallymature technologies, China now only hasshortcomings in drill geological position-ing, on-drill measurements andmicrometre-nanometre structure and com-position analysis. However, the majority ofwell-known oil services companies fromabroad are now participating in China’sshale natural gas development, and canprovide vital technologies. Sinopec’sChongqing Fuling (Fuling) Shale GasField has entered commercial develop-ment, attesting to the fact that China’sshale natural gas development technologyis now up to par. In addition, China’s shalenatural gas core equipment, such as sets ofdrills, fracturing vehicle groups, well toolsand accompanying project services, allhave powerful capabilities, with existingdomestic drill quantities and drill produc-tion capacities entirely meeting therequirements placed on well drillingquantities during construction and produc-tion stages.

(III) Good mining efficiency, guaran-teed economic benefit

As of November 30, 2014, Sinopec (Ful-ing) Region had completed fracturing testgas sites at 69 wells and obtained mediumto high production of shale natural gasflows, with an average well test productionvolume of 320,000 m3 per day. Based on

unhindered flow volume of 1/3, 1/4 and 1/5accompanying set production, averagesingle well annual production volume isapproximately 21.60 million m3 or higher,with average single well costs of CNY80 million (including exploration, miningand shipping). Adding simple processingsuch as water extraction to this, well costsare less than 1.5 CNY/m3, whereas currentshale natural gas well prices are2.78 CNY/m3. If a national financial sub-sidy of 0.4 CNY/m3 is added in, the actualprice is 3.18 CNY/m3, and single wellannual revenue once production stabilisescould reach CNY 68.688 million. In addi-tion to Fuling Region’s shale natural gasmining achieving commercial viability, inthe Chuanning, Changning and Weiyuanregion the shale natural gas is buried rela-tively deep, but shale natural gas andconventional gas overlap in distributionand both possess general economic value.The eastern Chongqing region and WesternHubei region shale natural gas areas alsofeature light oil, and the economic value ofmining this is also relatively high. Theeconomic success of the Sichuan Basin’sshale natural gas development isguaranteed.

(IV) Environmental controls can drawon experience elsewhere, and min-ing water is assured

Currently, the United States has over10,000 shale natural gas wells, and withthe participation and oversight of regula-tors and the public, there have been noenvironmental incidents affecting society.The majority of the shale naturalgas-producing layers in the Sichuan Basinare at over 2000 m in depth, and so long ascasing work is handled appropriately orassurance measures are added (such asinstalling an encircling casing), fracturingwater has no chance of permeating into the

168 7 China’s Natural Gas Resource Potential and Production Trends

water table system. In terms of waterusage, water usage volume for100 billion m3 of gas is approximately100 million L3 of water, which is 1.6% ofthe water usage of Sichuan Province. Sincethe Sichuan Basin has abundant waterresources, these water resources areentirely assured. However, recently in theUnited States, including Texas, there havebeen reports of small earthquakes and otherevents caused by development of shaleoil/gas that are worthy of public attention.

2. A shale natural gas developmentpilot area should be establishedquickly

Basing calculations on annual productionof 100 billion m3, an investment of CNY800 billion would be required during theconstruction and production period (2015–2025 well completion for around 10,000wells). Based on the current system (rely-ing only on CNPC’s south-west branchcompanies and Sinopec’s south-westbranch companies to invest), capabilitiesare extremely limited. This is especiallytrue for the Longwangmiao large gas fielddiscovered by CNPC’s south-west branchcompany, with reserves of over 400 bil-lion m3, located in central Sichuan. Con-ventional gas field construction likewiserequires a large quantity of investment intoexploration and development. Therefore,there is a need for new ideas for shalenatural gas development, and it is recom-mended that a general pilot zone for shalenatural gas development be constructed inthe Sichuan Basin and surrounding areas.With a controlled and safe environment,preliminary trials can be attempted,restructuring shale natural gas developmentusing a new model, with new mechanismsand new rules. This will promote shalenatural gas development and also offer new

points of reference for China’s oil and gasreforms so that successful experiences canbe replicated and promoted. Importantmeasures include:

(I) Innovative mining rights manage-ment and market accessmanagement

The first issue is mining rights manage-ment. Resources that the three major oilcompanies have not begun to produce,explore or are in the process of developingand exploring should be the subject oftenders. The second issue is market access.Not only should other state-owned enter-prises be introduced, but also privateenterprises and foreign investment enter-prises. In terms of foreign investmententerprise entry, not only should largetransnational corporations be introduced,but small and medium-sized oil and gasenterprises with abundant experience andinnovative capabilities should also beenabled to enter. These enterprises haveplayed a critical role in the shale oil andgas revolution in the United States. Interms of foreign investment access, so longas technical and environmental standardsare met, and national security reviews arepassed, foreign investment enterprisescould enter in an independent fashion.

(II) Make use of the economic advan-tages offered by mixed ownership

CNPC and Sinopec have taken stepstowards establishing new ownership para-digms, for example CNPC has establishedthe Sichuan Changning Natural GasDevelopment Co., Ltd in Changning andSinopec has established Chongqing ShaleGas Exploration and Development Co.,Ltd in Chongqing, each of which is amixed ownership company. Mixed own-ership offers state assets, private assets and

7.5 Accelerating the Development of China’s Domestic Natural Gas … 169

foreign assets the opportunity to enter theshale natural gas development sector. It isalso beneficial to central governmententerprises, enabling greater use of societalcapital and more rapid development. Withlocal state-owned asset participation, thereis greater breadth for enabling resettling,road repairs and natural gas nearby utili-sation. With private enterprise and foreignenterprise participation, company govern-ment can be improved, thus raising thelevel of mining efficiency and service. Thenext step in shale natural gas developmentmixed ownership reforms requires effortsin terms of corporate governance, strategicco-ordination and the division of labourand partnerships. In order to improveoverall activity, it is not enough simply tooverlook mechanism transitions to obtainmonetary funds. Likewise, the sole focusshould not be on bringing in mixed capital,while essentially refusing to allow outsideinvestors to participate in the correspond-ing management and operational activity.

(III) Exploring effective shale naturalgas regulatory models

It is possible to aim to create a pilot zonefor policy systems, management standards,oversight rules and regulatory systemsrelating to shale natural gas exploration,development, storage, and shipping usagewithin 2–3 years, including informationsearch and sharing platforms. In terms ofenvironmental oversight, central govern-ment standards and policies should beestablished, with local organisationsimplementing the environmental regula-tion. The Ministry of Environment is in theprocess of researching the establishing ofshale natural gas development assessmentguidelines. These could be tested in thisregion, with a preliminary launch andimplementation of national norms andstandards for such aspects as land usage,vegetation restoration, water resourceusage, waste water processing, waste

processing, gas emissions, drilling and wellcompletion. In terms of geological materialand information sharing, comparison canbe made to the United States’ administra-tive legislation approach to the mandatorycollection of shale natural gas geologicalinformation, thus establishing a geologicalengineering information managementplatform with government-controlledresource information. This will achieveinformation sharing and promote highlyefficient development.

Case 2: Chinese Coalbed MethaneProduction Volume Forecasts

1. Coalbed methane resourcesChina has abundant coalbed methaneresources, which are typically found inmultiple coal basins with multiple coalformations and a wide variety of coal typesand coalbed methane deposits. Due to thewide variance in the coal-containing basinsin China, subsequent construction andrestructuring is intense, resulting in a verycomplex geological environment for coal-bed methane resource deposits in China.Coalbed methane resources are primarilydistributed in China’s north, north-west,south and north-east regions.

China’s proved coalbed methane vol-umes have grown rapidly. In 2012,national proved coalbed methane reservesgrew by 134.4 billion m3, rising year onyear by 32.2%. In 2013, national coalbedmethane exploration proved new reservesof 23.577 billion m3. Proved coalbedmethane geological reserves now sit at575.4 billion m3, with technically recov-erable reserves of 285 billion m3.

The regions that are abundant in coalbedmethane are primarily the Qinshui Basin,the Erdos Basin and the Yunnan GuizhouNorth Depression. In 2012, new provedgeological reserves in the Qinshui Basin

170 7 China’s Natural Gas Resource Potential and Production Trends

were 90.242 billion m3, with the ErdosBasin newly adding proved coalbedmethane reserves of 37.11 billion m3. TheYunnan Guizhou North Depression in 2012deployed and implemented 11 assessmentwells and three well groups, for a total of 18wells as production capacity experiments.A total of 17 wells have achieved coalbedmethane flows, with single well daily pro-duction capacity of 500 m3.

2. Coalbed methane reserve forecasts

(I) Characteristics of coalbedmethane-intensive regions in China

Coal layer gas factors are generally asses-sed by usage of gas per ton of coal,absorption saturation, concentration ofmethane and resource abundance. Gas perton of coal is gas volume, and is a deter-mining factor in coalbed methane resourcequantity. Resource abundance is a generalreflection on the amount of gas in the coaland the thickness of the coal layer.Absorption saturation is a gas volumefactor related to gas mining feasibility.Methane concentration is a major standardin assessing gas quality.

Regarding regional distribution, averagecoalbed methane gas volume is highest insouthern China, followed by the north-eastregions and northern China. Thenorth-west region has the lowest amounts.The methane concentrations of each regionare similar, and from highest to lowest are:southern China, northern China, thenorth-west and the north-east. The averageresource abundance in each region variessignificantly, with the north-west regionmarkedly higher than other regions, fol-lowed by the north-east. Northern China isslightly lower than eastern China, withsouthern China the lowest. Averageabsorption saturation is led by north-eastChina, followed by southern China,northern China and the north-west.

From the perspective of coalbedmethanelayers, the Permo-Carboniferous, upperPermian series and Lower and MiddleJurassic series are representative of good gascontents. Other eras are relatively poor.From a general analysis, the northernregion’s major basins have good gas con-tents in the Permo-Carboniferous, and this isthe primary gas layer for important basins.

From the perspective of coal rank dis-tribution, the resource volume of high coalrank lean anthracite III (Ro = 1.9–2.5%) is7.8 trillion m3, accounting for 21.1%. Theresource volume of medium-rank gas/leancoal (Ro = 0.7–1.9%) is 14.3 trillion m3,accounting for 38.9%. Low coal rankbrown—long flame coal (Ro < 0.7%)resource volume is 14.7 trillion m3, andaccounts for 40%.

(II) Key target areas for coalbedmethane exploration

Based on summarising coalbed methaneabundance patterns and gas characteristics,there are 18 target regions that have beenselected nationwide as preferential loca-tions, including Pucheng, Ji County—Hancheng, Shenmu, Hengshanbao, Ning-wunan, Panguan, Gemudi, Pingle, Changji,Dajing, Wuermu, Wushenqi,Sanjiang-Mulinghe, Huolinhe and Yimin.Of these, six are Class I target regions, fiveare Class II target regions and seven areClass III target regions, giving a total areaof 54,700 km2. The target Class I coalbedmethane resource volume for the region is3.63 trillion m3, primarily distributed inthe Qinshui, Erdos, Zhunge’er and Ningwubasins. Coalbed methane geological con-ditions are good, representing coalbedmethane near- and mid-term reserve andproduction volume realisation target areas.Class II and Class III areas have a total of2.87 trillion m3 of resource volume, andare distributed across Tuha, Santanghu,Sanlian Basin, eastern Yunnan and Wes-tern Guizhou, and the Pingle Basin, and

7.5 Accelerating the Development of China’s Domestic Natural Gas … 171

have potential for mid- to long-termreserve growth and subsequent replace-ment blocks. As part of this, the QinshuiBasin south portion Jincheng region, ErdosBasin south-east region Ji County—Hancheng region, and the Zhunge’er Basinsouth-east Changji-Dajing are promisingcoalbed methane regions with reserves of100 billion m3 (Table 7.6).

This research is based on nationalcoalbed methane reserve historical data, inconjunction with coalbed methane geo-logical characteristics and resource distri-bution traits, making use of the Wengmodel method and Gompertz method toforecast proved coalbed methane reservesand production volume. It is expected thatby the end of the 12th Five-Year Plan, 10advantageous target regions will see newlyadded proved geological reserves of700 billion m3. During the period of the13th Five-Year Plan, the scope of explo-rations will be further expanded to south

China, and the north-east and north-westregions, with newly added proved reservesof 350 billion m3 in the Qinshui Basin,Erdos Basin, Zhunge’er Basin, NingwuBasin and Erlian Basin. From 2013 to2030, annual proved reserves will be atapproximately 100 billion m3. After 2030,as coalbed methane exploration anddevelopment technology continues to pro-gress, coalbed methane at 2000–4000 mwill also be possible to confirm and mine,with large increases in proved reservesexpected in coalbed methane (Table 7.7).

(III) Coalbed methane production vol-ume forecasts

As coalbed methane exploration anddevelopment technology matures andmining costs drop, coalbed methanedevelopment will become larger-scale andwill develop toward greater industrialisa-tion, gradually forming 10–15 coalbedmethane production bases. Using the Weng

Table 7.7 Nationalproved coalbed methanereserve forecast(100 million m3)

2015 2020 2025 2030

New proved geological reserves 7000 3500 4800 7200

Accumulated proved reserves 8619 12,119 16,919 24,119

Data source Ministry of Land and Resources and other material analysis and preparation

Table 7.6 National coalbed methane results of selection of favourable target regions

Class Basin Region Majordepth (m)

Major coalthickness(m/layer)

Gascontents(m3/t)

Area(km2)

Resourcevolume(108 m3)

I Qinshui Qinshui north 200–1200 8–17/2 10–32 5150 11,864

Erdos Erdos east 300–1500 7–22/2–3 9–20 7430 11,805

Zhunge’er Changji-Fukang 300–1000 25–32/3 5–15 7010 7460

Qinshui Yangquan-Heshun 150–1300 9–12/2–3 8–35 1200 2500

Ningwu Ningwu south 800–1500 11–14/1 11–21 534 1665

Sanlian Huolinhe 300–900 7–34/5 5–8 380 1025

Data source Ministry of Land and Resources and other material analysis and preparation

172 7 China’s Natural Gas Resource Potential and Production Trends

model and the Gompertz method to anal-yse China’s future coalbed methane pro-duction volume growth, it is expected that2015 coalbed methane production volumewill be 4.6 billion m3, rising to10–30 billion m3 by 2020. From 2021 to2030, 20–30 coalbed methane productionbases will be established, with40 billion m3 of production volume by2030 (Table 7.8).

Case 3: Forecast of China’s CoalMethane Production Potential

1. Coal methane developmentWith the implementation of a sustainabledevelopment strategy and the strengthen-ing of environmental and other policies,domestic natural gas consumption marketsare continually expanding, and there aremore channels and more methods ofexpanding the natural gas resource supply,and optimising the gas source structure has

become an important strategic part ofoptimising the national energy structure.Converting coal region resources into nat-ural gas can to a certain degree supplementChina’s shortage of conventional naturalgas supply.

China has approved its first two coalmethane projects: Keqi, with coal methaneproduction capacity of 4 billion m3/year,divided into three series, with each serieshaving production capacity of1.33 billion m3; and Qinghua, with5.5 billion m3/year, divided into fourstages of construction. The first stage hasproduction capacity of 1.375 billion m3/year.In 2013 the two coal methane projects in totalhad gas volume of 31 million m3.

Approved and in-progress coal methaneprojects include the Fuxin and Huinengcoal methane projects, with total produc-tion capacity in the region of 5.6 bil-lion m3/year, and expectations to begin gassupply in 2015. In-progress and operatingcoal methane projects are listed inTable 7.9.

Table 7.9 Operating and in-progress coal methane projects

Type Project name Date ofoperation

Scale Total production capacity(100 million m3)

In operation Datang Keqi Coal Methane Project 2013 13.3 40

Xinjiang Qinghua Coal Methane Project 2013 13.75 55

Underconstruction

Huineng Coal Methane Project 2015 – 16

Liaoning Datang Fuxin Coal MethaneProject

2015 – 40

Inner Mongolia Shenhua Erdos CoalMethane Project

2015 – 20

Total 27.05 171

Data source Public materials analysis and organisation

Table 7.8 National coalbed methane production growth forecasts (100 million m3)

2015 2020 2030

Production volume 45 100–300 400

Data source Ministry of Land and Resources and other material analysis and preparation

7.5 Accelerating the Development of China’s Domestic Natural Gas … 173

2. Progress in coal methane projectplanning and construction

In recent years, China has seen an acceler-ation in approvals of coal methane projects,primarily concentrated in Inner Mongoliaand Xinjiang. As of the end of June 2014,the NDRC had approved 18 coal methaneprojects, with a combined productioncapacity of 84.2 billion m3/year. Provincialplanning and filing showed 37 projectswith production capacity scale of129.6 billion m3/year. Operating pro-jects, or those with road permits and

approvals, as well as those under con-struction, had a total production capacityof 230.9 billion m3/year. Currently, onlya small number of these projects havebegun construction, and considering thatcurrent natural gas prices are a problem, aswell as the current policy environment, notall projects will necessarily be finished. Itis also not a given that the completedprojects will be able to satisfy the load ofproduction, but production capacity willstill offer basic assurances for China’snatural gas supply security (Table 7.10).

Table 7.10 China’s current coal methane projects with road permits

No. Province Project name Production capacity(100 million m3/year)

1 InnerMongolia

Xinmeng Energy Investment Co., Ltd Coal Methane Project 40

2 InnerMongolia

Erdoa Coal Methane Industrial Park and 12 billion m3 CoalMethane Project

120

3 InnerMongolia

State Grid Inner Mongolia Guxinganmeng Coal Methane Project 40

4 InnerMongolia

Huaneng Yimin Coal Methane Project 40

5 InnerMongolia

Inner Mongolia China Star Energy Limited Coal Methane Project 40

6 Xinjiang Huaneng Xinjiang Coal Methane Project 40

7 Xinjiang China Power Investment Corporation Xinjiang Huocheng CoalMethane Project (three phases)

60

8 Xinjiang Xinjiang Fuyun Guanghui Coal Methane Project 40

9 Xinjiang China Coal Energy Xinjiang Coal Methane Project 40

10 Xinjiang State Grid Pingmei Coal Methane Project 40

11 Xinjiang Xinjiang Longyu Coal Methane Project 40

12 Xinjiang Huadian Xinjiang Coal Methane Project (Xiheishan coal methane) 40

13 Xinjiang Sinopec Great Wall Energy Coal Methane Project 80

14 Xinjiang Xinjiang Yili Xintian Coal Methane Project (Xinwen phase one) 20

15 Xinjiang Suxin Energy Xinjiang Coal Methane Project 40

16 Xinjiang CPCEC Yinan Coal Methane Project (three phases) 60

17 Shanxi CNOOC Shanxi Datong Coal Methane Project 40

18 Anhui Anhui Huai’nan Coal Methane Project 22

Total 842

Data source Public materials analysis and organisation

174 7 China’s Natural Gas Resource Potential and Production Trends

3. Coal methane production potentialanalysis

According to the construction progress ofcoal methane projects, and in conjunctionwith project construction cycles and pro-duction capacity plans, an arrangement hasbeen made of all coal methane projectproduction capacity.

Projects in 2020 with full road permitswill have total production capacity of84.2 billion m3/year, and, considering theyare based on three phases, with basiccommencement post-2018, by 2020 it willbe possible to achieve two-phase scaledcapacity of 60 billion m3/year, reaching95 billion m3/year in 2025 and102 billion m3/year in 2030.

However, what is worthy of note is that,moving forward, coal methane develop-ment still faces many uncertainties. Onefactor is the currently relatively low inter-national oil and natural gas prices, whichhave greatly inhibited the profit space forcoal methane, especially given significantdifficulties with project cost difficulties.A second factor is water consumption andenvironmental pollution, which causessignificant controversy. Therefore, whilecoal methane production capacity will bebuilt in the future, specific productioncapacity is nonetheless still highlyuncertain.

Case 4: Rural Organic Waste NaturalGas Effects and PoliciesIt has been estimated that nearly 76% oforganic waste in China comes from agri-culture, with crop stalks and livestockmanure being the two major sources.China’s villages have 600 million tons ofcrop stalks dispersed among fields, andfarmers generally deal with these byburning them, which is inefficient and not

environmentally friendly. As livestockintensity becomes increasingly concen-trated, concentrated processing of manureis a problem that not only hinders enter-prise development but also endangers therural environment. Resolving ruralorganic waste transitioning has alwaysbeen one of the major issues facing agri-culture. Beijing Deqingyuan has exploreda series of technical models that transformrural organic waste into clean energy, andtheir experience is worthy of attention andwider promotion.

1. Improving rural environments andchanging rural energy usagestructures

Beijing Deqingyuan is an egg producer inBeijing that has won industry fame andmarket share by giving its eggs an “identitydocument” (using edible ink to print thebrand name, production date and a fraudprevention code on each egg’s shell).However, after they expanded their pro-duction scale, they discovered there werealso attendant environmental problems,with 2 million laying hens producing thesame amount of manure each day as300,000 people. If this waste is not pro-cessed, it causes contamination to thegroundwater and soil. To this end, BeijingDeqingyuan specially established a cleanenergy company to resolve the problem oftransforming and using chicken manure.After several years of study, a break-through took place in the three technicalareas of sand removal, high-concentrationpurity extraction and biological desul-phurisation, achieving power generationfrom chicken manure methane in 2007.Following on from this, they next devel-oped a mixed-source material productionof methane gas from crop stalks andchicken manure, making natural gas afterpurification compression. The break

7.5 Accelerating the Development of China’s Domestic Natural Gas … 175

throughs in these technologies have yiel-ded feasible solutions to bring about ruralorganic waste transformation and to allowfarming using renewable energy.

The first point to note is the improve-ments to organic waste conversion and tothe rural environment. Deqingyuan canprocess 100,000 tons of manure per year,equivalent to reducing CO2 emissions by71,000 tons, and 35 tons of nitrites. A totalof 25,000 tons of crop stalks are processedannually, equivalent to a CO2 reduction of40,800 tons and 25 tons of nitrites. Notonly has the manure generated by chickensbeen used effectively, the approach hasalso provided a solution for the problem ofstalk burning that farmers have alwaysfaced.

Also notable is the formation of a fullindustry chain. Deqingyuan’s methanepower generation plant achieved connec-tivity in 2009 with North China PowerGrid, and now produces upward of 14 MWof power annually, along with160,000 tons of organic fertiliser. In 2013,biogas sales revenue was CNY 600,000. In2014, this reached CNY 2.7 million. Theremaining liquid methane biogas residue isprocessed into solid and liquid organicfertiliser, with annual production of160,000 tons of organic fertiliser sold tolocal farms in Yanqing and prompting thedevelopment of 10,000 Chinese mu oforganic apples and 120,000 acres of envi-ronmentally friendly corn crops. Throughordered procurement, 60% of Yanqing’scorn is purchased, which is then used toprocess into chicken feed to be fed to the3 million layer hens at the farm. Thus acomplete industry chain has been created:ecological cultivation, food processing,clean energy, equipment manufacturing,organic fertilisers, agriculture and organicplanting.

Finally, there is the improvement torural production and living conditions thathas occurred. Deqingyuan transports the

natural gas generated from purification andcompression by tanker truck to variousvillage facilities for tank storage. It is thensent via pipeline to countless homes. In2013, biogas was supplied to 2000 homes,which had risen to 5000 homes by July2014, with a further rise to 7000 homesexpected. Deqingyuan and YanqingCounty are co-operating in new biomassenergy projects, with plans within the nextthree years to enable the 10,100 homes in39 villages within Yanqing County to usebiogas. During an on-site survey of thearea, we found that farmers used liquidmethane and remnant methane to carry outorganic planting, selling the organic applesthey produced to consumers, while theenvironmentally friendly corn was sold toDeqingyuan to raise chickens. The farmersno longer cooked, heated their homes andbathed in hot water that was reliant on cropstalks and coal, ending their high expen-diture on coal. This has resulted in anenormous change to their living andworking conditions.

2. Potential for larger-scale ruralorganic waste energy conversion

The first factor behind this scheme’s suc-cess is the mature technology:

• Cow manure and chicken manure con-tain approximately 10–15% sand. In thepast, due to technical restrictions onsand removal, pure chicken manurecould never be used as a source forfermentation of methane gas. AfterDeqingyuan invented organic separa-tion technology, achieving separationof chicken manure sand and organicmaterials, it was possible to extract over80% of non-soluble solids from chickenmanure.

• The methane gas produced after fer-mentation of livestock manure contains2000–5000 ppm of hydrogen sulphide.Traditional methods were never able to

176 7 China’s Natural Gas Resource Potential and Production Trends

solve the problem of desulphurisation.However, Deqingyuan inventedbio-desulphurisation of methane gas,using sulphur-consuming bacteria toturn sulphurised hydrocarbon into ele-mental sulphur. It is a low-costapproach and does not generate sec-ondary pollution.

• Conventional methane concentrationsare generally 2–5%. After Deqingyuaninvented high-concentration methanegas fermentation technology, chickenmanure fermentation and crop stalkfermentation concentration rose to 10–15%, which reduced water consump-tion and fermentation system area byover 50%.

• Deqingyuan invented a mixed-sourcematerial fermentation technology thatused crop stalks as a source of carbon,liquid methane as a source of nitrogenand fermenting microbes to achievejoint fermentation. This resolved vari-ous problems during fermentation,including saturation of stalks, floatingof stalks, rapid hydrolysis of zymo-phytes by the stalks, as well as the needfor large swathes of land. The com-pany’s membrane purification equip-ment uses only one-tenth of the area ofsimilar projects, and has reducedenergy consumption by over 50%.

The second factor behind the scheme’ssuccess is a more reasonable economicapproach:

• Investment costs are low. Deqingyuan’snewly constructed daily production8000 m2 biogas project can satisfy theresidential gas use requirements of10,000 households with an investmentcost of approximately CNY 30 million,CNY 16 million lower than industrycompetitors.

• Gas production costs are lower.Deqingyuan, because it can collect and

use the various source materials itrequires from the area 20 km aroundthe methane gas station, has an averagegas manufacture cost of 2 CNY/m3,which is markedly lower than the gasprice currently provided in the city ofBeijing (Beijing’s current natural gasstation pricing is 3.28 CNY/m3).

• There has been an increase in economicvalue: 1 m3 of methane gas can con-ventionally be generated into power at avalue of CNY 1.19, whereas Deqin-gyuan’s membrane purification methodenables conversion of 1 m3 of methaneinto CNY 2.4 worth of natural gas, thusachieving added value of 1.21 CNY/m3

of methane gas.

The third success factor behind thescheme’s success is the greater economicutility to farmers. Deqingyuan sells thenatural gas to farmers at a price of2.5 CNY/m3, while also accepting the cropstalks provided by farmers, convertingthese source materials into natural gas andcosting the farmers that provide crop stalksvery little actual expense. Taking ahousehold of 3–4 people as an example, inthe past, costs would be CNY 100–120 permonth using tank storage liquefied gas,whereas this is now only CNY 30–40 permonth using biogas.

3. Policy recommendationsThe first recommendation is that supportfor rural and small town biogas and pipe-line network construction should beincreased. As the pace of urbanisation andrising living standards quickens, China’snatural gas consumption is entering a per-iod of rapid growth, and natural gas supplyand demand conflicts are being high-lighted. If all of China’s 600 million tonsof crop stalks were fully utilised, annualproduction of methane gas could reach120 billion m3, providing 71.6% of 2013total natural gas consumption. Livestock

7.5 Accelerating the Development of China’s Domestic Natural Gas … 177

manure can also be converted into pro-duction capacity of 122 million tons ofstandard coal. These organic wastes aresignificantly concentrated, and crop stalksare concentrated in grain-producingregions while manure is concentrated inlivestock-cultivating areas. Forestry left-over materials are concentrated in forestregions, while industrial waste is concen-trated in agricultural product processingplans, with the characters of the majorportions being concentrated, thus facilitat-ing promotion of rural and small andmedium-sized town energy construction. Itis recommended that a perspective beborrowed from energy supply and demandand from rural development, starting anal-ysis of the issue at the level of overallnational strategy and deployment in orderto provide the best policy support for ruralorganic waste resource energy conversion.

The second recommendation is toresolve the problems faced by enterprisesin energy conversion innovation. Duringour Deqingyuan survey, enterprises repor-ted that some current policies do not sup-port enterprises in innovating. For instance,there are grid connection issues. Afterensuring sufficient rural gas usage, theremaining biogas has no channel throughwhich it can be sold, and it is recom-mended that biogas be permitted to mergewith urban natural gas pipeline networks toallow access to natural gas companiesinvolved with urban sales.

The third recommendation relates topricing problems. Currently, Deqingyuan’snatural gas sales price is 2.5 CNY/m3,while Beijing’s industrial user gas price is3.65 CNY/m3 and transportation andshipping gas prices are even higher. It isrecommended that biogas sales prices befreed up to open market competition.

The fourth recommendation relates totax waivers. Currently, China does notprovide price subsidies for biogas, and alsocollects 17% VAT. Considering biogas’slow carbon impact on the environment, andgiven that a certain amount of policy sup-port is given to development for solarpower, wind power, and biofuel energy, itis recommended that biogas be exemptfrom VAT.

Case 5: Upstream Policy for Uncon-ventional Oil and Natural GasUnconventional oil and natural gas devel-opment and production is a developmenttrend in the majority of regions worldwide.Currently, the United States and Canadaare leaders, followed by Argentina andAustralia. Russia, the United Kingdom andother nations have also attempted to ensurethat their shale natural gas/oil resourceshave potential. This paper summarisesfinancial policies in the United States (on-shore), the United Kingdom, Canada,Russia, Argentina and Malaysia, focusingon unconventional resource developmentincentive measures and making recom-mendations for China.

1. Argentina1

With the exception of China, Argentinahas the world’s largest shale natural gasresources while at the same time also beingone of the nations with the most abundantshale oil resources (after Russia, the UnitedStates and China) (Nulle 2014: 60).

Currently, Argentina is implementing aspecial licensing rights regime. Since 1991,all licences have been managed under aspecial licensing fee/tax collection system,including special rights usage fees, income

1Argentina summary materials are sourced fromHIS PEPS, WoodMac and Apache Enterprise website.

178 7 China’s Natural Gas Resource Potential and Production Trends

taxes, provincial sales taxes, other signingdeposits/lease amounts and oil/gas exporttariffs. This system was implemented dur-ing the period of economic crisis in 2002and has continued on to the present day.

In 2014, Argentina passed the new Oiland Natural Gas Law, prescribing speciallicensing usage fees and permit issuancesystems controlled centrally, and also giv-ing management rights to various provin-cial regulatory institutions. Prior to thelaunch of this approach, oil and natural gaslicensing and operational jurisdictionbelonged to the provincial governments.Thus provincial governments could benefitby issuing their own oil and gas rightslicences.

ENARSA plays a purely commercialrole, owning all unlicensed near-seaexploration on federal land within 12nautical miles of the shore. All activities inthese regions must be conducted inco-operation with ENARSA.

To describe Argentina’s upstreamindustries as “uncertain” would be veryapt. The RSC system was changed to thecurrent licensing rights usage fee/taxregime, and the existing laws thusentirely covers the “2006 Short Law”,giving oil and gas jurisdiction to provincialgovernments (with the exception of federalmarine regions).

In order to satisfy national demand,Argentina has consistently increased use ofthe oil and gas industries. In recent years,energy demand has continually grown, andthe government has admitted that it mustbecome more involved, and thus it hasimplemented multiple investment incentivemeasures in the hope that the newly passed

Oil and Natural Gas Law (October 2014)will help attract investment in unconven-tional industries. Some particular featuresare:

• The bidding procedure and licensingrights usage fee system is controlled bythe central government, and provincialgovernments are only responsible forhandling oversight.

• Provincial oil and gas company prefer-ential equity holdings in the explorationstage have been cancelled.

• Conventional and unconventionalassets are differentiated, with uncon-ventional asset development termsextended to 35 years (as opposed to25 years) and exploration terms limitedto 13 years.

• The minimum investment required tosecure international prices for 20% ofthe crude produced was reduced to US$250 million from US$1 billion (for3 years). This provides a window ofopportunity for small exploration andproduction companies. However, anal-ysis by Woodmac has shown that 20%of export volume over 3 years hasessentially no effect on improving pro-ject IRR. Removing the 3-year restric-tion, on the other hand, would increaseIRR dramatically.

• The Gas Plus project, which raises theprice of natural gas produced usingunconventional gas deposits.

• Establishment of an unconventionalproduction permit, allowing 5 years ofpilot production to establish commer-cial viability, and the splitting of adja-cent geological concessions into units.

7.5 Accelerating the Development of China’s Domestic Natural Gas … 179

• Once the pilot project stage is complete,unconventional project licensing usagefees are reduced by 25%.

• Unconventional industryassessments/appraisals periods areextended (1–5 years).

• Provide 20% of export supply.

However, there are still many problemsthat have yet to be addressed, and resolvingthese could achieve a lot of what is hopedto be realised:

• Pre-emptive measures must be taken toaddress problems of a lack of trainedlabour and labour allocation. Oneexample of such measures is the pro-vince of Neuquén, which improvedshale natural gas technical capabilitiesby establishing an Unconventional Oiland Gas Field Technology Centre.

• Lack of an environmental regime:Because existing oil and gas fields are farfrom communities, there is no problem atpresent, but as the industry develops,problems could potentially arise.

For many reasons, it is difficult to saywhetherArgentina has actually succeeded inincreasing unconventional sector activity,but it has certainly encouraged unconven-tional resource development recently, andappears to be on the right course in its efforts.However, the government must avoid thetrap of intervening in current success, or itwill damage the confidence of the interna-tional oil companies.

Licensing Authority

• ENARSA areas—ENARSA• Provincial areas—Provincial authorities

Regulatory Authority

• Federal level: Energy Secretariat—Has overallresponsibility for the hydrocarbons sector.Responsible for policy formulation andregulation

(continued)

• Provincial level: Provincial authority—Ingeneral, regulatory duties fall on the sameperson responsible for licensing

NOC

• ENARSA—Created in 2004 by LawNo. 25.943. The company is owned by thegovernment (53%) and the provincialgovernments (12%), with the remaining 35%listed in the Buenos Aires Stock Exchange

• Most provinces have their own ProvincialCompanies (e.g. G&P Neuquén)

2. Canada2

Canada (one of the countries with the mostabundant shale resources in the world)implements a tax/licensing rights systemthrough provincial governments. Multiplefactors determine basic system adjust-ments, such as contract terms, productioncircumstances, oil prices and so on. Eventhough there is no obligation to supplydomestically, operators must still obtaingovernment approval to export resources.

Canada’s various provinces play agreater role by being in charge of imple-menting and overseeing operators. Themajority of provincial governments havetheir own regulatory institution to carry outlicensing and oversight of oil and gasoperations: for example, in Saskatchewanthe Oil and Natural Gas Office of itsDepartment of Energy and Resources, andin British Columbia the Ministry of Energyand Mines and the Oil and Natural GasDivision.

Generally, with the exception of New-foundland, no province has a NOC. In2007, the Energy Act prescribed thatCanada should have an energy company tohold and manage oil and natural gasinterests. Nalcor Energy seems to haveplayed this role, and this company has also

2In addition to HIS PEPS and WoodMac, materialsrelating to Canada are sourced from Manitoba and Albertagovernment websites as well as oil and natural gas PWCtax collection reports.

180 7 China’s Natural Gas Resource Potential and Production Trends

co-operated in participating with New-foundland’s three marine developmentprojects.

Essentially all governments have usedlicensing to capture economic lease funds—when oil prices rise, the governmentrevenues increase, and when prices arelow, the limits are adjusted. In order toavoid continual changes, a price connec-tion mechanism was established, with themajority of governments already linkinglicensing rights usage fees with oil prices,production and contract years (Fig. 7.6).

According to some provincial financesystems, the licensing fee rate taxes prior torecovery of investment costs are different,allowing contractors to recover costs withrelatively low risk. There are also someprovinces that implement multi-tiered fee

rates based on rates of return, thus forminga tiered mechanism.

Canada’s Provincial Institutions

• British Columbia Ministry of Energy, Minesand Petroleum Resources—The Oil and GasCommission

• Saskatchewan Ministry of Energy andResources—Petroleum and Natural GasDivision

• Minister of Energy—The Alberta EnergyRegulator

• Department of Aboriginal Affairs and NorthernDevelopment Canada (AANDC)—NorthernOil and Gas Branch of the AANDC

• Canada Nova Scotia Offshore Petroleum Board• Canada—Newfoundland and LabradorOffshore Petroleum Board

• The Ministry of Energy in Alberta• Department of Energy, Mines and Resources ofYukon

• Ministry of Natural Resources in Québec

$400%

$60 $80 $100 $120 $140

Tax rate after investmentcost recovery

10%

20%

30%

40%

CAD/barrelAlberta licence usage free structure

Tax rate after investmentcost recovery

Old oil

45

New Oil

Third layer oil

40

35

30

25

Lice

nse

usag

e fe

e ra

te (%

)

20

15

10

5

00 50 100 150 200 250 300 350 400 450 500 550 600

Oil monthly production volume (cubic metres)Manitoba licence usage fee structure

Fig. 7.6 Licensing rights usage fee structure

7.5 Accelerating the Development of China’s Domestic Natural Gas … 181

Canada’s three tiers of taxes:

• First tier: Federal income tax collectedfor “taxable income” from oil and nat-ural gas projects.

• Second tier: Provincial income tax(differentiated from federal taxes by thedifferent tax-exempt amounts for eachprovince) collected for “taxableincome” from oil and natural gasprojects.

• Third tier: A provincial and nationalresource tax collected for ownershiprights of Canada’s resource assets. Inorder to allocate some tax amounts tothe provincial governments, the federaltax has a 10% exemption. Theseexemptions are only applicable toincome generated within Canada.

Like many countries, Canada has takena very active role in terms of policy, and isvery willing to use tax exemptions/reductions/offsets to provide correctincentives. Currently, overall measurestaken are as follows:

• Early-stage 10% Investment Tax Cred-its (ITCs) for oil and natural gasprojects.

• Provide other ITCs for scientificresearch and experimental development(SRED) activities to incentivise indus-try innovation.

• Unused tax offsets can be carried for-ward over 20 taxation periods.

• Unconventional projects enjoy highercapital cost subsidy rates, directlyaffecting the taxes that contractors pay.

• Implemented programmes includeencouragements for tight natural gasand shale natural gas development netprofit licensing rights, low productioncapabilities usage fee reductions, oilsand usage fee programmes, marginaloil field usage fee programmes and soon. These are aimed at satisfying

special needs related to resourcesand/or geographical restrictions, andmany other programmes are available.

In order to encourage innovation, theCanadian government connects oil pricesto production and usage fee structures,along with various tax exemptions, whichplay an important role in upstream industrydevelopment. For example, the develop-ment of steam-assisted gravity drainagetechnology was highly beneficial to oilsand projects.

3. MalaysiaMalaysia has a series of highly optimisedand stable systems that implement variousfinancial terms based on production vol-ume share contract (PSC) terms—themost recent revenue-over-cost PSC con-tract conducting licensed business(Fig. 7.7).

In conjunction with IOCs, Malaysia’sPetronas uses an exploration and develop-ment subsidiary (Petronas Carigali) as ajoint venture enterprise investor (some-times as operator) to participate inupstream industry activities. In addition, italso uses the subsidiary company MPM toact in a regulatory capacity, overseeing allof the nation’s upstream industry activities.According to PSC requirements, IOCs andoperators (including Petronas Carigali) payusage fees and taxes to MPM and the localgovernment. In the majority of contracts,Petronas Carigali holds incidental interestrights to all exploration regions, generallybetween 15 and 25% (negotiable).

Recently, Malaysia has introduced aRisk Service Contract (RSC) to increaseactivity both in mature fields and in stran-ded fields.

Recently, Malaysia has begun imple-menting risk service contracts (RSCs) tostrengthen the development of oil and gasfields and latent oil and gas fields. Thisincludes terms that not only protect

182 7 China’s Natural Gas Resource Potential and Production Trends

contractors from downside risk but alsolimit the upside. (It should be noted thatPetronas is not permitted to sign this typeof contract. The contract’s main purpose isto encourage and cultivate local Malaysianenterprises to participate in upstream oiland natural gas projects).

The potential for Malaysia in uncon-ventional resources has not yet beenrecognised, and the country is in the pro-cess of learning from the experience ofother nations (Australia and Canada). Infact, recent industry reports state that Pet-ronas could be able to partner with UScompany Hess to assess and learn how todevelop China’s unconventionalresources/shale oil or shale natural gas.

As cost structures change, or when newcost structures arise (as was the case withmarine oil), Malaysia’s government adjustsPetronas’s and its own proportions ofownership to achieve a balance. At differ-ent periods, the government has used avariety of mechanisms, including reduc-tions to taxes and usage fees, accelerationof depreciation, reduction of export tariffs

and so on, to attract more investment. In1985s revised version, there were manyadjustments that improved the rate of costrecovery, adding to the profits of contrac-tors while encouraging exploration anddevelopment of small gas and oil fieldsfound through earthquake research. At thesame time, Petronas’s participation becamemandatory, allowing it to play a larger role.In 1991, the government launched marineoil incentive measures and subsequentlysigned revisions of contracts with moreattractive terms for two oil fields withMobil Oil, exhibiting the pragmatic styleof the government and regulatory institu-tions. The increase in contractor profits andthe proportion of cost recovery, as well asreductions in taxes and export tariffs, haveraised revenue proportions for these con-tracts, prompting development of marineoil.

In terms of adjustment to financial termsin the macro environment, Malaysia hasalways been very pragmatic and flexible.When appropriate, it will take suitablemeasures to attract more investment and

Partners

Malaysian national oil companies

Government

Cost

10%

100% 100% 100% 100%

29% 16% 13%13%

13%16%14%

38%42% 42%

30%

23% 28%

45%

28%

1976 PSC 1985 PSC R/C PSC

Fig. 7.7 Malaysia production share contracts. Note In 1976 and 1985, R/C production share contracts were based on40 mmboe reserve volume. Moreover, deep-sea production share contracts assume oil volume of over 1 bnboe

7.5 Accelerating the Development of China’s Domestic Natural Gas … 183

turn standard PSC development into R/CPSC, increasing average purchase promo-tions of contracts and enabling one to seeMalaysia’s time arrangements during atransitionary period. The pragmatism ofMalaysia is also seen at appropriate timeswhen the country is expanding state pro-jects and encouraging commercial struc-tures, and the country does not use ageneral structure (for example, anenhanced oil recovery project increasedproduction of mine oil and used relativelyrelaxed rules).

4. Russia3

Russia currently has many types of con-tract. They are briefly summarised below:

• Government reserve: A financial sys-tem based on export taxes and mineralextraction taxes—usage fees (alsocalled “licensing rights”).

• Government control: Terms of 5–7–25 years (according to “UndergroundLaw”) for underground explorationand/or exploration or production licen-ces that are distributed through auctionor tender.

• Product share agreements (PSAs):Even though such agreements do stillexist in Russia, they should no longerbe part of any new project contracttemplates, now that the PSA law hasbeen revised.

• Strategic Industry Law and “Under-ground Law” amendments regarding“strategic oil and gas fields”: Russia’sinstitution in charge of undergroundmanagement is Rosnedra, which comesunder the country’s Ministry of NaturalResources. Rosnedra is responsible for

managing all issues related to the issu-ing and revocation of permit, as well aslicensing.

• NOCs: NOCs (Gazprom, Rosneft andZarubezhneft) have special status.Gazprom monopolises pipeline exportsand must hold at least 50% of shares inoffshore projects. In fact, infrastructureis monopolised by Gazprom and Ros-neft.

Whether or not a project is approved isdetermined by project type—foreign com-pany direct licensing and foreign companyshares in Russian companies, as well asjoint ventures between foreign and Russiancompanies, are each restricted by a specificcategory of laws.

In order to encourage the commerciali-sation of unconventional resources, Russiahas implemented several financial andregulatory incentive measures to attractinvestment in the sector:

• Starting with a resource consumptiondeduction of 1%, a 15-year zero minetax and reduced remote-region exporttax, as well as an extension of explo-ration permit periods from 5 to 7 years,have been implemented.

• Profit-based taxation for some projectsand a complete revision of the licensingsystem for unconventionals is currentlyunder way, as well as the introductionof finance terms to attract investmentinto Russian unconventional resources.Russia has among the most abundantreserves of unconventional resources ofany country, and this approach could beslowed due to recent sanctions placedon Russia by the West.

3In addition to HIS PEPS and WoodMac, reference wasalso made to Shell reports on Russia.

184 7 China’s Natural Gas Resource Potential and Production Trends

• In order to support conventionalresource development, VNIGUI,VNIGNI and the Shpilman ResearchInstitute are in the process of studyingthe legal status of unconventionalresource projects in Russia—defini-tions, resource types, reserve reports,permit issuances, commitments andregulation.

Some traditional problems, such as localauthorities presenting complex processesand bureaucracy, continue to cause foreigninvestment to be hesitant to enter Russia.Based on macro environment changes,Russia’s systems are also continuallychanging. One example is that after a newlaw was passed in December 2013, privatecompanies obtained the right to export LNG.

5. United Kingdom4

As a country whose oil sector is relativelymature in its development, the UnitedKingdom is continuing to implement sim-ple licensing usage fee/tax regimes. Cur-rently, special licensing only exists inNorthern Ireland, with all other regionsalready essentially being purely taxregions. Unconventional resources followsimilar systems to conventional resources,but there are also special exemptions aimedat encouraging their development.

Through the newly established EnergyDevelopment Unit, the United Kingdom’sDECC issues production, exploration, anddevelopment licences, which provideoperators with well drilling/developmentpermissions and construction permits forexploration and production activities. Welldrilling/development and constructionpermits are issued by local authorities, andrequire interaction between various localgovernment institutions.

Unconventional activities are relativelynew (compared to the United States) andmanagement methods await furtherimprovement.Mineral resources are all stateassets, but an industry group, UKOOG,wishes to launch a new method of com-pensating the communities affected by theshale gas operations, involving fixed feesand a linkage to total revenue. This modelhas been welcomed by the UK government.

In 2003, all oil and gas field usage feeswere discarded, with post-2003 approvedoil and gas revenue taxes being annulled.Oil and gas income taxes approved after2003 were waived, and in 2006, as the oilprice rose, surcharges were introduced. Inaddition, since the price environment wasnot sufficiently attractive, various types oftax exemption were introduced. All of thisshows that the UK government took activeand timely measures to intervene. Fur-thermore, based on different oil and gasfield history, the United Kingdom has dif-ferent tax collection structures, therebyachieving lease fee risk sharing through apositive balance between government andoperators.

With regard to unconventional resour-ces, the following incentive measures havealready been announced:

• for surrounding supplementary expen-diture applicable to scope expansion forshale and unconventional oil and gasresources—an extension of the lossstructure carry forward period to 10accounting periods (originally 6); and

• “pad” subsidy for shale projects (thedefinition of a “pad” is a well andmining area; a portion of generatedrevenue is exempted from the sur-charge, reducing the tax rate from 62 to30%) (Fig. 7.8).

4In addition to HIS PEPS and WoodMac, material sourcesalso include the DECC and UKOOG websites.

7.5 Accelerating the Development of China’s Domestic Natural Gas … 185

Wood Mackenzie used the Namurianshale region cost hypothesis (as well asthree cases of oil well production capacity)to carry out an analysis of the new condi-tions and calculate product break-evenprice (the pad has five producing oilwells, and another five will begin produc-tion in five years). The scenario’s config-uration is essentially based on threedifferent tax circumstances:

• the current land permit regime (notincluding small oil field subsidies);

• a new pad allowance based on 50% ofall capital expenditure—this expendi-ture can be used to offset payable SCTfrom profits over the following fiveyears, and all subsidies can be carriedforward;

• a new pad allowance based on 75% ofall capital expenditure—this expendi-ture can be used to offset payable SCT

from profits over the following year, andall subsidies can be carried forward.

However, negative appraisals still exist,and the government is currently solvingthese. It is now permitted to transfercross-pad exemptions from failed pads tosuccessful pads (though this must be donewithin three years), and it is also permittedto replace operating asset developmentdiscounts (in the early stages companiescould not implement oil/natural gas salesrevenue development periods unless therewas reinvestment into the British mainlandshelf). Subsidies can be used to pay capacityfees and fair trade expenses.

Financial incentive plans haveimproved the competitiveness of Britishshale natural gas in Europe. However, oilwell efficiency and local approval processsimplification are keys to the success ofBritish shale natural gas.

Rev

enue

-exp

ense

bal

ance

poi

nt

(US

D/m

icro

litre

)18

16

14

12

10

8

6

4

2

0

Low Baseline High

Germany Turkey UKScenario 1 Ukraine Romania Poland Bulgaria UK

Scenario 2UK

Scenario 3

Fig. 7.8 UK shale finance system competitiveness (Woodmac study)

186 7 China’s Natural Gas Resource Potential and Production Trends

UK Regulatory Framework

• Minister of Energy and Climate Change: Oilpermit licences are issued following a decisionby the minister

• DECC: Responsible for the issuance of oillicences, with specifics overseen by the EDU

• UOGO: UOGO is DECC’s internalunconventional oil and gas activity direct pointof liaison

6. United States—Mainland5

Unlike other countries, land owner mineralasset resources ownership rights are thefoundation of the US upstream industryinvestment regime. In the majority ofcases, this means that mainland resourceownership rights belong to the individual,and thus there are no licence-issuinginstitutions and only private leasing. Forfederal and state land, the government willissue lease agreements based on direct taxcollection and usage fee systems.

The United States works on a federalsystem, and thus the majority of laws andregulations governing the oil and naturalgas industry are determined and imple-mented by the states. The federal govern-ment is responsible for federal lands(namely federal water regions such as theGulf of Mexico (GOM)) and interstatetrade, including interstate pipelines.The US government’s regulatory systems(state and federal) are relatively optimisedand efficient.

Historically, US regulatory systemshave created an overall environment andthen a series of conditions that supportprivate investment development. In orderto support mining industry development,the United States has consistently avoided

nationalisation. The current shale revolu-tion is also a result of this overallenvironment.

After eliminating the price controls onnatural gas and its shipping (deregulation),the United States began to rely on themarket to satisfy demand (increased sup-ply). Shipping capability rights and pipe-line ownership rights are separated,allowing producers to compete with pipe-line capacity.

Interestingly, the US government offersdirect support for public research anddevelopment expenses. For example, theprimary goal of the Eastern Shale GasProject (1975–1992) was the developmentof shale natural gas production technology.The United States also offered directfunding support for several industry pilotprogrammes such as the first multi-breakhorizontal well in 1986. It also gave itsassistance to the 1991 hydraulic fracturinglaw in conjunction with water level wellscompany Mitchel Energy. After severaldecades of stable industry development,US technology and professional assistanceis far ahead of the rest of the world’s oiland natural gas industries (the UnitedStates has the world’s largest quantity ofwell exploration equipment).

Based on the positive experiences of theUnited States, some recommendations are(based on Nulle 2014):

• flexible land transfer rules and flexiblecommercialised statement requirements;

• advance provision of reliable pipelineand shipping infrastructure usagerights;

• implement free prices and guaranteeprices;

5In addition to HIS PEPS and WoodMac, reference wasalso made to Nulle (2014), the Eenergy website newssection and Daniel Johnston’s work on financial terms.

7.5 Accelerating the Development of China’s Domestic Natural Gas … 187

• import expert labour and equipmentcapabilities;

• encourage high-cost/risk unconven-tional development tax regimes;

• provide direct R&D support, andimprove geological and technologicalknowledge and skills;

• enable free return of profits to investors;and

• stability in terms of laws and policies.

The US government’s measures haveseen broad success, but it is worth notingthat this success was obtained only after along period of time, and was the result ofmultiple policies (financial incentives,R&D funding support, deregulation) andstructural elements related to the US eco-nomic and regulatory system (capitalavailability, mine asset private ownership(land owners also benefit), stability, highdegree of professional technology andexperienced human capital, existing pipe-line capacity tenders and so on).

Effects of Financial Incentives

The federal government implements specificpolicies for unconventional resources, and thesepolicies were launched in 1980 and expired in2002. The Crude Oil Windfall Profit Act playedan important role, for example in offeringsubsidies to unconventional resources developedfrom shale natural gas and in the formulation ofthe “Intangible Development Cost Expenditures”provisions, which permitted producers to writeoff a large portion of development costs asexpenses. The government’s share of revenuederived from primary producers on the OuterContinental Shelf of the Gulf of Mexico is verylow. Indeed, because of fee usage refunds and taxoffsets, there is an effective 0% royalty rate

7. Recommendations for China

1. Encourage provincial/communitymanagement of shale oil/gas

development and production: In theUnited States, Canada and Argentina,local authorities/governments play acritical role and for a period of timethere are direct regulatory institutions.Sometimes, provinces (such as inArgentina) will invest in partnershipsand form joint venture enterprises(rather than being an “incidental”partner).

2. Implement low licensing usagefees/tax rates for unconventionalnatural gas to provide tax reductionsand exemptions: In some countries(such as Canada), tax rates are linked toactual oil prices, and this allowsinvestors to know what the tax burdenis at different oil price levels withouthaving to adjust strategy based onchanges in oil price. For example,Russia is currently considering a can-cellation of unconventional oil/naturalgas mineral extraction tax, and mineralextraction tax is a significant tax burdenfor Russian companies. Other taxleverages include tax carry forward(such as in the UK).

3. Extend unconventional oil and gasfield small-scale trials, explorationand production terms: Formulatetransition timetables. In the majority ofcountries, shale oil/gas field licences areextended for 5–10 years.

4. Deregulate, and introduce competi-tion mechanisms: Provide reliablepipelines and shipping infrastructureusage rights in advance and cancelprice controls, which is believed to bethe key to the US’s success. In partic-ular, separate shipping infrastructureusage rights from pipeline ownershiprights, allowing producers to competeover pipeline capacity.

5. Support development of dedicatedoperation companies: The government

188 7 China’s Natural Gas Resource Potential and Production Trends

plays a unique role in developmentR&D and in supporting dedicatedoperation enterprises. These companiescan provide effective assistance toaccelerate the development and pro-duction of China’s shale natural gas/oil.To this end, the government shouldsupport the development of Chinesecompanies or foreign professionaltechnology companies, with particularattention given to the growth anddevelopment of small-scale enterprise,which plays a vital role.

Case 6: Mexico Oil and Natural GasIndustry Upstream Opening PoliciesIn 2013, Mexico revised its national con-stitution in an attempt to revitalise its oiland natural gas industry. Mexico’s gov-ernment took specific and transparentmeasures to promote Bid Round Zero.During this period, Pemex submitted anapplication and obtained 83% of proved oilfield/natural gas field mining rights and21% of unproved oil/gas area explorationrights. This was viewed as an effective andpractical method to balance the nation’soverall interests and the interests of thecountry’s oil companies. At the same time,it also offered sufficiently attractiveopportunities for foreign business and pri-vate investors.

It is recommended that China use theRound Zero procedure to enable existinglicensed state-owned oil companies toname portions they wish to hold and theportions that can be provided to newinvestors, thereby prompting investmentand in the mid- to short-term accelerating

change in unconventional energy shalenatural gas production volume. Using thisapproach, China could improvenon-renewable energy structure usage effi-ciency for natural gas while at the sametime controlling the degree of reliance onforeign imports—which has already grownfrom 0% in 2005 to 32% in 2013.

1. Mexico prior to 2013: awaitingchange

Mexico’s oil industry history is very long,with oil discovered for the first time backin 1904. Production volume had reached150,000 barrels/day by 1917. The IOClikewise rapidly joined, helping to raiseoil production volume. By 1921, Mex-ico’s oil daily production had exceeded530,000 barrels, accounting for one-fourthof the world’s total production volume.However, fierce disputes between unionsand the IOC ultimately led to Mexiconationalising all assets of the IOC in1938, and through this establishing aNOC. Since then, PetroleosMexicanos(Pemex) has always been the sole rightsholder of Mexico’s oil and natural gasresources.

For more than 70 years, Pemex hadoperated its own oil and natural gas busi-ness under the ISC. Such a monopolisingnational oil company has gradually becomesluggish, partly because budget and finan-cial management has been tightly con-trolled by Mexico’s Ministry of Financeand Public Credit. As seen in the diagram,Pemex’s production volume reached itspeak in 2004–2005, with daily oil output ofapproximately 3.6 million barrels, anddaily natural gas production of approxi-mately 3 billion ft3. Since 2004,

7.5 Accelerating the Development of China’s Domestic Natural Gas … 189

production volume continuously dropped,and the prospects appeared bleak. Wood-Mac made forecasts of rapid decline inproduction volume over the followingseveral years. Mexico was then awaitingchange.

In order to relieve production volumedeclines, Mexico launched an energy pol-icy reform in 2008, allowing Pemex tooutsource some mature marginal oil, gasfields and service contracts. The IOC wasnot particularly enthused. In 2011, Pemexlicensed out production volume based onoil and gas fields in two service contracts toFrench company Schlumberger and UKcompany Petrofac. In 2012 and 2013,Pemex again held two service contracttenders and still only attracted internationalservice companies (Fig. 7.9).

Deep Water Bay, Mexico has consis-tently been a major success story for theUS oil and natural gas industry. DeepWater Bay, Mexico is on par with West

Africa and Brazil and is known as theworld’s golden triangle for exploration andproduction. However, despite having themajority of jurisdiction over the GOM,Mexico is essentially behind all otherindustry participants, and has conducted noproduction of deep water oil/natural gas.

Recently, the US shale natural gas/oilrevolution has been another jolt to Mexico,since a portion of the shale oil/gas dis-tributed in Texas should, from a geologicalperspective, extend into Mexico.

The Mexican government and Pemexhave realised that radical change is neededand that the time has come to start a newchapter in the history of oil and gas inMexico.

2. Energy reforms in 2013 with the riseof a new president

On December 1, 2012, Enrique Peña Nietobecame president of Mexico. His party PRIbeat the PAN to win the presidency.

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

02004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015E 2016E 2017E 2018E 2019E 2020E

Mexico Oil and gas production

gas (kboed)

oil (kboed)

Fig. 7.9 Mexico oil and gas production

190 7 China’s Natural Gas Resource Potential and Production Trends

The PAN had been the ruling party from2000 to 2011. The PRI had controlledMexico since 1928, ruling for 71 years.

In August 2013 President Nieto sub-mitted an energy reform bill with a total of27 specific laws to the Mexican congress.The congress had to pass the bill andexecute reforms. By December 2013,Mexican law prescribed that once again itwas permitted for international oil compa-nies and private investors to invest in oiland natural gas through three types ofcontracts: service contracts; productionvolume or profit-sharing contracts; andlicence contracts (Fig. 7.10).

3. Round Zero: Balance between pro-tecting national oil company interestsand attracting foreign investment

Pemex, in terms of the overall oil industry,is far behind China. China has multiplenational oil companies, including the topthree, CNPC, Sinopec and CNOOC. These

three companies are all listed on theNYSE.

In order to use Pemex equity to protectoverall national interests, in 2014 theMexican government took the uniqueapproach known as “Round Zero”. Pemexhad to submit its choices for retaining andabandoning oil and gas fields prior toMarch 2014. The government’s regulatoryinstitution energy minister and CNG hadsix months to decide which oil fields/Podswould be retained by Pemex. In order toretain any production assets, Pemex had toexplain its capabilities in the applicationregarding technology, assets and opera-tions. In terms of exploration area, Pemexlikewise had to show that it had exploredwells and/or was currently exploringunderground areas.

Based on estimates by the CNH, theresult of Round Zero was that Pemexretained approximately 83% of provedreserves (2P reserves), as well as 21% of

2P Reserves

Round 0 outcome for Pemex before opening of Mexican energy sector for IOCs

Perspective Resources

Available to IOCs through2015 or future Bid round

Available to IOCs through2015 or future Bid round

21%

17%

79%

83%

1) Deepwater Gulf of Mexico

2) Shallow water Gulf of Mexico

3) Unconventionals onshore

Including enhanced oilrecovery of mature fields

Potential JVwith IOCs

Fields/blocks awarded in Round 0

Fig. 7.10 Mexican NOC prior to reforms

7.5 Accelerating the Development of China’s Domestic Natural Gas … 191

unproved reserves. For the held assets ofPemex, this still allowed it to invite foreigninvestment and transnational companies toco-operate in exploration/development/production.

4. Mexico’s Round 1 Bid Round: Whatto expect in 2015?

Since December 2014, the CNH has begunto carry out the first round of bidding instages, including for shallow water explo-ration, shallow water development, landand major production field Chicontepeccapital injections, unconventional energyand deep water. The CNH has continued toinvite potential international investors toparticipate in the Round 1 Bid Round.

Since June 2014, the drops in oil priceshave forced the Mexican government toreconsider whether or not to make 2015 theyear to attempt attracting international oilcompany investment. The current decisionappears to be to carry out all biddingrounds according to plan, including themost attention-grabbing deep water por-tion. The date for completion of bidding isreportedly mid-July 2015. Leading inter-national oil companies, including Chinesenational oil companies (such as CNOOC)and other foreign national oil companies,are expressing great interest in this first

round of bidding in Mexico. There is stillsome concern within the industry aboutwhether Mexico will continue to fullycontrol and occupy the oil/natural gasassets, whether there will be major changesto Pemex and whether there will beattractive financial terms for major deepwater regions so as to accelerate explo-ration and mining of deep water oil and gasin Mexico.

Of course, the industry has also con-sistently recognised the speed and deter-mination of the Mexican government in itsenergy reforms, as well as its detailed andtransparent approach. This includes theRound Zero opening up of over 20% ofproved reserves and 80% of unprovedreserves to international oil companies.

It is worth considering whether thesemethods are suitable to China, especiallygiven its attempts to accelerate unconven-tional energy and shale natural gas explo-ration and development and to speed upprogress attracting suitable international oilcompanies and private funding.

Another issue the oil and natural gasindustry should consider is whether Mex-ico can maintain its open policies if there isa leadership change after Nieto’s six-yearterm (see Fig. 7.11).

Mexico Round Zero bidding reform prospects

Shallow waterbay: exploration

Shallow waterbay: development

Land Chicontepec regionand unconventional

Deepwaterbay

Project date ofannouncement

December 2014 January 2015 February2015

March 2015 April2015

Data centre dateof establishment

January 2015 January 2015 March2015

April 2015 May2015

192 7 China’s Natural Gas Resource Potential and Production Trends

Case 7: Analysis of the Approach toOpening Up Upstream Industries in Oiland Natural Gas in Various CountriesGenerally speaking, the opening up of acountry’s oil and natural gas industry isclosely linked to its natural resources andits development strategy. For example, inan oil and natural gas-exporting nationwith abundant resources and good miningconditions, the terms on potential investor

contracts will be stricter. Thus in SaudiArabia, oil exploration and developmentare essentially not open to outside interests.Instead, Saudi Arabia hires internationalservice companies to provide their oilindustry with technical services. Inimporting nations with few resources anddifficulties with mining, the degree ofopenness is greater. For example, in theUnited States, Canada, the United

Upstream assets for sale -reserves and assets

Leased

New regions

Total

1,557

3,782

5,339

14,606

14,606

-

Confirmedreserves(mmboe)

Unconfirmedreserves(mmboe)

SabinasOaxaca

YucatanPlatform

Region awarded to Pemex

New region awaiting sale

Name of the basinState name

Leased region and labourcontract transfer region

Yucatan

Chihuahua

Coahulas

Sabinas

Nuevo Leon

Tamaulipas

Durango

Zacatecas

San Luis Potosi

Oaxaca

Campeche

QuintanaRoo

Chiapas

Tlaxcala

Puebla

Aguascalientes

Nayarit

Tampico Misantla

Burgos

Deepwater

Vera Cruz

Southeastern Basin

Fig. 7.11 Mexico’s Round Zero reform prospects

7.5 Accelerating the Development of China’s Domestic Natural Gas … 193

Kingdom, Australia and other OECDnations, oil and natural gas upstreamindustries are entirely open. The tax androyalty system between the nation andstates/provinces ensures that their interestsare protected. In terms of shale natural gas,US private land owners can also discussroyalties from the engaged company(Fig. 7.12).

Upstream contract terms are of fourtypes, from stringent to loose:

• Service contracts (or Technical Ser-vice Agreements (TSA), EnhancedTSA): Countries employing thisapproach are primarily countries withvery abundant oil and gas resources,such as Qatar, Iraq and Mexico. Inter-national oil companies and internationalservice companies are each able toapply for these terms. However, Qatarand Iraq only employ international oilcompanies, using their comprehensivemanagement for oil and gas develop-ment. It is worth noting that in recentyears Mexico only used service con-tracts, but has been unable to change itsprecipitous slide in oil and gas pro-duction. They are therefore in the pro-cess of using new and more attractive

contracts to attract foreign investmentand technology, especially in deepwater oil and gas exploration anddevelopment.

• Fixed margin contracts: Some coun-tries, such as the UAE and Nigeria(mainland), have used a special contractterm approach. For each barrel of oilproduced, the foreign party obtained afixed return, for example $1 per barrel.This term’s downside for foreign par-ties is a low rate of return, but thebenefit is that there is very littleinvestment risk and a high degree ofcertainty. For the country in question,this term’s greatest weakness is that itencourages cost controls by investors.

• Production sharing contract (PSC):In 1972, Indonesia led the way inproposing PSCs. This is an interna-tional approach, and in particular apopular approach in third-world coun-tries, that encourages foreign invest-ment. It caters for the interests of boththe country in question and the foreignparties. Investors generally assume allexploration risks and expenses. Prior tothe discovery of commercial opportu-nities, they receive their reward byrecovering investments and production

Not openCompletely open

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UAENigeria (onshore)Venezuela

IndonesiaRussiaBrazilChinaAngolaNigeria (offshore)Mexico (new)

USACanadaUKAustraliaOECD

Upscale fiscal terms for shale gas

(E) TSA Fixed margin PSC Tax royalty

Fig. 7.12 World natural gas upstream openness

194 7 China’s Natural Gas Resource Potential and Production Trends

volume sharing. It is worth noting thatinvestors see large differences in sharedproportions, and the recovery factor(also known as the R-factor) determinesthe differences.

• Tax and royalty: In Western countriessuch as the United States, the UnitedKingdom, Canada, Australia and others,domestic oil companies and foreign oilcompanies are essentially competitorson the same playing field. On average,tax systems offer investors rates ofreturn that are slightly higher. However,this also depends on the degree of tax-ation. Some countries, such as Canada,use a tax rate that is linked to interna-tional oil prices, which enables inves-tors to have a measure of certaintyregarding investment risk. However, taxsystems are not equivalent to a loss ofcontrol by the country in question.Using a tax system still allows thenation to continue to play an importantrole, especially in signing off on oil andgas exploration and development licen-ces, approval environments and safeproduction plans. The country can alsouse increases or decreases in tax rates to

encourage or inhibit a given direction ofdevelopment.

In summary, the more oil and gasresources there are, the more that nationstending to export will prefer to use TSAs.Moreover, in oil and natural gas-consumingnations, countries with open markets tendtoward using tax and royalty methods.Some countries such as Nigeria offerfixed-return contracts where land develop-ment is not particularly difficult and risk islow, and offer production volume sharingcontracts for marine oil mining where thereis higher difficulty and greater risk.

In China, conventional oil and gas sec-tors use relatively general productionsharing contracts. Shale natural gas isburied deeper, there are greater difficultiesand costs in its development, and it is solddomestically. If it is hoped to attract moredomestic and foreign investors to join inshale natural gas exploration developmentventures, then a reasonable improvementwould be to offer PSC or tax and royaltysystems that are more attractive than Chi-na’s existing production volume sharingcontracts.

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7.5 Accelerating the Development of China’s Domestic Natural Gas … 195

8International Natural Gas Supplyand Quantities Available to China

8.1 Preface

This section analyses potential future changes ininternational natural gas market supply anddemand and the available natural gas importvolume for China, as well as what reasonablemeasures China should take, including suitablepolicy adjustments, to promote its own naturalgas supply and demand security.

Currently, China’s natural gas market is in akey stage of development, with demand, supplyand system mechanisms each undergoing intensechange. This state of flux is having a major effecton the evolution of the natural gas market.The NDRC has already issued goals and policymeasures1 that differentiate base supply gas and

incremental increase volume, and that merge theprice structure of the two different types of gasby the end of 2015, setting a general road mapfor natural gas market reforms.

However, as the price of natural gas continuesto rise, there will inevitably be impacts ondownstream demand, and backward energyreplacement by some users (using coal instead ofnatural gas) and other phenomena could occur.There are also some who believe that the con-tinued increase in natural gas prices will lead tonatural gas supply in China exceeding demand in2017 (Jiaofeng et al. 2014). In addition, the largefluctuations in international oil market pricesseen recently will inevitably have a far-reachinginfluence on the evolution of China’s natural gasmarket. How to determine the future supply anddemand circumstances for the natural gas marketis thus of critical importance to the smooth exe-cution of China’s natural gas pricing reforms.

In 2013, China imported approximately53 billion m3 of natural gas, which alreadyaccounted for 32% of total consumption volume.How natural gas future imports change willundoubtedly have a significant impact on thestructure of China’s supply and demand. Becausenatural gas imports are long-term (the contractlength is long) and stable (take-or-pay), it is stillpossible to rely on current circumstances to makesome reasonable predictions about imports and the

* This chapter was overseen by Zhonghong Wang fromthe Development Research Center of the State Counciland Shangyou Nie from Shell International Explorationand Production. It was jointly completed by XiaoweiXuan, Yingxie Yang, Yongwei Zhang, Jiaofeng Guo,Weiming Li, Beiqing Yao, Tao Hong and Yuxi Li fromthe State Resource Department Oil and Gas Centre,Xiaoli Liu from the National Development and ReformCommission’s Energy Office, Guang Yang and JianhongYang from the China Energy Research Institute’sNatural Gas Centre, Xiaobo Ju and Beijing Yao fromShell China. Other members of the topic groupparticipated in discussions and revisions.

1See National Reform and Development CommissionNotice Regarding Conducting of Natural Gas PriceFormation Mechanism Pilot Sites in Guangdong andGuangxi Autonomous Region (FGJG [2011] No. 3033);National Reform and Development Commission NoticeRegarding Adjustment to Natural Gas Price (FGJG [2013]

(Footnote 1 continued)No. 1246); National Reform and Development Commis-sion Notice Regarding Adjustment to Non-ResidentialReserve Natural Gas Price (FGJG [2014] No. 1835).

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_8

197

near future, even though there may still be someuncertainty regarding a contract’s final process ofexecution. Such predictions could be highly sig-nificant in helping to understand the changingtrends inChina’s natural gasmarket and could thuscontribute to better natural gas price reforms.

This chapter is broken down into three parts.There is first a discussion of current internationalnatural gas supply and potential future changes.This is followed by an analysis of China’s cur-rent natural gas imports and future trends.Finally, recommendations are made regardingfuture natural gas trade policy for China.

8.2 Current and Future Sourcesof Global Natural Gas Supply

8.2.1 Current and Projected GlobalNatural Gas Resources

According to IEC determinations, current globalnatural gas resources are approximately784 trillion m3 (28,000 trillion feet3). Based oncurrent consumption levels, this could last sus-tainably for approximately 200 years or more.Based on proved resources that are recoverable

with today’s economics and technology, theglobal natural gas resource reserve to productionratio is 54.8 (BP 2014: 20). Therefore, on thewhole, the future supply of global natural gasresources is relatively ample.

In the global energy layout, natural gas isplaying an increasingly important role. In thepast 10 years (2005–2014), global natural gasconsumption growth has been around 2.7%,making it the fastest-growing energy type (BP2014). The IEA estimates that natural gas con-sumption will continue to maintain relativelystrong growth up until 2030, when growth rateswill be at approximately 2% (IEA Current Poli-cies Outlook) (see Fig. 8.1). According to fore-casts by Shell, natural gas supply and demandwill rise from 3.1 trillion m3 in 2010 (3100 bil-lion m3) to 5 trillion m3 (5000 billion m3) in2030.

In addition, according to an analysis byExxonMobil (2014), global energy consumptiongrowth will be approximately 1% from 2010 to2040, whereas natural gas growth will reach1.7%, markedly higher than overall energy con-sumption growth. It is clear that natural gas willplay a more significant role in global energystructures moving forward.

Data source: Shell AnalysisNote: all the tight gas / shale gas is calculated to standard value LPG

Natural gas demand growth up to 2030 Natural gas supply growth up to 2030

Liquefiednatural gas (LNG)

Regional pipelinenatural gas

Shale gas suppliedto the domesticmarket

Conventional gassupplied to thedomestic market

2010 - 3100bcm

2030 - 5000bcm

2010 - 3100bcm

2030 - 5000bcm

USgrowthover30%

Asiagrowthover40%

Middle eastgrowthover12%

2010 2020 2025 2030

Fig. 8.1 Growth in global natural gas supply and demand totals

198 8 International Natural Gas Supply and Quantities …

8.2.2 Global LNG Trade Development

For long periods, global natural gas trade hasfocused on pipeline imports as the major shippingmode, but as liquefied natural gas (LNG) tech-nology develops, LNG is accounting for a largerproportion of trade. Beginning in 1959 with theworld’s first shipment of LNG across the ocean,by 2013, 320 billion m3 of the total internationalnatural gas trade of 1 trillion m3 is LNG, 32% oftotal trade volume (IGU 2014) (Fig. 8.2).

LNG trade volume growth has broken throughthe shipping restrictions of pipeline natural gas,helping Japan, Korea and other countries to importnatural gas. In addition, for countries facing geo-graphical restrictions, LNG has also expandedpotential import sources, helping to lower importrisks. Moreover, LNG is more flexible than pipe-line natural gas, and can change its export desti-nation according to market changes. Thus LNGtrade circulation has had a major influence onglobal natural gas trade layouts and supply anddemand relationships as well as price trends.

8.2.3 Trends in Global LNG Trade

Since 2000, the global LNG trade volume annualaverage growth rate has reached approximately5%. This trend will continue for the foreseeablefuture. At the same time, global LNG trade struc-ture is becoming more complex. In 1990, therewere eight LNG exporting nations and nine

importing nations; those numbers are now up to 27and 31, respectively. It is accepted that in the next10 years, the number of LNG exporting nationswill rise to 50 and the number of importing nationsto 25. As changes to trade networks add touncertainties over market supply and demandrelationships, the future structure of global naturalgas trade is going to become more complex.

Figure 8.3 shows the 2012 production capac-ities of the major LNG exporting regions and theirrespective proportions. In 2012, global LNGannual production capacity was nearly 390 bil-lion m3. Qatar was the largest exporting nation,with production capacity of 77 billion m3,accounting for 27% of global capacity. Togetherwith other Middle East nations such as Oman,Yemen and UAE, and North African countriessuch as Egypt and Algeria, 47% of global LNGproduction capacity was controlled by the MiddleEastern and North African regions, followed bysouth-east Asian regions including Malaysia andIndonesia, which accounted for 23% of produc-tion capacity. This is then followed by Australiaand other African countries, which both accountfor approximately 9%, and then South Americawith 7% and Europe, including Russia, with 5%.

8.2.4 Developments in the GlobalLNG Export Market

In recent years, global LNG supply deploymentshave seen relatively major changes. First is that

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8.2 Current and Future Sources of Global Natural Gas Supply 199

Australia’s production capacity is in the processof rapid expansion, and is expected to exceedthat of Qatar, making it the world’s largest LNGproducer. It is in the process of investing in theconstruction of seven LNG projects, with pro-duction capacity totalling approximately 85 bil-lion m3. Adding the in-progress projects of itsneighbouring country Papua New Guinea bringsthe total to 95 billion m3. Following this is theUnited States, with its successful development ofshale natural gas, which has potentially trans-formed it from a natural gas-importing nation to anatural gas-exporting nation, with in-progressprojects alone reaching 25 billion m3. Figure 8.4shows global regional in-progress projects, witha total of approximately 130 billion m3.

If all the in-progress projects are completed asexpected, global LNG production capacity willgrow from around 390 billion m3 in 2012 toapproximately 520 billion m3 in 2017. The pro-portion accounted for by Australia and PapuaNew Guinea will rise from 9% in 2012 to 25%,with the proportions of the Middle East andNorth Africa dropping from 47 to 36%. TheUnited States’ proportion will rise from essen-tially zero to about 5%. This means that the

Middle East and North Africa in natural gassupply markets will see their leading positionsweakened, and market competition will be fur-ther strengthened (Fig. 8.5).

In addition to in-progress projects, there arealso many LNG projects in planning or beingproposed. There is capacity of about 30 bil-lion m3 in projects that have already submitted afinal investment decision, and 370 billion m3 inprojects that are in some stage of Front-EndEngineering Design. There is another total of500 billion m3 (IGU 2014) in projects that havesubmitted a motion but which are still in prelim-inary stages. Of course, not all projects will becompleted, especially those in the early stages,and there is a variety of factors and risks that couldend in their cancellation. However, this does showthat current international LNG supply markets arein a relatively active state. In addition to Australia,the United States and Canada are two countriesthat will join the list of LNG-exporting nationsand which have major potential for exports: EastAfrica’s Mozambique and Tanzania, which haveboth discovered major deep sea natural gas fields.The exports from these countries will have amajor impact on future global natural gas trade

North America, 1%South America, 7%

MENA, 47%

Europe, 5%

Oceania, 9%

Southeast Asia, 23%

Africa, 9%

Fig. 8.3 Global natural gas regional production capacity (2012). Source PFC global LNG supply and demand report(2013) and IGU global LNG report (2013)

200 8 International Natural Gas Supply and Quantities …

layouts, and will affect the interests and risks forChina’s natural gas imports.2

8.2.5 Growing Natural Gas Demandin China, India and OtherEmerging Markets

In the long term, natural gas demand growth willcome primarily from China, India and otheremerging economic entities. In Europe, NorthAmerica, Japan and other developed nations, dueto weakness in economic recovery and replace-ment with cheap coal, as well as subsidies giventoward renewable energy development amongother factors, natural gas consumption growth

will be limited. Developed nations are seeingsustained increases in natural gas demand in thetransportation sector, especially with increasedcontrols and higher emissions standards, as wellas growth in natural gas consumption in marineshipping fuels. However, on the whole, devel-oped nations will see relatively stable natural gasdemand growth moving forward (Fig. 8.6).

By comparison, non-OECD emerging nationswill have the strongest demand for natural gas.As economic development and income levelsrise, emerging economic entities will see grow-ing demand for natural gas. At the same time, themajority of emerging economic entities still haverelatively low levels of expansion of natural gasusage, leaving major room for growth in thefuture. Moreover, due to strengthened atmo-spheric pollution governance and the need to dealwith climate change, emerging nations will turnmore toward natural gas for new momentum.

LNG plants under constructionUS Southeast Asia Central and Southern

AmericaPacific Africa Middle East

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Fig. 8.4 Global in-progress LNG plant regional production capacity. Source Collected and assembled from PFCGlobal LNG Supply and Demand Report (2013), company reports and authors

2For the influence of LNG development in Australia, theUS, and Canada on Chinese imports, further detailedanalysis will be provided in the section dealing withChina’s Future LNG Imports.

8.2 Current and Future Sources of Global Natural Gas Supply 201

8.2.6 The Influence of Oil PriceDeclines Future NaturalGas Trade

International crude oil prices dropped from over$100 per barrel in June 2014 to a low of CNY 43in January 2015, driven by the US unconven-tional oil and gas revolution, which has seenmajor increases in US crude oil production vol-umes, falling international oil market demandand various other factors. By May 2015, the pricewas at approximately $60 per barrel. Becausemany natural gas contract prices are linked to theprice of oil, international crude oil price fluctu-ations also immediately set off major changes inthe international natural gas market, and willhave far-reaching impacts on future natural gastrade layouts (Fig. 8.7).

In the short to medium term, in terms ofdemand, the JKP price has dropped from$20/MMBtu in 2014 to $7. This means a reduced

cost for natural gas-importing nations such asChina, especially for spot and short- andmid-term contracts. For suppliers, the largestimpact is felt by existing projects and in-progressprojects, such as the projects currently underconstruction in Australia, where some projectinvestments will face sunk cost. Because manyprojects are established based on the economicexpectation of high oil prices, a major drop in oilprices will lower the expected gains from theprojects, and some could even face losses.

In the long term, major oil price drops affectnatural gas projects that are in planning. Theseprojects can have their progress halted as a result,for example the Browse project in Australia andthe Pacific Northwest project in Canada, whichhave currently delayed the time for making theirfinal investment decision.

A drop in international oil prices also causesAsian natural gas exports to lack their previousappeal. This is because US natural gas pricing

North America, 5%

MENA, 36%

South America, 5%

Europe, 4%

Oceania, 25%

Southeast Asia, 18%Africa, 7%

Fig. 8.5 Global LNG regional production capacity (2017 existing and in-progress capacity). Source Collected andassembled from PFC Global LNG Supply and Demand Report (2013), company reports and authors

202 8 International Natural Gas Supply and Quantities …

2013 2015 2017 2019 2021 2023 2025

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Fig. 8.6 Global LNG future supply and demand layout

8.2 Current and Future Sources of Global Natural Gas Supply 203

mechanisms are different from Asia, and are notlinked to oil prices but are directly determined bysupply and demand of natural gas itself. When oilprices plunge, US natural gas price advantagesare markedly reduced, and Asian market demandis thus reduced, so a portion of projects could turntoward Europe or Latin America, while anotherportion could be cancelled. It could be said thatinternational oil price drops have the effect ofreshuffling the deck for natural gas trade, causingmarkets to enter a new phase of balancing out.

If Japan’s Fukushima nuclear reactor disasterof 2011 is said to have ignited a new wave ofnatural gas export, international oil price drops canbe viewed as having poured cold water on thatmomentum and resulted in a more conservativeapproach. As can be expected, sustained low oilprices will cause natural gas international supplyreductions, and this to a certain degree will helpnatural gas prices to avoid becoming excessivelylow. However, in the long term, what will allownatural gas to find a new stable price will rely uponmany factors, and there are many major uncer-tainties. Another trend is that LNG industry par-ticipants will work hard to co-operate to reduceLNG project expenses while increasing their pro-jects’ economic competitiveness.

8.3 China’s Current Natural GasImports and Future Trends

8.3.1 China’s Current Natural GasImports

In 2013, global natural gas consumption wasapproximately 3.5 trillion m3, with natural gastrade totals of 1 trillion m3. LNG accounted forabout one third of this, while pipeline natural gasaccounted for two thirds. China’s 2013 natural gasimports were 53.4 billion m3, at an average price of10.4 $/MMBtu (about 2.6 CNY/m3) (Chen 2014).As part of this, LNG imports were approximately25 billion m3, at an average price of 10.5 $/MMBtu. Pipeline natural gas imports wereapproximately 28 billion m3, at an average price of10.4 $/MMBtu. China’s natural gas consumptionvolume, imports of natural gas, LNG imports andpipeline imports correspond to 4.8, 5.3, 7.6 and4.2% of global amounts, respectively (Table 8.1).

In terms of LNG, China’s major import sour-ces are Qatar, Australia, Malaysia and Indonesia.Import volumes are 9.2, 4.8, 3.6 and 3.3 bil-lion m3, respectively, at prices of 17.9, 3.5, 8.1and 3.9 $/MMBtu. In terms of pipeline gas, majorimporting nations are Turkmenistan, Uzbekistan,

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Fig. 8.7 WTI oil price trends (2004–2015). Source Energy Information Administration, US

204 8 International Natural Gas Supply and Quantities …

Myanmar and Kazakhstan, with import volumesof 24.4, 2.9, 1.0 and 0.10 billion m3, respec-tively, at prices of 9.6, 9, 3.5 and 11.5 $/MMBtu.

Looking at the numbers, Turkmenistan iscurrently China’s largest importer, accounting for47.1% of all natural gas imports, followed byQatar, Australia, Malaysia and Indonesia,accounting for 17.7, 9.3, 7.0, and 6.4% of importvolumes, respectively. These five countriesaccount for 87.4% of China’s import volume.From the perspective of price, Qatar’s LNG priceis highest, at 17.9 $/MMBtu (approximately4.48 CNY/m3), and the Australian LNG price isthe lowest, at 3.5 $/MMBtu (approximately0.88 CNY/m3) (Fig. 8.8).

Compared to other international natural gasprices, China’s current imported natural gasaverage price of 10.4 $/MMBtu is in themid-range, and much higher than the price on theHenry Hub of 4 $/MMBtu. However, it ismarkedly lower than Japan’s imported LNGprice (approximately 16 $/MMBtu) and roughlyequal to the imported natural gas prices of theUnited Kingdom NBP3 (about 10.4 $/MMBtu)and Germany (about 11.3 $/MMBtu) (Fig. 8.9).

Overall, since China began importing naturalgas in 2006, import volumes have risen rapidlyand import prices have also markedly risen. AsAustralia and other nations that signed early

import contracts with China have had theirimport contracts come to term, China is nowseeing a new wave of natural gas contract sign-ings, which are having a decisive influence onChina’s future natural gas imports.

8.3.2 Potential Source Nationsfor China’s Future LNGImports

1. Australia

Australia currently has 22 proposed LNGprojects, with annual production capacity of atotal of 200 billion m3. These projects are atdifferent stages of development. Of these, sevenprojects are under construction and represent85 billion m3 of annual production capacity,with 50 billion m3 of signed sales contracts,primarily with China, Japan and South Korea. Aspart of this, China and Australia have signedcontract agreements for approximately 20 bil-lion m3: 5 billion m3 between CNOOC andQueensland Curtis, 4.7 billion m3 betweenCNPC and Gorgon and 10.5 billion m3 betweenSinopec and Australia Pacific. This results inChina importing 25 billion m3 of natural gasfrom Australia, accounting for over 35% ofsigned LNG contract agreements.

From the perspective of project progress,Australia’s project development is in a leadingposition, with seven projects planned to

Table 8.1 China’s natural gas imports, by source

Natural gasimports

LNG andpipelineimports

Majorimportingnation

Importedamount(100 million m3)

Import price($/MMBtu)

Proportion ofChina’s totalimports (%)

Total: 534,100 million m3

Price: 10.4$/MMBtuImport dependency: 31.6%

LNG Total: 250,100 million m3

Price: 10.5 $/MMBtuProportion: 14.9%

Qatar 92 17.9 17.7

Australia 48 3.5 9.3

Malaysia 36 8.1 7.0

Indonesia 33 3.9 6.4

Pipeline Total: 284,100 million m3

Price: 10.4 $/MMBtuProportion: 16.7%

Turkmenistan 244 9.6 47.0

Uzbekistan 29 9 5.6

Kazakhstan 1 3.5 0.1

Myanmar 10 11.5 1.9

Source “BP Statistical Review of World Energy (2014)” and author calculations

3NBP, National Balancing Point. This is the UK’s virtualgas trading hub price.

8.3 China’s Current Natural Gas Imports and Future Trends 205

Uzbekistan, 5.6%Trinidad &

Tobago, 0.3%

Other Europe*,0.1%

Angola,0.2%

Algeria, 0.1%

Egypt, 1.1%

Equatorial Guinea,1.0%

Australia, 9.3%

Nigeria, 1.0% Indonesia, 6.4%

Yemen, 2.9%

Malaysia, 7.0% Kazakhstan,0.1%

Turkmenistan,47.1%

Qatar, 17.7%

Fig. 8.8 Chinese natural gas import sources. Source BP Statistical Review of World Energy (2014)

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Fig. 8.9 Comparison of China’s natural gas import prices and other international natural gas prices. Source MichaelChen (2014)

206 8 International Natural Gas Supply and Quantities …

commence prior to 2017. Moreover, because ofadvantages in geographical location, shippingfees to China are lower compared to the UnitedStates and Canada. However, these projects inAustralia are all scheduled to develop simulta-neously, causing source material and labourmarket shortages and price increases that havecaused project cost rises. In some projects, forexample Gorgon, costs have even risen by asmuch as 40% (Forster 2013). These cost increa-ses could affect natural gas pricing. In addition,even if cost increases are only temporary, sub-sequent projects could face similar problems, andAustralia could face issues of insufficient naturalgas supply. This problem could then furtheraffect subsequent projects. These risks must beconsidered as China further signs LNG purchasecontracts, especially since so many LNG con-tracts have already been signed with Australia.

2. United States

The US shale natural gas revolution is cur-rently changing American and even globalenergy market layouts. According to materialsfrom the US Energy Information Administration,in the past several years, American shale naturalgas production volume increases have seen anover 20-fold increase. Today, the United Stateshas surpassed Russia to become the world’s lar-gest natural gas producer. Research by interna-tional consulting company ICF has shown thatthe United States can use the natural gas reservesheld as of 2011 for 130 years of consumption.Shale natural gas development has drasticallyreversed the United States’ reliance on imports.In 2007, the United States was still planning toinvest enormously in the construction of naturalgas import ports, whereas as of July 2014, therewere 29 LNG export projects currently seekingapproval from the Department of Energy, for atotal of 430 billion m3.

American natural gas export targets includethe FTA and non-FTA nations. According to theUnited States Natural Gas Act, revised in 1992,natural gas approvals for export to FTA nationscan be obtained automatically, but to export tonon-FTA nations requires authorisation from the

Department of Energy, and approval is onlygiven if the proposal is in the interests of theAmerican public. China is a non-FTA nation.

The United States has seen fierce debate overthe last two years about whether it should exportnatural gas. Opposition to export includes USmanufacturers, the chemical industry and othernatural gas downstream enterprises, who believethat exporting natural gas will cause domesticnatural gas prices to rise, as well as Americanenvironmentalists, who believe that shale naturalgas will harm water resources as well as add togreenhouse gas emission increases. Supporters ofexporting natural gas include natural gas upstreamdevelopment enterprises and free market sup-porters, who believe that export of natural gas willbe beneficial in stimulating the US economy andcreating jobs. There are also some internationalenergy political considerations that relate towhether American exports of natural gas will helpput an end to halts placed on European nations byRussia. Finally, based on its analysis and research,the US Department of Energy believes that exportis on the whole beneficial to American economicinterests, and thus approved a series of natural gasexport projects. By July 2014, there were sevenprojects that had received approval, with a total of100 billion m3 of capacity exporting to non-FTAnations, including Sabine Pass (2.30 billion m3),Freeport (20 billion m3), Lake Charles (20 bil-lion m3), Cameron (18.0 billion m3), Cove Point(8.0 billion m3), Jordan Cove (8.0 billion m3)and Oregon LNG (13.0 billion m3).

The major reason for American natural gasattracting such excitement from natural gasbuyers is that US LNG imports improve thediversification of import sources in thosenations. This diversification is in two respects:one is in terms of geographical location, sinceprior to this natural gas exports primarily camefrom the Middle East and North Africa. Theother is from the perspective of pricing mech-anisms. For a long period, international naturalgas pricing was essentially linked to oil prices,but due to its own natural gas market, andbecause natural gas markets are somewhatindependent from oil markets, the United Statesprices domestic natural gas using the natural gas

8.3 China’s Current Natural Gas Imports and Future Trends 207

price on the Henry Hub as a baseline. Thus thenatural gas exported from the United Statesmight not be entirely linked to oil prices, andprovides a hedge against oil risk in natural gasimport channels. From the perspective of actualprice, the US Henry Hub price is currentlybetween $3 and $5. In the long term, it couldrise, especially if international oil prices plum-met. There is also the consideration that themajority of US export ports are in the GOM,and require the Panama Canal in order to reachAsia, and shipping fees are going to be moreexpensive than Australia.

From the perspective of project progress, theUnited States currently only has one LNG projectunder construction, Sabine Pass, which is expec-ted to be completed in 2015/2016. However,American LNG has been the focus of significantattention, especially among Asian buyers such asin Japan, South Korea, India and China, withapproximately 120 billion m3 of natural gasalready signed under purchase contract: 65 bil-lion m3 signed with portfolio players, 23 bil-lion m3 with Japan, 7 billion m3 with Spain,9 billion m3 with India and 7 billion m3 withSouth Korea. Currently, China has not signed anynatural gas purchase agreements or contracts.

3. Canada

Canada’s LNG projects got under way laterthan those in Australia and the United States.Currently, there are proposals for a total of 19LNG projects for a total of 355 billion m3. Noproject has as yet entered construction. Approx-imately 20 billion m3 have already been signedunder some kind of purchase agreement andcontract, including 5.8 billion m3 betweenCNPC and Pacific Northwest, 830 million m3

between Huadian and Pacific Northwest, and1.38 billion m3 under a memorandum betweenGuangzhou Natural Gas Group and Woodfire.

As far as distance is concerned, Canada iscloser to China than the United States, and thusshipping fees will be slightly lower. Moreover,political barriers could be less of a problem.Project development has lagged behind Australiaand the United States, and thus there is significant

project uncertainty. At the same time, in somecommunities, including the native residents,opposition is still an important factor holdingback project progress. In addition, severe weatherand the need to construct infrastructure couldincrease the project development costs and thusaffect future natural gas prices. Regardless, as along-term potential natural gas-exporting nation,Canada’s natural gas export dynamics anddevelopment are worthy of attention and study.

8.3.3 Trends in China’s FutureNatural Gas Imports

1. Trends in LNG imports to China’s

Since China’s natural gas consumption hasincreased rapidly in recent years, the three majoroil corporations are actively seeking out opportu-nities to purchase natural gas from internationalnatural gas markets to satisfy future demand.Table 8.2 shows long-term signed LNG contractsthat China currently holds, including sales andpurchase agreements, heads of agreement andmemorandums of understanding. It is estimatedthat in the next few years China will see rapidgrowth in LNG imports. New LNG imports fromAustralia will be largest part of this increase, risingfrom approximately 5 billion m3 currently to25 billion m3 by 2015. Other LNG importincreases currently planned will be from Russia(approximately 4 billion m3), Papua New Guinea(approximately 3 billion m3) and from third par-ties (approximately 9 billion m3). In addition,China is currently in talks with Canada to sign apurchase of LNG contract letter of intent ormemorandum of understanding for approximately8 billion m3.

However, these projects are still uncertain.First, contract letters of intent or understandingcould potentially endwithout the final transition toa purchase contract taking place. In addition, whilethese projects plan to begin imports to China in2017–2019, they have still not entered construc-tion, and the repercussions of the international oilprice drops could introduce uncertainty into theexpected timeframe. For example, the Pacific

208 8 International Natural Gas Supply and Quantities …

Northwest project recently announced a delay inthe project’s final investment decision due tointernational oil price drops. Therefore, even if inthe long term international oil prices support thecontinued progress of these projects, they are stillvery likely not to be executed until after 2020.Taking this into consideration, China is likely tosee a rise in LNG imports from the current25 billion m3 to approximately 57 billion m3 in2020. By 2030, if theCanadian contract is realised,LNG imports will rise to approximately 65 bil-lion m3. Two east African countries are also likelyto become LNG-exporting nations in the latter halfof the 2020s.

Looking at importers (see Table 8.2),CNOOC accounts for a major share of the cur-rent LNG long-term contracts, and has signedcontracts for approximately 30 billion m3. Sino-pec and CNPC currently have approximately14 billion m3 and 20 billion m3 of LNG con-tracted, while Huadian Group and GuangzhouNatural Gas Group have signed for 0.83 bil-lion m3 and 1.28 billion m3 in LNG contractsrespectively (Fig. 8.10).

In addition to long-term contracts, spot andshort-term contracts are also used to import nat-ural gas. In 2013, Chinese spot imports of LNGwere approximately 5.4 billion m3, accounting

Table 8.2 China’s LNG long-term contracts

Type Exportingnation

Name of plant Buyer Volume(bcm)

Startyear

Endyear

Spot Australia Withnell Bay CNOOC 4.55 2006 2030

Spot Indonesia Tangguh CNOOC 3.59 2009 2033

Spot Malaysia Malaysia LNGTiga

CNOOC 4.14 2009 2029

Spot Qatar Qatargas CNOOC 2.76 2009 2034

Spot Portfolio seller Portfolio CNOOC 1.38 2010 2024

Mid-/long-term Portfolio seller Portfolio CNOOC 6.90 2015 2035

Contract letter of intent Portfolio seller Portfolio CNOOC 2.07 2019 2039

Purchase contract Australia QueenslandCurtis

CNOOC 4.97 2014 2034

Spot Qatar Qatargas CNPC 4.14 2011 2036

Purchase contract Russia Yamal CNPC 4.14 2018 2038

Purchase contract Australia Gorgon CNPC 3.10 2014 2033

Purchase contract Australia Gorgon CNPC 2.70 2014 2033

Purchase contract Australia Australia Pacific Sinopec 10.49 2015 2035

Purchase contract Papua NewGuinea

PNG LNG Sinopec 2.76 2014 2034

Contract letter of intent Canada PacificNorthwest

Sinopec 4.14 2019 2039

Contract agreement Canada PacificNorthwest

Sinopec 1.66 2019 2039

Contract agreement Canada PacificNorthwest

Huadian 0.83 2019 2039

Memorandum ofunderstanding

Canada Woodfibre GuangzhouNaturalGas Group

1.38 2017 2042

Source International Group of Liquid Natural Gas Importer (GIIGNL), LNG Industry 2006–2014, and author compiledand organised

8.3 China’s Current Natural Gas Imports and Future Trends 209

for around 22% of the total LNG import volume,slightly less than the current global LNG spottransaction volume percentage of all trades of27%. As shown in Fig. 8.11, global spot

transactions have seen a rising trend in recentyears, primarily due to their flexibility, whichallows them to top up supply shortages fromlong-term contracts and enables arbitrage of price

-

10.0

20.0

30.0

bcm 40.0

50.0

60.0

Australia Indonesia Malaysia Qatar Papua New Guinea Russia Canada Portfolio sellers

70.020

09

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Fig. 8.10 China LNG imports. Source International Group of Liquid Natural Gas Importer (GIIGNL), LNG Industry2006–2014, and author compiled and organised

30

%mmtpa

25

20

15

10

5

0

70

50

60

40

30

20

10

02000 2005 2010 2012 2013

LNG spot tradeLNG spot trade percentage (right axis)

Fig. 8.11 Global spot trade market change trends this year. Source GIIGNL 2013. Data source International Group ofLiquid Natural Gas Importer (GIIGNL), LNG Industry in 2013

210 8 International Natural Gas Supply and Quantities …

between different LNG markets. As China’snatural gas trade market develops, awareness ofrisk aversion will strengthen and the constructionof a natural gas financial market is sure to resultin spot and short-term markets also seeing furthergrowth through natural gas import increases.Taking 20–25% as an estimate of spot LNGtrade’s percentage of total LNG trade volume, by2020 spot LNG trade volume could reachapproximately 10 billion m3, and approximately15 billion m3 by 2030.

2. China’s LNG receiving station construc-tion trends

Natural gas receiving stations are a criticalpart of the infrastructure for the LNG trade chain,and can also restrict the ability to import naturalgas. China’s first LNG receiving station, theShenzhen Dapeng Receiving Station, started

operations in 2006. China currently has LNGreceiving station capacity of 45.4 billion m3/year(33.4 MMt/y), with projects under constructionof 40 billion m3/year (29 MMt/y). There is alsoplanned construction of 140 billion m3/year(102 MMt/y).

Based on these figures, by 2020 China’s LNGreceiving station capabilities could reach 85–225 billion m3/year, which would enormouslysurpass the possible scope of future LNG imports.These planned projects could be increased orreduced along with China’s natural gas demandand international natural gas trade market chan-ges. However, considering current signed naturalgas long-term contracts and expressions of intentson the part of China, at first sight it seems clearthat the overall capabilities of China’s LNGreceiving stations will not be a bottleneck for theimport of natural gas (Fig. 8.12).

Tianjin(Sinopec)

Tianjin (CNOOC)

Caofeidian(Hebei)

DalianExpansion

DalianYantai LNG

Rizhao

Lianyungang LNG

Shanghai LNGand expansion

ShenzhenDeifu (CNOOC)

Jiangmen LNGGuangxi LNG

Beihai LNG

Hainan LNG

Zhuhai LNG

Shenzhen Dapeng

Yuedong LNG and Expansion

Qingdao LNG Jiangsu Yancheng LNGJiangsu Yancheng FSRU

Rudong and ExpansionQidong LNG

Zhoushan LNGZhejiang Ningbo LNGand Expansion

Tianjin FSRUand Expansion

Zhangzhou LNGFujian LNG Expansion

Fuqing LNG

Ningde LNGTaizhou

ExistingPlannedUnder construction

new in 2013

new in 2014

expansion

33.4102.029.0

Capacity (MMt per year)

Fig. 8.12 China natural gas receiving station construction

8.3 China’s Current Natural Gas Imports and Future Trends 211

3. China’s future pipeline natural gasimports

China’s existing pipeline natural gas importsprimarily come through central Asia andMyanmar, with the future Russian pipeline setto become a major import source as well(Table 8.3).

The Central Asia line is divided into the fourlines: A, B, C and D. The A and B lines aresourced from Turkmenistan and currently havecapacity of 30 billion m3/year. The C line is25 billion m3/year (10 billion m3 from Turk-menistan, 10 billion m3 from Uzbekistan and5 billion m3 from Kazakhstan, began operationin June 2014). The D line shipping capability is30 billion m3/year and is expected to open in2016. The Myanmar line began operation inAugust 2013 and by August 2014 hadimported 4 billion m3, with capacity for12 billion m3/year.

With regard to Russia, currently Russia andChina have signed an East Line contract as ofMay 2014, with shipment capabilities to reach

38 billion m3/year. The Western Line has had amemorandum of understanding signed as ofNovember 2014, and could include scope of30 billion m3/year. Of course, until a formalcontract is signed, nothing is certain. Althoughboth projects are slated to commence prior to2020 (the Eastern Line in 2018, and the WesternLine in 2019), the actual start time could yet beafter 2020. First, since 2014, Russia’s projectprogress and development has slowed, withapprovals not yet obtained from the Russiangovernment. In addition, Russia’s geographicallocation and severe weather, among other factors,will make it more difficult for the project to makeprogress. Moreover, the Eastern Line and Wes-tern Line both require large quantities of funds,labour and resources to be invested, which is achallenge for Gasprom, especially as interna-tional oil prices have dropped.

In summary, it is expected that in 2020 Chi-na’s pipeline imports will be in the region of97 billion m3. In 2030, China’s pipeline importcapacity will reach approximately 135–165 bil-lion m3, with the main uncertainty in this figure

Table 8.3 China’s future pipeline natural gas import capacities

Current(100 million m3)

Future imports(100 million m3)

Remarks

CentralAsiapipeline

550 850

A line andB line

300 300 Gas sourced from Turkmenistan, having entered operation inDecember 2009 and October 2010 respectively

C line 250 250 Gas source: Turkmenistan (10 billion m3), Uzbekistan (10billion m3) and Kazakhstan (5 billion m3), began operation inJune 2014

D line 300 Expected to begin operation in 2016

Myanmar 120 120 Began operation in August 2013, and as of August 2014 hadreceived 4 billion m3

Russia 380–680

East line 380 Began construction in September 2014, expected to open in2018

West line 3000–6000 Came to understanding memorandum in November 2014,expected to open in 2019. Signed intention is for 60 billion m3,but 30 billion m3 is a more realistic expected goal

Pipelinenatural gas

670 1650–1950

Data source Company websites, news, and author collected and arranged information

212 8 International Natural Gas Supply and Quantities …

coming from the progress of Russia’s WesternLine.

4. China’s future natural gas import trendoutlook

In summary, given the long-term LNG andpipeline contracts that China has already signed,China’s natural gas imports will grow rapidly inthe next few years, from 53 billion m3 in2013 to 167 billion m3 in 2020, including70 billion m3 from LNG and 97 billion m3 frompipeline natural gas. By 2030, imported naturalgas will further expand to approximately210 billion m3, including 75 billion m3 in LNGand 135 billion m3 in pipeline supply. If Rus-sia’s Western Line is able to implement its30 billion m3, then imported natural gas willgrow further to around 240 billion m3, including75 billion m3 in LNG and 165 billion m3 inpipeline supply.

Figure 8.13 shows China’s 2030 natural gasimport source country proportions based onlong-term contract calculations. Currently signed

contracts and intentions clearly indicate thatTurkmenistan and Russia will become the majornatural gas importers to China, each accountingfor approximately 30%. Following this will beAustralia, whose natural gas imports will accountfor 12%. Another approximately 30% will besourced from eight nations, including Myanmar,Qatar, Uzbekistan and Papua New Guinea, aswell as from third-party natural gas suppliers.This is a major change from the figures in 2013:the proportion of China’s imports that are sourcedfrom the Middle East will have been reduced themost, from 17.7% in 2013 to just 3%. Turk-menistan’s proportion will move from nearly 47to 30%, while Russia will move from 0 to 32%. Inaddition, Australia will see a slight increase. It isclear that from 2020–2030, China’s will increasethe diversity of its natural gas import sources,primarily by achieving historical breakthroughswith Russia in natural gas contract negotiations,thus enabling China to reduce its reliance onCentral Asia’s natural gas (Fig. 8.14).

What should be noted is that the predictions ofChina’s future natural gas import trends outlined

2013

0

50

2020 2030

100

150

200

250

300 Turkmenistanbc

m

UzbekistanKazakhstanMyanmarAustraliaIndonesiaMalaysiaQatarPapua New GuineaPortfolio SellerSpot & short-term contractsRussiaCanada

Fig. 8.13 China’s future natural gas imports. Note Long-term contracts include purchase contracts, co-operationintention agreements and memorandums of understanding

8.3 China’s Current Natural Gas Imports and Future Trends 213

above are based on natural gas import capabilitiesand quantity of contracts. However, importcapabilities are not entirely equivalent to thequantity of actual imports. For example, after apipeline is constructed, the volume of actualshipments can be less than its maximum shippingcapability. Moreover, even though natural gaslong-term contracts are relatively stable, they arestill not completely fixed, and both parties are stillable to negotiate and make adjustments accordingto actual changes in circumstances. Thus China’sactual natural gas import volume in the future willbe determined not only by import capabilities andcontracts, but also by domestic demand.

At the same time, the risks and uncertaintiesfacing China’s future natural gas imports must beacknowledged:

• First, the global natural gas market structurestill presents several variable factors. ManyFront-End Engineering Design projects are inplanning stages and may not be ultimatelycompleted, especially those in early stages,which could be influenced by various factorsand risks and cancelled. Currently there issignificant export potential in Australia, theUnited States and Canada, and various projectplanning capabilities are very promising, buthow these projects will ultimately affect theglobal natural gas trade is hard to say.

• Second, international oil price changes pre-sent a major variable to the international tradein natural gas. A drop in international oilprices represents a reshuffling of the cards,and currently markets have begun to enter a

Canada4%

Turkmenistan31%

Uzbekistan4%

Kazakhstan2%

Myanmar5%

Australia12%

Indonesia2%

Qatar3%

Papua New Guinea1%

Portfolio Seller4%

Russia32%

Fig. 8.14 Future Chinese natural gas import source nation proportions. Source GIGNL and author collection andarrangement

214 8 International Natural Gas Supply and Quantities …

new process of balancing out, and long-termnatural gas prices will have their new pointsof balance determined by multiple factors.There are significant uncertainties, and thiswill affect China’s interests and risks as itimports natural gas.

• Furthermore, along with cost increases,political risk and various other factors are alsohaving significant influences on future Chi-nese natural gas imports. Currently, Aus-tralia’s in-progress projects are seeingsignificant cost increases, while if Chinawishes to achieve imports from the UnitedStates and Canada, there are significantpolitical barriers that must be overcome,presenting major political risks. Therefore,even if China insists in future upon a strategyof natural gas import diversification, thesuccess of this strategy will still depend onthe circumstances of the international naturalgas market and the political environmentswithin individual nations.

• Finally, there is a certain amount of uncer-tainty over China’s future imports of pipelinenatural gas. Even based on current circum-stances, pipeline natural gas imports will playa determining role in future natural gasimports for China, but the final realisedpipeline natural gas import volume is as still asignificant variable. For example, in theRussian pipeline natural gas project, actualproject progress since 2014 has not beenideal, and the project has encountered diffi-culties as a result of Russia’s geographicallocation and severe weather. Russia still facesa major challenge to satisfy the enormousrequirements for funding, labour and resour-ces that are necessary to complete the project.

In brief, looking at the current LNG contractsand pipeline natural gas agreements, Chinesenatural gas imports are set to expand. However,close attention must be paid to risk and uncer-tainty, as well as to the rapid changes in inter-national circumstances and specific conditions innations which can lead to fluctuations in

international natural gas markets. China mustprepare for a rainy day and make suitablepreparations to ensure its own security of supplyas it pursues a strategy to diversify natural gasimports.

8.4 China’s Natural Gas TradePolicies and Recommendationsfor Reform

8.4.1 China’s Current Natural GasTrade Policies

China’s natural gas trade policies can be groupedinto the following major sectors, based on thestages of the natural gas import process:

• Commodity trading policy: Treating naturalgas as a trade commodity while managingimports. This includes answering questionssuch as: Do domestic entities have the right toimport natural gas? Do approvals from rele-vant authorities need to be obtained? Areapprovals from authorities required for adomestic entity to sign a contract with a for-eign company?

• Facility construction and operation policy:After natural gas is imported into China,managing facilities (receiving stations, gasreserve pipeline networks etc.), constructionand operation. This includes answeringquestions such as: Which entities can con-struct receiving stations and other infrastruc-ture? Are approvals required, and how arethey handled? What policies are there forinfrastructure operation? How are policiesimplemented?

• Price and taxation policy: Policies relatingto imported natural gas pricing and taxes.This includes answering questions such as: Isthere regulatory interference in importednatural gas pricing? For imported natural gas,what tax policies apply, for example subsidiesand tax rebates?

8.3 China’s Current Natural Gas Imports and Future Trends 215

1. Commodity trading policy

In terms of the foreign trade sector, natural gasdoes not constitute a state-run commodity, and isviewed as a “general commodity”.4 At customs,conducting natural gas trade does not requireprior approval, with customs currently oversee-ing statistics for natural gas commodity trading.Requirements for corporate reporting and filinghave also been cancelled, making it no differentthan other general commodities.

Therefore, in theory, natural gas imports areopen to all qualifying enterprises, and there is nosubstantial barrier arising from commodity trad-ing policies. So long as the business scopeincludes “natural gas trade” (when handlingadministration for industry and commerce regis-tration) and all Ministry of Commerce approvalshave been obtained (routine procedures), theenterprise can carry out natural gas import busi-ness, and the signed trade contracts do not requireapproval and review from relevant authorities.

2. Facility construction and operation policy

The main facility construction and operationpolicy approvals are at the facility constructionstage. According to national policy, a construc-tion project beyond a certain size requiresapproval from the NDRC, and natural gas sectorbuilding construction is included within thescope of approvals. Currently, there are differentpolicy directions for the different natural gasfacilities. For LNG receiving station projectconstruction, since receiving capabilities are farahead of actual shipping volume, China is strictlycontrolling such projects. For pipeline networksand gas reserves and other facilities, China isimplementing an attitude of encouragement,encouraging various ownership systems to par-ticipate in gas reserve facility investment, con-struction and operation.5 Therefore in practicethe true barrier to an enterprise conducting LNG

trade is whether or not it has correspondingfacilities to accept the imported natural gas.

Even if the nation is attempting to encouragemore enterprises to participate in natural gasimport trade, thereby expanding imports,enlivening markets and increasing the degree ofcompetitiveness, thanks to restrictive factors suchas the limit on receiving stations, there is stillonly a limited number of enterprises engaged innatural gas trade markets (the three major oilcompanies, Huadian, Jiufeng, ENN and a smallnumber of other companies).

Regarding receiving station construction,third-party access is not yet in place (policieshave just been released) and thus various entitiesstill wish to construct their own receiving sta-tions. As a result, current receiving stationcapabilities have become much greater thanactual shipping volume, but even so, domesticparties are still actively seeking to build newreceiving stations. At the same time, the NDRCis strictly controlling construction of newreceiving stations. In practice, whether or notapproval can be obtained depends on an interplaybetween the central government, local govern-ment and enterprises, and there is a lack ofopenness and transparency in the approval stan-dards and procedures, resulting in significantuncertainties.

With natural gas trade being restricted byfacilities such as receiving stations, and receivingstation construction also being closely controlledby the central government, the core questionaffecting natural gas trade is therefore: Can cur-rent domestic receiving station facilities providetrue third-party access?

There is already a clear provision that hasbeen provided in the recently released NaturalGas Infrastructure Construction and OperationManagement Measures (implemented April 12014):

4See Commerce Department Office Opinions RegardingSeveral Issues Involving LNG Commodities, June 5,2007.

5See NDRC Guiding Opinions Regarding Acceleration ofReserve Gas Facilities, April 5, 2014; NDRC OpinionsRegarding Establishment of Effective Mechanisms toEnsure Stable Supply of Natural Gas, May 5, 2014.

216 8 International Natural Gas Supply and Quantities …

Natural gas infrastructure operators shall announceand provide information regarding service condi-tions, obtained service procedures, and remainingservice capacity, fairly and justly providing allusers with pipeline shipping, storage, gasification,liquefaction, and compression services.Natural gas infrastructure operators may not usetheir control of infrastructure to exclude othernatural gas operators. Where service capacityexists, users meeting requirements may not berefused provision of service, or be presented withunreasonable requirements. Existing users prefer-entially obtain natural gas infrastructure service.

However, the third-party access policyrequirements for natural gas infrastructuredescribed above are somewhat vague, lackingspecific details and a relevant series of proce-dures, and thus lacking practicality. In reality,because of the imperfection of the above policyprovisions, and also due to current marketstructure, monopolistic powers are still strong,and without proper regulation the current policiesrelating to third-party access are essentially ablank document. As far as international naturalgas pipeline trade is concerned, the enormousinvestment involved and complex geopoliticalfactors, and the extreme requirements these placeon the relevant entities, currently appear to haveresulted in an exclusive monopolistic structure,and in the short term this is unlikely to see fun-damental change.

3. Price and tax policy

There are no review and approval require-ments for trade commodity natural gas prices.So, from a policy perspective, natural gas pricedecisions are open, and are decided by the buyerand seller involved in the trade. This is particu-larly true of LNG, though in pipeline natural gaspricing there is indirect reliance on nationalnegotiating power. However, this reliance isindirect, and pipeline natural gas contracts arestill ultimately determined by the two partiesinvolved in the trade. In terms of tax policy,policies on VAT rebates or discounts on naturalgas imports are determined and adjusted by theMinistry of Finance. As China’s natural gaspricing becomes better adjusted in the future, thispractice could be halted (Table 8.4).6

8.4.2 Recommendationsfor Adjustmentsto China’s Natural GasTrade Policy

1. Encouragement imports and focus onexpanding domestic production

In terms of natural gas import policy focus,China needs to balance three main conflictingfactors: dealing with environmental pollution; thecontinued growth of domestic natural gas con-sumption as economic growth and residentialliving standards rise; and ensuring natural gassupply security. The first two require more nat-ural gas usage, and to a certain degree will resultin the import of more natural gas. The third,however, requires restraining natural gas importdependency at a certain level, and thus therecould be a need to take some sort of control ofthe rapid growth of natural gas imports.

In the next period of time (from the present to2020, 2030), the direction that should be taken interms of natural gas import policy is: prudentencouragement. This is because currently Chi-na’s natural gas sector’s most fundamentalproblem is how to rapidly increase domesticconsumption of natural gas, and whether it be interms of proportion of energy consumption(6.5%) or residential diffusion rate (16%),domestic natural gas consumption is still in needof major increase. Considering that as economicdevelopment increases and residential livingstandards rise there will be a greater requirementfor energy consumption models, there is a need

6Relevant policy references: Finance Department GeneralAdministration of Customs National Tax Bureau NoticeRegarding Issues Surrounding Ratio-Based Return ImportStage VAT for 2011–2020 Imported Natural Gas andPre-2010 “Central Asia Pipeline” Project Imported Nat-ural Gas (CGS [2011] No. 39); Finance DepartmentGeneral Administration of Customs National Tax BureauNotice Regarding Adjustments to Imported Natural GasPreferential Support Policies (CGS [2013] No. 74); andFinance Department General Administration of CustomsNational Tax Bureau Notice Regarding Adjustments toPreferential Tax Policy Natural Gas Import Projects (CGS[2014] No. 8), April 21, 2014.

8.4 China’s Natural Gas Trade Policies and Recommendations for Reform 217

Table

8.4

China’s

existin

gnaturalgastradepo

licies

Com

mod

itytrade

Facilityconstructio

nFacilityop

eration

Price

Taxes

Foreign

investment

Policy

“Natural

gas”

isconsidered

tobe

ageneralcommod

ity.

Solong

asthebu

siness

scop

einclud

es“natural

gas

trade”

(whendealingwith

Adm

inistrationforIndu

stry

andCom

merce

registratio

n)andallMinistryof

Com

merce

approv

alshave

been

obtained

(rou

tine

procedures),theenterprise

cancarryou

tnaturalgas

impo

rtbu

siness,andthe

sign

edtradecontractsdo

not

requ

ireapprov

alandreview

from

relevant

authorities

Pipelin

enetworks,gas

reserves

andotherfacilities

areencouraged

inconstructio

n,with

participationpo

ssible

bya

varietyof

ownership

structures.LNG

receiving

stationconstructio

nis

strictly

controlledand

foreigninvestmentisbarred

from

participation

Requiresexistin

gnaturalgas

infrastructure

operatorsto

prov

idetheirexcess

capacity

inform

ationandoffer

third-partyaccess.Natural

gasop

eratorscann

otcontrol

theirinfrastructure

toexclud

eothernaturalgas

operators.With

regard

toservicecapacity,they

may

notrefuse

userswho

meet

thecond

ition

s,no

rmay

they

makeun

reason

able

demands

onthem

–Fo

rnaturalgasim

port

VATprop

ortio

nal

rebate

discou

ntpo

licies,thetarget

ofrebatesisdeterm

ined

andadjusted

bythe

Ministryof

Finance

App

roval

requ

ired

for

foreign

investment

over

acertain

amou

nt

Reality

Marketentitiesinvo

lved

indo

mestic

naturalgastrade

arestill

very

limited(only

thethreemajor

oil

companies,Huadian,

Jiufeng,

ENN,andasm

all

numberof

othercompanies)

Currently,receivingstation

capacity

isfarhigh

erthan

actual

shipping

volume,

but

gasreceivingandpipelin

efacilitiesareseverely

lacking

Because

oftheim

perfectio

nof

thepo

licyprov

isions

and

dueto

thecurrentmarket

structure,

mon

opolistic

powersarestill

strong

,and

with

outp

roperregu

latio

nthe

policiesreleased

relatin

gto

third-partyaccess

essentially

amou

ntto

ablankdo

cument

Priceis

determ

ined

bythetrade

participants

andthereare

noapprov

alor

review

requ

irem

ents

––

Prob

lems

Inpractice,thetrue

barrierto

anenterprise

cond

uctin

gLNG

tradeiswhether

orno

tithascorrespo

ndingfacilities

toaccept

theim

ported

naturalgas

Whether

orno

tapprov

alcan

beob

tained

depend

son

aninterplaybetweenthecentral

government,local

governmentandenterprises,

andthereisalack

ofop

enness

andtransparency

intheapprov

alstandardsand

Natural

gasinfrastructure

third-partyaccess

policy

requ

irem

ents

aresomew

hat

vagu

e,lackingspecific

details

andrelevant

series

ofprocedures

andmissing

correspo

ndingop

erability

–Not

allnaturalgas

impo

rtersaretreated

equally

–

(con

tinued)

218 8 International Natural Gas Supply and Quantities …

for energy consumption that is more efficient,safer and cleaner. From this perspective,domestic natural gas consumption has entered astage of rapid growth, and there is already stronginherent growth momentum.

Given the serious need to control environ-mental pollution, especially in terms of limitingatmospheric smog, a major increase in domesticnatural gas consumption has become a pressingmeasure that must be addressed. So, driven bythe need to rapidly increase natural gas domesticconsumption, the formulation and announcementof policies for this sector must address this majorissue. Thus policy incentives to increase naturalgas supply and promote natural gas domesticconsumption should be enacted.

At the same time, given that China hasabundant natural gas resources (including con-ventional and unconventional gas), and thatcurrent exploration and development levels arestill relatively low, ensuring natural gas supplysecurity requires controlling external reliance onnatural gas to a certain level, and thereforeincreasing natural gas imports to satisfy growingdomestic demand for natural gas is not a viableoption. A more reasonable policy is, at the sametime as expanding natural gas imports, to givegreater attention to domestic natural gas pro-duction, implementing a principle of “the nationfirst”. In this way, natural gas import growth canbe encouraged to satisfy domestic demand whilealso preventing dependency on imports and asdomestic natural gas production volumes quicklyrise. Therefore, if import dependency is to becontrolled to a reasonable level without inhibit-ing imports, then creative efforts should be madeto increase the domestic production volume—and this will also solve the dilemma caused bydomestic natural gas consumption being insuffi-cient. In addition, even at the same level ofimports, import methods (import source diversi-fication, contract and pricing diversification) anddomestic infrastructure conditions (whether gasreserve and peak shaving capabilities are suffi-cient, and whether pipeline network facilities arewell established) also have an important influ-ence on natural gas supply security.

Table

8.4

(con

tinued) Com

mod

itytrade

Facilityconstructio

nFacilityop

eration

Price

Taxes

Foreign

investment

procedures,resulting

insign

ificant

uncertainties

Recom

mendatio

ns–

Streng

then

facility

constructio

napprov

alstandards,op

enness

and

transparency

Con

siderinternational

experience

inreleasing

operable

rulesforthird-party

access

andstreng

then

correspo

ndingregu

latio

n

––

–

8.4 China’s Natural Gas Trade Policies and Recommendations for Reform 219

In summary, China on the one hand needs toenact policies that are supportive and encourag-ing toward natural gas imports, effectivelyexpanding them and striving to diversify thecountry’s import sources and import modes. Onthe other hand, it must also focus on expandingdomestic production and optimising relevant gasreserves, pipeline networks and other facilities.Therefore, China should take the following atti-tude toward natural gas import policies in thecoming years: prudent encouragement.

2. Make LNG an integral part of China’snatural gas supply

Given the unique properties of LNG, itsflexibility and the natural gas consumption cen-tres nearby China’s eastern regions, LNG can beused in peak shaving and complementaryapproaches. In addition, international experiencehas shown that connecting Chinese LNG pro-curement with international markets can intro-duce and promote competition, which will in turnpromote market liberalisation in the China’snatural gas market.

In the European Union market, LNG bothbalances out EU natural gas supply and demandand also balances out global LNG markets. Thisis beneficial to EU natural gas consumers, andLNG in Chinese markets can play a similar role.LNG can promote market openness while alsoplaying a role in optimising energy structures,giving consumers greater benefits and alsoprompting further progress in the market liber-alisation of the China’s natural gas market.

3. Diversify imported natural gas, encourag-ing multilateral participation

China should take measures on the interna-tional market for import of natural gas. First, itshould include long-term, mid-term, short-termand spot portfolios to facilitate increased flexi-bility to deal with and control market changes.Second, integration should be achieved with oilindexes and reserve typical diversified pricingindexes. Furthermore, when assessing pricecompetitiveness, full consideration must be given

to project risk, commercial structure and otherfactors, and through rolling contracts suited toone’s own supply/demand balance, procurementof LNG can be achieved to relieve risk andachieve a natural gas supply portfolio that issourced from diverse geographical locations.

At the same time as this, it is important toencourage more large-scale end users to purchasenatural gas from international LNG markets.Whether it is power companies or large urban fuelenterprises, all of these will bring benefits to themarket. This is because this will help to reduceintermediary stages and improve natural gasvalue chain efficiency. In order to achieve thisgoal, it is necessary to have third-party access,which is a key to supporting liberalisation.

4. Strengthen regulation promotingthird-party access

Policies in the Chinese natural gas trade sectortend, on the whole, to be open and encouraging,though some specific rules still need to becomemore practical. This openness is clear frompolicies such as: seeking to diversify the coun-tries imported from; importing more natural gasto resolve the issue of “domestic natural gasconsumption being insufficient”; and promotingincreased market supply while raising marketcompetitiveness. Therefore, whether it is treatingnatural gas imports as a commodity, open tradeand encouraging third-party access to facilities orVAT rebate discount policies, on the whole,further natural gas imports are being encouraged.

However, in reality, the construction andoperation of receiving stations and other facilitieshave become key influences on natural gasimports. Third-party access has become a coreissue affecting Chinese natural gas trade. Basedon the current policies, even though there arerelevant provisions, there is still a lack ofcommon-sense workability and there is a majordoubt as to how effective they will be.

Thus, on the one hand it is important toachieve better standard processes and greateropenness and transparency in the approval ofbuilding new receiving stations and other facili-ties. On the other hand, it is necessary to learn

220 8 International Natural Gas Supply and Quantities …

from international experience in order to bring inrules for third-party access and effectivelystrengthen the relevant regulation.

8.5 Conclusions for Chinese NaturalGas Supply and Availability

In summarising domestic natural gas productionvolume and international natural gas availablevolume, we can come to the following prelimi-nary conclusions:

• China’s natural gas available volume totalwill rise from 234–239 billion m3 in 2015 to425–495 billion m3 in 2020. The 640–800billion m3 in 2030 will be a relatively stableand ample supply: Specifically, by 2015, theamount is expected to reach 234–239 billionm3. As part of this, conventional gas pro-duction volume will reach 140 billion m3,shale natural gas will reach 6.5 billion m3,coalbed methane will reach 4.5 billion m3,imported pipeline gas will reach 39–42 billionm3 and imported LNG will reach 39–41 bil-lion m3.By 2020, the amount is expected to reach425–495 billion m3. As part of this,conventional gas production volume willreach 180 billion m3, shale natural gas willreach 40–60 billion m3, coalbed methanewill reach 10–30 billion m3, coal methaneproduction will reach 30–60 billion m3,imported pipeline gas will reach 95 billion m3

and imported LNG will reach 70 billion m3.

By 2030, the amount is expected to reach640–800 billion m3. As part of this, conven-tional gas production volume will reach 260–280 billion m3, shale natural gas will reach80–150 billion m3, coalbed methane willreach 40 billion m3, coal methane productionwill reach 50–90 billion m3, imported pipe-line gas will reach 135–165 billion m3 andimported LNG will reach 75 billion m3.

• From the perspective of natural gas avail-ability structure, domestic conventionalgas proportion will drop, and domesticunconventional gas proportion will rise,with a rise in import pipeline gas and adrop in LNG imports: In 2015, conventionalgas proportion of total production volumeavailability will reach 60%, while shale nat-ural gas will account for approximately 2.7%,coalbed methane approximately 2%, importpipeline gas approximately 17–18% andimported LNG approximately 17%.In 2020, conventional gas proportion of totalproduction volume availability will drop to36–42%, while shale natural gas will accountfor approximately 8–13%, coalbed methaneapproximately 2–7%, coal methane willaccount for 7–13%, import pipeline gasapproximately 19–22% and imported LNGapproximately 14–16%.In 2030, conventional gas proportion of totalproduction volume availability will be 33–42%, while shale natural gas will account forapproximately 11–21%, coalbed methaneapproximately 4–6%, coal methane willaccount for 6–13%, import pipeline gas

Table 8.5 China’s naturalgas supply volume(100 billion m3)

2015 2020 2030

Conventional gas 1400 1800 2600–2800

Shale natural gas 65 400–600 800–1500

Coalbed methane 45 100–300 400

Coal methane 0 300–600 500–900

Import pipeline 390–420 970 1350–1650

Imported LNG 390–410 700 750

Total 2290–2340 4270–4970 6400–8000

Data source Analysis based on Ministry of Land and Resources and State CouncilResearch Center study results

8.4 China’s Natural Gas Trade Policies and Recommendations for Reform 221

approximately 18–25% and imported LNGapproximately 9–12%.

• From the perspective of foreign reliance,China’s reliance on foreign natural gas willcontinue to rise significantly and be con-trolled to within 36% by 2030: In 2015,China’s reliance on foreign natural gas wasapproximately 33–35%, while in 2020 thatnumber will reach approximately 33–39%. Ifdomestic natural gas, especially shale natural

gas, production volume achieves majorincreases through breakthroughs in technologyor policy, then in 2030China’s foreign reliancein natural gas will be at approximately 27–36%. Namely, by 2030, China’s reliance onforeign natural gas can be controlled within36%. However, the prerequisite is thatdomestic natural gas production, especiallyunconventional natural gas, sees a break-through increase (Tables 8.5, 8.6, 8.7 and 8.8).

Table 8.6 2015 China natural gas supply volume and structure

Gas source Domestic gas (100 million m3) Imported gas(100 million m3)

Remarks

Conventionalnatural gas

Shalenatural gas

Coalmethane

Coalbedmethane

LNG Pipelinegas

Production volumeor import volume

1400 65 45 50 390–410 390–420

Total 1560 780–830

2340–2390

Data source Integration, analysis, and compilation of study results from the Ministry of Land and Resources and otherinstitutions

Table 8.7 2020 China natural gas supply volume and structure

Gas source Domestic gas (100 million m3) Imported gas(100 million m3)

Remarks

Conventionalnatural gas

Shalenatural gas

Coalbedmethane

LNG Pipeline gas Conventionalnatural gas

Production volumeor import volume

1800 400–600 100–300 300–600 700 950

Total 2600–3300 1650

4250–4950

Data source Based on the above analysis and compilation

Table 8.8 2030 China natural gas supply volume and structure

Gas source Domestic gas (100 million m3) Imported gas(100 million m3)

Remarks

Conventionalnatural gas

Shalenatural gas

Coalbedmethane

LNG Pipeline gas Conventionalnatural gas

Production volumeor import volume

2600–2800 800–1500 400 500–900 750 1350–1650

Total 4300–5600 2100–2400

6400–8000

222 8 International Natural Gas Supply and Quantities …

Case 9: Global natural gas/LNG marketoutlook

1. Global energy and natural gas mar-ket developmentGlobal energy demand is continuing to

rapidly grow, especially in nations andregions outside of OECD countries. Aspopulations quickly grow and economiesflourish, people have more numerouschannels through which to obtain reliablepower supply, and this will cause demandto grow for energy across the world by50% from 2010 to 2050 (Shell 2014).

In the past several decades, natural gashas consistently been one of the fastestgrowing energies. From 2005 to 2014,average annual growth maintained atapproximately 2.7% (BP 2014). Currentlyit is commonly recognised that up to 2030,natural gas demand will maintain annualaverage growth rates of 2% (IEA, CurrentPolicies Outlook). Global natural gasresource reserves are massive and broadlydistributed, and at current productionspeeds can be used for more than200 years.

With the exception of the United States,growth in unconventional resources inother countries is very uncertain, becausethese countries have very little or nomomentum toward production. Argentina(23 trillion m3; source: US Energy Infor-mation Administration) could have the bestdevelopment conditions, but faces severefinancial and non-technical risk limitations.

Even though, according to the US EIA,China has approximately 32 trillion m3 ofunconventional resources, the Chinesegovernment recently adjusted its recentdevelopment expectations for shale naturalgas downward by half, and thus China’senergy growth could be reduced. (China’snatural gas is distributed across 500 basins,but because there are currently only a fewcompanies, and there is a lack of interna-tional company involvement in this sector

to carry out development, complex terrain,costs, infrastructure construction, wastewater treatment and technical innovationinsufficiencies and other problems arefaced).

The national authorities and relevantpolicies will affect long-term LNGdemand growth, and it is not a case ofsimple determination of project cyclecosts, especially in Europe and Asia.Policymakers incorporate four aspects intoenergy policy portfolios, namely energysecurity, cost and competitiveness, envi-ronment and health, and energy avail-ability. The choices they make willdetermine the energy structure of nationsand regions.

This means that even though broadareas have become homogenous in termsof energy growth, nonetheless local andshort-term dynamic factors have a highdegree of uncertainty and changes areoccurring rapidly.

2. Global LNG market outlookSince 2000, global LNG demand has

grown at a rate of approximately 5%, andthis trend will continue for the foreseeablefuture (BP 2014).

In the past 10 years, there have been 31nations engaged in LNG imports, and 27nations engaged in export. Therefore, LNGdemand and supply has enormouslydiversified, and estimates are that in thenext 10 years, LNG demand nations andsupply nations will grow respectively to 50and 25.

Looking to the long term, LNG growthin demand will primarily come from Asianemerging markets (in particular China,India, and south-east Asia) and Europe.Even though LNG is only in early stages ofdevelopment in the transportation sector,nonetheless LNG has major potential tobecome an important niche market.

Japan, South Korea and Taiwan cur-rently account for approximately 60% of

8.5 Conclusions for Chinese Natural Gas Supply and Availability 223

the global LNG market, and will continueto be a major demand centre in a movingworld. Even though as nuclear powerreturns and renewable energy develops(especially solar power) Japan’s demandfor LNG will be limited, LNG demand willstill continue to remain at a high level.Another uncertainty is future degree ofmarket liberalisation.

In south-east Asia and India, becausedomestic gas reserves are declining, andbecause electricity and other industries areincreasing demand for LNG, south-eastAsia and India LNG demand will increasefurther. The major uncertainty in thisregion is price tolerance and the infras-tructure construction needed for import andshipping of LNG.

China’s policy to increase natural gasmarket share is critical. Given China’sreleased policies for pollution control andGDP growth, China has already and willcontinue to become a market with rapidgrowth in natural gas. China has thepotential to influence global market bal-ance and price levels. Uncertainties arepotential slowdowns in GDP growth, aswell as degree of implementation ofambitious policies.

With regard to Europe, in addition tolocal production and pipeline importenergy, LNG offers flexible supply. Europehas ample regasification capabilities (in2013 for each 140 mtpa, 40 mtpa could beproduced), and the region could become aflexible market for LNG. Europe’s LNGused in transportation sectors has potentialfor growth, especially in marine shipping,because strict air quality laws will drive afuel switch.

From 2010 to 2013, Europe’s economicgrowth slowed, and with cheap Americancoal and significant subsidies in Europe forrenewable energy development, natural gasdemand in Europe was pushed lower. Eventhough to a certain degree the factorscausing this reduction will exist in the long

term, European market natural gas demandcould still rebound, with the preconditionbeing reduced import of coal and reduc-tions in subsidies supporting renewableenergy growth.

3. Global LNG supplyBy 2030, the United States, Australia,

and Eastern Africa LNG supply willaccount for over 80% of total supply(source: 2015 Shell analysis).

• North America has already proposedutilising its over 6 million tons/yearproduction capacity for LNG export(shared equally between the UnitedStates and Canada).

• A total of over 44 million tons/year ofnatural gas has already received a finalinvestment decision and is under con-struction (locations all in the UnitedStates). North American natural gassupply quantities rely upon permits,financing, construction costs and speed.Russia and Australia have a potential

new project list. Cost increases andnon-technical risks have slowed the pro-gress of many projects. In addition, sanc-tions could delay or destroy the Russia’sLNG plans.

Eastern Africa (primarily Mozambiqueand Nigeria) could in the next 10 yearsbecome new gas supply sources. Chal-lenges faced include the fact that EasternAfrica has large swathes of undevelopedregions, and the majority of companies arenot LNG companies with stable marketpresence.

• Nigeria’s non-technical risks (such aspolitical, regulatory and financialuncertainties, damage risks anddomestic power demand) continue torepresent the major obstacles to LNGsupply growth.

• Due to domestic market demand, Egypthas seen a reduction to zero LNG

224 8 International Natural Gas Supply and Quantities …

exports, and will even need to importLNG. Egypt is currently actively seek-ing LNG exporters (and has alreadysigned contracts with Algeria’s Sona-trach and Russia’s Gazprom; additionalnatural gas supply could come fromIsrael or international enterprises).

• Qatar has not yet clarified its directionpost-2016 for its northern oil fields, andthus there exists some supply uncer-tainty. Despite this, Qatar has 77 mtpaof LNG supply capability, and becauseit is equidistant from Europe and Asia,it will continue to hold an importantprice-determining position.

• For Middle Eastern regions, theremoval of sanctions on Iran couldbring about major effects, and naturalgas supply is able to catch up todomestic demand growth. Therefore,LNG imports will be incorporated intoplanning.

4. A focus on North American marketsThe United States was once one of

Shell’s largest markets, and now ispreparing to export LNG. Potential exportprojects have not been announced for300 mtpa in the United States and over130 mtpa in Canada.

Initial project liquefaction costswill be relatively “low” (approximately$3.5/MMBtu) (addition of LNG importend), but subsequent costs will succes-sively rise (we have already seen the initialprice of <$3/MMBtu rise to the currentquote of >$4/MMBtu) (Fig 8.15).

Such projects are equivalent to tradi-tional Asia Pacific project levels, and areeven at HH$4/MMBtu.

Other barriers are: approval, construc-tion speed, construction costs (labour) andusers seeking resource portfolios (if majorAsia Pacific users restrict North Americanproject development risks to 20–30%, thenthis will turn into 100 mtpa supply).

However, the former view of Ameri-can LNG being “cheap” has changed, as oilprices have significantly dropped. Add tothis the market uncertainty (for exampleJapan’s deregulation of electricity), andthis has caused users to limit LNG invest-ment portfolio Henry Hub quoted supplyvolumes.

Therefore, when users are unwilling tosign large volumes of Henry Hub quotedlong-term agreements, project final invest-ment decisions will face major challenges,because final project investment decisionsrequire the support of long-term agreements.

5. Global LNG market is more activeWe have seen continuous increases in

the market share held by natural gas infundamental energy. Other energy indus-tries are continually growing, but naturalgas growth rates have been faster. Weexpect that in the next 20 years, globalnatural gas demand will grow at an annualrate of 2–3% (Fig. 8.16).

As natural gas usage increases,cross-border natural gas trade usingpipelines and LNG will continue toincrease.

The growth in natural gas trade requiresthat natural gas import and export infras-tructure continue to receive investment.

Large new pipeline projects are contin-ually achieving progress. For example, lastyear an early announcement was made ofthe Sino-Russian natural gas pipelineexport project having early stage shippingvolume that should reach 38 billionm3/year, with the possibility of furtherincreases. LNG has also become a majorpart of natural gas trade. Currently, LNGaccounted for 10% of natural gas trade, andthis will rise to 15% by 2025.

In recent years, LNG supply anddemand has markedly diversified. Thereare now 30 LNG importing nations and 20exporting nations, with this expected tochange in the next decade to 50 LNG

8.5 Conclusions for Chinese Natural Gas Supply and Availability 225

exporting nations and 25 importingnations. This is different from the situationin the 1990s when the global LNG market

was only 50 million tons per year, andthere were only eight exporting nations andnine importing nations.

GulfCoastLNG

AnnovaLNG

CorpusChristi LNG

Freeport LNGGolden Pass LNG

Sabine Pass

Magnolia LNG

Lake Charles Exports GasfinLNG Venture Global LNG

Gulf LNG EnergyLouisiana LNG Energy

Main Pass HubCE FLNG

Waller LNGDelfin LNG

Texas LNGBarca LNG

EOS LNGSouth Texas LNG

Cameron LNGExcelerate FLNG

Kitsault LNGPrince Rupert-BG

ValdezLNG

Alaska SC LNG(ExxonMobil,

ConocoPhillips, BP)*Manzanillo

Costa Azul

Magnolia LNGCameron

Woodfibre LNGWCC LNG

LNG CanadaPacific Northwest LNGAurora LNG

H-Energy

Existing Regas

Potential Export Site

Goldboro LNG

Northeast GatewayNeptune

EverettCove Point

Jordan CoveOregon LNG

Discovery LNGKitimat

Douglas ChannelTriton LNG

Canaport

Existing Regas andPotential Export Site

Under ConstructionExport Site

Sabine PassGolden Pass LNG

Freeport LNGSouth Texas LNG

Corpus Christi LNGGulf Coast LNG

Annova LNGAltamira

Texas LNG

EOS LNG

Barca LNGExcelerate FNLGDelfin LNGGasfin LNGWaller LNG CE FLNG

Main Pass HubLouisiana LNG Energy

Gulf LNG Energy

Lake Charles ExportsVenture Global

LNG

Elba Island

©2014 IHS

POTENTIAL NA LNG SUPPLY (MTPA)

Location

0

Project Type Shell 2025Outlook

100

200 USA

Canada

300

400Greenfield

Brown-field

HIGH

BASE

INDUSTRY VIEWS OF NA LNG SUPPLY (MTPA)

02020

20

40

60

80

100

120

2021 2022 2023 2024 2025

CERA

POTEN

Woodmac

McKinsey

RDS

Fig. 8.15 North American LNG supply. Source IHS Cera. * Potentially located near Valdez

226 8 International Natural Gas Supply and Quantities …

From now until 2025, a major changewill occur as North America rises as asubstantive natural gas exporting region.

6. Recommendations for China

(I) Multiple supply channels to ensureenergy supply securityIn the past decade, China’s natural gas

consumption volume growth has beenfierce, and in 2014 reached 183 billion m3.In addition, natural gas supply has com-prised domestic supply, pipeline naturalgas imports and liquefied oil and gasimports. This shows that diversified sup-plies are an important guarantee for energysecurity. In the next decade, the govern-ment has designated the natural gas portionof energy structure to grow from 4% toover 10%. This will require multiple sup-ply channels to satisfy market demand.Furthermore, considering the market scaleat that time, the wide diversity of supplychannels will play an important role inguaranteeing energy security.

In the north-east Asian regions of Japanand South Korea, reliance is on single

natural gas supply sources, and this ismarkedly different from China. Preciselybecause of this diversity in supply portfo-lios, China enjoys benefits when procuringnatural gas from international markets,ultimately helping Chinese consumers.

(II) LNG’s unique role makes it anintegral part of China’s natural gassupply portfolio

Considering that China has constructedimport channels to import natural gas viapipeline corridors (whether it be fromWestern Central Asia, Eastern and WesternRussia or south-western Myanmar), andthese are maturing by the day, this casestudy focuses on the possible choice ofLNG as a supply source on the interna-tional market.

Given that LNG has the unique prop-erties of being flexible and near to theeastern consumption centres, LNG canplay a unique role in peak shavings and asa complement to pipeline gas.

In addition, prior experience has shownthat because Chinese LNG procurement isdirectly linked to international markets,

Import region

Export region

LNG

Cross regional pipeline

Africa

Europe

MENAIndia & China

Russia & CIS

Australia

SouthAmerica

North America

Japan & Korea

Fig. 8.16 Global natural gas import and export

8.5 Conclusions for Chinese Natural Gas Supply and Availability 227

this can introduce and promote competi-tion, through which Chinese natural gasliberalisation can be catalysed.

Previously we have discussed the roleof LNG in EU markets. On the one hand itbalances out EU natural gas supply, whileon the other it balances out the global LNGmarket, benefiting natural gas consumers inthe European Union. We have reason tobelieve that LNG can also play a similarrole in the Chinese market, but it isimportant to realise that the reason thatLNG could play such a role in the EU wasbecause of the historical progress of marketliberalisation. Therefore, we would say thatLNG on the one hand can promote marketopening, bringing benefits to consumers,while on the other hand it can also assist asChina completes the liberalisation of itsnatural gas market.

(III) LNG procurement considerationsBy observing similar markets, it is

possible to obtain some lessons:

1. Experienced LNG buyers on interna-tional markets often have a diversifiedportfolio, including long-term,medium-term, short-term and spotportfolios to facilitate improvements toflexibility and to meet market changes.They also have a connection to oilindexes or a hub as a platform ofdiversified pricing mechanisms,because when the market changes, forexample when oil prices change, theprice competitiveness of each sales andpurchase agreement will likewisechange. In addition, when assessingprice competitiveness, it is necessary towholly consider project risk, commer-cial structure and other factors, thusavoiding only considering price labels,otherwise it is not a valid comparison.LNG supply portfolios must have adiversity of geographical sources.Another commonly made error is to

believe one is smarter than the marketand able to manipulate the market.Therefore, a commonly seen method ofrisk avoidance is to procure LNGthrough rolling windows to satisfyone’s own supply and demandbalances.

2. If more numerous large end users canpurchase natural gas from internationalLNG markets, whether it be powercompanies or large urban fuel enter-prises, this would bring benefits to themarket. This is because such actionshelp to reduce intermediary stages andmake the natural gas value chain moreefficient. To achieve this, though,third-party access is needed, and this isa key factor to supporting progress inliberalisation. We are very happy to seecompanies such as Huadian becomingactive in the realm of liberalisation.

3. However, this is not to say that everyenterprise should be encouraged toestablish its own receiving terminal andcarry out importing, since this wouldcause a large quantity of infrastructureto be less than amply utilised, resultingin price wars and ultimately harmingthe sustainable and healthy develop-ment of natural gas markets. In thisregard, we recommend that managersmake adjustments through formulationof game rules rather than artificialcontrols.

4. As regards the game rules for the nat-ural gas sector, including natural gaspipeline networks and receiving stationinfrastructure, management standardsare extremely important. This isbecause as pipeline network standardi-sation becomes more mature and playsa greater role, it will increase naturalgas value chain transparency, thusimproving market efficiency. Takingthe European Union as a typical maturemarket, they primarily use the follow-ing typical pipeline management rules

228 8 International Natural Gas Supply and Quantities …

to manage major issues: (a) requiringnon-discriminatory third-party accessrule restrictions; (b) capacity auctions,balance, pricing, distribution andreceipt issuance; (c) holding full nego-tiations; (d) natural gas delivery pipe-line network capacity release andprice schedules; (e) auction tradesheld in secondary markets; (f) separa-tion of input/output, separation ofcapacity/commodity; (g) third-partyaccess to receiving stations, gas stor-age, and pipeline networks, whether itbe established through bilateral negoti-ations or based on TPAs.

5. Maintaining natural gas/fuel oil portfo-lios is also of assistance, because thiswill enable natural gas users to optimisegas portfolios through switching, thusavoiding gas users seeking to resolveall problems through LNG SPA, whichpushes LNG purchase contract negoti-ations into a stalemate.

Case 10: China international pipelinenatural gas importsChina has an advantageous geographicallocation for pipeline natural gas imports,with Russia to its north, central Asia(especially Turkmenistan) to its west andsouth-east Asia (especially Myanmar).Existing and planned import pipelinecapacity is approaching 190–200 billionm3/year, which is likely to be one quarterto one third of the natural gas consumptionvolume of China expected in 2030.

Pipeline gas imports are one of the threemain supply sources forChina,with the othertwo being domestic natural gas productionand LNG imports (respectively having mul-tiple supply channels). These three funda-mentals ensure China’s natural gas supplywhile also forming competition with regard

to baseline prices, thus satisfying the naturalgas demand that continues to grow in China.

Regarding the greatest factors ofuncertainty for these international naturalgas pipeline imports, they are as follows:

1. Russia’s natural gas supply base for theeast-west line.

2. Whether Russian companies have theability to develop the eastern Siberiannatural gas field and create natural gaspipelines and deliver natural gas withinthe promised timeframe. Given that theUnited States and European Union areimplementing sanctions on Russia, thisis especially critical.

3. In order to enrich client groups, whatdecisions will Turkmenistan make? Forexample, participating in the Turk-menistan-Afghanistan-Pakistan-India(TAPI) natural gas pipeline and/orovercoming legal and political difficul-ties to co-operate with Azerbaijan anddirectly supply Turkmenistan naturalgas to Europe through Azerbaijan andTurkey.

1. Pipeline natural gas import sourcesAs can be seen from Table 8.9, the

world has 14 nations whose conventionalnatural gas reserves exceed 100 trillion m3,and based on its advantageous geographi-cal location, China can import natural gasfrom essentially any country.

Currently, Iran, which is subject toUnited Nations sanctions, has the largestproved natural gas reserves in the world,with proved conventional natural gasreserves of nearly 120 trillion m3. Ifdeveloped, Iran will very likely becomelike Qatar, another LNG and unconven-tional natural gas supplier to China.

Russia and Turkmenistan have naturalgas resource reserves that respectively ranksecond and fourth globally. Russia

8.5 Conclusions for Chinese Natural Gas Supply and Availability 229

produces 605 billion m3 of natural gaseach year, to satisfy enormous domesticdemand and to meet 30% of Europe’sdemand for natural gas. Their reservemining term is 52 years, which is relativelyshort compared to other major natural gasresource reserve nations. Russia has alsopromised to supply China with nearly90 billion m3 of natural gas per yearthrough the Eastern and Western lines. Indoing so, unless new resources are dis-covered, Russia’s reserve mining term willbe markedly shortened. This could perhapsexplain why Russia is so urgently wishingto develop unconventional natural gas,including its domestic coalbed methaneand shale natural gas.

In comparison, the landlocked Turk-menistan has 617 trillion m3 of provednatural gas and over 280 years of naturalgas reserves to mine. It is also very likelyto enrich its own natural gas demandmarket, supplying natural gas to China,Russia and Iran. Two considerations forthe future are worth noting:

• TAPI can provide natural gas to twocountries with major populations—India and Pakistan. According to pre-vious reports, Chevron and other UScompanies are looking to join this plan,and recent reports show that Frenchcompany Total might also participate inrelevant discussions.

• The European Union urgently wishes toincrease its supply diversity, and thepipeline through TAPI is one importantpotential source. The European Union,including Vice President of the Euro-pean Commission Maroš Šefčovič, isactively encouraging Turkmenistan toplan out this pipeline (Financial Times2015), despite the fact that in the shortterm there are many legal and politicalroadblocks to its achievement. If theTAPI pipeline is realised, Europe andChina could face direct pricecompetition/connectivity.Kazakhstan and Uzbekistan and other

central Asian nations are not major naturalgas reserve nations, and in the foreseeable

Table 8.9 Most provedconventional natural gasreserves by country

Proved reserve quantity 2013 production volume R/P

Trillion m3 Trillion feet3 1 billion m3/year Year

Iran 33.8 1193 167 202

Russia 31.3 1104 605 52

Qatar 24.7 872 159 155

Turkmenistan 17.5 617 62 282

United States 9.3 330 688 14

Saudi Arabia 8.2 291 103 80

UAR 6.1 215 56 109

Venezuela 5.6 197 28 199

Nigeria 5.1 179 36 141

Algeria 4.5 159 79 57

Australia 3.7 130 43 86

Iraq 3.6 127 0.6 5980

China 3.3 116 117 28

Indonesia 2.9 103 70 42

Source BP Data Review (2014) (only conventional natural gas)

230 8 International Natural Gas Supply and Quantities …

> 1,000 Tcf

500 1000 Tcf

100 500 Tcf

Mozambique (est >100 Tcf)

From USA

From Canada

From Venezuela?

From Iran?

From Russia

LNG export to China (dash line – planned/potential)Pipeline gas to China (dash line – planned/potential)

_

_

Fig. 8.17 Major natural gas resource reserve nations and China’s potential natural gas export nations

Table 8.10 China’s existing and planned natural gas import pipelines

Capacity(1 billion m3)

Announcedterm

PFC expectedtime

Remarks

Imported natural gas pipelines (operation)

Central Asia natural gas pipeline Line A 15 2009

Central Asia natural gas pipeline Line B 15 2010

Myanmar-China 1 12 2013 Not yet at full load operations (>50% idle capacity)

Sub-total 42

Imported natural gas pipelines (planned)

Central Asia natural gas pipeline Line C 25 2014 10 billion m3 comes from Turkmenistan,10 billion comes from Uzbekistan,and 5 billion comes from Kazakhstan

Central Asia natural gas pipeline Line D 30 2016 2017

Siberian pipeline 38 2018 2021 Signed natural gas export agreement.Under construction

Siberian pipeline extension 30

Azerbaijan (West Line) 30 Signed memorandum

Kazakhstan–China 5

Myanmar–China 2 7

Sub-total 165

Pipeline import capacity total 207

Source WoodMac, HIS. Basic arrangement by study group

8.5 Conclusions for Chinese Natural Gas Supply and Availability 231

future there is still limited possibility forthem to become natural gas pipeline supplynations to China.

In south-east Asia, Myanmar is currentlysupplying approximately 5 billion m3 ofnatural gas per year to China through Yun-nan. Likewise lacking in natural gas aresouth-east Asian nations, and Myanmar iscurrently supplying Thailand with pipelinegas. Recently, Myanmar successfullyobtained a deep sea oil tender, attracting theattention of large transnational companies.According to geological analysis, these deepsea regions have the potential to have morenatural gas than oil. In the next 5–10 years,could Myanmar find a large quantity (largerthan 1 trillion m3) of deep sea natural gas tobecome the Mozambique of Asia? If it doeshappen, China should consider makingMyanmar’s (deep sea) natural gas anothersource of pipeline delivery. It could neces-sitate a round of competition, withMyanmarperhaps hoping to develop other LNG mar-kets in Asia to improve its own exportcapabilities in LNG, for example Japan andSouth Korea, so as to expand its buyernation group.

2. Existing and planned natural gasimport pipelinesTable 2.16 lists the import natural gas

pipelines from Russia, Central Asia andMyanmar to China. Currently, China’spipeline import capacity is approximately40 billion m3/year, but this is not to saythat each line is always at capacity. In2013, China’s pipeline import volume wasapproximately 25 billion m3, accountingfor approximately 15% of China’s naturalgas consumption of 166 billion m3.

Once they are fully completed, thesepipelines will have total capacity of nearly200 billion m3/year, and will account for onequarter to one third of all of China’s estimatednatural gas consumption by 2030. Therefore,the focus of the 13th Five-Year Plan may notbe confirming added pipeline natural gasimport volume, but joint efforts with Turk-menistan, Russia andMyanmar to ensure thattheseprojects canbecompletedon time so thatChina can import pipeline natural gas at acompetitive price (Fig. 8.17, Table 8.10).

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232 8 International Natural Gas Supply and Quantities …

9Analysis of China’s Natural GasInfrastructure Development Strategy

9.1 Current Developmentof Natural Gas Infrastructure

Since the West-East Pipeline began operating in2004, China’s natural gas infrastructure hasdeveloped rapidly. As of the end of 2014, apipeline network distribution layout has beenformed with the West-East Pipeline, marine gasand near-region supply, providing coverage to allprovinces with the exception of Tibet. There arealso both pipeline gas and LNG import resourcechannels, opening up central Asia’s pipeline gas,central Myanmar’s pipeline gas and marine LNGimport channels. There is also underground gasstorage and LNG receiving stations as two majorpeak shaving methods, covering the seaboardregion, gas-producing regions and regionsaround the Bohai Sea.

9.1.1 Current State of InfrastructureDevelopment

As of the end of 2014, China had constructed82,000 km of natural gas pipeline, of which23,300 km are national trunk pipelines, 16,500 kmare national branch pipelines and 13,800 km areprovincial trunk pipelines, with major progressachieved in termsofurbangas pipelinenetworks. Inaddition, 11 LNG receiving stations have beenbuilt, with total receiving capacity of 39.40 mil-lion tons. Constructed underground gas storagebases number 19, with total warehousing capacityof 45.2 billion m3 and designed working gas vol-ume of 15.1 billion m3, and effective working gasvolume of 4.2 billion m3.

1. Natural gas pipeline networks

Since the 1960s when China built its firstnatural gas pipeline, the “Bayu Line”, over manydecades of development, China’s natural gaspipelines have undergone significant growth.This is especially true with the 2004 West-EastPipeline, which accelerated China’s natural gaspipeline construction. As of the end of 2014,China had the West-East Pipeline, Shaanxi-Beijing Line, Sichuan to East Gas Pipeline Pro-ject, the Yuji Line and China-Myanmar naturalgas pipeline as major national trunk pipelines,and the Jining Line, Zhongwu Line, ZhongguiLine and Huaiwu Line as major connectionpipelines, with regional pipeline networksbetween the Yangtze River Delta, Sichuan and

* This chapter was overseen by Zhonghong Wang fromthe Development Research Center of the State Counciland Shangyou Nie from Shell International Explorationand Production. It was jointly completed by XiaoweiXuan, Yingxie Yang, Yongwei Zhang, Jiaofeng Guo,Weiming Li, Beiqing Yao, Tao Hong and Yuxi Li fromthe State Resource Department Oil and Gas Centre,Xiaoli Liu from the National Development and ReformCommission’s Energy Office, Guang Yang and JianhongYang from the China Energy Research Institute’sNatural Gas Centre, Xiaobo Ju and Beijing Yao fromShell China. Other members of the topic groupparticipated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_9

233

Chongqing, and North China. This has achieveda long-distance transport pipeline connectivity tomajor consumption markets, as well as tounderground gas storage and LNG receivingstations, providing coverage to all provinces withthe exception of Tibet and preliminarily forminga national natural gas grid.

2. LNG receiving stations

As of the end of 2014, China’s operating,approved and under construction LNG receivingstations numbered 15, of which 11 were cur-rently in operation, and four had been approvedand were under construction, located in over10 provinces and regions including Guangdong,Fujian, Shanghai, Zhejiang, Huainan, Jiangsu,Liaoning, Shandong, Tianjin, and Tangshan.Currently operating LNG receiving stations havea receiving and unloading capability of39.40 million tons per year, which is equivalent

to 55 billion m3 of natural gas. In 2014, annualimported LNG resources amounted to18.79 million tons, equivalent to 26.3 billion m3

of natural gas (Figs. 9.1 and 9.2).

3. Underground storage

As of 2014, China had constructed the fol-lowing underground storage facilities: LamadianNorth, Dazhangtuo, Ban 876, Banzhong North,Ban 808, Ban 828, Jinyun, Jing 58 Storage, Wen96, Suqiao, Xiangguo Temple, Hutubi, Shuang 6and Bannan. These were primarily distributed ineight provinces—Jiangsu, Tianjin, Hebei,Liaoning, Heilongjiang, Xinjiang, Chongqingand Henan—with total designed capacity of45.2 billion m3 and designed total working gasvolume of 15.1 billion m3 and effective workinggas volume of 4.2 billion m3 (Fig. 9.3).

Legend

LNG terminal

Existing provincial pipeline

Existing long-distancepipeline networkPlanned long-distancepipeline network

Planned provincial pipeline

Station

Fig. 9.1 China’s natural gas pipeline network distribution

234 9 Analysis of China’s Natural Gas Infrastructure Development…

9.1.2 Assessment of DevelopmentLevels and ExistingProblems

1. Pipeline construction capacity shortcomings

With the completion and operation of theWest-East pipeline in 2004, China’s natural gaspipeline length reached 25,000 km. In 2010,after the West-East Pipeline 2 and the Sichuan toEast Pipeline, China’s natural gas pipeline lengthreached 56,000 km. As of the end of 2014,pipeline network length was 82,000 km, withnatural gas consumption volume having reached183 billion m3. According to the natural gasindustry development experience of the UnitedStates, when consumption volume is 130 bil-lion m3, pipeline length was 175,000 km.

Whether it is in terms of satisfying China’s nat-ural gas usage demands or when compared to thehistory of developing nations, China’s naturalgas pipeline construction is markedlyunderdeveloped.

As of the end of 2014, China’s natural gaspipeline network distribution capabilities were240 billion m3, with natural gas consumptionexceeding 128 billion m3. Based on market con-sumption volume of 1.2 fold as a peak shavingdemand, the required pipeline distribution capac-ity was 220 billion m3. From this it is clear that thecurrent pipeline network distribution capabilitiescan only meet the market demand of the nextseveral years, and if future natural gas marketdevelopment is to be supported, accelerated pro-motion of pipeline network facility constructionwill be required (Fig. 9.4).

Tianjin FLNG completed construc on by end of 2013. Phase I capacity is 2.2 million tons/year.

Tangshan LNG completed construc on by end of 2014. Phase I capacity is 3.5 million tons/year.

Qingdao LNG completed construc on by end of 2014. Phase I capacity is 3 million tons/year.

Jiangsu Rudong LNG put into opera on in 2011. Phase I capacity is 3.5 million tons/year.

Shanghai LNG completed construc on in 2009. Phase I capacity is 3 million tons/year.

Fujian Pu an LNG put into opera on in 2008. Phase I capacity is 2.6 million tons/year. Phase II is 5 million tons/year.

Guangdong Shenzhen Dapeng LNG put into opera on in Jun 2006. Phase I capacity is 3.57million tons/year. Phase II is 6.7 million tons/year

Dalian LNG completed construc on in 2011. Phase I capacity is 3 million tons/year.

Zhejiang Ningbo LNG put into opera on in 2012. Phase I capacity is 3 million tons/year.

Hainan LNG put into opera on in 2014. Phase I capacity is 2 million tons/year.

Guangdong Zhuhai LNG put into opera on in 2013. Phase I capacity is 3 million tons/year.

Fig. 9.2 LNG receiving station distribution map

9.1 Current Development of Natural Gas Infrastructure 235

Beijing 58 Gas Storage: Designed Capacity is 750 million m3 and put into opera on in 2010

Lamadian Gas Storage: Designed capacity is 2.5 billion m3, and put into opera on in 1993

Hutubi Gas Storage: Designed capacity is 4.51 billion m3 and put into opera on in July 2013.

Yulin Gas Storage Facili es: Designed capacity is 6 billion m3

Xiangguosi Gas Storage: Designed capacity is 2.28 billion m3. Gas has been injected since July 2013.

Wen 96 Gas Storage: Designed capacity is 295 million m3 and was put into opera on in 2012.

Jintan Gas Storage: Designed capacity is 210 million m3.

Owner: Hongkong China Gas

Jintan Gas Storage: Designed capacity is 210 million m3.

Owner: Sinopec

Jintan Gas Storage: Designed capacity is 241 million m3and gas injec on had started in 2011.

Double 6 Gas Storage: Designed capacity is 1.6 billion m3and major structure had been completed in Sep 2012.

Dagang Gas Storage Facili es: Designed capacity is 2.27 billion m3 and had been put into construc on during 2000-2006.

Suqiao Gas Storage: Designed phase I capacity is 400 million m3. Gas injec on has started since June 2013.

Under construction

Constructed

Fig. 9.3 Underground gas storage distribution

10,000 km

9

8

7

6

5

4

3

2

1

0

2.52.9

3.33.6

3.9

4.5

5.6

6.3

7.17.7

8.2

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Fig. 9.4 China’s natural gas pipeline construction

236 9 Analysis of China’s Natural Gas Infrastructure Development…

2. Development of LNG infrastructure

Since 2006 when the Dapeng LNG facility wascompleted, China’s LNG receiving station con-struction speed has gradually accelerated. As ofthe end of 2014, constructed and operating LNGreceiving stations numbered 11 in total, withreceiving and offloading capacity of 39.40 mil-lion tons per year, equivalent to 55 billion m3 ofnatural gas.

Because current LNG receiving stations pri-marily satisfy city demand in a radius around thereceiving station itself, and each region’s naturalgas development has had a relatively long andstaged development, LNG receiving stations arequick to enter production once they are com-pleted. Also, because of regional preferentialdevelopment of urban fuel, and limited increasesin volume, in order to resolve the lack of marketspace for LNG receiving stations as a result oftheir rapid growth, accompanying fuel gas plantshave been established to consume the exceed gasvolume. As markets continue to develop, urbangas demands are gradually growing, and pricetolerance is higher than power plants, making iteasy for a power plant to have ample gas volumein early stages of development of a receivingstation, but once the market develops to needLNG as a major gas source, the power plantscould see supply shortages.

Therefore, China’s current LNG receivingstations have played an important role inincreasing supply capacity, and their strong abil-ities in terms of peak shaving offer critical effectsin maintaining secure and stable operation of themarket. However, their rapid growth can lead touneven development of natural gas infrastructure.

3. Shortage of underground gas storage peakshaving capability

China’s natural gas peak shaving method isprimarily based on underground gas storage.Location is very particular for gas storage, withlong construction cycles and a significant quan-tity of gas required to build the reserve. Under-ground gas storage has high requirements forgeological conditions, and it is difficult to find

suitable locations. Salt cavern undergroundstorage facility construction periods are long, forexample the Jinyun underground storage locationtook over 10 years from commencement ofconstruction to operation. In addition, under-ground gas storage requires significant input forthe initial reserve, and with a designed gas vol-ume of 200 million m3, approximately 100 mil-lion m3 are required as an initial reserve.

China’s research and construction of under-ground storage began relatively late, and there is arelatively major gap as compared to developednations. According to operational experience inforeign markets, if natural gas market operationalrisk remains at relatively low levels, then thestorage dissipation ratio (referring to the ratiobetween natural gas peak shaving volume andnatural gas demand volume) should reach 15%. In2014, China’s natural gas apparent consumptionreaches 183 billion m3, with underground storagepeak shaving volume of 4.2 billion m3, makingpeak shaving volume account for less than 3% oftotal natural gas consumption, thus meaning thatpeak shaving capabilities are severely lacking.

9.2 Opportunities and Challenges

9.2.1 The Energy DevelopmentStrategy Action Plan(2014–2020)

The Energy Development Strategy Action Planproposed major development of natural gas, withnon-renewable energy consumption totals to becontrolled by 2020 to within 4.8 billion tons ofstandard coal, and natural gas to account for over10% of non-renewable energy consumption.Based on principles of developing land andmarine resources and conventional and uncon-ventional sources, acceleration of conventionalnatural gas production would be sought, resolvingdevelopment battlements as quickly as possible inunconventional natural gas, thus prompting nat-ural gas reserve production volume growth.Based on the gas supply layout involving theWest-East Pipeline, the North to South GasPipeline and the Sea to Land Pipeline, natural gas

9.1 Current Development of Natural Gas Infrastructure 237

pipeline and reserve facilities were to be con-structed more rapidly, thereby forming a nationalnatural gas trunk pipeline network connectingproduction regions and consumptions regions.There was a clear proposal to reach over120,000 km of natural gas trunk pipeline by2020.

9.2.2 Policy Catalyses RapidDevelopmentof the Natural GasIndustry

“Several Opinions Regarding Establishing anEffective Mechanism to Ensure Stable NaturalGas Supply” proposes acceleration of thedevelopment of natural gas supply, with400 billion m3 of natural gas supply capability by2020 and striving to reach 420 billion m3, sup-porting the progress of the “Coal to Gas” project.Further support is proposed for various marketentities to participate equally in gas reserve facil-ity investment, construction, and operation, withvarious regions to strengthen their gas reservepeak shaving facilities, LNG receiving stations,and storage facilities. “Guiding Opinions of theNDRCRegardingAcceleration of Progress inGasReserve Construction” proposes strengtheningthe sense of urgency regarding gas reserve facilityconstruction, speeding up in-progress construc-tion and encouraging various ownership modelsfor construction and operation of gas reserves.Gasreserve facilities are the guarantee for safe andstable natural gas operation, and the nation sup-ports various entities in participating in gasreserve facility construction, operation and man-agement, promoting the construction of suchfacilities.

9.2.3 The Atmospheric PollutionPrevention Action Plan

In order to deal with atmospheric pollution andto improve air quality, the Atmospheric Pollu-tion Prevention Action Plan was formulated,which proposes an acceleration of clean energysubstitution, raising supplies of natural gas, coalnatural gas and coalbed methane. By 2015,

newly added natural gas trunk line pipelinecapabilities will reach over 150 billion m3,offering coverage to Beijing-Tianjin-Hebei, theYangtze River Delta and the Pearl River Delta.Optimisation of natural gas usage methods willbe overseen, adding new natural gas that pref-erentially ensures residential usage or substitu-tion of coal, thus encouraging development ofnatural gas distributed energy and other highlyefficient utilisation projects while limiting thedevelopment of natural gas chemical engineeringprojects. This approach enables an orderlydevelopment of natural gas peak shaving powerstations. Infrastructure for natural gas is animportant assurance for market development,and the powerful implementation of “Coal toGas” has accelerated efforts in infrastructureconstruction.

9.2.4 Existing Pipeline NetworkCapabilities AreInsufficient

According to resource support and market demandanalysis, it is expected that by 2020, China’s nat-ural gas market demand for natural gas will be400 billion m3, and by 2030 it will be 600 bil-lion m3. If 1.1 times the demand volume can pro-vide resource supply assurance, demand volume of1.15 times shipping capabilities can assure marketdistribution. By 2020, pipeline network distribu-tion capabilities should reach 260 billion m3/year,and 690 billion m3/year in 2030. As of the end of2014, China’s resource distribution pipeline net-work capabilities were 240 billion m3, only satis-fying 52% of distribution demand expected for2020 and 35% that of 2030. There is a need toaccelerate promotion of infrastructure constructionto satisfy the needs of market demand.

9.2.5 Peak Shaving Capabilities AreSeverely Lacking

Calculating based on 15% at the storage dissi-pation ratio, in 2020 China’s natural gas marketdemand will be 400 billion m3, and peak shavingdemand will be 60 billion m3. By 2030, peakshaving demand will be 90 billion m3. Currently,

238 9 Analysis of China’s Natural Gas Infrastructure Development…

underground storage peak shaving capabilitiesare only at 4.2 billion m3, and LNG receivingstations have peak shaving capability of 2.6 bil-lion m3, calculated based on 0.2 times that steadydistribution of gas at market peak shaving. Fromthis it is clear that current peak shaving facilitycapabilities are far from adequate to meet futurenatural gas market peak shaving demand.

9.2.6 Increasing Pressure for SafeOperations

As natural gas markets continue to grow, infras-tructure construction is likewise building, andthere is increasing pressure for safe and steadyoperations. Currently, China’s trunk pipelinescontinue to use a point-to-point resource supply,with different operators lacking interconnectivitybetween their pipelines. Provincial trunk lineinvestment entities are more diversified, andpipeline supplies do not intersect. At peak gasperiods, resource allocation is impossible, andwhen a pipeline network encounters malfunctionthere is no effective energy response approach. Infuture, China’s natural gas trunk pipelines shouldestablish interconnectivity and provincial trunklines should be freely allocable.

9.3 Natural Gas InfrastructureDevelopment Strategy

China’s overall natural gas business and policyguidance has formulated natural gas develop-ment objectives, proposing a natural gas infras-tructure development strategy to guide the rapiddevelopment of natural gas infrastructure.

9.3.1 Guiding Considerations

Taking the safe and stable operation of nationalpipeline networks as a target function, infrastruc-ture construction should be planned to achievediversified supply. The aim should be to constructflexible allocation infrastructure systems,strengthening gas pipeline hub construction,speeding up peak shaving facility construction,

establishing interconnectivity and securing gassupply systems that can be flexibly allocated.Modern natural gas industry systems need to beconstructed, with stable supply, efficient operationand co-ordinated upstream, midstream and down-stream development, and a national unified infras-tructure development strategy needs to beestablished.

9.3.2 Development Objectives

Bearing in mind the guiding considerations fornatural gas infrastructure development, and inthe context of China’s natural gas industrydevelopment, the natural gas infrastructuredevelopment goals for China by 2030 are asfollows:

• Achieve interconnected gas supply systemsfor various operators at top-tier natural gaspipelines. Pipeline network length will reach150,000 km by 2020, and gas deliverycapability will exceed 460 billion m3.2030 will see 250,000 km of pipeline net-work and gas delivery capability of over690 billion m3.

• Achieve a four-pronged layout that includesWest-East Pipeline, North to South Pipeline,Sea to Land Pipeline, and local supply. Opti-mise the natural gas supply and allocationstations in Ningxia Zhongwei, Hubei, HebeiYongqing, Shanghai and Guangdong Wuqu.Construct six major underground reservegroups in the central plains region, northernChina, the north-east, in Changqing, in thenorth-west and in the south-west. Aim toachieve 62 billion m3 of peak shaving capa-bility by 2020, with an effective undergroundreserve working volume of 44 billion m3.Achieve 90 billion m3 of peak shaving capa-bility by 2030, and an effective undergroundreserve working volume of 77 billion m3.

• Establish four major LNG import channelsbased on north-west China-Asia imports,south-west China-Myanmar imports, northernChina-Russia imports and eastern imports.From 2020 to 2030, achieve 85 billion m3 ofdistribution capability on the China-Asia

9.2 Opportunities and Challenges 239

Lines A, B, C and D, with 12 billion m3 ofcapability on the China-Myanmar line, 38–68 billion m3 on the China-Russia line, and100 million tons of receiving capabilitythrough LNG imports.

9.3.3 Development Strategy

In order to guarantee that China’s natural gasinfrastructure is designed for safe and stableoperation, interconnected systems between thenation’s various entities involved in natural gasinfrastructure should be firmly established. Tostrengthen infrastructure construction capabili-ties, there should be overall planning for facilityconstruction, building up diversity of investmentand implementation. Finally, in order to improveinfrastructure usage efficiency, fair third-partyaccess operation and management platformsshould be created.

As natural gas market demand further grows,China’s natural gas infrastructure must be furtheroptimised, and by 2020 important pipeline con-structionmust be completed, including the China-Russia natural gas pipeline, the West-East Pipe-line 3,West-East Pipeline 4,West-East Pipeline 5,Shaanxi-Beijing, Xinjiang coal methane pipeline,Erdos coal methane, coastal arteries and theSichuan-Chongqing-Hubei natural gas pipeline.There is also a need to bring national pipelines to150,000 km, with long-distance distributionpipelines to reach 44,000 km. By 2030, based onmarket demand, efforts will intensify in largepipeline network deployments, with the newlyaddedWest-East Pipeline 5,West-East Pipeline 6,the China-Russia east-west pipeline and con-struction of at least 250,000 km of nationalpipelines with long-distance distribution of up to60,000 km and gas distribution capabilities toexceed 690 billion m3.

The ultimate goal in achieving interconnect-edness between different operating entityinfrastructure is to achieve secure and stableoperations, reasonable resource allocation andconnection between resources and markets andbetween gas reserves and markets. The impli-cations of interconnectivity between the infras-tructure of various operating entities are:(1) national long-distance trunk pipelines are

interconnected through hub stations and con-nection lines; (2) provincial trunk pipelines arefreely allocated through split hubs; (3) under-ground gas reserves and LNG receiving stationsare connected to national long-distance trunkpipelines; and (4) neighbouring provincial andmunicipal markets form a regional network.

1. National long-distance trunk pipelineinterconnectivity

China’s long-distance trunk pipelines areprimarily constructed by CNPC and Sinopec,with CNOOC primarily constructing marine gasshore connection and LNG receiving stationexternal distribution pipelines. Long-distancetrunk pipeline interconnectivity is not only toachieve connection with internal pipelines of oilcompanies, but also to achieve connection withpipelines between oil companies. Nationallong-distance trunk pipeline interconnectivityrelies on pipelines connected by central hubs andthrough connection lines.

Forming central hubs: Based on China’scurrent natural gas infrastructure developmentand future infrastructure development, centralhubs are to form in Ningxia Zhongwei, HebeiYongqing, Hubei, Shanghai and Guangdong. Aspart of this:

• Ningxia Zhongwei is a point of coalescencebetween western resources and eastern distri-bution, sending western gas to eastern distri-bution systems, and connecting to theXinjiangcoal methane pipelines and Shaanxi Beijingline systems, the Zhongwei-Jingbian pipeline,the Zhonggui Line and other pipelines. Thisachieves connection between importedChina-Asia gas, Xinjiang gas fields, Changq-ing gas fields and Xinjiang coal methane.

• Hebei Yongqing is the hub for northernChina, and connects the Shaanxi-Beijing line,the China-Russia natural gas pipeline, thenorth China gas reserve groups and theTianjin-Hebei resource pipeline. In northernChina it adjusts natural gas supply, optimis-ing natural gas resource allocation andrelieving demand for gas at peak periods.

• Hubei has many national long-distance trunkpipeline channels, and is the point of

240 9 Analysis of China’s Natural Gas Infrastructure Development…

coalescence for the central and southernregion hubs, forming a connection withXinjiang conventional gas, Xinjiang coalmethane, imports from the China-Asia line,imports from the China-Russia line,Sichuan-Chongqing conventional gas andSichuan-Chongqing shale natural gas.

• Shanghai is China’s natural gas market cen-tre, and from the perspective of supplystructure, Shanghai is the central hub forWest-East Line 1 and 2, the Sichuan to Eastpipeline and other important natural gas lineswhile also receivingEast Sea gas and importinga large volume of LNG. From its characteris-tics, Shanghai is a natural gas trading centre butalso a national natural gas pricing baselinelocation, and in future will become an impor-tant natural gas hub for China.

• Asan important resourcehub,Guangdong is settobecomeapoint of integration formultiplegassources. From the perspective of supply struc-ture, there is pipeline gas,marine gas and LNG,with pipeline supply including the West-EastLine2, theXin’aozheline, theWest-EastLine3,marine gas and multiple LNG receiving sta-tions.Fromtheperspectiveofproperties,supplyresources includeconventionalnaturalgas,coalmethane and LNG.With a variety of resourcescoming together, it is a complex province withnational gas sources.

Construction of connection lines: Connec-tion lines are important complementary resourcebridges between national long-distance trunkpipelines, with constructed examples being theCheng Zhong Gui Line, the Huai Wu Line andthe Ji Ning Line. Of these, the Zhong Gui con-nects the West-East Pipeline, Changqing gasfields, Sichuan-Chongqing gas region and theChina-Myanmar pipeline resources. The HuaiWu line connects the West 1 Line, West 2 Lineand the Zhong Wu Line. The Ji Ning Lineconnects the Shaanxi-Beijing Line, the West 1Line and the Rudong LNG resources.

China’s coastal LNG receiving stations pro-vide supply essentially point-to-point, withsupply regions and peak shaving capabilitiesbeing limited. Moving forward, the focuses ofconstruction for connection lines will be along

coastal arteries, with pipelines to connectreceiving stations from Liaoning Dalian LNG toGuangxi’s North Sea LNG receiving stations,with intermediary LNG receiving stations, mar-ine gas to shore pipelines and the transitednational trunk pipelines (Fig. 9.5).

2. Provincial trunk line free allocation

China’s various provincial natural gasinfrastructure entities are diverse, with nationalenterprises and private corporations competingwith one another, and without interconnectedbusiness communications, which causes over-lapping construction of infrastructure, low usageefficiency and an inability to optimally allocateresources. Provincial natural gas infrastructuremust form a unified management and operationsplatform, carrying out unified planning andconstruction for provincial infrastructure whileunifying operations and management, resourceco-ordination and distribution. Provincial trunkline interconnectivity is required to achieveflexible allocation of resources and prefecture-level dual gas source supply deployment.

Current provinces in China that have only oneprovincial natural gas company include: Beijing,Tianjin, Hebei, Jiangsu, Shanghai, Zhejiang,Guangdong, Shaanxi, Anhui, Inner Mongolia,Hubei and Chongqing. Provinces with two ormore provincial natural gas companies include:Shanxi, Jiangxi and Hunan. Each provincial nat-ural gas company’s business model can be cate-gorised as: unified purchase of resources, agentdistribution, mixed operation, monopolistic con-struction of infrastructure and free construction.In order to realise the goals of provincial pipelineunification planning, provincial trunk line freeallocation and provincial market balanced devel-opment, each province should actively establishprovincial natural gas companies, with unifiedoperation and management from the provincialnatural gas companies, whose business modelsshould be divided into two categories:

• The first category includes provincial trunkline unified planning, staged implementationand unified purchase of resources. In order toavoid overlapping infrastructure construction

9.3 Natural Gas Infrastructure Development Strategy 241

Coastal transportation arteryShanghaiHubHubei

Hub

YongqingHub

GuagdongiHub

ZhongweiHub

LegendLNG Terminal

( ) Station

Existing provincial pipeline

Existing long-distance pipeline nePlanned long-distance pipeline n

Planned provincial pipeline

Fig. 9.5 Interconnectivity between various entity natural gas infrastructures across the country

and the resulting inefficiencies, there shouldbe overall planning for provincial natural gasinfrastructure. Based on the degree of marketdevelopment, staged implementation shouldtake place, with provincial trunk lines andpeak shaving and allocation facilities con-structed and operated by provincial naturalgas companies. Resource procurement shouldbe procured in unison by the provincial nat-ural gas companies, with the natural gasresources that provincial users require nego-tiated with the provincial natural gas com-pany and sold at a standard price that is notdifferentiated by distance.

• When infrastructure construction stages are inline with the above, but provincial companies donot carry out resource procurement and sales,the downstream users carry out negotiationsdirectly with upstream gas suppliers, and gassuppliers then distribute the natural gas throughthe provincial natural gas companies. Theprovincial natural gas companies collect amanagement and distribution fee, and down-stream users pay resource fees to the upstreamgas supplier and a distribution fee to theprovincial natural gas company. To safeguardthe interests of users relatively distant fromlong-distance pipelines, provincial natural gascompanies provide a uniform price to userswithin the province.

3. Underground gas reserves and LNG receiv-ing station peak shaving co-ordination

Currently, China has two major large peakshaving facilities. One is underground gas reserves,and the other is LNG receiving stations. Of these,the underground gas reserves are distributed acrossthe mainland and are distributed via pipeline. Forthese, the peak shaving principle is to adjustbetween long-distant and nearby pipelines. LNGreceiving stations are distributed along the coast-line, with their peak shaving principle beingadjustment of nearby supplies and liquid adjust-ments. After 2020, underground reserve peakshaving will be the primary approach, with auxil-iary peak shaving from LNG receiving stations.

Two types of peak shaving facilities: Cur-rently, China’s natural gas peak shaving facilitycapabilities are limited and are far from being ableto satisfy future development demands, given thatpeak shaving capabilities should reach 62 bil-lion m3 by 2020 and effective underground gasreserve volume will need to be 44 billion m3. By2030, peak shaving capabilities must reach90 billion m3, with effective underground reservevolume of 77 billion m3.

Based on China’s current natural gas cir-cumstances, in future the country’s newly builtunderground gas reserves will primarily relyupon exhausted oil and gas deposits. By 2030 a

242 9 Analysis of China’s Natural Gas Infrastructure Development…

group of six reserves will be formed in the cen-tral plains region, northern China, the north-east,in Changqing, in the north-west and in thesouth-west. As part of this, the central plainsreserve group connects the Yu Ji Line, Xin’aozheYu Lu Sub-Trunk Line and the West 2 LineTai’an Sub-Trunk Line. The northern Chinagroup connects the Shaanxi-Beijing Line and theChina-Russia import pipelines. The north-eastgroup connects the China-Russia import pipe-lines. The Changqing group connects theShaanxi-Beijing Line and the West-East Pipe-line. The north-west group connects to theWest-East Pipeline. The south-west group con-nects the Zhong Gui Line and shale natural gasexternal distribution pipelines.

LNG receiving stations are connected throughcoastal arteries, and exchange resources withcoastal region natural gas markets during peakshaving. Using tanker trucks for external distri-bution, peak shaving is provided for urban fueland enterprise LNG reserve gas.

Regional peak shaving method distributionand options: Reserve facilities for natural gas arean important measure used to ensure the safe andstable supply of natural gas, and form an integralcomponent part of natural gas delivery systems.Currently, the construction of gas reserve capa-bility is lagging seriously behind, and accordingto national natural gas pipeline network layouts,the construction of such facilities should beaccelerated, aiming to ensure that natural gaspeak shaving emergency response requirementsare met. In long-distance pipelines, details mustbe determined according to specific local needs,ensuring reasonable deployments, clear focalpoints and staged implementation of accessoryconstruction of peak shaving facilities.

There was relatively early construction of gasreserve facilities in provinces and cities, includ-ing Beijing, Tianjin, Hebei, Shanxi, Liaoning,Jilin, Heilongjiang and Shandong, and theseregions have good foundations. Moving forward,the focus will be on gradual optimisation ofexisting gas reserves and newly built under-ground reserves, complemented by small andmedium LNG facilities and LNG receiving sta-tion storage. In conjunction with existing gas

storage facilities, there will be optimised con-struction within exhausted oil deposits in Liaohe,Dagang, North China, Daqing and Shengli,including Liaohe Shuang 6, Qi 13, Shengliyong21, Dagangban South, North China Su 1, Gong20, Su 4, Su 49, Guxinzhuang, Wen 23, Saqingand Jilin oil fields.

Gas reserve facility conditions are relativelypoor in Shanghai, Jiangsu and Zhejiang. Priorityshould be given to constructing LNG reservoirs,with underground storage and small and mediumreserves as auxiliary peak shaving systems. Pri-mary projects include the Jiangsu salt cavern gasreserve and the Jiangsu oil field exhausted oildeposit gas reserve. Prior to 2015, the focus hadbeen on LNG gas reserves, relying on Jiangsuand Zhejiang existing LNG receiving stationexpansions to grow LNG reserves, therebyforming an LNG gas reserve system comprisingJiangsu and Zhejiang.

Fujian, Guangdong, Guangxi, Hainan andYunnan have focused on LNG receiving stationreserves, with small and medium storage andunderground gas reserves, as well as small andmedium liquefaction facilities providing auxiliarysupport. This region is working to construct anLNG reserve system prior to 2015 that is based onthe LNG receiving station expansions in Fujian,Guangdong and Hainan, so as to satisfy regionalpeak shaving demand. Prior to 2030, once a rea-sonable network has been established, new LNGreceiving stations will be constructed to increasegas reserve capabilities, while at the same timebuilding a certain amount of underground gasreserve working gas volume, thereby establishingmultiple interrelated peak shaving measures thatsatisfy local gas reserve system needs and theneeds of the surrounding region.

Anhui, Hubei and Hunan have a certainamount of advantageous geography, and canmainly construct underground gas reserves, withauxiliary peak shaving systems of LNG smalland medium reserves and small and mediumliquefaction facilities. Major projects includeHubei Yingcheng, Yunying and Huangchang saltcavern gas reserves.

Shanxi, Henan, and Sichuan must useexhausted oil and gas deposits to build

9.3 Natural Gas Infrastructure Development Strategy 243

underground gas reserves while at the same timeusing upstream gas fields to resolve a portion ofpeak shaving problems. This is supplemented bypeak shaving of users that can have supplieshalted and small and medium liquefaction facilitypeak shaving. Major projects includeZhongyuanwen 23, Zhongyuanwen 96 andSouth-West Xiangguosi, among other exhaustedoil and gas deposit gas reserves.

Shaanxi, Gansu, Qinghai, Ningxia, and Xin-jiang are focused primarily on underground gasreserves for their gas reserve systems, buildinggas reserves from exhausted oil and gas deposits,including in Xinjiang Hutubi and Yulin.

4. Regional networks between provinces

Due to administrative zoning and approvalprocedures, regional pipeline networks are pri-marily concentrated within provinces (with theexception of long-distance pipelines and con-nection lines that run between provinces),resulting in relatively large differences in naturalgas consumption between neighbouring provin-cial economies. In future, government guidanceand support for construction of trunk line con-nections between provinces will allow resourcesupplementation, and thus boost the developmentof regional natural gas markets and optimise theregional pipeline network systems.

9.4 Standardising InfrastructurePlanning and DiversifyingInvestment

9.4.1 Infrastructure ConstructionPlanning and ProjectProgress Oversight

Infrastructure development involves foreignimport pipelines, LNG receiving stations,national trunk long-distance pipelines, provincialpipelines and underground gas reserves, amongother facilities. As part of this, pipeline networkconstruction is critical to developing the naturalgas market, but currently China’s natural gasinfrastructure is primarily constructed and

operated by three large oil companies that havenot established effective interconnectivity. Asinfrastructure continues to be optimised andinterconnection of infrastructure deploymentsbecomes critical to ensuring the secure and stableoperation of the national natural gas network,effective infrastructure interconnection willbecome increasingly important, with the con-struction of Xin’aozhe, the West 4 Line, West 5Line, China-Russia East-West Line, coastalreceiving stations and underground gas reserves.Only with effective co-ordination in planningstages to form a complete industry chain caneffective infrastructure connectivity be realised.Therefore, government intervention is required tocreate entities to oversee infrastructure con-struction and to strengthen oversight and controlsof such development.

The major reason for a low degree of infras-tructure planning is the lack of review mecha-nisms for planning construction projects. There isplanning for projects, but no subsequentfollow-up regarding progress in project imple-mentation. A review needs to be carried out ofenterprises involved in the planning of infras-tructure projects at the national level, reviewingproject implementation progress and timelinegoal completion, taking measures to reward andpenalise as required. A review should also becarried out for departments involved in provin-cial infrastructure, with consistent review criteria;provincial departments should actively imple-ment relevant work involving the planning ofprovincial projects, working hard to co-operateand creating review systems for units under theirsupervision to promote active construction ofinfrastructure and optimise the outcomes of thepractical work.

9.4.2 Promote Construction ofEntities and InvestmentDiversification

The country encourages and supports variousforms of capital participation and investmentstructure in the central planning of natural gas

244 9 Analysis of China’s Natural Gas Infrastructure Development…

infrastructure. The three major oil companiesshould release investment and construction rightsto national trunk pipelines, introducing privatecapital. Some of the provincial natural gascompany monopolies on provincial infrastructureconstruction need to be broken. The introductionof private capital to infrastructure constructioncan increase participation in construction andimprove the capacity for it.

The construction of CNPC West 3 Linebrought together equity from the national socialinsurance fund council, an urban infrastructureindustry investment fund and Baosteel Group,diverging from the previous model of investmentcontribution that was monopolised by CNPC’sown investments and for the first time allowingprivate capital to be included in natural gaslong-distance pipeline construction. The plannedWest 4 Line, West 5 Line and Xin’aozhe, amongother national natural gas trunk pipelines, shouldcarry out joint investment construction with pri-vate capital, based on the West 3 Line model.The uniformity seen in national long-distancepipeline construction entities has not yet beendisrupted completely, though, and entities out-side the three major oil companies should beintroduced to diversify investment in the nation’slong-distance pipelines.

Provinces with provincial natural gas compa-nies should co-operate actively in investmentswith qualified private capital, accelerating theconstruction of provincial infrastructure. Pro-vince sub-trunk pipeline construction rightsshould be fully opened, and permission should begranted for qualified enterprises to construct andoperate infrastructure within the ambit ofnational and local government planning.

9.5 Establishing Fair Third-PartyAccess to Infrastructure

9.5.1 Create the Conditionsfor Third-Party Access

As at the end of 2014, China had put into oper-ation 16 natural gas national trunk pipelines,

over 80 national sub-trunk pipelines, 11 LNGreceiving stations and 19 underground gasreserves. There are no statistics availableregarding the operating conditions of mostinfrastructure. By using open and fair operatingsystems, it would become possible to learn aboutinfrastructure operating conditions, and excesscapabilities could be put to use. When natural gaspipeline network facility operators have excesspipeline network facility capabilities, they canfairly open their pipeline network facilities tothird parties, providing delivery, storage, gasifi-cation, liquefaction and compression services. Inthis mutually beneficial scenario, good use of canbe made of facility capabilities while ensuringthat existing users continue to have access toservices, with a preferential order based onsigned contracts with newly added users so as torealise fair, non-discriminatory open usage ofnatural gas pipeline network facilities.

Considering the fact that third-party accessconditions are not yet mature, barriers betweencompanies are difficult to eliminate, though somesuggestions to catalyse third-party access are asfollows:

• Construct third-party review institutionsto fairly and equitably verify excessinfrastructure capabilities: Considering thelack of transparency regarding infrastructureexcess capabilities and the difficultiesinvolved in downstream user verification,which result from asymmetry in information,third-party independent verification institu-tions should be established in order to fairlyand equitably verify oil and gas pipelineinfrastructure, storage, gasification, liquefac-tion and compression excess capability.

• Pipeline network independence: Currently,infrastructure enterprises provide transmis-sion, storage, gasification, liquefaction andcompression services while at the same timehaving businesses such as exploration andsales. This has resulted in local or partialmonopolies within the natural gas industry atits various stages of development. Partitionproduction shipping and sales business. At

9.4 Standardising Infrastructure Planning and Diversifying Investment 245

the sales stage, break the monopolies toachieve highly efficient infrastructure usage.At the same time, due to the uniqueness ofnatural gas shipping and the heavy reliance onpipeline networks, separate national pipelinenetworks into several independent pipelinenetworks, with competition and co-operationbetween and among them to achieve highlyefficient infrastructure utilisation.

• Enterprise establishment and implementa-tion measures: On June 24, 2014, CNPCreviewed and passed in principle the CNPCNatural Gas Group Oil and Gas PipelineNetwork Infrastructure Open Access Imple-mentation Measures (Pilot), stipulating thatoil and gas pipeline network facilities befairly opened, as well as assigning manage-ment responsibilities to the relevant depart-ments. Each enterprise should establish andimplement measures based on its owninfrastructure operating capabilities, operatingcosts and operating scope, including timeused, scope and price.

• Infrastructure interconnectivity, fee ratesand liberalised market operation: Throughconnectivity between pipelines and otherinfrastructure, break through natural gastransmission stage monopolies. Pipelinetransmission fees should be liberalised intheir operation, with the market to determinefinal resource allocation.

9.5.2 Establish Openand Transparent Oiland Gas Managementand Operation ReleasePlatforms

According to the Natural Gas DevelopmentTwelfth Five-Year Plan, natural gas infrastruc-ture interconnectivity and services for third-partyaccess should be implemented. At the end of theTwelfth Five-Year Plan, China will achievepartial connectivity of its pipelines, and have theconditions in place to achieve third-party access.

The utilisation of excess infrastructure capa-bility cannot be entirely resolved simply byestablishing operating entities, and each facility’soperations can only be fully understood by theoperating entity, with third parties unable toobtain information about them. Therefore, openand transparent oil and gas management andoperation release platforms must be established, tocover all existing excess capacity in the infras-tructure, with operators allowing third-partyaccess to terms and fees, and operator-relatedcontact information. Third parties should carry outspecific negotiations with operators based on theirneeds. Because the status of infrastructure opera-tors can be variable, they should provide the latestdata relating to their infrastructure operations tothe platforms, and the platform can then providetimely updates that are publicly available.

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246 9 Analysis of China’s Natural Gas Infrastructure Development…

10Analysis of China’s Peak Shavingand Natural Gas Storage Systems

Natural gas security is one of the core componentsof energy security, and is an important componentpart of national security. Experience in manynations has shown that the establishment of arobust natural gas storage and peak shaving sys-tem is an effectivemeans to address short-term andmid-term natural gas supply halts and to ensurenatural gas industry stable operation as well asstability in the economy and society itself. AsChina’s natural gas demand continues to grow,scaling up this infrastructure in various ways andreasonable deployments of effectiveemergency-response natural gas reserve systems isthe direction and long-term goal of China.

10.1 Importance of Natural GasReserves for Peak Shaving

As China’s economy continues to grow quicklyand living standards are rising, as a clean,high-quality and efficient energy, natural gas’sshare of China’s energy consumption is gradually

increasing. Since the official completion in 2004of the West-East Pipeline project, natural gasconsumption has rapidly expanded, and in 2014 itreached 183 billion m3, more than a double thefigure in 2004. At the same time, China’s naturalgas transmission pipeline network is also con-tinually growing and being optimised, with nat-ural gas now among main energies used in urbanoperations and development and involved in dailylives and urban economic functions. If natural gassupply encounters a shortage or halts, this sig-nificantly affects lives and the security of society.

In recent years, China has seen some majorshortfalls in natural gas supply in some regions,with winter shortages even leading to a lack ofsupply for urban residential heating or for taxiswanting to refuel. As a result, ensuring naturalgas supply security is of utmost political andeconomic significance for gas supply enterprisesand the cities that use gas. Establishing a naturalgas peak shaving reserve emergency responsesystem that corresponds to the scale of citydemand is an important undertaking for the sakeof China’s natural gas supply security.

Systems of natural gas involve upstream pro-duction, midstream transmission and downstreamutilisation stages, and if any stage exhibits prob-lems, this will affect the stable operation of theentire system. Because downstream users includeresidents, public services, commerce, industry,power plants, vehicles and air conditioning unitusers, various types of user use gas in their ownpatterns, resulting in fluctuations in gas usage thatcan result in peaks and troughs in demand.Moreover, the room for production adjustments

* This chapter was overseen by Zhonghong Wang fromthe Development Research Center of the State Counciland Shangyou Nie from Shell International Explorationand Production. It was jointly completed by XiaoweiXuan, Yingxie Yang, Yongwei Zhang, Jiaofeng Guo,Weiming Li, Beiqing Yao, Tao Hong and Yuxi Li fromthe State Resource Department Oil and Gas Centre,Xiaoli Liu from the National Development and ReformCommission’s Energy Office, Guang Yang and JianhongYang from the China Energy Research Institute’sNatural Gas Centre, Xiaobo Ju and Beijing Yao fromShell China. Other members of the topic groupparticipated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_10

247

in upstream production is limited, and normally20% additional gas volume can be provided atmost, making it difficult to satisfy actual peakdemand. Therefore, it is necessary to establishpeak shaving emergency response facilities tosatisfy the peak demand and to deal with suddengas supply halts.

China’s large-scale use of natural gas has onlyjust begun, and natural gas reserve constructionis still in its early stages. From the perspective ofcurrent development, as China’s gas usagegrows, the requirements for secure supply willgrow. Therefore, it is necessary to integrateChina’s natural gas market development layoutand reserve facility construction, and also tolearn from overseas experience in constructingnatural gas reserve systems.

10.2 Issues and Challenges

10.2.1 Rapid Increase in Natural GasConsumption and PeakPeriod Demand

1. China’s natural gas demand continuesto grow

China’s natural gas consumption growth hasbeen rapid. As China’s natural gas resourceexploration and development continues to seebreakthroughs, proved reserves and productionvolumes are rising, especially in theShaanxi-Beijing line, West-East Pipeline andother project locations that are currently involvedin commercial operation. China’s natural gasindustry has entered a stage of rapid growth, andnatural gas consumption markets are expandingquickly, with natural gas accounting for anever-rising proportion of energy consumptionstructure. In 2014, China’s natural gas con-sumption volume reached 183 billion m3, mark-ing a six-fold increase over 2000, and annualaverage growth of 15%. The proportion of nat-ural gas among non-renewable energy con-sumption structure has risen from 2.3 to 6%.

For a significant period into the future, asChina’s emerging industrialisation and

urbanisation accelerates, there will be increasingpressure to improve regional environmentalquality and to deal with climate change, activelyadjusting energy structures to promote energyconservation and emissions reductions. This isespecially true for atmospheric pollution pre-vention and other environmental protectionpolicies that will be the major policy direction ofChina in the future, powerfully developing nat-ural gas and other low-carbon energies. This isalready a strategic task in the sustainable devel-opment of energy in China.

China’s natural gas demand will continue togrow rapidly, leading to it becoming one of themajor consuming nations of natural gas in theworld. The research team believes that in abaseline scenario, natural gas demand in 2015 islikely to approach 200 billion m3, surpass300 billion m3 in 2020, exceed 450 billion m3 in2030, and exceed 600 billion m3 in 2050. In apolicy environment of implementation of moreactive and effective environmental and energytransitioning (such as carrying out carbon tradingor collecting a carbon tax), China’s demand in2020 could reach 344.7 billion m3, essentiallyreaching the goal of 350 billion m3 noted in the12th Five-Year Plan. By 2030, consumptionvolume would be likely to reach 580 billion m3,and approach 800 billion m3 by 2050.

2. Urban fuel grows fast, as does peakperiod demand

Since 2000, China’s natural gas consumptionstructure has tended toward diversification, withurban fuel becoming the fastest-growing sectorof gas usage. From 2000 to 2013, China’s urbanfuel natural gas rose from 4.3 to 73.2 billion m3,with the proportion of total consumption volumerising from 17.6 to 40%. Moving forward, withemerging urbanisation and industrialisationrequiring more energy support, and at the sametime as ecological cultural construction isstrengthening efforts in lifestyle improvementsand environmental protection, urban gas in Chinais set to be pushed toward continued rapidgrowth in four respects in particular:

248 10 Analysis of China’s Peak Shaving and Natural Gas Storage Systems

• newly added natural gas users, acceleratingthe use of LPG and artificial coalbed methaneas a replacement in residential gas usage;

• changes made by multiple provinces in rela-tion to coal boiler standards for PM2.5, withincreased gas use for heating;

• gas used in transportation and other accom-panying infrastructure, which will see rapidrises; and

• distributed energy projects that will succes-sively enter production.

The rapid growth in urban fuel has greatlyincreased natural gas peak demand. In recent years,in order to improve atmospheric environmentquality, northern Chinese regions such as Beijingand Tianjin have developed large quantities ofnatural gas heating users, including large gaspower plants, gas boilers and residentialwall-installed heaters. Winter season natural gasusage has skyrocketed. Taking Beijing as anexample, its heating season (November–Marcheach year) accounts for approximately 76% ofannual gas usage, with winter and summer peakand trough having a ratio of 12.5:1. Currently,eastern Chinese region winter seasons have yet toimplement residential heading, but they also exhi-bit seasonal characteristics, as peak values occur inthe hot summer period and there is a peak to troughratio of 1.6:1. CNPC’s West-East Pipeline

company has calculated winter peak demand basedon northern and eastern Chinese region natural gasusage load curves, and the two regions’ seasonalpeak demands are respectively 31 and 4% ofannual gas usage volume (Table 10.1).

In the future, as various regions increaseusage of gas heating, seasonal peaks and troughswill continue to increase. According to forecastdata by CNPC in 2013 for China’s variousregional natural gas demands, as well as com-parative operation of peak shavings in northernand eastern regions in China, it is possible tocalculate China’s natural gas peak demandpotential. By 2020, natural gas seasonal pealdemand will reach 45 billion m3, rising to76 billion m3 in 2030. In addition, as gas heatingand electricity proportions increase, daily peaksand hourly peaks, among a wide range of prob-lems, will also appear, and must be comprehen-sively resolved.

10.2.2 Gas Reserve Peak ShavingCapabilities Insufficient

1. Great advances in gas reserve facilityconstruction

Reserve natural gas peak shaving facilities arean important component part of natural gas

Table 10.1 China’s natural gas peak demand calculations (100 million m3)

w 2020 2030

Natural gasdemand volume

Peakfactor (%)

Peak gasvolume

Natural gasdemand volume

Peakfactor (%)

Peak gasvolume

Circum-Bohai 630 31 195 1102 31 342

North-east 280 31 87 522 31 162

North-west 245 31 76 348 31 108

Yangtze RiverDelta

595 4 24 928 4 37

South-east coast 595 4 24 870 4 35

South China 385 4 15 870 4 35

South-west 455 4 18 638 4 26

Mid-west 315 4 13 522 4 21

Total 3500 452 5800 764

Data source 2020 data from CNPC Planning Institute, 2030 data from study group arrangements

10.2 Issues and Challenges 249

transmission system projects. They not onlyensure stable pipeline supply but are also integralto strategic reserves and commercial cycles. Theyare important measures to ensuring the secureand stable supply of natural gas.

China’s large-scale gas storage constructionbegan in 1999 with the commencement of theShaanxi-Beijing Pipeline, in order to resolveimbalances in Beijing’s seasonal gas usage andto relieve peak demand, with subsequent largepower gas reserve groups and northern China gasreserve groups. Later, along with the construc-tion of the West-East Pipeline, construction ofthe Jinyun and Liuzhuang storage facilities alsobegan, so that West-East Pipeline market userscould use gas as expected. From 2013, China’sgas reserve construction saw major progress, andexisting gas reserve working gas volume capa-bility is 17.3 billion m3, approaching 10% ofnatural gas consumption volume. As far as gasreserve capabilities are concerned, there is still agap to the global average of 11.3%.

According to the national Natural GasDevelopment 12th Five-Year Plan, in the next5–10 years China will continue to heavily pro-mote underground gas reserve construction:“accompanying construction of gas reserve peakshaving facilities are required along long-distance pipelines according to local require-ments, with reasonable deployments and clearpoints of focus, implementing staged construc-tion”. It is likely that by about 2020, China’s gasreserve total working gas capabilities will exceed30 billion m3 (Table 10.2).

LNG commercial reserve capabilities havebegun to take shape. As a large quantity of LNGreceiving capability comes online, LNG com-mercial storage in the receiving station, transferstate commercial storage and urban peak shavingLNG storage is receiving increasing attention.Currently, China has yet to have a guidingstrategy for LNG reserves, and the country’svarious large first-stage LNG receiving stationdesigns likewise lack commercial storage beyondensuring basic load supply. However, they canabsorb spot LNG at low prices and release athigh prices, while at the same time ensuring thatsupply security in commercial reserves remains a

major point of further development. This isespecially true for small and medium-sized LNGreceiving and transfer centres, which have rela-tively small annual transfer capabilities, andapproval procedures that are relatively simple. Ifprojects and existing large LNG receiving sta-tions could interconnect, this would not involveLNG import approvals, and would be somewhatsimpler, and thus it is currently a focus in theindustry. Prior to 2013, China only had twoprojects in operation, Shanghai Wuhaogou andDongguan Jiufeng, with annual receiving capa-bilities of 1.5 million tons in total. China nowhas more than 10 in-construction, reported orplanned LNG receiving and transfer centre pro-jects, and there has been active enthusiasm forinvestment and construction from local energycompanies and private corporations.

In addition to LNG receiving station accom-panying construction of reserve facilities, urbanfuel is also gradually becoming a major force inLNG reserves. China currently has a certainamount of LNG volume in reserve stations inBeijing, Shanghai, Changsha, Wuhan, Xi’an andChengdu, ranging from several hundred to over100,000 m3.

China’s commercial reserves are in theirinfancy, but strategic gas reserves have justbegun to build, with only Xinjiang Hutubi rep-resenting a functioning large-scale undergroundstrategic gas reserve.

2. Gas usage load region peak shavingcapabilities are insufficient

Even though there has been some progress ingas reserve facility construction, nonethelesscurrent peak capabilities are still markedlyinsufficient. Because large-capacity reserves suchas Hutubi, Xiangguosi, Suqiao and Jinyun haveonly been built in the past two years and are stillin the gas injection stage, peak shaving capabili-ties are as yet insufficient, and designed workinggas volume is hard-pressed to come into full play.

Currently, winter peak shaving primarily reliesupon gas reserves, LNG, gas fields and pressurereduction market gas volumes among other jointpeak shaving approaches. Gas field adjustments

250 10 Analysis of China’s Peak Shaving and Natural Gas Storage Systems

Table

10.2

China’s

constructedun

dergroun

dgasreserves

Con

structed

sites

Nam

eof

reserve

Capacity

/108

m3

Working

gas

volume/10

8m

3Working

pressure/M

paNum

berof

wells

Daily

gasinjection

capabilities/10

4m

3Daily

gascollection

capabilities/10

4m

3

DagangReserve

Group

Dazhang

tuo

17.81

613

.0–30

.519

320

1,00

0

Ban

876

4.66

2.17

13.0–26

.57

100

300

Zho

ngzhon

gNorth

24.48

10.97

13.0–30

.515

300

900

Banzhon

gSo

uth

9.71

4.7

13.0–30

.510

225

600

Ban

808

8.24

4.17

13.0–30

.58

360

600

Ban

828

4.69

2.57

15.0–37

.06

360

600

Jing

58Reserve

Group

Jing

588.1

3.9

11.0–20

.613

210

350

Jing

511.27

1.2

8.6–

16.5

421

035

0

Yon

g22

7.4

37.0–

31.4

519

025

0

Jiangsu

Liuzhuang

4.55

2.45

7.0–

12.0

1015

020

4

Central

plains

Wen

96–

2.95

––

––

Shuang

6Liaoh

e–

16–

–12

0015

00

Hutub

iXinjiang

–45

––

1393

2855

Xiang

uosi

Cho

ngqing

–23

––

1393

2855

Suqiao

Reserve

Group

North

China

–23

––

––

Ban

South

Dagang

7.8

5–

–15

5028

00

Jiangsu

Jiny

un26

.417

.1–

––

–

Total

173.18

10.2 Issues and Challenges 251

and pressure reduction markets are still the twomajor modes of peak shaving. For example, in2012 with its total peak shaving volume of12.8 billion m3, gas reserve contributions accoun-ted for 16%, LNG for 24%, gas field peak shavings28% and pressure reduction markets 31%.

Regions with the largest variance between gasusage peaks and troughs have the most markedshortfalls in peak shaving. The region surround-ing the Bohai Sea is the region with China’slargest gap between peak and trough, and peakshaving demand is significant. According toforecasts, even if currently constructed andunder-construction gas reserves were all suc-cessfully established, in 2015 there would still bea shortfall in peak demand of 3.1 billion m3,which will grow to 4.3 billion m3 by 2020. Thereare relatively many oil and gas fields around theBohai region, and there are good conditions forselection of reserve sites. However, there are notmany high-quality gas reserve site locations, andthe decision can be difficult and the investmentrequirements high. If the issue of gas peakshaving cannot be resolved, winter peak shavinggas collection capabilities will fall short andmajor problems could arise.

3. Pronounced problems with gas reserveprices and operation mechanisms

Gas reserve facilities are unable to unilaterallycreate prices, and newly constructed gas reservefacilities are restricted in their development.Currently, China’s gas reserves have been sup-plemented by pipeline facilities and lack inde-pendent pricing. Gas reserve stage investmentsand costs are all linked to pipeline economicefficiency calculations, and corresponding trans-fer fees are incorporated into pipeline transmis-sion fees, collected together with pipelinetransmission fees, and there is no natural gaspricing system to independently establish an itemfor “gas reserve fees”. For example, in 2003 theNDRC announced that the average shippingprice (including gas reserve fees) for West-EastPipeline line-wide pipelines was 0.79 CNY/m3.

Prior to the 12th Five-Year Plan, undergroundgas reserve investments were generally

incorporated and collected through pipelineinvestments as pipeline transmission fees, and gasreserve construction and investment did not haveaccompanying peak shaving gas prices andtransfer fee policies. The nation invested in naturalgas commercial reserve facilities, with construc-tion investments (including baseline gas) and 30%working gas procurement expenses in the formof arebated income tax that was paid for by the nation,with assets belonging to the group or company andgas reserve and shipping fees assumed by theenterprise. In its guiding opinions regardingacceleration of gas reserve facility construction,the NDRC noted that a reserve price must beestablished for independently operated gas reservefacilities, but the policy was not implemented.

Gas reserve facility and long-distance pipelinebundled operation affect long-term development.China’s natural gas industry is still in the oper-ational mode of having a unified upstream,midstream and downstream. Production, ship-ping, storage and sale of natural gas is primarilyoperated and managed by CNPC, Sinopec andother large oil companies. Gas reserves are sim-ilar to the early stage of operations in the UnitedStates and Europe, and with pipeline auxiliaryfacilities bundled along with pipelines, there isno independent stage for the natural gas industrychain development. Even though after 2010 therewere national investments into construction ofgas reserves, nonetheless gas reserve operationalmodels have not undergone fundamental chan-ges. Currently, China’s gas reserves are primarilyused to co-ordinate supply and demand and peakshavings, as well as for optimisation of produc-tion and pipeline network operations, includingemergency response and strategic reserves.

4. Peak shaving and emergency responseassurance mechanisms awaitimprovements

Responsibilities for gas reserve peak shavingare unclear. Currently, China’s accountability fornatural gas industry chain peak shaving at eachstage is unclear, and this causes a divesting ofresponsibility in emergency natural gas peakshaving within the natural gas industry chain.

252 10 Analysis of China’s Peak Shaving and Natural Gas Storage Systems

Currently, upstream enterprise peak shavingtasks are excessively challenging, as they notonly assume responsibility for regional and sea-sonal adjustments to gas supply, but also fordaily adjustments in key regions. At the sametime, China’s natural gas emergency responsereserve construction investment mechanismsneed to be optimised, as they lack the necessarypricing mechanisms and incentive policies. Thishas led to lack of enthusiasm in the natural gasindustry chain upstream, midstream and down-stream, causing severe limitations to winter sea-son natural gas peak shaving abilities.

An effective natural gas warning mechanismand emergency response mechanism have yet tobe established. Warning forecasts and emergencyresponse mechanisms are important measures forshort-term halts of energy supply. Currently,China has yet to optimise mature operatingmechanisms in this regard.

In addition, China also lacked progress inmatters such as participation in internationalenergy security co-operative frameworks. Chinahas co-operative relationships with essentially allglobal and regional energy organisations, but notmuch substantive co-operation, which is nothelpful when it comes to using internationalefforts to co-ordinate dealing with energy secu-rity risks. Overseas oil and gas resourceco-operations lack effective emergency responsemechanisms for sudden incidents, and robustpolitical, foreign relation, economic and evenmilitary means are lacking to tackle anti-terroristemergency response systems and many otherplans. As soon as an incident occurs, the nationeasily becomes a passive player in events.

10.3 Key Objectivesand Considerations GoingForward

10.3.1 Basic Considerations

Comprehensively implement overall nationalsecurity requirements, making natural gas supplysecurity an important component part of nationalsecurity while accelerating deployment of robust

and reasonable reserve systems appropriate to thesize of the market. As soon as possible, buildprompt and flexible warning systems for emer-gency response, constantly improving China’snatural gas supply assurance capabilities, riskavoidance and handling abilities.

10.3.2 Major Objectives

Based on the scale of China’s future natural gasconsumption, current natural gas reserve peakshaving capabilities, underground gas reserveresource conditions and progress in the con-struction of LNG receiving stations, and withreference to overseas major naturalgas-consuming nation experience, this researchproposes some 2020 and 2030 objectives for thenatural gas commercial and strategic reservesector in China, as well as emergency responsesystem construction objectives.

In 2020, establish underground gas reservesand LNG reserve integrated peak shaving systemswith underground reserves of approximately50 billion, and LNG reserves of 5–10 billion for atotal gas facility working volume of 35–40 bil-lion. This will account for up to 10–11% of totalnatural gas consumption volume, changing thecurrent peak shaving method, which is primarilyfocused on pressure to force reduction of userdemand. At the same time, establish an emer-gency response mechanism for China’s naturalgas as soon as possible, optimising special projectemergency response preparation plans, establish-ing warning systems for emergency response andensuring key region gas supply security.

In 2030, further expand the scale and capa-bilities of the reserve peak shaving system, withgas facility working volume to reach 65 billionand account for 12% of natural gas consumptionvolume at that time, reaching global levels. Withregard to 2030 natural gas import scale, strategicreserves should reach approximately 5% ofimport volume. In keeping with large-scale andfull coverage for national natural gas marketdemands, form effective emergency responsereserve systems for fluctuations in natural gassupply and demand.

10.2 Issues and Challenges 253

10.4 Recommendationsfor Developing NaturalReserves for Peak Shaving

10.4.1 Accelerate the Formulationof Natural Gas PeakShaving EmergencyResponse Plans

In recent years, some regions in China haveencountered frequent gas shortages during thewinter season, clearly exposing China’s lack ofdevelopment in natural gas peak shaving reservefacilities, compared to the rapid development ofthe natural gas market as a whole. In order toguarantee natural gas supply security and thesecure operation of the economy, acceleratedconstruction should be pursued by the nation andprovincial and municipal governments as well asenterprises to jointly participate in the construc-tion of a top-down natural gas peak shavingemergency reserve system and managementsystem and mechanisms.

It is recommended that national natural gasauthorities accelerate the drafting of natural gaspeak shaving emergency response reserve plans,making good use of local and enterprise enthu-siasm for involvement, ensuring the scale ofreserve objectives, the number of emergencyreserve days, and deployment and locationselection while also incorporating the mid- tolong-term natural gas planning of the nationaland provincial 13th Five-Year Plan. Someunderground gas reserve and LNG reserve con-struction projects meeting certain conditionsshould be incorporated into the overall frame-work for national natural gas reserves.

10.4.2 Emphasise Gas ReserveFacility Legaland RegulatoryConstruction

Optimise as quickly as possible the nation’scorresponding policies and legislation, ensuringthat natural gas reserves have good externalpolicy environments from a systemic perspective

so as to encourage enterprises to constructreserve facilities, and carry out research oninnovative mechanisms for the reserve operationmodel. Based on foreign experience, formulateChina’s natural gas reserve management statutesand reserve laws, clarifying reserve organisationand management institutions and their account-abilities and obligations. For example, in theUnited States’ Natural Gas Act (1983), it wasprescribed that the FPC regulates interstate nat-ural gas pipelines, while each state government isresponsible for overseeing state natural gaspipelines. China’s natural gas authorities shouldoversee the formulation of plans and policies andcarry out regulation of gas reserve facilitythird-party access, gas reserve prices, reserveusage, emergency mobilisation and corporateoperational actions. Enterprise operations anduser consumption should be lawfully operatedwithin reasonable frameworks of law and regu-lation, avoiding abuse of market strengths andpromoting effective competition within themarket.

Use national laws to clarify the requirementsfor each level of government, upstream enter-prise and fuel enterprise and their responsibilitiesand obligations in the natural gas reserve system.Implement stepped reserve management systems.The nation is responsible for the strategicreserves of natural gas. Natural gas upstreamenterprises assume responsibilities and obliga-tions for seasonable peak shaving and emergencyresponse reserves. Reserve facilities are invested,built and operated by those enterprises, and eachprovince and city’s gas enterprises assume dailyand hourly peak responsibilities and obligations,with the necessary peak shaving gas reservesbeing invested in, constructed and operated bythose enterprises.

10.4.3 Accelerate Natural Gas PeakShaving EmergencyReserve FacilityConstruction

The first task is to accelerate construction oflarge-scale gas reserves and LNG storage tanks

254 10 Analysis of China’s Peak Shaving and Natural Gas Storage Systems

that can satisfy seasonal peak shaving demands.In northern China, the north-east and thenorth-west, seasonal peaks and troughs are sig-nificant, and there are ample gas reserve loca-tions for resources. First, underground gasreserves should be established, supplemented byLNG, small and medium liquefaction facilitiesand LNG receiving stations for seasonal peakshaving systems. In central China and thesouth-west, among other regions with goodgeographical conditions and nearby oil produc-tion areas, use exhausted oil and gas deposits tobuild underground gas reserves while at the sametime using upstream gas fields, with a supple-ment from small and medium-sized liquefactionfacilities. In eastern China, southern China andother locations with relatively poor environmentsfor underground reserves, construction of LNGreserve storage should be a focus, supplementedby underground gas reserves and small andmedium-sized storage for peak shaving systems.

The second focus is to construct small peakshaving facilities that can satisfy daily peakdemand for gas. In central load gas-using cities,give full play to city fuel companies, acceleratingconstruction of small LNG reserves, CNG tanksand accessory gas reserve facilities to resolve citydaily peak shaving demands.

The third focus is to construct natural gasemergency response reserve systems. Clarifynatural gas upstream production enterprise andcity fuel company emergency reserve responsi-bilities. Rely upon and expand large reserves ofgas, LNG storage and small tank reserves amongother facility construction scope, accelerating theestablishment of natural gas commercial reservesand satisfying issues of regional supply halt gasdemand.

The fourth issue to address is to study thestrategy for establishing suitably scaled naturalgas reserves. From a global perspective, naturalgas has not experienced a supply crisis on aglobal scale such as the oil crisis, and natural gassecurity issues are not yet pronounced. However,compared to oil, natural gas has a high degree ofunification in the upstream, midstream anddownstream. As part of this, if any stage hasproblems, it will affect the entire chain of natural

gas supply security, and there are major potentialrisks. The 2009 dispute between Russia andUkraine is one such example of the danger.Therefore, China should develop research intonatural gas strategic reserves as quickly as pos-sible upon the basis of properly handling com-mercial reserves, so as to determine the layout inthe mid- to long term for natural gas securityissues, making plans early and establishing nat-ural gas strategic reserve scale and models suitedto China.

10.4.4 Formulate Proactive Taxand Price Policies

Establish reasonable gas reserve pricing mecha-nisms. The pricing stage in gas reserves mustensure that gas reserve investment and operationcosts are recovered while guaranteeing that gasreserve enterprises obtain a reasonable return. Onthe other hand, standard service and fair com-petition must be promoted among gas reserveenterprises. The United States has developedpeak period/off-peak period or seasonal gasreserve pricing based on service cost pricingapproaches that has to a certain degree reducedthe risk of imbalance in gas reserve services. Inorder to promote gas reserve service competition,the United States has also developed marketdemand pricing approaches. These pricingapproaches have improved services to makethem more suited to gas reserves, ensuring thatgas reserve service providers obtain reasonableeconomic rewards. China should formulatepricing mechanisms suited to the current state ofdevelopment of the natural gas industry at the gasreserve stage. Based on the operating costs forgas reserves/storage facilities, and based ongovernment-determined internal rates of returncalculations, the government can determine pricelevels and for each interval of time carry out anassessment and adjustment on gas reserve prices.

Commence differential pricing based on peakand off-peak periods, expressing natural gasvalue during peak periods. It is recommendedthat China implement differential pricing forvarious users during peak and off-peak periods,

10.4 Recommendations for Developing Natural Reserves for Peak Shaving 255

thereby guiding reasonable consumption,achieving a minimisation of peak and off-peaklimits and improving system operation efficiency.The peak and off-peak pricing difference in theUnited States and France is generally 1.2–1.5fold, determining January–February andNovember–December as the peak periods for gasusage. By implementing peak gas usage prices,price levels rise from base amounts.

Formulate discount policies and measures toencourage enterprises to construct reserve facili-ties. Because the construction expenditure foremergency reserve facilities can be enormous,along with major costs for the procurement ofreserves and daily operating expenses, andbecause the main function is to satisfy seasonalpeak shaving supply demand, it is recommendedthat the government put in place specific prefer-ential policies for construction expenses relatedto facilities for peak shaving reserves. This could,for example, be similar to the approach takenwith commercial product oil reserves, withupstream suppliers enabled to use 30% of LNGreserve costs to construct LNG peak shavingemergency response equipment as a rebate inpayable income taxes. This is aimed at encour-aging upstream suppliers to construct suitableamounts of LNG reserves so as to deal withtemporary supply cuts or extra volume duringpeak demand periods.

10.4.5 Accelerate Gas ReserveManagement SystemReforms

System reforms include business unbundling,independent settlement and promotion ofstate-owned oil company gas reserve modelreforms. Currently, the United States and Euro-pean nation gas reserve operations have devel-oped into entirely free-market independentbusiness models, but the model must be within acompetitive market environment, including fornatural gas supply, shipment and storage stages,which must have many market participants whorespect market rules and form a market envi-ronment with fair competition.

Considering the current circumstances ofChina’s natural gas industry, future gas reserveoperations could first employ a business modelwithout full market liberalisation by establishinga gas reserve operating company within CNPCthat is financially independent from the pipelinetransmission business, thereby becoming anindependent stage of the industry chain. As anindependent profit-making entity, the gasreserves company can help facilitate the profes-sionalisation of the gas reserve business andliberalise the market, while also helping tofacilitate individual pricing at the gas reservestage. As China’s gas reserve business rapidlygrows, it will be partitioned from the pipelinetransmission business to become a stage of theindustry chain that operates and developsindependently.

Gas reserve peak shaving facility constructionand operation diversification should be encour-aged. Establish a diverse portfolio of entities aspart of a gas reserve system, includingstate-owned oil companies, urban fuel companiesand independently operated gas reserve compa-nies. This will be beneficial in ensuring thatnatural gas supply security and gas reservecapabilities can rapidly grow. Looking at theAmerican experience, this achieved natural gasreserve peak shaving commercialisation to a veryhigh degree, with management and operationentities including interstate and intrastate pipelinecompanies, local distribution companies andindependent gas reserve service providers. Inorder to encourage private enterprise and othersocial capital to enter gas reserve facility con-struction and operation, it is necessary to inno-vate in a commercial model, forming reasonableprice mechanisms that achieve gas reserve facil-ity third-party access and other measures for jointrealisation.

10.4.6 Establish Prompt and FlexibleWarning Systemsfor Emergency Response

Prompt and flexible warning systems for emer-gency response means active precautions and

256 10 Analysis of China’s Peak Shaving and Natural Gas Storage Systems

effective measures to relieve natural gas securityrisks. The aim is gradually to establish andoptimise precautionary emergency response legalsystems, organisational institutions and strategicmechanisms, information collection analysis anddistribution systems, and various types and levelsof emergency preparation and internationalassistance and co-operation agreement for naturalgas emergency response systems.

1. Establish a natural gas forecast warningsystem

Use research to find favourable opportunitiesto build an indicator system for energy con-sumption, monitoring systems and evaluationsystems to further standardise natural gas statis-tical systems. Establish statistical data as quicklyas possible to monitor and assess as well as todistribute information, wholly integrating energyinformation channels to continually optimiseenergy statistics and information collection sys-tems. Enhance forecasting and warning methodresearch and develop forecast warning modelssuited to China’s energy circumstances. Organisea professional team with strong capabilities toestablish a timely and flexible forecast warningplatform.

2. Establish an emergency response systemcovering natural gas production,transmission, sales and all other stages

Based on gas industry and regional charac-teristics, determine various levels of emergencyresponse preparation. Establish emergencywarning systems in the upstream and midstreamfocused on the central government and centralgovernment enterprises, and downstream plansfocused on local governments and local fuelcompanies. Make full use of the co-ordinatingrole of the National Energy Council to establishhandling for major energy incidents, to providefeedback and for information release reviewregimes as well as strategy mechanisms, ensuring

that emergency response is prompt, strict andauthoritative.

3. Promote communication and co-operation

China’s natural gas forecast warning systemconstruction should likewise be a broad interna-tional co-operation. First, strengthen governmentinterdepartmental communication and contact.Strengthen the dialogue and co-operationbetween the National Energy Administration,National Bureau of Statistics, NDRC OperationsBureau and other relevant departments in therealms of mobilisation, data sharing, forecastingand warning, and other matters so as to establisha unified and well-prepared natural gas forecastwarning and emergency response system.

At the same time, in terms of reserve projectconstruction deployment, the National EnergyAdministration and other local governmentsshould take a scientific approach to planning,with full proofs provided. For approved andauthorised project construction sites, variouslevels of government should offer support toenterprises. In terms of peak shaving emergencyresponse interregional deployment, the NationalEnergy Administration and provincial energybureaux as well as relevant enterprises shouldco-ordinate efforts.

Also, strengthen international dialogue andcommunication relating to energy. In terms of dataand information, continue to strengthendata-sharing mechanisms with institutions such asthe IEA. Promote dialogue with natural gas sourcenations including Russia, central Asia, Australiaand Qatar, negotiating resolutions to major andoutstanding problems. In terms of managementexperience, make full use of advanced interna-tional experience, with management systems andmechanisms to become more scientific in theirhandling. In terms of research results, fully absorbthe research results from various nations and withrelation to international organisations, so as todesign forecast warning systems suited to China’sspecific circumstances.

10.4 Recommendations for Developing Natural Reserves for Peak Shaving 257

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258 10 Analysis of China’s Peak Shaving and Natural Gas Storage Systems

PART III

Creation of Natural Gas MarketMechanisms and Reform of Natural Gas

Management Systems

The research in this chapter concentrates on thecurrent state of China’s natural gas marketmechanisms and regulatory systems, on the nat-ure of established natural gas market mechanismsin other countries and how they were created,and on the direction, underlying thinking, aims,main pathways, approaches and measures neededto ensure the success of reforms. For the pur-poses of this research, the natural gas industry isdivided into upstream, midstream and down-stream sectors.

The problems in China’s current natural gasindustry mechanism and regulatory systeminclude: over-centralisation of mineral rights, amajor lack of investment in exploration; bund-ling of infrastructure operation, with low usageefficiency; inappropriate natural gas pricingmechanisms which are detrimental to the devel-opment of downstream markets and the con-struction of associated natural gas storagefacilities; regional monopolies controlled bydownstream pipeline operators andcross-subsidies between different types of users;and incomplete supervisory systems.

It can be deduced from the experiences ofmature overseas natural gas markets that diver-sification of the participants involved in themarket is a precondition to the creation of acompetitive natural gas market, while the open-ing of the upstream sector is absolutely essential.Implementation of reforms to pipeline accesspolicy must progress gradually, with third-party

access policies as the first step in infrastructurereform. Market-based pricing is a very importantstage of the process of market liberalisation ofnatural gas, as natural gas pricing mechanismsare closely linked to the extent to which themarket is able to develop. The creation ofregional trading markets is essential for themarket to be able to develop to any degree, whilethe creation of an independent, legally estab-lished regulatory system is the final guarantee forthe effectiveness of natural gas market systems.

The basic concepts and overall aims of Chi-na’s natural gas market liberalisation reformsinclude:

• the creation of a diversified, competitive,open, orderly modern natural gas marketsystem;

• the establishment of pricing mechanismsthat reflect factors such as scarcity ofresources, the market fundamentals of sup-ply and demand, external environmentalpricing mechanisms and green taxation; and

• the creation of a legally established,service-oriented natural gas administrativesystem.

Based on the current level of development ofChina’s natural gas market, proposals concerningnatural gas market liberalisation reforms involvethree stages:

• By 2020, a preliminary mineral rights pri-mary market should be created in theupstream sector, in addition to the first steps

being taken towards the creation of a sec-ondary market. This will establish a primarymarket for preliminary midstream pipelinecapacity trading and storage trading,including LNG facilities. Downstream, thenatural gas terminal prices should bederegulated, to that they will then be basedon market competition.

• By 2025, an upstream mineral rights pri-mary and secondary market should be moreor less complete. In the midstream, a pipe-line capacity trading and storage tradingprimary market should be more or lesscomplete, and this should be accompaniedby the preliminary creation of a pipelinecapacity trading and storage trading sec-ondary market. A natural gas sales marketsystem based on a spot-trading marketconsisting of manufacturers, independenttraders, major users, local distributioncompanies and end users should be estab-lished downstream.

• By 2030, an upstream mineral rights pri-mary market and secondary market shouldhave been established, as well as midstreampipeline capacity trading and a storagetrading primary market and secondarymarket. Downstream, a natural gas salesmarket system based on a combination ofspot-trading and futures should have beenestablished.

The main measures necessary to establish anatural gas regulatory system and to reformregulatory structures in China are:

• establishment of a market system: set upthe Sichuan-Chongqing natural gas marketliberalisation reform trial region;

• completion of natural gas pricing mech-anisms: staged introduction of reforms tonatural gas pricing, acceleration of the cre-ation of a natural gas futures market;

• clearing out pipeline transport bottle-necks: extensive reform to the operationand regulation of natural gas infrastructuresuch as pipeline networks, clearly estab-lishing functional roles, to ensure thatpipeline transport services and sales ser-vices become separate from upstream anddownstream activities and that third-partyaccess occurs;

• carrying out regulatory reform: stagedcreation of a comprehensive, centralised,vertically unified, integrated, independent,specialised regulatory system;

• stimulation of activity among marketparticipants: make reforms to state-ownedoil companies more extensive;

• setting up and broadening of the scope ofthe natural gas industry-related servicemarket: development of the market fornatural gas will help broaden and deepenthe ancillary gas-related services industry.

Finally, a comprehensive legislative systemwill need to be established as part of the reformsto China’s natural gas institutions. The adminis-tration needs greater reform, and there should befinancial and tax incentives to encourage thedevelopment and usage of non-conventionalnatural gas. A variety of measures can beemployed to back up these goals, such asencouraging technical innovation, coordinatedplanning and greater international cooperationwith commercial entities.

260 Creation of Natural Gas Market Mechanisms …

11China’s Current Natural Gas MarketMechanisms and Regulatory System

11.1 Current State of Natural GasMarket Mechanisms

11.1.1 Natural Gas Upstream Market

In 1998, as part of the separation of governmentfunctions from enterprise management, the for-mer China Petroleum and Natural Gas Companyand the China Petrochemical Corporation wererestructured according to principles of fair allo-cation, interaction, preservation of advantagesand orderly competition, resulting in the creationof the China National Petroleum Corporation andthe China Petrochemical Corporation (Sinopec).In February 2000, Star Petroleum, which hadoriginally come under the auspices of the Min-istry of Geology and Mining, was completelyabsorbed into the China Petrochemical Corpora-tion. China National Petroleum Corporation,China Petrochemical Corporation and ChinaNational Offshore Oil Corporation all becameindependent operations, responsible for their ownprofitability, each an amalgamated organisationthat competed both upstream and downstream.According to the regulations, these three main oilcompanies were allowed to apply for oil andnatural gas exploration plots extending

throughout the whole country. Even thoughChina National Petroleum Corporation andChina Petrochemical Corporation were allowedto carry out marine exploration and ChinaNational Offshore Oil Corporation could alsocarry out land-based exploration, other compa-nies were still not permitted to enter to the fieldsof conventional gas exploration and develop-ment. When it came to non-conventional naturalgas, the Coal Industry Ministry issued the Coal-bed Methane Exploration and ExtractionAdministration Temporary Regulations in 1994,then in 2012 the Ministry of Land and Resourcesissued a notice encouraging shale natural gasexploration and development monitoring andregulation, which permits other market partici-pants access to the coalbed methane and shalenatural gas exploration and development field.However, the proportion of total natural gasoutput that this accounts for is minimal.

Currently, the majority (97% or more) of oiland gas exploration rights and mineral rights areconcentrated in the hands of the three large oilcorporations. Based on Ministry of Land andResources data, there were 1023 oil and gasexploration rights registered in China in 2012,covering 4,009,340 km2, of which 942 belongedto the three main oil corporations, accounting for3,906,848 km2, or 97.44% of the total. Therewere also 671 oil and gas extraction rights reg-istered, covering a total registered area of118,949 km2, of which 655 belonged to the threemain oil corporations, covering 117,685 km2, or98.93% of the total (see Table 11.1 andFig. 11.1).

* This chapter was overseen by Xiaoming Wang fromthe Development Research Center of the State Counciland Mallika Ishwaran from Shell International. It wasjointly completed by Yusong Deng, Jiaofeng Guo,Shouhai Chen from China University of Petroleum andQingle Wu from Shell China. Other members of thetopic group participated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_11

261

Because the three main oil companies own thevast majority of natural gas exploration andmineral rights, in addition to owning all naturalgas importing pipelines, LNG receiving stationsand other infrastructure, the three main oil com-panies completely dominate natural gas supplies.

In 2014, natural gas consumption was183 billion m3, domestic natural gas output was125.6 billion m3, and coal-based gas output was1 billion m3. Imported natural gas accounted for59 billion m3, around one third of natural gasconsumption. China National Petroleum

Corporation was responsible for 95.5 billion m3

of domestic gas output, 31 billion m3 of impor-ted pipeline gas and around 5 million tonnes ofLNG (approximately 6.5 billion m3), making up72% of China’s total natural gas consumption.China Petrochemical Corporation’s domesticnatural gas output was 20.2 billion m3, with100,000 tonnes of imported LNG (130 millionm3), accounting for 11% of China’s total naturalgas consumption. China National Offshore OilCorporation’s domestic natural gas output was12.4 billion m3, with 14.11 million tonnes of

Table 11.1 Oil and gas exploration rights and extraction rights registrations in 2012

Exploration rights Extraction rights

Number Area (km2) Number Area (km2)

China National Petroleum Corporation 415 1,608,291 396 91,578

China Petrochemical Corporation 284 908,211 194 20,420

China National Offshore Oil Corporation 243 1,390,346 65 5687

Yanchang Oilfield 24 75,958 5 444

China United Coalbed Methane Corporation 24 18,019 2 193

Others 33 8515 9 627

Total 1023 4,009,340 671 118,949

Exploration Rights

China National Petroleum Corporation

China Petrochemical Corporation

China National Offshore Oil Corporation

Extraction Rights

Yanchang Oilfieald

China United Coalbed Methane Corporation

Others

Fig. 11.1 Oil and gas exploration rights and mineral rights registered areas in 2012

262 11 China’s Current Natural Gas Market Mechanisms …

imported LNG (18.8 billion m3), accounting for17% of China’s total natural gas consumption.

Overall, China National Petroleum Corpora-tion had a three-quarter share of China’s naturalgas market, with China Petrochemical Corpora-tion and China National Offshore Oil Corpora-tion having somewhat smaller shares. In terms ofregional markets, each of the three major oilcompanies have very high shares of the market inthe regions that each supplies, in some casesreaching 100%. For instance, even though Bei-jing has seen diversification of gas sources,—with the natural gas being used including“Western gas going East”, Central Asian gas,Inner Mongolian coal-based gas, imported LNGand Shaanxi-Beijing pipeline gas, this gas isprovided by only one entity—China NationalPetroleum Corporation. However, as the BeijingGas Group pointed out, China National

Petroleum Corporation was not actively seekinga monopoly in the Beijing market; the situationwas brought about by Beijing’s desire for ChinaNational Petroleum Corporation to act as the solegas supplier, making it responsible for gas supplysecurity. On the other hand, in south easterncoastal regions such as Guangdong and Fujian, itis China National Offshore Oil Corporation thathas a relatively high market share.

11.1.2 Natural Gas Midstream Market

The natural gas midstream market encompassesnatural gas transport and storage services, withthe extent of development of the market beingindicated by the scope of infrastructure present,including natural gas pipelines, LNG receivingstations and subterranean storage (see Fig. 11.2).

Completed pipeline

Pipeline under construction

Completed LNG receiving station

LNG receiving station under construction

Completed gas storage facility

CentralAsian Gas

Russian Gas Russian

Gas

Burmese Gas

Fig. 11.2 China’s natural gas infrastructure. Source China National Petroleum Corporation Economics andTechnology Institute, 2014 Domestic and Overseas Oil and Gas Industry Development Report

11.1 Current State of Natural Gas Market Mechanisms 263

1. Long-distance natural gas pipelines

The data and statistics for the current state ofconstruction of China’s natural gas pipelines areincomplete. By the end of 2014, the main naturalgas backbone pipelines and branch pipelinescovered around 63,000 km, of which around46,000 km was owned by China National Pet-roleum Corporation, 73% of the total in China.Aside from the natural gas backbone pipelinesowned by the three main oil companies, since2003, as the natural gas market began to develop,local pipeline companies have begun to crop up,mainly owning provincial-level branch pipelines,and transporting natural gas from the backbonepipelines to municipal gate stations. In Zhejiangand Guangdong provinces there is a “completeprovince single network” policy, and heremonopolistic provincial pipeline companies werecreated. In other provinces, where there were noprovincial level-pipeline network companies,there are usually a number of pipeline compa-nies; Shanxi province, for instance, has threemain pipeline companies, while Henan provincehas almost 20. In general terms, the distancescovered by local pipeline company pipelines arenot great, for instance the length of pipelinescompleted by the Zhejiang provincial pipelinecompany is less than 1000 km. Details of themain natural gas pipelines in China built after1996 can be found in Table 11.2.

2. LNG receiving stations

By the end of 2014, 11 LNG receiving sta-tions had already been completed and broughtonline in China, with a combined receivingcapacity of 40.8 million tonnes/year (seeTable 11.3). Apart from this, there are 12 moreLNG gas receiving stations under construction orplanned for construction, with completion due in2017, which will further increase China’sreceiving capacity of 42.4 million tonnes/year,after which the combined receiving capacity willbe 83.2 million tonnes/year (see Table 11.4).The completed LNG receiving stations alreadyonline are all controlled by the three main oilcompanies. Of the 11 completed LNG gas

receiving stations, China National Offshore OilCorporation owns 7, China National PetroleumCorporation owns 3 and China PetrochemicalsCorporation owns 1. However, as the stateencourages access by private enterprise to the gasand oil infrastructure industry, diversification ofLNG receiving station investors is graduallytaking place, and both private capital and non-oiland gas companies are competing to build LNGshore-based discharging-receiving stations.The ENN Zhoushan LNG receiving station pro-ject is already under construction, while XinjiangGuanghui Industry Investment (Group) Com-pany Limited, China Huadian Corporation,Hanas Group and Beijing Jingneng PowerCompany Limited are all actively involved in theLNG receiving station development sector.

3. Subterranean storage facilities

A gas shortage occurred on a national scale inthe winter of 2009, exposing the severe lack ofnatural gas storage facilities. As a result, thenatural gas administration proposed a series ofmeasures to accelerate the construction of naturalgas storage facilities. During the 12th Five-YearPlan, China National Petroleum Corporationplanned to build 13 oil and gas storage banks,with a total storage capacity of 453 � 108 m3,the designed working gas capacity of which was184 � 108 m3, while it was expected that a totalworking gas capacity of 170 � 108 m3 wouldhave been created by 2015, equivalent to 10% ofChina National Petroleum Corporation’s sales,which should be enough to satisfy downstreampeak regulation requirements. Based on the“Sichuan gas going East” and Yuji pipelineprojects, China Petrochemical Corporation isconducting a comprehensive selection of gasstorage sites in relation to central and easternregion oil and gas fields and the western Sichuangas region, and, based on this, construction ofkey gas storage facilities is planned during the12th Five-Year Plan at Zhongyuan Wen 96,Zhongyuan Wen 23, Jintan in Jiangsu andHuangchang in Jianghan etc. Apart from ChinaNational Petroleum Corporation and ChinaPetrochemical Corporation using depleted oil and

264 11 China’s Current Natural Gas Market Mechanisms …

Table

11.2

Detailsof

themainnaturalgaspipelin

esbu

iltin

China,19

96–20

14

Pipelin

eOwner

Startpoint

End

point

Length

(km)

Gas

transportcapacity

(100

millionm

3 /year)

Cam

eonlin

ein

Com

pleted

long-distancepipelin

es

Ya-

GangLine

China

NationalOffshore

OilCorporatio

nSo

uthChina

SeaYa

13-1

gasfield

HongKong,

Hainan

778

341996-06

Shaan-Jing

Line

China

NationalP

etroleum

Corporatio

nJingbian

Beijin

g911

331997-09

Se-N

ing-Lan

Line

China

NationalP

etroleum

Corporatio

nSebeiNo.

1Lanzhou

921

35.5

2009-11

Zhong-W

uLine

China

NationalP

etroleum

Corporatio

nZhong

County,

Chonqing

Wuhan

1364

702004-12

Western

Gas

Going

East

China

NationalP

etroleum

Corporatio

nLun-nan,Xinjiang

Shanghai

3836

170

2004-12

Shaan-Jing

No.

2Line

China

NationalP

etroleum

Corporatio

nYulin,Sh

aanxi

Beijin

g983

170

2005-07

Chang-H

uLine

InnerMongolia

Natural

Gas

Com

pany

Ltd.

Changqing,Jingbian

Hohhot

286

72009-01

Yong-Tang-Qin

Line

China

NationalP

etroleum

Corporatio

nYongqing,

Hebei

Qinhuangdao

320

902009-06

Chang-Chang-Ji

China

NationalP

etroleum

Corporatio

nChanglin

g,Jilin

Jilin

Petrochemical

Com

pany

221

232009-12

SichuanGas

Going

EastLine

China

NationalP

etroleum

Corporatio

nPu

guangGas

Field,

Sichuan

Shanghai

1702

120

2010-03

Shaan-Jing

No.

3Line

China

NationalP

etroleum

Corporatio

nYulin,Sh

aanxi

Beijin

g894

150

2010-12

WestNo.

2Line

China

NationalP

etroleum

Corporatio

nHuo-er-guo-si,

Xinjiang

Guangzhou

9242

300

2011-06

Qin-ShenLine

China

NationalP

etroleum

Corporatio

nQinhuangdao

Shenyang

404

862011-06

Jiang-RuLine

China

NationalP

etroleum

Corporatio

nJiangdu

Rudong

222

100

2011-06

Da-Sh

enLine

China

NationalP

etroleum

Corporatio

nDalian

Shenyang

423

842011-09

(con

tinued)

11.1 Current State of Natural Gas Market Mechanisms 265

Table

11.2

(con

tinued)

Pipelin

eOwner

Startpoint

End

point

Length

(km)

Gas

transportcapacity

(100

millionm

3 /year)

Cam

eonlin

ein

Chang-H

uDualLine

InnerMongolia

Natural

Gas

Com

pany

Ltd.

Changqing,Jingbian

Hohhot

518

802012-10

Yi-Huo

Line

China

NationalP

etroleum

Corporatio

nYining

Huo-er-guo-si

64300

2013-06

China-BurmaLine

China

NationalP

etroleum

Corporatio

nRuili,

Yunnan

Guigang,Guangxi

1727

100

2013-10

Fu-ShenLine

DatangInternational

Power

Generation

Com

pany

Ltd.

Fuxin

Shenyang

125

402013-10

Ke-GuLine

DatangInternational

Power

Generation

Com

pany

Ltd.

Keshiketeng

Banner,

InnerMongolia

Gubeikou,

Miyun,

Beijin

g359

402013-11

Changning

RegionSh

aleGas

Trial

ExtractionBackbone

China

NationalP

etroleum

Corporatio

nNing201-H1

well-groupgas

supply

station

Shuanghe

group

distributio

nendstation

95.6

152014-05

WestNo.3LineWestern

Section

China

NationalP

etroleum

Corporatio

nHuo-er-guo-si

Zhongwei

2445

300

2014-08

Com

pleted

connectin

gpipelin

es(1)

Jing-Y

uLine

China

NationalP

etroleum

Corporatio

nJingbian

Yulin

113

155

2005-11

Ji-N

ingLine

China

NationalP

etroleum

Corporatio

nAnping,

Hebei

Yizheng,Jiangsu

1474

56.3

2006-06

Huai-WuLine

China

NationalP

etroleum

Corporatio

nHuaiyang

Wuhan

444

222006-12

Lan-Y

inLine

China

NationalP

etroleum

Corporatio

nLanzhou

Yinchuan

460

192007-06

Zhong-G

uiLine

China

NationalP

etroleum

Corporatio

nZhongwei

Guiyang

1613

150

2013-10

Source

China

NationalPetroleum

Corporatio

nEconomicsandTechnologyInstitu

te,2014

Dom

estic

andOverseasOilandGas

Industry

DevelopmentReport

266 11 China’s Current Natural Gas Market Mechanisms …

Table

11.3

LNG

receivingstations

onlin

ein

2014

inChina

(�10

4tonn

es/year)

Nam

eof

project

Location

Owner

PhaseI

Total

forPh

ases

I+II

PhaseIon

line

PhaseIIon

line

DapengLNG,Guang

dong

DapengBay,Sh

enzhen

China

NationalOffshoreOilCorpo

ratio

n68

020

06-06

2011

PutianLNG,Fu

jian

Putian,

Meizhou

Bay

China

NationalOffshoreOilCorpo

ratio

n63

020

08-04

2013

YangshanLNG,Sh

angh

aiYangshanDeepWater

Port

China

NationalOffshoreOilCorpo

ratio

n60

020

09-10

Rud

ongLNG,Jiangsu

Yangk

ouHarbo

ur,

Rud

ong

China

NationalPetroleum

Corpo

ratio

n65

020

11-06

2016

DalianLNG,Liaon

ing

DagushanPeninsular,

Dalian

China

NationalPetroleum

Corpo

ratio

n60

020

11-07

2017

Ningb

oLNG,Zhejiang

Zho

ngzhai,Baifeng

zhen,

Ningb

oChina

NationalOffshoreOilCorpo

ratio

n60

020

12-12

2016

Jinw

anLNG,Zhu

hai

GaolanPo

rt,Zhu

hai,

Guang

dong

China

NationalOffshoreOilCorpo

ratio

n70

020

13-10

CaofeidianLNG,Hebei

CaofeidianPo

rtZon

e,Tangh

ai,Tangshan

China

NationalPetroleum

Corpo

ratio

n65

020

13-12

FushiLNG,Tianjin

Nanjiang

PortZon

e,Tianjin

Port

China

NationalOffshoreOilCorpo

ratio

n22

060

020

13-12

2016

Qingd

aoLNG,Sh

ando

ngDon

gjiako

u,Jiaonan,

Qingd

aoChina

Petrochemical

Corpo

ratio

n30

030

020

14

Yangp

uLNG,Hainan

HeiyanPo

rtZon

e,Yangp

uEcono

mic

Develop

mentZon

e

China

NationalOffshoreOilCorpo

ratio

n30

060

020

14

Source

China

NationalPetroleum

Corpo

ratio

nEcono

micsandTechn

olog

yInstitu

te,20

14Dom

estic

andOverseasOilandGas

Indu

stry

Develop

mentReport

11.1 Current State of Natural Gas Market Mechanisms 267

Table

11.4

LNG

receivingstationprojectsun

derconstructio

nor

plannedforconstructio

nin

China

(�10

4tonn

es/year)

Nam

eof

project

Location

Owner

PhaseI

PhaseIon

line

Status

Diefu

LNG,Guang

dong

Diefupian

Zon

e,DapengNew

District,Sh

enzhen

China

NationalO

ffshoreOilCorpo

ratio

n40

020

15Und

erconstructio

n

BeihaiLNG,Guang

xiTieshan

PortZon

e,Beihai

China

Petrochemical

Corpo

ratio

n30

020

15Und

erconstructio

n

Yuedo

ngLNG,G

uang

dong

Huilai,Jieyang,

Yuedo

ngChina

NationalO

ffshoreOilCorpo

ratio

n20

020

15Und

erconstructio

n

Nangang

LNG,Tianjin

Nangang

Indu

strial

Zon

e,BinhaiNew

District

China

Petrochemical

Corpo

ratio

n30

020

16Und

erconstructio

n

Zho

ushanLNG,Zhejiang

Zho

ushanEcono

mic

Develop

mentZon

eENN

300

2017

Und

erconstructio

n

BinhaiLNG,Jiangsu

BinhaiPo

rtZon

e,Yancheng

China

NationalO

ffshoreOilCorpo

ratio

n26

020

17Perm

itreceived

Wenzhou

LNG,Zhejiang

Xiaom

enIsland

,Wenzhou

China

Petrochemical

Corpo

ratio

n30

020

17Perm

itreceived

Zhang

zhou

LNG,Fu

jian

Xingg

uBay,Lon

ghai

China

NationalO

ffshoreOilCorpo

ratio

n30

020

17Perm

itreceived

Liany

ungang

LNG,Jiang

suXuw

eiPo

rtZon

e,Liany

ungang

China

Petrochemical

Corpo

ratio

n30

020

17Perm

itreceived

Yuexi

LNG,Guang

dong

Bojia

New

PortZon

e,Maoming

China

NationalO

ffshoreOilCorpo

ratio

n30

020

17Perm

itreceived

YantaiLNG,Sh

ando

ngWestern

PortZon

e,Zhifu

Port

China

NationalO

ffshoreOilCorpo

ratio

n30

0Unk

nown

Early

stage

Shenzhen

LNG

Difup

ianZon

e,DapengBay

China

Petrochemical

Corpo

ratio

n30

0Unk

nown

Early

stage

Source

China

NationalPetroleum

Corpo

ratio

nEcono

micsandTechn

olog

yInstitu

te,20

14Dom

estic

andOverseasOilandGas

Indu

stry

Develop

mentReport

268 11 China’s Current Natural Gas Market Mechanisms …

gas reserves to create subterranean storagefacilities, China Petrochemical Corporation isworking together with China National SaltIndustry Corporation to construct gas storagefacilities in subterranean salt caverns in the Jintandistrict of Jiangsu, while the first gas storagefacility constructed with investment from amunicipal gas company—Ganghua Jintan GasStorage Facility—is already under construction.By 2013, the designed working capacity of gasstorage facilities that had been completed or thatwere under construction had already reached300 billion m3, but due to the need to extendsubterranean storage facilities gradually, theactual completed working gas capacity is only28.6 � 108 m3, which is only 1.7% of the cur-rent annual national gas consumption (seeTable 11.5).

11.1.3 Natural Gas DownstreamMarket

The natural gas downstream market has a com-plex structure, and market participants aresomewhat dispersed. Downstream users can bedivided by gas supply method into users that aresupplied directly and urban gas enterprises.Directly supplied users are those who purchasenatural gas directly from upstream suppliers forthe purposes of manufacturing or their ownconsumption, and that do not resell gas; urbangas enterprises buy gas from upstream suppliers,then resell gas to end users via their urban gasdistribution networks. Direct users are generallyindustrial users that use large quantities of gas,but not all large industrial gas consumers aredirectly supplied customers. Due to thecross-subsidising that exists between residentialusers and commercial users in the pricing of gassupplied by urban gas enterprises, large-volumeindustrial users where the cost of supplying gas isrelatively low are a major source of profit forurban gas enterprises. As a result, urban gasenterprises are violently opposed to upstreamsuppliers selling gas directly to industrial cus-tomers that fall within the geographical area towhich their trading licences apply. Based on

research by the China Oil Economy Institute ofTechnology, the quantity of gas sold by urbangas enterprises in 2013 was around 90 billionm3, which accounts for 56% of China’s naturalgas consumption for that year.

In December 2002, the Ministry of Con-struction issued Suggestions Concerning Accel-erating the Rate of Marketisation of UrbanUtilities, which was followed by the publicationof the localised legislation and policy-relatedProvincial and Urban Gas Administrative Regu-lations in various locations. This adopted theprinciple that “the party investing should makedecisions on policy, the party benefiting shouldtake on risks”; this was designed to activelyattract state, private and overseas investment inurban gas infrastructure and management. Cur-rently, China’s urban gas industry has begun toconvert from its previously ring-fenced situation,towards one with a new “four-pronged approach”consisting of centralised corporations, localstate-owned enterprises, overseas investment andprivate enterprises, with over 800 gas companiesthroughout China in addition to the formation offive major transregional gas groups, includingTowngas, China Resources Gas, PetroChinaKunlun Gas Company Limited, China GasHoldings and ENN. In addition, there are rela-tively large local gas groups such as the BeijingGas Group, Shanghai Gas (Group) CompanyLimited and Shenzhen Gas (Table 11.6).

11.2 Current State of China’sNatural Gas RegulatorySystems

11.2.1 Upstream MarketAdministrative System

1. Upstream natural gas administrativepolicy and legislation

When compared to the midstream anddownstream sectors, market regulation and leg-islation in China’s upstream market is relativelycomplete; a preliminary core Mineral andResources Rights Law has already been drafted,

11.1 Current State of Natural Gas Market Mechanisms 269

Table

11.5

Con

structionstatus

ofmainsubterranean

gasstoragefacilitiesin

China

Gas

storage

facility

Owner

Location

Type

Designed

capacity

(�10

8m

3 )

Designedworking

gascapacity

(�10

8m

3 )

Working

gascapacity

alreadycreated

(�10

8m

3 )

Highestinjection

rate

(104

m3 /day)

Datebroughtonlin

e

Lam

adian

China

NationalP

etroleum

Corporatio

nDaqing

Depleted

reserve

1.00

Already

abandoned

–1975

Dazhangtuo

China

NationalP

etroleum

Corporatio

nDagang

Depleted

reserve

17.8

6.00

18.4

320

Being

broughtonlin

esuccessively

startin

gin

1999

Ban

876

China

NationalP

etroleum

Corporatio

nDagang

Depleted

reserve

4.7

1.9

100

Central-N

orthern

Ban

China

NationalP

etroleum

Corporatio

nDagang

Depleted

reserve

24.5

11.0

300

Central-Southern

Ban

China

NationalP

etroleum

Corporatio

nDagang

Depleted

reserve

9.7

4.70

225

Ban

808

China

NationalP

etroleum

Corporatio

nDagang

Depleted

reserve

8.2

4.17

360

Southern

Ban

China

NationalP

etroleum

Corporatio

nDagang

Depleted

reserve

5240

Ban

828

China

NationalP

etroleum

Corporatio

nDagang

Depleted

reserve

4.7

2.57

360

Jing

51China

NationalP

etroleum

Corporatio

nHuabei

Depleted

reserve

1.3

0.60

4.2

–2010

Jing

58China

NationalP

etroleum

Corporatio

nHuabei

Depleted

reserve

8.1

3.90

–

Yong22

China

NationalP

etroleum

Corporatio

nHuabei

Depleted

reserve

6.0

3.00

–

Liu

Zhuang

China

NationalP

etroleum

Corporatio

nJiangsu

Depleted

reserve

4.5

2.45

1.9

–2011

Wen

96China

Petrochemical

Corporatio

nZhongyuan

Depleted

reserve

2.95

–2012-09

Shuang

6China

NationalP

etroleum

Corporatio

nLiaohe

Depleted

reserve

16–

2013-01

Hutubi

China

NationalP

etroleum

Corporatio

nXinjiang

Depleted

reserve

117

452.6

1123

2013-07

(con

tinued)

270 11 China’s Current Natural Gas Market Mechanisms …

and the natural gas upstream policy and legisla-tion is based mainly on State Council regulationsand rules implemented by the industrialadministration.

In terms of oil and gas mineral rights man-agement, the main legislation applicable is theMineral and Resources Law (1996), the Rules forImplementation of Mineral and Resources Law(1994), the Mineral and Resources ExplorationPlots Registration Administrative Measures, theMineral and Resources Extraction RegistrationAdministrative Measures and the ExplorationRights and Mineral Rights Transfer Administra-tive Measures. Regarding overseas co-operation,the main legislation applicable is the Regulationsfor Overseas Co-operation in the TerrestrialExtraction of Oil Resources and the Regulationsfor Overseas Co-operation in the MarineExtraction of Oil Resources. Regarding taxationand price regulation, apart from the general legalprovisions in Enterprise Income Tax Law and theVAT Temporary Regulations, the main source oflegislation is the Temporary Regulations ForResources Taxation, the Administrative Regula-tion for the Collection of Mineral ResourcesCompensation and the Exploration and MineralRights Usage Fees and Remuneration Adminis-trative Rules, in addition to notices issued by theNational Development and Reform Commissionrelating to adjustment of gas prices.

The sets of mineral administrative measuresthat apply to coalbed methane and shale naturalgas differ from those that apply to conventionalnatural gas, and mainly consist of policy-typedocuments issued by the administration,including:

• Certain Suggestions in Relation to Acceler-ating Coalbed Methane (Coal-mine Gas)Extraction and Usage (2006) and Suggestionsin Relation to Further Accelerating CoalbedMethane (Coal-mine Gas) Extraction andUsage, issued by the General Office of theState Council;

• Temporary Administrative Regulations forthe Exploration and Extraction of CoalbedMethane, issued by the Coal IndustryMinistry;Ta

ble

11.5

(con

tinued)

Gas

storage

facility

Owner

Location

Type

Designed

capacity

(�10

8m

3 )

Designedworking

gascapacity

(�10

8m

3 )

Working

gascapacity

alreadycreated

(�10

8m

3 )

Highestinjection

rate

(104

m3 /day)

Datebroughtonlin

e

Xiangguosi

China

NationalP

etroleum

Corporatio

nChongqing

Depleted

reserve

231380

2013-06

Suqiao

China

NationalP

etroleum

Corporatio

nHuabei

Depleted

reserve

67.4

230.2

1300

2013-06

Jintan

China

NationalP

etroleum

Corporatio

nJiangsu

Salt

caverns

2617.20

1.3

–2007

Yunying

China

NationalP

etroleum

Corporatio

nHubei

Salt

caverns

6–

2015

Total

299.9

179.44

28.6

Source

China

NationalPetroleum

Corporatio

n(CNPC

)

11.2 Current State of China’s Natural Gas Regulatory Systems 271

• Notification Concerning Enhancing Admin-istration of Overall Exploration and Extrac-tion of Coal and Coalbed Methane andNotification Concerning Enhancing Supervi-sory and Administrative Work Relating toShale Gas Resources Exploration andExtraction, issued by the Ministry of Landand Resources;

• Shale Gas Development Planning (2011–2015), Notification Concerning VariousIssues in Relation to Standardisation ofApproaches to the Development of the CoalGasification Industry, issued by the NationalDevelopment and Reform Commission;

• Notification in Relation to Subsidy ProvisionPolicies Relating to Development and Usageof Shale Gas, issued by the Ministry ofFinance; and

• Coalbed Methane Industry Policy, issued bythe National Energy Administration.

2. Natural gas upstream administrativebodies

A multi-departmental shared administrativeregime is employed. Apart from the Ministry ofEnvironmental Protection and the State Admin-istration of Work Safety, which are responsiblefor technical supervision of environmental pro-tection and production safety, the main upstreamadministrative departments are the NationalDevelopment and Reform Commission, theNational Energy Administration, the Ministry ofLand and Resources and the Ministry of Com-merce, while the Ministry of Finance workstogether with the industrial administration toprovide financial and taxation policy that pro-motes the development of the industry.

The National Development and ReformCommission (NDRC) is responsible for carryingout research into economic and social

Table 11.6 Main provincial capital and urban gas enterprises in 2012

No. Provincialcapital/city

Gas enterprise No. Provincialcapital/city

Gas enterprise

1 Beijing Beijing Gas Group 17 Shijiazhuang ENN

2 Shanghai Shanghai Gas (Group)Company Ltd.

18 Jinan Towngas, China Resources Gas

3 Tianjin Jinran Huarun 19 Nanjing Towngas, China Resources Gas,China Gas Holdings

4 Chongqing Chongqing Gas 20 Zhengzhou China Resources Gas

5 Guangzhou Guangzhou Gas 21 Wuhan Towngas, China Resources Gas,China Gas Holdings

6 Shenyang Shenyang Gas 22 Changsha ENN

7 Taiyuan Taiyuan Coalgas 23 Fuzhou China Resources Gas

8 Hangzhou Hangzhou Gas 24 Nanning China Gas Holdings

9 Hefei Hefei Gas 25 Hohhot China Gas Holdings

10 Nanchang Nanchang Gas 26 Xi-An Towngas

11 Haikou Minsheng Gas 27 Harbin Kunlun Gas

12 Guizhou Guizhou Gas 28 Kunming Kunlun Gas

13 Yinchuan Hanas 29 Lanzhou Kunlun Gas

14 Urumqi Xinjiang Gas 30 Xining China City Natural GasInvestment Co. Ltd.

15 Changchun Changchun Gas 31 Lhasa Kunlun Energy Co. Ltd.

16 Chengdu Chengdu Gas

272 11 China’s Current Natural Gas Market Mechanisms …

development policy on behalf of the StateCouncil and is involved in maintaining a balancewhile carrying out macroscopic adjustmentsthrough reforms to the overall economic system.When it comes to drafting policy in relation tothe natural gas industry and industry regulation,it mainly plays a role through:

• drawing up and organising strategy in relationto the national economy and social develop-ment, mid- to long-term planning and annualplanning;

• prediction, forewarning and guidance infor-mation, making suggestions in terms ofmacroscopic policy, co-ordinating solutionsfor important issues affecting the progress ofthe economy, regulating economic activity,emergency interventions and transport-relatedco-ordination;

• involvement in establishing fiscal policy,currency policy and land policy, drawing upand organising the implementation of pricingstrategy and the supervision and monitoringof pricing strategy implementation;

• organisation of drafting of comprehensiveschemes relating to economic reforms,co-ordinating specific reforms to the eco-nomic systems, providing leadership in eco-nomic reform trials and in reform trialregional work; and

• authorisation, approval and auditing of majorconstruction projects, projects with majorforeign investment, major overseas resourcedevelopment investment projects and projectsrequiring investment of large quantities offoreign currency.

The main duties of the National EnergyAdministration in terms of drawing up naturalgas industrial policy and industrial supervisioninclude:

• drafting of relevant supervisory and admin-istrative legislation and its delivery for ratifi-cation and passing into law; drawing up andorganising implementation of natural gasdevelopment strategy, planning and policy;advancing institutional reforms; drafting

relevant reform schemes; co-ordination inareas of development and reform where seri-ous issues exist;

• organising and establishing natural gasindustrial policy and related standards;approvals; checking and auditing of invest-ment in fixed-asset investment projects;

• forecasts and warnings; dissemination of datarelating to natural gas; involvement in oper-ational adjustments and emergency measuresin the natural gas industry;

• drafting of national natural gas planning andpolicy and management of its implementa-tion; monitoring of changes in supply anddemand in both domestic and internationalmarkets; proposals concerning ordering nat-ural gas storage equipment and suggestionsconcerning rotation and usage in addition toorganising the implementation of such activ-ities; approval or auditing of natural gasstorage equipment and installations andmonitoring and regulation of commercialnatural gas storage facilities;

• supervision of fair access to natural gaspipeline network installations;

• organisation and encouragement of interna-tional co-operation relating to natural gas;co-ordinating overseas resources develop-ment and exploitation; approval or auditing ofmajor overseas investment projects;

• involvement in establishing policy relating toresources, finance and taxation; environmen-tal protection and responses to climatechange; proposals concerning pricing adjust-ments and suggestions concerning totalimport and export quantities.

The Ministry of Land and Resources is amajor upstream administration for the natural gasindustry, and its main responsibilities in relationto natural gas industrial policy and industrialregulation are:

• organisation of drafting of developmentplanning and strategy;

• drafting of legislation, establishing regula-tions, policy, technical procedures andstandards;

11.2 Current State of China’s Natural Gas Regulatory Systems 273

• leading local government law enforcementand investigation and handling seriouscontraventions;

• organisation, drafting and implementation ofschemes relating to the application of mineralrights; handling rights applications; issuingexploration and development permits; audit-ing and authorisation of rights transfers;organisation and mediation in major rightsdisputes;

• standardisation and regulation of the rightsmarket; investigation of rights holders; mon-itoring and supervision of extractionoperations;

• regulation of the geological explorationindustry and reserves of mineral resources;control over geological exploration accredi-tation; geological data; geological explorationresults (it is legally entitled to gain fromresources financially);

• authorisation of plots for foreignco-operation; supervision of foreign involve-ment in exploration and extraction activities.

The main role of the Ministry of Commerce inthe regulation of the upstream natural gasindustry is the drawing up of natural gas importpolicy, in the course of which they co-ordinatewith other administrative departments regardingnatural gas imports.

3. Main legislative regime applying toupstream natural gas regulation

(I) Rights management

Grade I national supervision applies to theexploration and extraction of conventional natu-ral gas and shale natural gas, with unified plan-ning applicable to the exploration and extractionof coalbed methane and administration at variouslevels, while there are differences in terms ofadmittance to the industry.

Applications for exploration or extraction ofconventional natural gas are handled accordingto the Mineral and Resources Law and the min-eral and resources exploration and extraction

registration administrative measures, and requiresubmission of State Council documents approv-ing the creation of an oil company or theirapproval for oil or natural gas exploration orextraction, in addition to submission of evidenceof the identity of the legal representative of theexploration company. Exploration permits andextraction permits can only be issued afterchecking, after approval by an organisationstipulated by the State Council (the NationalDevelopment and Reform Commission or theNational Energy Administration) and after reg-istration with the Ministry of Land and Resour-ces. The threshold for admission to theconventional natural gas upstream field is there-fore set very high, and requires “the approval orpermission of the State Council”.

While Grade I national supervision alsoapplies to shale natural gas exploration andextraction, a notice issued by the Ministry ofLand and Resources about the encouragement ofshale natural gas exploration and developmentmonitoring and regulation outlines a procedurefor the sale of exploration rights based mainly ontendering and other such competitive approaches,with the aim of encouraging a variety of invest-ment entities to enter the shale natural gasexploration and extraction field. In 1994, theCoal Industry Ministry issued the CoalbedMethane Exploration and Extraction Adminis-tration Temporary Regulations, and this had nospecific accreditation requirements for companiesinvolved in the development of coalbed methane,while also promoting the use of foreign capitaland the adoption of advanced foreign technologyfor exploration and development of coalbedmethane.

(II) Pricing regulation

Due to the monopolistic characteristics of theupstream natural gas market, the upstream natu-ral gas price has been subject to long-term gov-ernment control. In June 2013, the NationalDevelopment and Reform Commission issued anotice relating to the adjustment of natural gaspricing. This notice mainly dealt with converting

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natural gas price regulation from anex-factory-based approach to a gate stationapproach, with the introduction of gate stationpricing regulation. The original “cost plus”approach to pricing was converted to a “marketnetback” approach.

Gate prices are government-guided prices,with a regulated maximum price, allowing sup-pliers and consumers to negotiate prices within arange beneath the maximum price.Government-guided pricing only applies tostate-produced terrestrial natural gas and impor-ted pipeline gas, while the prices of shale naturalgas, coalbed methane, coal-based gas and LNGhave been deregulated, now being determinedpurely by negotiation between suppliers andconsumers. The natural gas gate price is peggedagainst the price of alternative energy sources.The alternative energy sources adopted for thispurpose are fuel oil and LPG, with weighting of60 and 40% respectively. Distinctions are madebetween stock gas and incremental gas, with anapproach of “old approaches apply to old gas,new approaches apply to new gas”, and theincremental gas gate price is no longer based oncategory of use. According to a notice issued bythe National Development and Reform Com-mission, since the April 1, 2015, the pricing ofstock gas and incremental gas has been com-bined, with one approach to pricing beingapplied, and with deregulation trials adopting adirectly supplied gas-user gas-use gate price.

(III) Fiscal and taxation regimes

There are four categories of fiscal policy thatapply to the upstream natural gas sector:

• taxation and administrative fees in relation tothe extraction of natural gas resources—theseare mainly a resource tax, a mineral resourcecompensation fee, a mineral rights usage fee,a mineral rights cost and plot use fee etc.;

• taxation and administrative charges in relationto imported natural gas—a VAT tax rate of13% is applied to import, while some VATrefunds are available at import in relation to“state-approved natural gas projects”;

• the general tax applicable to all companies,such as company income tax and VAT etc.;

• the fiscal subsidies provided by the state inrelation to the development and usage ofnon-conventional natural gas resources; cur-rently the subsidy provided by central gov-ernment is 0.2 CNY/m3 for coalbed methaneand 0.4 CNY/m3 for shale natural gas.

(IV) Overseas co-operation

Overseas co-operation is based on the Regu-lations for Overseas Co-operation in the Terres-trial Extraction of Oil Resources of the People’sRepublic of China and the Regulations forOverseas Co-operation in the Marine Extractionof Oil Resources of the People’s Republic ofChina. China National Petroleum Corporationand China Petrochemical Corporation areresponsible for overseas terrestrial co-operation,while China National Offshore Oil Corporation isresponsible for overseas maritime co-operation.Based on a notice jointly issued in December2010 by four ministries including the Ministry ofCommerce and the National Development andReform Commission, China National PetroleumCorporation, China Petrochemical Corporation,China United Coalbed Methane CorporationLimited and Henan Coalbed Methane Develop-ment Company Limited are allowed to developoverseas co-operation in the coalbed methanesector.

11.2.2 Midstream MarketAdministrative System

1. Midstream natural gas administrativepolicy and legislation

Regulation of the midstream natural gasmarket is divided into economic supervision andtechnical supervision. Economic supervisionincluded pricing supervision and third-partyaccess etc.; technical supervision includes envi-ronmental supervision and safety supervision. Interms of supervisory policy and legal documents,apart from the Oil and Natural Gas Pipeline

11.2 Current State of China’s Natural Gas Regulatory Systems 275

Protection Law issued by the National People’sCongress in 2010, the main measures and regu-lations in force are:

• the Natural Gas Infrastructure Constructionand Operation Administrative Measures,issued by the National Development andReform Commission in February 2014;

• the Oil and Gas Pipeline Network InstallationFair Access Supervisory Measures (TrialImplementation), issued by the NationalEnergy Administration;

• the Natural Gas Development Planning Underthe 12th Five-Year Plan, issued by theNational Development and Reform Commis-sion; and

• Catalogue for the Guidance of Industries forForeign Investment (revised 2015), issued bythe Ministry of Commerce.

The Oil and Natural Gas Pipeline ProtectionLaw’s aim is to protect oil and natural gaspipelines, ensuring the security of oil and naturalgas pipeline transport, and this mainly provides alegal framework for technical supervision. TheNatural Gas Infrastructure Construction andOperation Administrative Measures providefairly wide-reaching legislation regarding super-vision of the midstream natural gas industry, andinclude natural gas infrastructure planning, con-struction and operation. They also include leg-islation covering natural gas market regulationand emergency guarantees. The Oil and GasPipeline Network Installation Fair AccessSupervisory Measures (Trial Implementation)provide the legal framework in relation to therequirement for fair access to natural gas infras-tructure, and establish the supervisory structures,supervisory duties and powers and modes ofsupervision that apply to ensuring fair access tonatural gas infrastructure. In the Catalogue forthe Guidance of Industries for Foreign Invest-ment revised by the Ministry of Commerce in2015, gas transportation pipelines and gas stor-age facilities are still listed as industries whereforeign investment is encouraged. The purpose ofthis is to indicate openness to investment byforeign businesses, but it does not relate to

construction project planning or approval, andhas even less weight when it comes to thesupervision of natural gas pipeline operation orstorage facilities. The Natural Gas DevelopmentPlanning Under the 12th Five-Year Plan pro-posed certain infrastructure targets and guaran-tees, and presented planning for a number ofpipelines and gas storage facilities and other suchmajor infrastructure construction projects, andthis is the main source of guidance in terms ofdevelopment of the natural gas midstream sector.

2. Natural gas midstream administrativebodies

Based on integrated upstream and midstreamoperational modes, oil companies both constructpipelines and other such infrastructure and selland transport natural gas that they producethemselves, so there is no conflict of interestsbetween the pipeline company and pipelineusers, and economic supervisory requirementsare low. As a result, there is no specialist regu-latory body. From the point of view of naturalgas industry regulation, China adopts anapproach whereby governing and regulation arecombined, but there are a number of differentbodies involved. The midstream natural gasadministration includes the National Develop-ment and Reform Commission, the NationalEnergy Administration and natural gas adminis-tration departments of People’s Governments atthe province, autonomous region and directlygoverned city levels, and these also takeresponsibility for economic supervision of themidstream natural gas industry. Technicalsupervision is carried out by geological, qualitymonitoring, environmental protection and pro-duction safety departments of local People’sGovernments.

The National Development and ReformCommission and the National Energy Adminis-tration are responsible for planning of nationalnatural gas infrastructure construction. The nat-ural gas administration departments of province,autonomous region and directly governed cityPeople’s Governments, on the other hand, act inline with national planning in drawing up natural

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gas infrastructure development plans for theiradministrative districts, submitting reports ofsuch activities to both the National Developmentand Reform Commission and the NationalEnergy Administration. Planning departmentsare responsible for approval, auditing andrecording of construction of natural gas infras-tructure. Authorisation documents relating tonatural gas infrastructure projects authorised orapproved by province, autonomous region anddirectly governed city People’s Governments aresubmitted to the National Development andReform Commission. Where a natural monopolyexists, natural gas infrastructure services aresubject to government pricing control, with theNational Development and Reform Commissionand pricing departments at province, city andautonomous region level being responsible fordetermining the natural gas infrastructure serviceprices. The National Energy Administration andbodies under its auspices are responsible forsupervisory work where it comes to fair access tonatural gas pipeline networks.

3 Midstream market supervision

Midstream market supervision mainlyinvolves establishing planning, project approval(authorisation), pricing control and enforcing thelaw etc.

The Natural Gas Development PlanningUnder the 12th Five-Year Plan issued in 2012was the first-ever natural gas-specific planning inChina. The main focus was to develop the naturalgas industry by proposing development targets,policy assurance measures and major construc-tion projects, and this provided guidance to leadthe way for business investors. Based on theregulations, natural gas infrastructure construc-tion projects required authorisation, approval orfiling by industrial administration departments; ifa project had not been authorised, approved orfiled, then that project could not commenceconstruction. Pricing for services in relation tonaturally monopolistic natural gas infrastructuresuch as pipelines is controlled by the govern-ment, with service charges being collected basedon prices set by government pricing departments.

Because “administrative measures” issued by theNational Development and Reform Commissionand the National Energy Administration fall intothe category of ministerial regulations, they donot carry weight in terms of establishingadministrative penalties. The punitive measuresavailable to supervisory departments are there-fore limited; apart from warnings and correctionorders, they mainly rely on pricing law,anti-monopoly law and contract law to enforcethe legal responsibilities of the relevantenterprises.

4. Midstream market regulation

In countries where reform of the natural gasmarket is advanced, such as the UK and the US,natural gas industry regulation mainly involvesmidstream regulation. This results in “supervi-sion of the middle with freedom at both ends”,thus creating an “X + 1 + X” market structure.In “X + 1 + X”, the first X is the upstreamsupplier, the second X is the downstream user,and the 1 in the middle is the midstream pipelinenetwork. “Supervision of the middle” refers toimplementing strict supervision of natural pipe-line network monopolies, enforcing a regime ofthird-party access and exerting control overpricing. Due to the long-term application ofmonopolistic operation to the upstream sector inChina’s natural gas industry and the unifiedmode of operation encountered in the midstreamand upstream sector, a third-party access regimehas never been established, and the majority ofregulation relating to pipeline transportation pri-ces stems from natural gas pricing requirements.

The first time that “fair access” was men-tioned was in the Natural Gas InfrastructureConstruction and Operation AdministrativeMeasures, issued by the National Developmentand Reform Commission in February 2014, andthe Oil and Gas Pipeline Network InstallationFair Access Supervisory Measures (Trial Imple-mentation), issued by the National EnergyAdministration. The Natural Gas InfrastructureConstruction and Operation AdministrativeMeasures stipulate that natural gas infrastructureoperators:

11.2 Current State of China’s Natural Gas Regulatory Systems 277

• should publicise information, including con-ditions of service provision, the proceduresfor obtaining such services and excess servicecapacity, and provide fair and just pipelinetransport, gas storage, gasification, liquefac-tion and compression services to all users;

• may not use infrastructure in a manner thatdiscriminates against other natural gasenterprises;

• where there is sufficient capacity, may notrefuse to provide services to users who satisfythe necessary conditions; and

• may not make unreasonable demands.

The Oil and Gas Pipeline Network InstallationFair Access Supervisory Measures (Trial Imple-mentation) defines the regulations relating to theconditions and procedures for handling useraccess applications and specific regulatorymethods in more detail.

11.2.3 Downstream MarketAdministrative System

The downstream natural gas administrative sys-tem includes supervisory bodies, policies andlegislation, in addition to main supervisoryregimes.

1. Supervisory bodies

There are users in the downstream natural gasindustry sector who are directly supplied by theupstream sector. There are also residential andcommercial users, small industrial users, dis-tributed power generation users and transportusers who are supplied with gas via urban dis-tribution networks. Where directly supplied userswith larger gas consumption are concerned, suchas gas for power generation, industrial fuels, gasfor use in chemicals etc., the focus of govern-ment economic supervision is mainly the price ofgas supplied and the fields in which gas is used.Currently, the National Development andReform Commission is responsible for issuingnatural gas pricing and natural gas use policy.

From the point of view of users supplied viathe urban distribution networks, the main focusof government economic supervision is industryplanning, control over admission to the gasindustry, project allocation, price regulation,emergency assurance and so on, and the mainobject of such supervision is the gas companies.According to the regulations laid out in theurban gas administrative regulations, the StateCouncil is responsible for the creation ofadministrative departments with responsibilityfor natural gas supervisory work at the nationallevel. According to the relevant laws and reg-ulations, People’s Government gas administra-tion departments at town level and above areresponsible for determining and adjusting pipe-line gas sales pricing, safety monitoring, qualityinspections and provision of firefighting ser-vices, while other departments are responsiblefor specialist technical supervision.

2. Policy and law

Supervision of the downstream natural gasindustry includes technical supervision and eco-nomic supervision. Technical supervision relatesto supervision of product quality, of standardsapplied in engineering and construction and ofsafety in production. Economic supervisionrelates to supervision of admittance to theindustry, of natural gas sales prices, of gas usesectors and of gas supply responsibilities. Gen-erally, within policy or legislative documents,there may be both technical supervisory contentand economic supervisory regulations. TheUrban Gas Supervisory Regulations issued in2010 are one such example of generalisedadministrative regulations, including both urbangas development planning and emergencyassurances, and covering areas of economicsupervision such as urban gas business and ser-vices, in addition to technical supervisory regu-lations relating to gas use, protection of gasinstallations, gas safety and prevention of acci-dents and their handling.

Certain specialist policies and legislation doexist in relation to downstream natural gas

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industry supervision. These mainly consist ofnatural gas usage policy and pricing regulationdocuments issued by the National Developmentand Reform Commission, and national urban gasdevelopment planning issued by the Ministry ofHousing and Urban Construction, as well asurban gas supervisory regulations issued in 2010by the State Council. Apart from this, contractlaw, emergency response law, product qualitylaw, pricing law, fire prevention law, productionsafety law, metering law, special equipmentsafety inspection law, safe administration ofdangerous chemicals regulations, housing con-struction and municipal infrastructure projectcompletion and inspection filing administrativeregulations and other such general law and reg-ulations are also dealt with by downstream nat-ural gas industry supervision.

3. Special business licence regime

In order to implement the reform demandsexpressed at the Sixteenth National Congressconcerning “increasing reform to monopolisticindustries, actively introducing competitionmechanisms”, in December 2002 the formerMinistry of Construction issued SuggestionsConcerning Accelerating the Rate of Marketisa-tion of Urban Utilities, which suggestedencouraging the involvement of social andoverseas capital in the form of sole ownership,joint ventures and co-operation in the construc-tion of municipal public utility infrastructure, toconstruct commercially operated municipal pub-lic utility facilities for water supply, gas supply,heating supply, waste water processing and wastetreatment; tendering would allow selection ofinvestment entities and would allowtrans-regional and cross-industry involvement inthe operation of municipal utilities enterprises,with special permits to be awarded by the gov-ernment for such business operations. In 2004,regulations in the Municipal Public UtilitiesBusiness Licence Administrative Measures sta-ted clearly that permitted municipal public utilityoperators are investors or operators of municipal

public utilities that have been selected by thegovernment on the basis of relevant laws, statutesand regulations according to a market competi-tion regime, and clearly outlines a regimewhereby they may trade in certain public utilityproducts or provide such type of services withina certain range and for a certain period of time.The special permits regime gives priority toappointments relating to specific businessschemes, via a tendering process that allowsselection of the best company, to which a specialoperators permit is awarded.

According to the Municipal Public UtilitiesBusiness Licence Administrative Measures,entities taking part in tendering for special busi-ness licences should:

• be a legally registered business entity;• have corresponding registered capital, instal-

lations and equipment;• have a good credit rating, be in good financial

condition and be capable of servicing anyoutstanding debt;

• have experience in such operations and havea good business record;

• have sufficient key technical, financial andoperational staff;

• present a realistic and feasible business plan;• comply with any other conditions according

to local laws and regulations.

After authorisation by People’s Governmentsat the directly governed city, city and town level,government departments could then sign a busi-ness licence agreement with the successful bidder(the company that was awarded the specialoperators permit), the content of which included:the specifics of the permitted business operation,its geographical extent, its scope and duration;product and service standards; methodsand standards for determining prices and fees andprocedures for their adjustment; ownership anddisposal of facilities; facility maintenance, updateand conversion; safety management; perfor-mance guarantees; termination or alteration ofterms of the permitted business operations;

11.2 Current State of China’s Natural Gas Regulatory Systems 279

liability for breach and methods of resolvingdisputes etc. Special business licence durationsdepended upon such factors as the type ofindustry, the scale of the operation and type ofbusiness and did not exceed 30 years.

4. Gas business licences

In July 2004, after the AdministrativeLicensing Law was issued, the original urban gascompany accreditation administrative regimewas rescinded, and the majority of provinces anddirectly governed cities drew up or revised localregulations and statutes to create a gas businesslicence regime. Clause 15 of the Urban GasSupervisory Regulations of 2010 states that thestate has adopted a business licence regime forgas businesses, and that companies involved inconducting gas business activities should satisfythe following conditions:

• they should satisfy the requirements of gasdevelopment planning;

• they should possess fuel gas sources and gasfacilities that satisfy the national standards;

• they should have a fixed business address, acomplete safety management regime and acomplete business plan;

• the main person responsible for the business,the production safety manager and opera-tional, maintenance and emergency repairstaff should all have undergone professionaltraining and have been found satisfactory;

• other conditions applicable according to legaland statutory regulations.

If these conditions are met, then the gasdepartments (at town level) and People’sGovernments (for larger areas) may issue gasbusiness licences. It is clear from these regula-tions that the standard for the award of a gasbusiness licence is “satisfactory” (satisfies theconditions), and as such, those that satisfy suchconditions should all be awarded businesslicences.

11.3 Challenges Facedby the Current System

11.3.1 Over-Centralisation of MineralRights and Lackof Exploration

There are already oil and gas exploration rightsregistered in relation to 4 million km2 acrossChina as a whole. Of these, 3.9 million km (over97%) belong to the three main oil companies,China National Petroleum Corporation, ChinaPetrochemical Corporation and China NationalOffshore Oil Corporation. Oil and gas extractionrights already registered cover an area of 118,000and 117,000 km2 (99%) of these belong to thethree main oil companies. The monopolisticposition of the three main oil companies in termsof upstream exploration is hardly the result offree competition, but is rather due to legalrestrictions and administrative monopolies.Based on the Mineral and Resources Law, theregulations governing mineral and resourcesexploration and the administrative measuresgoverning the registration of extraction plots,applications to carry out exploration and extrac-tion of oil and natural gas must be approved oragreed to by the State Council, but in actualpractice only a very small number of companiesever receive such authorisation or permission.

Even though the exploration and extraction ofshale natural gas, coalbed methane and othernon-conventional types of natural gas is nowopen to other types of company, the number ofplots actually accessible is limited, and the threemain oil companies continue to dominatenon-conventional natural gas extraction. Thereason for this is that, in the majority of cir-cumstances, non-conventional natural gas(mainly shale natural gas) plots coincide to alarge degree with conventional natural gas plots.Apart from the legal restrictions, there are issueswhereby it has not been possible to implementtotal third-party access to infrastructure, resultingin technical barriers arising in terms of extraction,

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and presenting difficulties for other companiestrying to enter the upstream sector of the naturalgas industry.

Due to the legal restrictions and the adminis-trative protection of these monopolies, the threemain oil companies virtually dominate all avail-able oil and gas exploration plots. However,there is still a major lack of exploration.According to the Mineral and Resources Explo-ration Plots Registration Administrative Mea-sures, owners of exploration rights should investnot less than 2000 CNY/km2 in explorationwithin one year of the date on which the explo-ration permit was issued, rising to5000 CNY/km2 in the second year and10,000 CNY/km2 in the third. The Mineral andResources Exploration Plots RegistrationAdministrative Measures were issued in 1998and were applied to all types of minerals, basedon today’s prices, and the level of investment thatwould be required for exploration for oil or gas(an annual exploration investment of10,000 CNY/km2) is unquestionably far too low.

In November 2014, the Ministry of Land andResources subjected China Petrochemical Cor-poration and Henan Coalbed Methane Develop-ment Company Limited to fines of CNY7,978,800 and CNY 6,035,500 respectively, andratified reduction of the extent of their explo-ration plots. The reason for this was that thesetwo companies had not been able to carry outexploration to the extent of their undertakings.Even though China Petrochemical Corporationand Henan Coalbed Methane DevelopmentCompany Limited had only completed 73 and51% of their undertakings in relation to explo-ration, their actual investment had alreadyreached a level equivalent to 11.6 times and3.6 times the level of investment required bylaw, respectively. According to China Petro-chemical Corporation’s annual accounts, ChinaPetrochemical Corporation’s investment inexploration in 2013 was only CNY 25.3 billion,which would be the equivalent of exploration of1,600,000 km2 of registered exploration rights,and based on this their average explorationexpenditure was only 15,800 CNY/km2. In actualfact, that CNY 25.3 billion also included the cost

of overseas exploration, therefore it should notall be allocated to areas of domestic exploration.

11.3.2 Bundling of Infrastructure,Low Utilisationand Blocking Accessto Upstream Markets

From the point of view of developing the naturalgas market, building pipeline infrastructure isenormously important. Construction of naturalgas pipelines and other infrastructure requiresmassive investment, with investment in back-bone pipelines often reaching between tens andhundreds of billions of CNY, and branchpipelines costing between billions and tens ofbillions. The structure of every country’s naturalgas market is different, so variations in gasindustry development and the types of infras-tructure investment entities will naturally differ.In the early development stages of the US naturalgas market, the upstream was very dispersed, andit was therefore often the downstream urban gascompanies that were responsible for extendingpipelines to oil and gas fields, where they boughtgas for transport to, and sale in, downstreammarkets. In China, the development of the naturalgas industry has followed the exactly oppositepath; there is a relatively high level of monopolyupstream, while downstream it is relatively dis-persed, and generally it is the upstream compa-nies that are responsible for construction ofpipelines and transport of natural gas for sale indownstream markets. In both cases, the approachadopted at the early stage involved bundling ofpipeline transport and natural gas sales, withpipeline transport enterprises using their ownpipelines to transport and sell natural gas.

Natural gas pipeline natural monopolies andbundling of business affects fair competitionbetween upstream enterprises. In the UnitedStates in 1938, the Natural Gas Act introducedcontrol over wellhead prices that continued for40 years. The initial aim was to prevent pipelinetransport companies from treating dispersedupstream producers unfairly. As described else-where, inappropriate wellhead price control

11.3 Challenges Faced by the Current System 281

eventually restricted the development of thenatural gas industry in the United States, result-ing in the severe gas shortages that occurred inthe 1970s. In 1985 and 1992, the Federal EnergyRegulatory Commission (FERC) issued Order436 and Order 636, which introduced third-partyaccess (TPA) and division of business, providingthe basic conditions for the formation of a highlyeffective competitive natural gas market, whilealso acting as a stimulus for the shale natural gasrevolution that has occurred in the US.

In February 2014, the Natural Gas Infras-tructure Construction and Operation Adminis-trative Measures and the Oil and Gas PipelineNetwork Installation Fair Access SupervisoryMeasures (Trial Implementation), issued by theNational Development and Reform Commissionand the National Energy Administration respec-tively, stated that natural gas infrastructureoperators should provide fair and open access totheir services. However, without strict supervi-sion, the “fair access” required by the Oil andGas Pipeline Network Installation Fair AccessSupervisory Measures (Trial Implementation) isactually “negotiated access” rather than fairthird-party access. On top of this, neither of thesetwo measures actually require the division ofpipeline services from natural gas sales business.Although there is currently no actual evidencethat bundled natural gas pipeline business oper-ations act as an obstruction to entry to theupstream fields of exploration and extraction, inthe second half of 2014, against the backdrop ofa major drop in international oil prices, bundledoperation of LNG receiving stations andlong-term agreements in relation to gas priceswere definitely responsible for obstructing theimport of low-priced LNG from the internationalmarkets.

11.3.3 Irrational Pricing Mechanisms,Which DampenIncentive to Build GasStorage

The pricing reforms in 2013 were a major stepforward in terms of liberalisation of the

mechanisms that go to shape natural gas prices.However, prices are still not determined by themarket; the transition from “cost plus” to “marketnetback” has only altered the method applied topricing, rather than changing the actualprice-determining mechanism. There are a lot ofartificial factors at play in the choice of alterna-tive energy source type, and these may notactually reflect the market value of natural gas.Taking the United States as an example, between2000 and 2008, the price of fuel oil continued torise while the price of natural gas virtually stayedthe same. In 2010, with the arrival of the shalenatural gas revolution, prices of fuel oil andnatural gas began to deviate, with fuel oilincreasing in price by one third, while the naturalgas price dropped by two thirds. Against thebackdrop of the widespread adoption of energysaving, emissions reduction and pollution con-trol, the demand for coal dropped, as did theprice, while the demand for gas continued togrow, as did the price, their prices changing inopposite directions. Therefore, adopting the priceof coal to determine the price of natural gasmakes no sense. Even if one tries adopting fueloil and LPG as references, the changes in theirprices still don’t fully reflect the changes insupply and demand in the natural gas market, dueto the differences in their uses and the difficultiesin fuel conversion, and this may result in inves-tors and natural gas users being exposed toerroneous market signals.

According to the pricing reforms of 2013, thenatural gas gate station price was adjusted once ayear based on the alternative energy source pricesagainst which it is pegged, gradually transition-ing to six-monthly and then quarterly adjustment.Regardless of whether adjustments take placeonce a year or at six-monthly or quarterly inter-vals, this year’s natural gas price is still based onlast year’s alternative energy source prices. Bymaking an adjustment once each quarter, thewinter natural gas price is based on the autumnalternative energy source price. Warmer tem-peratures in autumn result in there being lessneed for heating and a relatively low demand forenergy sources. Adopting the autumn alternativeenergy source price when deciding the price of

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gas for the peak gas use winter season is coun-terintuitive. So with a government-determinedprice based on the “market netback” approach,adjusted once a year or once each quarter, there islimited scope for adjustment and no capacity toreflect changes in supply and demand in thenatural gas market up to the actual moment whenthe decision is made. Such an approach is not anattractive proposition to natural gas companies,given the massive levels of investment requiredto construct natural gas storage facilities.Unsurprisingly, gas storage facility working gascapacity in the US is between 18 and 20%of annual consumption, while in China it is only2–3%.

11.3.4 Downstream PipelineOperator RegionalMonopoliesand Cross-SubsidisingBetween Different Users

Although the reform of public utilities that star-ted in 2002 resulted in competition in terms ofmarket admission, it also had the effect of rein-forcing monopolistic business operations. Com-panies that were awarded special businesslicences were allowed to carry out bundling ofnatural gas sales and network distribution over aperiod of time and within a certain range, thusexcluding the possibility of competition occur-ring with other companies. Not only did theseother companies encounter problems supplyinggas to end users via urban gas networks, suchactivities as construction of pipelines to supplyend users directly were also seen as aninfringement of the special business licencesawarded to urban gas companies. In addition tovarious urban gas companies being awardedspecial permits for supply of gas on the urbanlevel via the tendering process, some provincesalso set up provincial pipeline network compa-nies, which then enjoyed provincial monopoliesin purchasing and sales of natural gas. As aresult, other companies were prevented frominvesting in and constructing natural gas pipeli-nes in those provinces.

• Due to the monopolistic nature of urban nat-ural gas networks and the bundling of salesand distribution, government-set pricing isgenerally applied to natural gas sold by urbangas companies. There are issues where pric-ing of urban gas is concerned.

• The pricing mechanisms are inflexible—sincethere is a mismatch between upstream anddownstream pricing, the downstream pricecannot immediately reflect changes inupstream gas source prices.

• It is difficult to monitor gas supply costs, andthe pricing methods are somewhat opaque, sourban gas pricing departments find it hard togain a clear understanding of the actual costof gas supplied to urban gas companies, andthere is no unified pricing method.

There is a mismatch between the natural gassales price and the cost of gas supplied, withcross-subsidising occurring between differentusers, as industrial and commercial users (whohave a low-cost of gas supply) pay a high pricefor their natural gas and a low natural gas price isapplied to residential users (with a high-cost gassupply). In view of the cross-subsidising thatexists between different users and the govern-ment control over residential user gas prices, itmakes sense to some degree that urban gascompanies then prevent upstream enterprisesfrom developing direct supplies to users withintheir operational jurisdiction.

11.3.5 Incomplete SupervisorySystems and InsufficientSupervisory Capability

The laws that apply to natural gas are not com-plete, and this is not only reflected in the rela-tively few levels of legislation, with the majorityof regulatory documents being ministerial regu-lations and there being no specific natural gaslaw, but also the fact that in certain sectors thereare still no administrative regulations at all. TheMineral and Resources Law only requires sub-mission for “authorisation or approval by theState Council”, but does not actually define

11.3 Challenges Faced by the Current System 283

clearly what kinds of company can actuallyreceive the “authorisation or approval” of theState Council. Although there is a fairly highhierarchical structure in Regulations for OverseasCo-operation in the Terrestrial Extraction of OilResources and Regulations for OverseasCo-operation in the Marine Extraction of OilResources, this is only applicable to foreignco-operation in extraction. The Oil and NaturalGas Pipeline Protection Law is the onlyadministrative-type document dealing with theoil and natural gas industry at the legal level, butit was enacted to protect oil and natural gaspipelines and thereby ensure oil and natural gastransport security, and thus it mainly covers thelegal issues of technical supervision. The NaturalGas Infrastructure Construction and OperationAdministrative Measures provide a fairly com-prehensive legal framework for supervision ofthe midstream natural gas industry, but lack forcebecause they are merely ministerial regulationsissued by the National Development and ReformCommission and thus lack hierarchical structureand are not particularly binding. The Oil and GasPipeline Network Installation Fair AccessSupervisory Measures (Trial Implementation)provides the administrative framework toimplement fair access to natural gas infrastruc-ture; however, there are drawbacks in terms ofthe practicality of its application, with fair accessactually being “negotiated access”. In terms ofthe natural gas industry downstream sector, thereare no legal documents providing an adminis-trative framework, the legal document at thehighest hierarchical level being the Urban GasAdministrative Regulations.

There is no specific natural gas industry reg-ulator, and, apart from the areas of the environ-ment, production safety and product quality

supervisory departments, industry regulationadopts separate supervision of the upstream,midstream and downstream sectors, withco-operation and supervision divided betweendifferent departments, relying on a combinedgovernmental supervisory approach. Under thismultifaceted approach to regulation, natural gassupervisory functions are distributed between anumber of departments, and inevitably there is acertain amount of duplication of roles as well asareas that are not fully covered. For example, theMinistry of Land and Resources, the NationalDevelopment and Reform Commission and theNational Energy Administration all have thepower to decide industrial development planningand structure, to draft legislation and to establishadministrative policy, while to some extent thereare also jurisdictional conflicts between centralgovernment departments and local governmentdepartments.

With such a combined governmental super-visory regulatory system, there is a serious lackof supervisory input. For instance, the schemeregulation drafting team in the oil and gas sectionof the National Energy Administration whosearea of responsibility is the “three establish-ments” (establishing functionality, establishingstructure and establishing draft regulations)comprises less than 20 persons to cover thewhole of China’s oil and gas industry. Moreover,they are responsible not only for determiningindustrial development planning, drafting leg-islative framework and determining departmentalprocedures and industrial development strategy,but also for such supervisory functions asauthorisation, surveying, co-ordination andimposition of penalties on specific individualprojects, as well as the administration of work inrelation to national strategic oil and gas storage.

284 11 China’s Current Natural Gas Market Mechanisms …

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11.3 Challenges Faced by the Current System 285

12International Experienceof Liberalisation and Evolutionof Natural Gas Markets

During the liberalisation of their natural gasmarkets, the United States and the UnitedKingdom both underwent a reform process thatinvolved a transition from government supervi-sion and gradual deregulation. This providesvaluable experience to draw on in various areas,including natural gas exploration and develop-ment, storage and transportation, pricing mech-anisms, market trading and institutionalguarantees.

12.1 Incentivising New Entrantsand Establishing CompetitiveNatural Gas Markets

From comparisons of the state of development ofthe natural gas markets of six countries andregions, it can be deduced that a competitivenatural gas market requires the involvement ofentities of a certain size (Table 12.1). The UnitedStates and Britain are the most typical competi-tive markets, and reflect the involvement of, andhigh levels of competition between, a multitudeof different entities in many areas of the market,including exploration and extraction, storage andtransportation, wholesale and retail, and trading

centres. By comparison, in China, Japan andSouth Korea there is a lack of competition;upstream and midstream business is mainlymonopolised by oligarchs and there has been nodivision of production, storage, transportation orsales operations.

A competitive, reactive and fluid natural gasmarket should have the following characteristics:

• a greater number of entities, allowing com-petition in the upstream and midstream mar-ket sectors to provide diversified services toconsumers, for which funds can be raisedfrom investors;

• competitive prices at both the wholesale andretail levels;

• non-discriminatory access to pipelines, gasstorage, LNG receiving stations and othersimilar infrastructure.

12.2 Opening the Upstream Sectorto Competition

Availability of resources is a precondition ofnatural gas usage, so, looking at the natural gasindustry as a whole, upstream productiondepartments have virtual control over the opera-tion of the whole industrial chain and the distri-bution of returns. As a result, opening upupstream exploration and development to newentrants is of major importance to the develop-ment of the natural gas market.

* This chapter was overseen by Xiaoming Wang fromthe Development Research Center of the State Counciland Mallika Ishwaran from Shell International. It wasjointly completed by Yusong Deng, Jiaofeng Guo,Shouhai Chen from China University of Petroleum andQingle Wu from Shell China. Other members of thetopic group participated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_12

287

In developed European countries and in theUnited States, the natural gas exploration anddevelopment field is for the most part a com-petitive market, and this is closely related to thesystem of access to mineral rights. For instance,the privatisation of land ownership (and resour-ces that lie beneath it) has been effective inencouraging exploration and development ofnatural gas, while also creating the conditionsnecessary for the shale natural gas revolution.The approach adopted in The Netherlands of“50-50 state-private ownership” has acted as amajor stimulus in encouraging exploration fornatural gas resources. The government generallyimplements a system of business licences,including mineral rights release mechanisms, forany companies that have been awarded mineralrights, thus avoiding hoarding of rights anddelayed development. In the UK, for example,companies involved in bidding for mineral rightsare expected to strictly abide by exploration and

development requirements, otherwise they arelikely to lose their licences. However, such asystem requires strict supervision by the regula-tory body.

However, natural gas resources differ from theaverage commodity in that not only do they havea value as a raw material, but access to suchresources is also accompanied by massive profitsand, in addition, they have a strategic value thatderives from their relatively large influence onthe national economy as a whole. It is due to suchfactors that in recent years, resource holderssuch as Russia and Middle Eastern and SouthAmerican countries have been exerting ever-tighter control over their oil and gas resources. Inlight of this, the problem of how to increaseactivity in the upstream exploration and devel-opment field, while also ensuring that themajority of profits remain within the country, inaddition to ensuring greater energy security forChina, deserves greater consideration.

Table 12.1 Main characteristics of natural gas markets of various countries and regions

Natural gas index Type USA EU UK Japan S.Korea

China

Supply (bcm/year) Domesticproduction

689 269 38 3 0.5 115

Net imports 37 231 39 123 53 49

Consumption(percentage of total bysector %)

Power 40 30 30 65 50 15

Industry 20 20 10 5 20 45

Transport pipelines (km) 500 k 200 k 8 k 5 k 4 k 50 k

Wholesale competition ✓ Limited(oligarchicmonopoly)

✓ Limited(oligarchicmonopoly)

X X

Open access Upstream ✓ ✓ ✓ ✓ X X

Transportation ✓ ✓ ✓ ✓ X X

Distribution Diversified Diversified ✓ X X X

Division of ownership of transportationand sales

✓ Diversified ✓ X X X

Independent (federal) market rights ✓ ✓ ✓ X X X

Fluid market centre ✓ ✓ ✓ X X X

Note Data is for 2013 (except natural gas consumption levels for China, which are based on 2011 data from powergeneration and industrial departments)Source Vivid Economics, based on IEA, EIA, Chinese Government and ENTSOG data

288 12 International Experience of Liberalisation…

12.3 Orderly and GradualImplementation of PipelineAccess Policies

Between the 1980s and the present day, policyregarding the regulation of natural gas pipelineshas been reformed in both the United States andthe European Union, resulting in the creation ofan independent, open natural gas transportationsystem. The increased level of supervision overthe operation of natural gas pipeline networks(i.e. the aspects that usually attract naturalmonopolies) has ensured pipeline and networkinterconnectivity and access to services for thirdparties. The process by which this was achievedin general consisted of three stages.

In the first stage, pipelines were encouraged toprovide transportation services to third parties,while government regulation was strengthened.This stage may be seen as a period of preparatorywork for the encouragement of third-party access.However, governments do not force oil compa-nies to provide non-discriminatory services interms of access to their pipelines; incentives areprovided to companies that provide access, and atthe same time the gas end user is allowed to sign

contracts directly with producers. This procedureallows feasibility to be examined and enables thediscovery of any problems that may exist inimplementing third-party access to pipelines. Atthe same time, during this stage, the governmentcontinues to enhance its supervisory capabilities,with the gradual creation of an independent,unified, impartial and effective natural gasindustry regulatory framework. This is in factpreparatory work that will allow the reform ofsupervisory capabilities and the formation of theteams necessary to carry this out.

In the second stage, pipeline third-party accessis enforced. This effectively eliminates the bund-ling of natural gas sales and pipeline transport. Thegovernment issues the relevant regulations thatmake it obligatory for natural gas infrastructureoperators to provide fair and just access to pipelinetransport, gas storage, gasification, liquefactionand compression services to all users.

In the third stage, independence of pipelinetransportation services is encouraged. The naturalgas pipeline businesses of upstream/midstream/downstream integrated companies are split fromthem, creating a number of independent pipelinecompanies, after which creation of the oil and

1985 Order 436 Allowing users to sign contacts directly withmanufacturers, encouraging the provision of pipeline services to third parties

USA

EUROPE

1978 Natural gas policyencouraging pipelines to provide access to their transport services

1992 Order 636 Completely removedthe “bundling” of natural gas sales withpipeline transport

2000 Order 637 Further removal of“bundling” betweennatural gas sales andpipeline transport

1998 The first Gas Directive required non-discriminatoryaccess to 20% of the market in transport services,introducing the concept of “unbundling” withoutbeing obligatory

2009 The third Gas Directive was responsible for pipeline transport services becoming independent, giving customers the freedom to choose orchange supplier

2003 The second Gas Directivemade it obligatory to“unbundle”, and launchedthe proposal that households should be free to choose theirnatural gas supplier

Fig. 12.1 Timeline of development of pipeline regulatory policy in the United States and Europe

12.3 Orderly and Gradual Implementation of Pipeline Access Policies 289

natural gas pipeline supervisory system can becompleted (Fig. 12.1).

Analysis of experience in the United Statesindicates that, from start to finish, reform of pipe-line policy took more than 20 years, while in theEUtheprocesshas taken10 years, soclearly this isa fairly slow process and cannot be achievedovernight. Moreover, pipeline reform in both theUS and the EU involved a process of encouragingthird-party access, followed by obligatory access,which was then followed by the splitting up ofupstream/midstream businesses. This is the pat-tern of reform best suited to the natural gas indus-try, and deserves further study and emulation.

The development of US natural gaspipeline regulatory policyIn terms of structure, the structure of theearly natural gas industry in the UnitedStates was similar to that encountered todayin China: producers sold natural gas topipeline transportation companies, andpipeline transportation companies then soldthe natural gas to local distribution com-panies, with the natural gas being sold to theend user by the local distribution company.The natural gas sales price was controlledby federal government, and the price ofnatural gas sold to the end user by the localdistribution company was controlled bylocal government institutions. The admin-istration had virtual control over all parts ofthe natural gas industry, and the state wasnot only responsible for supervision of thenaturally monopolistic pipeline transporta-tion sector, but also for the competitivesectors of the natural gas industry (such asproduction and wholesale supplies). Thestrict regulation by the state resulted notonly in natural gas companies being placedunder a great deal of pressure, but also inabnormal development in terms of naturalgas prices and consumption. The excessiveregulation of natural gas producers led tothe gas supply shortages encountered in theUnited States in the 1970s.

In order to remove the monopolies thathad resulted from closed-type industrial

operations, and to encourage andco-ordinate development in the natural gasindustry, the United States governmentbegan to adjust its policies towards naturalgas industry regulation, and as a result nat-ural gas pipeline regulatory policy under-went four main rounds of revision. In 1978,the Natural Gas Policy Act (NGPA) intro-duced a staggered process for relaxation ofnatural gas wellhead pricing controls, at thesame time as encouraging pipelines to openup access to their transport services. In1985, the Federal Energy RegulatoryCommission (FERC) issued Order 436,which put pressure on pipeline transportcompanies of different states to separatesales and transport functions, while intro-ducing competition mechanisms that gavenatural gas end users and manufacturersmore freedom of choice. In 1992, FERCissued order 636, which required statepipeline companies to separate natural gassales from pipeline transport and establishseparate companies to handle sales. Byadopting pipeline usage rights, this ordereliminated the widespread unfair competi-tion largely associated with the supply ofnatural gas by state pipeline companies. Italso introduced procedures whereby con-tracted transport could be sold on, allowinga “firm shipper” (any user of pipelinetransport) to buy transport capacity fromanother firm shipper with excess transportcapacity. In 2000, FERC then issued order637, which went further, completing theunbundling of gas supplies and transportservices.

The development of European naturalgas pipeline regulatory policyEurope is one of the three main globalnatural gas-consuming regions, and in thelast 40 years, natural gas’s share of overallenergy consumption has continued togrow. At the same time, the businessmodes and regulatory systems applied to

290 12 International Experience of Liberalisation…

the natural gas industry in Europe haveundergone continual adjustment. The nat-ural gas industry regulatory systems andpolicies of each individual member coun-try of the European Union are establishedwith reference to “directives” provided bythe European Union. If one looks at thedevelopment of the European natural gasindustry over the last 10 years, theEuropean Union issued three main direc-tives, and a major component of theserelates to encouraging the market liberal-isation of natural gas pipelines.

In 1998, The EU issued the First GasDirective, providing the impetus for theacceleration of the liberalisation of theinternal European natural gas market. Thisdirective proposed that in order to ensurethe establishment and efficient operation ofa European internal natural gas market,each country within the EU had a duty toensure fair competition in terms of trans-port, storage and distribution, whilerequiring that all members should completerevision of their legislationwithin twoyearsof the directive taking force. In terms ofpipeline policy, the directive recommendedthe opening of a 20% non-discriminatorymarket access, with the introduction of theconcept of “unbundling”, without it beingobligatory.

In 2003, the EU issued the Second GasDirective, which required that all memberstates adhere to the regulations concerningthe single market and adjust their ownstatutes, requiring that the natural gasmarket be opened to the non-residentialusers of all European countries before July2004. Integrated companies had to com-plete the legal dismantling of their pipelineand marketing businesses, followed by theopening of natural gas markets to all usersbefore July 2007, finally achieving the aimof allowing the consumer freedom ofchoice of gas supplier. Regarding pipelinepolicy, the enforcement of regulationsrelating to unbundling resulted in house-holds being given the right to freelychoose their natural gas supplier.

In 2009, the EU issued the ThirdInternal Energy Market Package (alsoknown as the Third Package), whichbrought into force EU energy industryreforms. Based on these new reforms,large power and gas companies had toselect one of the following three reformschemes:

• ownership unbundling, which requirescompanies to sell their distribution net-work, thus completing the separation ofthe manufacturer from the network;

• unbundling of business operations,which, while allowing retention ofownership of distribution networks,required the establishment of an inde-pendent company (known as an “in-dependent system operator”) whowould be responsible for the operationof the gas distribution network;

• unbundling of managerial responsibil-ity, allowing the ownership and man-agement of gas distribution networksbut requiring a subsidiary to managethe gas distribution network andentailed ensuring managerial andpolicy-making autonomy (known as an“independent transmission operator”).

These reforms also required that eachcountry establish an independent regula-tor, responsible for ensuring that largeenergy companies actually implementedthis “division of production and supply”and for ensuring that the rules that apply tofree competition in energy markets wereput into play.

12.4 Third-Party Access: The FirstStep to Infrastructure Reform

In the natural gas industrial chain, upstreamproduction and downstream sales are both sec-tors to which natural monopolies do not apply,and as such, efficiency can be improved by theintroduction of market competition. Operation of

12.3 Orderly and Gradual Implementation of Pipeline Access Policies 291

midstream assets such as pipelines, on the otherhand, exhibits the characteristics of a naturalmonopoly, with high fixed-cost investment andrelatively low operational and managementcharges. There is thus a rationale for operation ofpipeline services by a single company being themost effective approach to operation. This in turnis effective in reducing the overall operationalcost to society. The special characteristics ofmidstream asset natural monopolies are one ofthe reasons that they are not exposed to thepressures of market competition, and to someextent they also dominate the markets. As a resultof this, we recommend that greater regulation ofmidstream pipeline assets is required, to preventcompanies that occupy a position that can beconsidered a “natural monopoly” from abusingtheir power to influence markets and extractever-higher levels of monopolistic profits.

Generally, supervision of midstream assetsconsists of a number of approaches: regulation offee standards applied to pipeline transportationand other such infrastructure, implementation ofinfrastructure third-party access and division ofownership. In order to prevent monopolisticenterprises extracting extremely high monopo-listic fees for midstream services, the governmentneeds to investigate actual operating costs andreasonable profit levels in order to establishreasonable charging standards. Apart from this,independent owners of midstream assets mayalso take advantage of their market dominance toincrease pipeline transportation costs or restrictnatural gas transportation, and this in itself is alsoresponsible for reduced upstream and down-stream competition, while also reducing pipelineusage. To prevent owners with natural monopo-lies over infrastructure taking advantage of theirmarket position, and to ensure that all otherparties have fair access to usage of pipelines andother infrastructure, the government is generallyrequired to exert a supervisory influence, and thisis exactly what is being referred to as thethird-party access (TPA) regime.

International experience has demonstrated thatthird-party access policies balance out the eco-nomic interests of the owners of midstream

pipelines and upstream and downstream pro-duction and consumption. This is not only ben-eficial in that it allows full use to be made of thepotential of such infrastructure, but also in termsof attracting capital investment into the infras-tructure construction sector

Regulatory policy and its effects in the UKprovide excellent proof of this. Between the1960s and the 1980s, when the North Sea oilfields were being developed on a significantscale, the production and transportation of Britishgas was led by only a few major companies.However, as the yield of these oil and gas fieldshas dropped, large companies have begun to findit hard to obtain satisfactory benefits, whilereceiving stations and pipelines have redundantcapacity. At the same time, many small enter-prises have entered the upstream field, develop-ing small-scale oil and gas fields, using thepipelines of the larger companies to transporttheir oil and gas products. There is a lack of legalframework, and thus the potential exists for dis-putes to occur between the owners of infras-tructure and the owners of oil and gas fields.Indeed, throughout the 1990s there was a worrythat the cost of usage of infrastructure wasbecoming too high in relation to the costs andrisks associated with the development of smalloil and gas fields.

In order to resolve this situation, between the1990s and the early 21st century, the Britishenergy regulator (or the Department of Energyand Climate Change as it is now known) estab-lished a new access negotiation procedure,accompanied by a raft of legal and regulatorymeasures that reduced stakeholders’ uncertaintiesat the same time as providing a regulatoryframework with a legal basis and arbitrationmechanisms that became a foundation via whichnegotiations could be completed in a manner thatbenefited both stakeholders. With the gradualappearance and introduction of this legal andregulatory framework, the natural gas marketswere able to develop further, which benefited allthe stakeholders concerned. This allowed smallerenterprises to enter the larger oil and gas explo-ration market, which in turn offered further

292 12 International Experience of Liberalisation…

benefits to the owners of infrastructure, reducingthe cost of redundant infrastructure, while thegovernment also benefited in terms of reducedunemployment and an increase in tax revenues.

A well-designed third-party pipeline accesspolicy and regulatory framework should satisfythe following conditions:

• the policy should be effective, with the reg-ulator being responsible for drafting andimplementing policies relating to duties andstandards;

• appropriate pricing, with the regulator pro-viding a framework, allowing investors andusers to reach agreement on pricing in termsof TPA and appropriate returns mechanisms;

• risk avoidance, requiring the regulatoryframework to be stable and reliable, in a waythat reduces the risks to the investor and theuser to the minimum.

Third-party access policy frameworks willaffect different types of natural gas markets indifferent ways. For instance, Japan is a typicalnatural gas importer, being incapable of achiev-ing competition between upstream manufactur-ers, therefore TPA policy is limited. However,where China with its continuously growingmarkets is concerned, a regulatory frameworkoffers significant benefits, providing a stimulusfor investment in the midstream field.

12.5 Unbundling: An ImportantElement of Liberalisationof Natural Gas Markets

As mentioned previously, regulation that appliesto the midstream sector generally involvesapproaches such as pricing standards appliedbeing to infrastructure such as transport pipeli-nes, the implementation of third-party access tosuch infrastructure and the unbundling or parti-tioning of ownership. In practice, even when thegovernment establishes the principles ofthird-party access, monopolistic companies still

have many methods of ostracising third parties,for instance by a lack of transparency regardingavailable pipeline transport capacity or pricing,or by contractual obligations such as conductingobligatory technical research etc. Strict applica-tion of the principles of third-party access cansuppress these anti-competitive market forces tosome degree.

However, some experts are of the opinion thatunbundling is a more effective approach toresolving such issues. Unbundling involves sep-arating the factors that motivate operators at themidstream stage from those that motivate oper-ators at the upstream and downstream stages,which reduces the likelihood of anti-competitiveactivities. Unbundling is not the actual objective,though; it is just an effective method of ensuringthe feasibility of third-party access. Whether ornot open access measures eventually result in anefficient actively competitive natural gas marketis the final proof of whether mechanisms forunbundling have been successful or not. Forinstance, one of the benefits of unbundling is theadditional upstream activity resulting fromcompetition, encouraging greater manufacturingefficiency and expansion.

Where nations that have a domestic productioncapability are concerned, the earlier unbundlingtakes place and the more completely it occurs, themore effective it will be. Looking at the UK andThe Netherlands and their domestic North Searesources, and comparing them to nations such asFrance and Germany that have only limiteddomestic resources, unbundling occurred morerapidly. In the case of Japan, which has onlyminimal natural gas resources, only tentativeunbundling occurred. In juxtaposition to this isthe United States. The US has plentiful upstreamresources, with a wide distribution. In fact,unbundling commenced in the US at a very earlystage; in 1992 the United States had alreadyrequired the introduction of legislation and otherstructural unbundling measures. One has to becautious about making generalisations in theanalysis of the factors that motivated this, butwhere nations that possess domestic resources

12.4 Third-Party Access: The First Step to Infrastructure Reform 293

were concerned, unbundling resulted in greatereconomic benefits, and this in turn has led to suchnations being more willing to institute suchreforms.

The unbundling process is of great impor-tance, and depending on the extent to whichunbundling takes place, it can be split into fivecategories: service unbundling, financialunbundling, legal unbundling, structuralunbundling and unbundling of owner-ship. Unbundling at a higher level lays thefoundations for unbundling at a lower level,lower-level unbundling being simply an exten-sion of the unbundling occurring at higher levels.A good example of this is that financialunbundling must be implemented at the sametime as service unbundling, and so on; the mostthorough form of unbundling is ownershipunbundling (see Table 12.2).

Analysis of midstream asset unbundling casehistories from the United States and Europe indi-cates that, if regulators are given sufficient powersby the state, it is unnecessary to implement com-plete ownership unbundling. Among the nationsanalysed, only the UK and The Netherlandsinstigated complete ownership unbundling, whileFrance and Germany carried out structuralunbundling and never attempted complete own-ership unbundling. Experiences in the US alsodemonstrated that, by applying a strict model tothe operations of natural gas transport companies,it became unnecessary to apply ownershipunbundling in order to ensure effective competi-tion in the natural gas market. To summarise, themajority of the nations mentioned above insti-gated structural unbundling, without the need tocarry out complete ownership unbundling. Fromthis one may conclude that simply carrying outstructural unbundling in conjunction with strictregulation provided the best results.

In contrast to pipelines, implementation ofunbundling applied to infrastructure such asLNG receiving stations and peak gas storageinstallations has not been so strict. The reason forthis is that, generally speaking, there is a large

number of natural gas receiving stations and peakgas storage installations, therefore there is moreopportunity for competition to arise; when com-pared to LNG receiving stations and peak gasstorage installations, natural gas pipelines exhibitmore pronounced natural monopoly characteris-tics. Where a pipeline network is connected to afairly well developed market, LNG receivingstations take on the characteristics of supplyresources, competition occurring with otherreceiving stations thus restricting market domi-nance. In a similar manner, in a diversifiedmarket with dense connections there will bemany storage providers, while pipeline storagecapacity, flexible natural gas production capacityand dynamic increase and decrease in demandcan also be considered as providing storage ser-vices. In light of this, unbundling and third-partyaccess policy should take this into account andtreat such installations with more leniency.

12.6 Natural Gas Pricing Reformas Part of the MarketLiberalisationand Development Process

Due to different natural gas markets havingdeveloped to differing degrees, there are threetypes of main pricing mechanism found in themain global importers of natural gas: the firsttype relies completely on market-driven prices,such as is encountered in the US and the UK.Here we have relatively mature natural gasmarkets, and a completely unregulated naturalgas price, determined by market demand andsupply; however, third-party access to pipelinesis obligatory, resulting in a market where com-petition occurs directly between different gascompanies. The NYMEX Henry Hub and theUK’s NBP trading prices act as the referenceprices for North American and European trading.

The second category is reliance on the net-back pricing method, such as is adopted inEuropean countries other than the UK. Market

294 12 International Experience of Liberalisation…

Table

12.2

Five

keyun

bund

lingmod

els

Extentof

unbu

ndlin

gMod

elChang

esAim

sRelationshipto

previous

changes

IService

unbu

ndlin

gMidstream

services

(inparticular

pipelin

eservices)mustbe

unbu

ndledfrom

gas

who

lesale

businesses,with

servicethen

beingprov

ided

independ

ently

From

thepo

into

fview

ofthegaswho

lesale

business,iftransportservices

areno

tprov

ided

independ

ently

,thiswill

have

anegativ

eim

pact

onmarketcompetition,

asthesupp

lierisun

likelyto

sellgasto

users

otherthan

thepipelin

ecompany

IIFinancial

unbu

ndlin

gThe

profi

tsandlosses

ofmidstream

operations

will

bebo

rneby

thecompany

itself,having

been

isolated

from

the

upstream

anddo

wnstream

concerns

Thispreventsrelianceon

midstream

assets

tocoverlosses

orsupp

ortup

stream

ordo

wnstream

operations

Ifmidstream

operations

dono

tbecomean

independ

entservicesubjectto

individu

altaxatio

n,then

themidstream

services

are

unlik

elyto

possessaseparate

accoun

tfor

theirow

nfinances

III

Legal

unbu

ndlin

gThe

midstream

business

becomes

anindepend

entlegalentity,

while

remaining

with

inthevertically

integrated

structure,for

instance

existin

gas

awho

lly-owned

subsidiary

The

subsidiary

mustbe

intheform

ofa

legalrepresentativ

ewith

itsow

nlegal

standing

.Byintrod

ucingindepend

entlegal

entities,itispo

ssible

toachievemore

effectiveseparatio

nof

managerialdu

ties

Anindepend

entlegalentitymusthave

separate

accoun

tsforits

finances

and

prov

ideaseparate

service

IVStructural

unbu

ndlin

gIn

orderto

isolatethem

selves

from

upstream

anddo

wnstream

motivations,

manymidstream

services

form

ulatetheir

business

policiesin

advance

Thisrootsou

tanyanti-competitive

motivation;

byremov

ingsuch

motivation

from

themidstream

business

oftheentities

concerned,

itispo

ssible

toachievemore

effectivemarketlib

eralisation

Amidstream

company

needsto

bealegal

entity;

only

then

will

itbe

able

torespon

dapprop

riatelyto

circum

stancesandfulfilits

duties

VOwnership

unbu

ndlin

gThe

midstream

servicemustbe

split

off

from

thevertically

integrated

structureand

ownershipmusth

avebeen

transferredto

anindepend

ententity

Com

prehensive

ownershipun

bund

ling

completelyseparatestheinterestsof

midstream

businesses

from

upstream

and

downstream

businesses

Ifacompany

isun

derindepend

ent

ownership,

then

itisintrinsically

anindepend

entlegalentity,

with

independ

ent

accoun

tsforfinances

andprov

idingan

independ

entservice

NoteIn

theEU

Third

Package,

structural

unbu

ndlin

ginclud

estheIndepend

entTransmission

Operator(ITO)mod

elSo

urce

Vivid

Econo

mics

12.6 Natural Gas Pricing Reform … 295

netback pricing is based on the market value ofenergy sources which are an alternative fuel tonatural gas; this employs retrospective methods,involving deduction of transport, storage, distri-bution and other such costs to determine anupstream price. When compared to the US andUK markets, the European market is still in thestage of transition to full market competition.Natural gas consumption relies mainly on exter-nal imports, and most natural gas is traded inlong-term contracts. The price is mainly peggedagainst oil products, but there is a certain amountof lag in the adjustment in contract prices.

The third type mainly relies on peggingagainst the price of imported oil, examples ofwhich are Japan and South Korea. The devel-opment of the natural gas markets in both Japanand Korea have been somewhat delayed, withreliance mainly being on imports. At the sametime, since there is a lack of a representativetrading centre, there is little choice but to pegnatural gas prices against crude oil. For instance,Japan’s Chubu Electric Power agreed a pricingformula with the Qatar Gas Transport Companyin 2001 which stated: P = 0.1485 � JCC +0.08675 + S. Here, S is an adjustment figure,which was used to moderate the effects of theviolent fluctuation in the international oil price.Prior to 2005, the international oil price wasrelatively low, with the price of gas imported byJapan and South Korea being more or less thesame as in Europe and the United States. Inrecent years, with further fluctuations in theinternational oil price, an “Asian Premium”phenomenon has arisen, with a major increase inthe cost of gas use.

Reform of pricing mechanisms is a gradualprocess, with the final objective being a pricingmechanism which achieves completelyopen-market competition between different gascompanies. If you take the historical situation inthe US, the government controlled natural gasprices, applying a “cost plus” method to importprices, with the federal government controllinglong-distance transport pipeline pricing and localgovernment organisations being responsible forthe price paid by the final user. Governmentalpricing regulation resulted in the price remaining

relatively low over a long period of time, whichled in turn to problems of supply being unable tosatisfy demand. Subsequently, the governmenteased controls over the price of imported naturalgas, and the creation of a trading centre allowedthe gradual evolution of open-market pricingregulation. Historically, the reform of pricingmechanisms in the UK was similar to that of theUS, involving a transition from prices being setby the government to prices being set by mar-kets. Subsequently we find that the pricing reg-ulation that was applied to these markets resultedin trading centres adopting pricing based on areference market price model.

12.7 The Role of Natural GasTrading Markets

Currently, global gas trading relies mainly onlong-term contracts, and this plays a major role inbalancing upstream and downstream interestsand stabilising the relationship between supplyand demand. Long-term contracts allow naturalgas to be linked to the prices of alternative fuels,market trading prices and many other indices,thereby ensuring that upstream investors receivea stable return over a number of decades andprotecting investment in exploration and pro-duction. This is particularly beneficial for sta-bilisation of upstream investment. Relative tolong-term contracts, spot trading is more flexibleand fluid and is taking on an ever-greater role innatural gas trading. Taking shale natural gas inthe US as an example, due to uncertainties overyields, shale natural gas developers are unable toobtain long-term contracts on favourable termsand therefore the development of shale naturalgas relies heavily on the spot trading market.

More important, though, is the fact that thecreation of spot trading markets has provided anew pricing method for natural gas market lib-eralisation, which has also accelerated the cre-ation and growth of trading centres. Take, forinstance, US FERC order 636 in 1992, whichmade it obligatory for pipeline companies toprovide access to their services, an event thatresulted in a substantial loosening of regulation

296 12 International Experience of Liberalisation…

over gas markets, and a market competition-based pricing mechanism replacing the previouspricing model, a government-driven pricingmechanism. At the same time, FERC began topromote the concept of natural gas market trad-ing centres, adopting the stance that natural gasmarket trading centres should be responsible forproviding natural gas supplies, transport, storage,deployment, enhanced administration and othersuch services or combinations of services to thecustomers of pipeline transport operators. As aresult, 36 internal natural gas market tradingcentres were created, covering all the US naturalgas pipeline networks between 1993 and 1998.By 2003, 13 of these natural gas trading centreswere closed down, either due to their trading basebeing insufficient, resulting in small tradingvolumes, or because they lacked competitive-ness. Currently, there are a total of 24 natural gastrading centres, mostly in Texas and Louisiana,which provide hub services to the natural gasmarkets. The appearance of these natural gastrading centres accelerated the formulation andsystematisation of open-market natural gas pric-ing mechanisms, streamlining the allocation ofresources within the gas markets, increasingmarket efficiency and enriching the choice ofinvestments available to those involved in thesemarkets. This evolution also helped the US toestablish itself as a leader in terms of energy

pricing, as well as ensuring US national energysecurity.

Natural gas trading centres clearly offer bothbenefits and drawbacks. They have two majoreffects. The first is that there is a physical con-nection between the buyer and the seller, thesecond is that pricing is set based on marketcompetition. As a result of this, allowing marketsto provide pricing signals increases economicefficiency in terms of trading and investmentdecision-making, in addition to resulting in arelative drop in trading costs, giving greaterreturns to those investing in such markets. Inaddition, natural gas trading centres are able tobalance problems in supply and demand due totheir pricing mechanisms, thereby ensuring thesecurity of natural gas supplies. A potentialdrawback is their impact on current marketmodels. With pricing being determined by com-petition between different parties, rather than bythe government or other leading influences withinthe market, it is possible that they can causegreater fluctuations in pricing in the short term.

From the global experience already gained bythe main countries operating natural gas hubtrading centres, we can conclude that, in light ofthe different functioning of natural gas tradingcentres, the success or otherwise of natural gastrading centres depends on three preconditions(see Table 12.3):

Table 12.3 Conditions for creation of a natural gas trading centre

Basicinfrastructureconditions

A complete and open naturalgas distribution network

Connections to both domestic and overseas gas-consumingand supplying enterprises in an open channel gasdistribution network

Marketconditions

A large number of differentparticipants within the market

There must be sufficient numbers of entities within themarket, including both buyers and sellers

Relatively low level of marketconcentration

There should not be dominant suppliers or consumers

Formalised trading activities Natural gas trading and pipeline transport prices should beregulated by the government, with fair and reasonableprices; traded gas quantities should be able to enter pipelinesfreely; market prices should be made public and transparent

Systemconditions

Market liberalisation of prices The wholesale trading price of gas along the supply chainshould be determined freely by the market

Stable regulatory framework The government must create a fair commercial environmentin order to allow competition policy and market models totake effect

Source Vivid Economics

12.7 The Role of Natural Gas Trading Markets 297

• a natural gas transport network which iscompletely open to access, which is availablefor the use of market participants on anon-discriminatory basis;

• large numbers of independent buyers andsellers actively involved in arbitrage, none ofwhom possess the capability to dominate themarket;

• government support for the opening of itsnatural gas wholesale markets accompaniedby stable, transparent and reliable rules andregulations.

Trading centres also require enterprises toengage in trades based on arbitrage, which willimprove market operating efficiencies, and arbi-trage activities rely on the accuracy and hightransparency of reports of natural gas prices.

By carrying out extensive natural gas sectorreforms, China will possess the conditions thatwould allow it to become the premier natural gastrading centre in Asia. Looking at China’sadvantages, its natural gas output, the extent ofdevelopment of its gas transportation pipelines,the scale of its LNG imports and the significanceof its position in the Asian energy market are allclear. However, China’s natural gas distributionnetwork is not well developed, the market is stillrelatively concentrated, third-party access mech-anisms are ineffective and pricing is still subjectto government control, all of which are factorsthat are restricting the creation of a natural gastrading centre in China.

Experience gained in the United States andEurope since the 1990s in the creation anddevelopment of natural gas trading markets pro-vides a valuable reference for China. The firstthing to note is the extent to which the creation ofa natural gas market will have a major effect onthe development of trading centres. The devel-opment of natural gas hubs in Europe only star-ted in 2008, and for a period of time they werenot that successful, due to the slowness of marketliberalisation in the European natural gasmarkets.

Second, government restrictions over tradingactivities can also have a major influence ontrading centre development. Benefiting from theenormous supplies of the Groningen gas field,and recent increases in the number of LNGreceiving stations and increased storage facilities,the Dutch Title Transfer Facility (TTF) is widelyrecognised as being the most successful Euro-pean continental natural gas hub, and contractvolumes indicated that by 2013/2014 TTF hadalready surpassed NBP to become the largestEuropean fluidity hub (Natural Gas Daily 2014).Zeebrugge (Belgium), on the other hand, isviewed as the least successful example, due to itslow level of trading activity, even to the extentthat it is no longer viewed as a hub. Zeebruggepossesses suitable geographic conditions for it tobecome a natural gas hub, but commercialrestrictions imposed by the local governmenthave restricted the number of participantsinvolved, reducing the trading platform’s rate ofgrowth.

Third, government impetus is capable ofhaving a substantial effect in the short term. Inthe early 1990s, the United States had alreadyachieved market liberalisation of its natural gasprices, but the link between natural gas prices ofdifferent regions (eastern region and westernregion) showed only a weak correlation. At theend of the 1990s, as the United States govern-ment promoted the adoption of the “law of oneprice” across the whole of the US natural gasmarket, after subtraction of transportation costs, asingle transregional price was applied, at whichstage price correlation had already developed to avery high degree (Cuddington and Wang 2006;Doane and Spulber 1994).

Fourth, formalised and orderly trading mech-anisms also have a beneficial effect in encour-aging the development of natural gas tradingcentres. Taking the development of the NBP inthe UK as an example, the Uniform NetworkCode has played a crucial role. The UniformNetwork Code provided the regulations andprocedures for supervision of third-party

298 12 International Experience of Liberalisation…

(TRA) use of the UK natural gas network. Thisintroduced a daily balance system and short-termnatural gas trading and one of the standardisedcontracts (NBP97) became the cornerstone of theUK direct trading contract.

Based on the experience gained in the devel-opment of natural gas trading centres in theUnited States and European Countries, and inlight of the specific characteristics of China’snatural gas industry, development of China’snatural gas trading centres requires a 5- to10-year plan to be drawn up. Trial trading centresshould be established first. The governmentcould establish natural gas pipeline networks towhich third-party access applies in individualregions such as Shanghai, with the introductionof transparent natural gas pricing mechanisms.This would create the conditions for competitionin natural gas demand and supply. Then, afterconditions have developed over a certain periodof time, a real-time gross settlement systemshould be introduced to trial trading centres. Onthe basis of this, the government can extend theareas covered by trials further, or increase thenumber of categories of buyers and sellers, at thesame time as making further enhancements tomarket regulation. As the effects of these trialsbecome more noticeable, they will attract theparticipation of greater numbers of producers andconsumers in market trading. Once the price ofnatural gas in trading trials is less than the priceof natural gas for traditional contracts, the num-ber of traditional contracts traded by consumerswill drop and further interest in purchasing nat-ural gas from trial trading centres willdevelop. On the other hand, when the price ofnatural gas traded by trial trading centres ishigher than that of traditional natural gas con-tracts, suppliers will be more willing to supplygas to these trial centres, thus also reducing thenumbers of traditional contracts traded. As moreand more diverse participants become involvedin trading in these trial centres, the benefits oftrading will increase, due to the network effectmentioned above. Hub-based pricing will beapplied on an increasing scale and over a greater

range, until partial market liberalisation isachieved or geographical limits become a factor.

12.8 Establishmentof an Independent and LegallyProtected Regulatory System

Major state regulatory bodies generally includean overall energy administration and an energyregulator, with powers being divided betweenthese two bodies. The overall energy adminis-tration is mainly responsible for establishingenergy strategy, planning and policy, playing arole in the balancing of total energy resources,with responsibility for energy security, modifi-cation of energy structures, promotion of energysaving and energy efficiency administration,collation and analysis of data, scientific innova-tion in relation to energy and international energyco-operation. It is also responsible for harmon-ising activities in conjunction with relateddepartments. The energy regulator, on the otherhand, is mainly responsible for ensuring orderwithin energy markets, while promoting marketcompetition within the industry and resolvingdisputes. It is also responsible for regulation ofsectors in which natural monopolies exist, thusprotecting the overall interests of the marketparticipants. The overall energy administration isresponsible for establishing policy; the energyregulator is responsible for implementing it (seeTable 12.4).

These two bodies may be partially indepen-dent or completely separate from each other, andfrom the point of view of energy managementthey ideally act as a counterbalance to each other,which satisfies the requirements of modernadministrative systems by separating the threepowers of regulation-making, implementationand supervision. The regulator should be inde-pendent in terms of powers and positioning, toensure that it is capable of reaching appropriatedecisions which treat all market participantsequally. Take the US Federal Energy RegulatoryCommission (FERC) as an example. This is an

12.7 The Role of Natural Gas Trading Markets 299

Table

12.4

The

energy

regu

lators

ofdifferentcoun

tries

Nam

eFu

nctio

nRelationshipto

theoverallenergy

administration

Fund

ingsource

Staff

United

States

FederalEnergyRegulatory

Com

mission

(FERC)

Regulationof

interstate

power,g

asandoil

transport,responsibleforapprovalof

LNG

term

inal

andnaturalgaspipework

constructio

n,while

also

issuing

hydroelectricpo

wer

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its

While

innameitform

spartof

the

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actualfactFE

RC

isan

independ

entbo

dy

From

fees

chargedfor

regulatio

nof

public

utilitiesandservice

charges

Over12

00

Japan

Power

marketdepartments

andgasmarketd

epartm

ents

Regulates

distributio

npricing,

controlo

ver

power

stationenvironm

ental,technicaland

safety

standards,respon

sibilityfor

encouragingmarketcompetitionand

resolvingtradedisputes

Aninternal

branch

organisatio

nof

the

AgencyforNatural

Resou

rces

andEnergy

oftheMinistryof

Trade,completely

subordinateto

theAgencyforNatural

Resou

rces

andEnergy

Gov

ernm

entbu

dgeting

Intheregion

of50

person

sor

more

United

Kingd

omThe

Office

ofGas

and

Electricity

Markets

(OFG

EM)

Coreprincipleisto

encouragecompetition

with

intheindustry,p

rotectingtheinterests

oftheconsum

er,includingeffective

prom

otionof

competition,

regulatio

nof

mon

opolistic

companies

andpricing

control

Ago

vernmentorganisatio

n,bu

tcompletelyindepend

entfrom

other

energy-related

departments

Prov

ided

bychargesfor

regulatio

nof

public

utilities

291person

s

Germany

FederalC

artelO

ffice

(FCO)

Regulationof

thepo

wer

andnaturalgas

markets,resolvingtradedisputes,

encouragingmarketcompetitionin

additio

nto

carrying

outsurveys

relatin

gto

pipelin

echarges

Subordinateto

The

FederalMinistryof

EconomyandTechnology;

thisisan

administrativebo

dyon

thesamelevelas

otherenergy

relateddepartments

Gov

ernm

entbu

dget

The

FCO

office

has

arou

nd30

0person

s,with

10people

allocatedto

thepo

wer

section

Russia

The

FederalEnergy

Com

mission

oftheRussian

Federatio

n(partof

the

FederalCom

modity

Pricing

Bureausince20

04)

Regulationof

deliv

eryof

electrical

power,

hydrotherm

alpower,oil,naturalgasand

petrochemical

products,regulatio

nof

wholesale

andretailelectricity

pricing

Ago

vernmentorganisatio

n,independ

ent

from

departmentsof

industry

andenergy

Gov

ernm

entbu

dget

Prob

ably

arou

nd20

0person

s

India

Central

Electricity

RegulatoryCom

mission

(CERC)

Mainlyresponsibleforregulatio

nof

electricity

prices

ofcentralpower

generatin

gcompanies

andinterstate

power

transm

ission

companies

aswellas

issuing

licencesforpower

transm

ission

and

trading

Ago

vernmentorganisatio

n,bu

tcompletelyindepend

entfrom

theMinistry

ofPo

wer

Fund

sprovided

bycentral

governmentas

wellas

chargesmadeon

licensed

operatorsin

additio

nto

otherincome

68person

s

Korea

KoreanElectricity

Com

mission

specialtask

force,

power

regulator

committee

Regulationof

electrical

power

andother

energy

industries

Subordinateto

theMinistryof

Com

merce,

Industry

andEnergy(M

OCIE),a

semi-independentregulatory

body

Gov

ernm

entbu

dget

Respo

nsibility

lies

with

aninspector,

butexactnu

mbers

unknow

n

300 12 International Experience of Liberalisation…

independent administrative body which is sub-ordinate to the US government. It is responsiblefor the regulation of business activities involvinggas, electrical power, hydroelectric power andoil, covering pipelines and distribution links; andpolicy-making and the resolution of disputesrequire a majority vote of the five committeemembers. There are five committee members,one of whom is the chair of the committee, andthe names of whom are suggested by the Presi-dent and ratified by the Senate (though not morethan three fifths of the committee members maycome from one political party). Policy decisionsare issued by a court of law, and not by theUnited States Congress, and when cases arebeing heard, no private discussions are permitted.

The main regulatory role of FERC is to pre-vent companies from taking advantage of theirmonopolistic position, with the aims of the reg-ulation including:

• prevention of discriminatory or preferentialtreatment;

• prevention of inefficient manufacturing andunfair pricing practices;

• ensuring excellence of service;• prevention of infrastructure redundancy and

wastage;• where competition does not exist or is not

able to exist, acting as an agent for the pro-motion of competition;

• promotion of safe, high-quality, environ-mentally friendly energy infrastructure viaimplementation of consistent policies;

• where possible, encouraging overall marketcompetition in place of traditional regulation.

From the point of view of the natural gasindustry, the main function of the Commissionrelates to pricing controls, interpretation of therelevant legal statues and service regulation, andthe scope of regulation includes roughly 120interstate gas pipelines. At the same time, theCommission has the power to authorise theconstruction and siting of gas delivery-relatedinfrastructure as well as being responsible for theevaluation of the environmental impact that thismay cause.

12.9 A Roadmap for Natural GasMarket Reform

Reform of market structures and the administra-tive regime applied to natural gas is a gradualprocess. Looking at the timeline of developmentsin the US natural gas market, this processinvolved a progression from complete govern-ment regulation and the government setting ofprices to a situation where pricing controls weregradually withdrawn and bundling of gas saleswas eliminated, followed by a fully developednatural gas market with pricing determined bythe market itself (see Fig. 12.2).

The reform of the natural gas market is along-term and difficult process, requiring a par-ticular political environment, relevant infras-tructure and associated government policy.Favourable political and market climatesencouraged the reform of both the British andAmerican natural gas markets. For instance,looking at the period from the 1970s to the1980s, the oil crisis resulted in massive pressurebeing put on the government to introduce marketreforms, while the extensive pipeline networkinfrastructure was also a driving force behind thenatural gas market reforms in the US. In the UK,the Conservative party, which was in power atthat time, under the leadership of MargaretThatcher, was in the midst of carrying out pri-vatisation of publicly owned industries, includingvertically integrated power and gas companies, inorder to relieve the financial problems faced bythe government at that time; this also createdpolitical and market conditions favourable tomarket reform. In contrast to this, if reforms donot proceed effectively, there is also the possi-bility that they will fail. In the last 20 years,South Korea has encountered many difficulties inthe reform of its natural gas market, in particularrelating to the powerful unions of the publiclyowned, vertically integrated monopolisticKOGAS, which objected to the surrender ofKOGAS’s global natural gas market purchasingcapabilities. It is easy to see from this that thenatural gas market reform process in all countriesin question has been both slow and tortuous, andrequired tailoring to fit the current political and

12.8 Establishment of an Independent and Legally Protected Regulatory System 301

economic climate at the same time as imple-mentation of the required policies and measurestook place. As such, establishing a roadmap for

reform and enforcing its implementation is cru-cial from the perspective of implementing naturalgas market reforms.

In 1938 theNatural GasAct increasedinterstatepipeline regulation

Starting in1954, wellheadprices werefixed by thegovernment

In 1978 newpolicy in relationto gas resultedin the relaxationof gas importpricingrestrictions,while providingincentives topipelines toopen up accessto their transportationservices

Order 436 in1985, providedincentives topipelineoperators toopen access totheir services,allowing users topurchase gasdirectly from theproducer

In 1989 TheNatural GasWellheadDecontrol Acteliminatedwellhead pricingregulation

In 1992 order636 made it obligatory forinterstatepipelines toseparate theirtransportationand salesservices

In 2000, order637 went yetfurther toeliminate thebundlingbetweensuppliers andtransportservices

Monopolisticpricing, lack ofgovernmentregulation

1938 1954 1978 1985 1989 1992 2000

Earlydevelop-ment phase

Complete governmentregulation phase

Adjustment and restructuring phase,with easing of regulation and relaxingof pricing restrictions

Marketisationphase with pricingset by markets

Fig. 12.2 Timeline in the reform of the US natural gas market

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302 12 International Experience of Liberalisation…

13Regulatory System Reformto Support Natural Gas MarketLiberalisation

13.1 Direction of Reforms

Summarising international experience in relationto natural gas market reform, while giving spe-cial consideration to China’s specific situation,the creation of a natural gas market system andreform of administrative systems should embodythe principles described below.

The direction taken by reforms should beidentical to the direction taken in the creation of asocialist market economic system. The creationof a market economy with specific Chinesesocialist characteristics has been the overalldirection adopted in the reform of Chinese eco-nomic systems. Statements issued during the18th plenum of the People’s Congress also madenew proposals regarding the refinement of thesocialist market economy system. The reform ofthe natural gas market must satisfy the require-ments of a socialist market economy, ensuringthat the relationship between the government andmarkets is dealt with effectively, in particularrequiring the transformation of governmentalfunctions. This applies particularly in the clari-fying of the boundaries between the governmentand its markets; this will provide oil and gascompanies with more opportunities to

develop. At the same time, in addition to pro-viding the basic functions of a market system inoptimising and allocating resources, it mustimprove the macroeconomic and market regula-tory roles of the government, allowing imple-mentation of effective regulation of naturallymonopolistic markets while encompassing theimportant society-wide functions of safety,energy efficiency and emissions reduction regu-lation, in addition to evening out various flawswithin the market.

Reforms must be implemented according toboth long-term and short-term goals, taking placegradually. Natural gas is a basic element of ournational economy; the reform of the natural gasindustry must take into consideration both thepositive and the negative impacts on socioeco-nomics, and this requires us to keep our eyes onthe bigger picture, while establishing new systemmechanisms. At the same time as we seek toimplement these in the present, we also need tobe able to solve current problems as they appear.This requires a unified design, which establishesthe direction and objectives of such reforms,while allowing special emphasis to be placedwhere necessary, dealing first with the easierobjectives and then the more difficult ones, firstbuilding up experience from trials, followed bygradual extension, followed by step-by-stepimplementation.

Reforms must ensure that they areall-encompassing and that the burden of them isshared evenly. Sufficient consideration must begiven to the ability of different industrial sectors

* This chapter was overseen by Xiaoming Wang fromthe Development Research Center of the State Counciland Mallika Ishwaran from Shell International. It wasjointly completed by Yusong Deng, Jiaofeng Guo,Shouhai Chen from China University of Petroleum andQingle Wu from Shell China. Other members of thetopic group participated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_13

303

to withstand adjustments in pricing, and to theirdifferent requirements in terms of the adjustmentprocess. Special consideration must also be givento the harmonising of international and domesticmarket prices, and to the ability of both urbanand rural residents to withstand such changes.The creation of new systems and proceduresshould ensure that reform of the market, theadministrative system and pricing reform occurin step with reforms to taxation, while makingactive efforts to ensure the sustainable develop-ment of the natural gas industry.

The objectives of reforms should be closelylinked to increasing industrial competitiveness.As globalisation takes on even greater economicsignificance, the rate at which China’s oil and gasindustries are becoming involved internationally,in addition to inviting international involvementin China, is increasing, and against this backdropincreasing the competitiveness of our energyindustry is a matter of a major urgency. Reformof the natural gas industry must be linked to thecreation of a more competitive industry. Whetheror not China’s oil and gas industries becomemore competitive internationally is a majorbenchmark against which we can measure thesuccess of market reforms. Allowing competitionto enter our markets will ensure that our oil andgas industries become more efficient and scien-tifically advanced, thus increasing the competi-tiveness of our industry.

13.2 Key Pillars of Reform

Reforms must follow the proposals aired at the18th plenum of the People’s Congress concerningcompletion of a market economy with specificChinese socialist characteristics, which wouldallow markets to play a definitive role in the allo-cation of resources, accelerating the transforma-tion of government functions, reducingbureaucratic red tape and interference in microe-conomic activities and establishing aservice-based natural gas administrative system.Reforms should be sufficiently market-oriented,while establishing pricing parity between naturalgas and alternative energy sources, in addition to

creating pricing systems that reflect the extent ofscarcity of resources, the market relationships ofsupply and demand and environmental externalityin the creation of a green financial and taxationsystem. This will introduce the diversity of com-petition to the overall natural gas production chain,increasing external access yet taking care to ensurethat the state retains control over the economy,enhancing regulation in terms of fair extension ofaccess to services, while establishing a diversified,competitive, open and orderly modern marketsystem. In overall terms, in order to guarantee thatthe strategic objectives regarding the developmentof natural gas inChina are achieved, the natural gasmarket liberalisation reforms should accelerate theestablishment of three main pillars, as outlinedbelow.

13.2.1 Pillar I: Establish a Diversified,Competitive, Open,Orderly Modern NaturalGas Market System

The natural gas market liberalisation reformsmainly cover three areas. The first is the breakingup of monopolies, encouraging diversificationand competition among participants. The intro-duction of private capital into the oil and gasexploration field should be supported, allowingits participation in conjunction with state oil andgas companies in oil and gas exploration anddevelopment. Reform of the current oil and gasmineral rights allocation regime, graduallyallowing competitive tendering and bidding forquotas, based on implementation of a licensingregime, would then allow the structure of acompetitive oil and gas resource exploration anddevelopment market to be established. Encour-aging diversification of natural gas importers willattract private capital for the construction of oiland gas pipelines, which will then allow theseparation of natural gas transport and sales. Atthe same time, it will make it possible to ensurethat access to the midstream and downstreamsectors is allowed on the basis of companysafety, energy efficiency, environmental, qualityand technical performance indices.

304 13 Regulatory System Reform to Support Natural Gas Market Liberalisation

The second area is the acceleration of thecreation of a natural gas trading market, involv-ing training market intermediary organisationsand ensuring an improvement in service. Theconstruction of the Shanghai Oil and Natural GasTrading Centre should be accelerated. In addi-tion, at an appropriate time, research should becarried out regarding the creation of natural gastrading platforms for Beijing, Tianjin, Guangz-hou, Chengdu and other trading centres.Encouragement should be given to energy effi-ciency conversion, financial, insurance, IT, con-sulting and other such participating professions,in order to improve the professional standards ofall involved.

The third area is deepening the extent ofreform of state-owned enterprises, encouragingthe growth of modern energy companies. Thiscan be accomplished by:

• promoting reforms such as mixed ownership,allowing private companies and overseasinvestors to hold shares in state-owned energycompanies, as well as refining the process bywhich state-owned energy companies may liston the stock exchange, creating a diversifiedownership structure while maintaining astate-owned controlling share over naturalmonopolies;

• optimising corporate governance structures instate-owned enterprises, introducing modernbusiness regimes, creating boards of directorsthat are more than just symbolic and allowingshareholder meetings and other similar busi-ness administration and decision-makingstructures;

• tightening up company budgetary andexpenditure management, ensuringcost-effective accounting, while giving fullconsideration to the social function of suchenterprises, historical problems and futuredevelopmental requirements, increasing theproportion of profits being passed on, andensuring that excess profits arising due tomonopolies revert to the public coffers and goto benefit everyone.

13.2.2 Pillar II: Create a PricingSystem that Reflectsthe Extent of Scarcityof Resources, the MarketRelationships of Supplyand Demandand EnvironmentalExternality and a GreenFinancial and TaxationSystem

Natural gas pricing reform and financial andtaxation reform must be dealt with in five ways:

• ensure that there is a mechanism by whichcompetition in the natural gas industry results inmarket adjustments, and that natural monopo-listicmechanismsare subject to legal regulation;

• internalise the costs of externalities such asenvironmental protection that required in thecourse of exploitation of energy resources andreduction of greenhouse gas emissions, whichwill go towards establishing energy pricingparity;

• bring about gradual integration with interna-tional natural gas markets;

• adopt natural gas as a clean and highly effi-cient energy type, with major encouragementbeing given to increased production capacityand importing;

• eradicate cross-subsidisation, which willensure that “hidden subsidies” become“known subsidies”.

In terms of pricing reform, it will be necessary toimprove the “market netback” laws. This will allowregular dynamic adjustments correlating to energyresources, including pricing, category selection andweighting correlating to energy resource. Dynamicupstream and downstream linkage systemsmust beput in place, allowing for locally created pricetransmission systems, in addition to refiningmechanisms via which low-income groups willreceive financial subsidies. Creation of the Shang-hai Oil and Natural Gas Trading Centre should beaccelerated, while the scope of the trial should be

13.2 Key Pillars of Reform 305

extended. The introduction of differential pricingpolicies should be brought forward, encouragingthe introduction of stepped prices and peak priceadjustment etc. Once themarket structure and otherconditions allow, competitive systems should beintroduced, allowing suppliers and users to deter-mine prices freely. Once natural gas trading centreshave been established, this will act as the basis forestablishing and adjustingmarket prices and lead tothe creation of a gas storage market and a pipelinemarket, allowing market forces to provide a solu-tion to peak storage problems.

In terms of financial and taxation reform, itwill be possible to create a green energy taxationsystem, which will act as a major financialstimulus in the development of natural gas. Then,at an appropriate point, carbon tax should beintroduced, with “emissions charges” beingconverted to an “emissions tax” with the intro-duction of collection of an ad valorem natural gasresources tax, in conjunction with introduction ofan energy efficiency/emissions reduction quotatrading system. By increasing the financial sup-port for infrastructure construction, scientificinnovation, energy efficiency and safety assur-ances, it will be possible to accelerate reforms ofthe pipeline and storage infrastructure financingand investment systems. The duration of subsi-dies for shale natural gas and othernon-conventional forms of natural gas should beextended and tax breaks offered to interruptibleusers, which in turn will increase research interms of energy efficiency and emissions reduc-tion within the industry as a whole. Strategicstorage costs should be included in financialbudgeting in addition to establishing a system ofsubsidies for low-income groups.

13.2.3 Pillar III: Establisha Service-CentredNatural GasAdministrationwith a Legal Basis

The transformation of government functionsshould be accelerated, reducing bureaucratic redtape and interference in microeconomic

activities. Natural gas administrative bodiesshould mainly be concerned with macroeco-nomic administration relating to the field ofnatural gas. The formulation and realisation of oiland natural gas-related law and related policystrengthening will establish a developmentalstrategy that gives priority to energy efficiency,providing the capacity to respond to climatechange and guide society as a whole in thedirection of reduction of emissions and sustain-able development. This should also entailenhanced macroscopic planning and industryguidance while reducing regulatory control overproject approvals and pricing, thus reducing thelevel of interference in terms of market opera-tions, production and other business activities.Enhanced demand-side management ofgas-using industries is necessary, with greaterattention being paid to long-term energy effi-ciency and greenhouse gas emissions manage-ment. At the same time, attention must be paid toensuring the security of natural gas supplies;international co-operation should be encouraged,combining increased “Chinese external involve-ment” and “international involvement withinChina”, improving reserve management capa-bilities and ensuring effective resource alerts andprediction.

Enhanced social oversight should be put inplace through the creation of a service-centrednatural gas administrative system. Natural gasregulatory bodies should mainly be concernedwith market malfunction, with their main effortsbeing concentrated on their regulatory role. Theymust act appropriately in the regulation andencouragement of fair competition and the pre-vention of market monopolies. They need toextend their regulatory functions to include nat-ural gas pipeline development and other areaswhere natural monopolies may exist, as well asthe regulation of market prices and other aspects.In addition, they must be responsible for safety ofoperations, pollutant discharge and emissions aswell as ensuring fairness of service and protect-ing the rights of consumers. They should becapable of ensuring compliance, strengtheningproduction safety and improving levels of energyefficiency and environmental protection,

306 13 Regulatory System Reform to Support Natural Gas Market Liberalisation

ensuring that development is sustainable andmaking the social accountability of businesses apriority.

13.3 Reform Objectives

Full advantage should be taken of the strategicpossibilities for reform that present themselves atthis time of massive drops in international oilprices. Any actions should be taken according tothe requirements of Chinese socialist marketeconomic development, taking advantage of thedefinitive effect that markets play in the alloca-tion of resources and making more effective useof the role played by the government, in order tosupport the establishment of “an effective gov-ernment + an effective market”. This approachwill result in the creation of a mechanism fornatural gas pricing mainly determined by marketforces. The transformation of the governmentapproach to regulation will result in the creationof a comprehensive oil and natural gas-relatedsystem of legislation, the founding principles ofwhich are encouragement of independent controlof businesses over their operations, fair compe-tition, freedom of choice for consumers allowingthem greater control over expenditure, freemovement of commercial factors and equality inexchange. This will in turn ensure an effective,competitive market structure and market system,resulting in the overall advancement of reformsin the field of natural gas while both promotingand accelerating energy resource reforms inChina.

Establish a comprehensive system of natu-ral gas related legislation and standards: A“comprehensive legal system” means a nationallegal system which is complete, standardised,systematic, harmonised and unified. This shouldembody the legal principles of socialism withChinese characteristics, providing a completelystandardised legal system, with an effective sys-tem for the implementation of such laws. Itshould also be a system capable of rigorousmonitoring of the law, which also consists of asystem of legal guarantees, whereby nationalorder is enforced according to the law, involving

both governing by law and the government act-ing according to the law, in supporting the cre-ation of a unified legal state, legal governmentand legal society. This in turn ensures that lawsare scientifically established, strictly enforced,formulated fairly and obeyed by society, in amanner capable of modernising China’s gover-nance systems and capabilities. Regarding natu-ral gas, legislative revision should occur rapidly,as there is a legal basis for the introduction ofmajor reforms, while policy should be closelyconnected with such legislation. Moreover, thereshould be increased governance according tolaw, ensuring that industry administration occurson a legal basis, ensuring fair legal process,enhancing the public’s faith in the judicial pro-cess. Finally, increased work should occur inrelation to the creation of legal teams andenforcing a restriction list, thereby ensuring that“no actions should be taken without a legal basis,while legal responsibilities must be fulfilled”.

Create a new kind of integrated, open,competitive, orderly natural gas market sys-tem: The modern market systems must be inte-grated in nature, relying on the interaction andinterconnection of a number of submarketswhich are organically integrated. Integration,openness, competition and order are all essentialcharacteristics of a market economy. Integrationis the foundation of economic development, withproducts and factors able to flow between dif-ferent industries, departments, regions, bothdomestically and internationally. Openness is aprerequisite in terms of economic vitality—interms of the international division of labour,Chinese companies exhibit a major strength inthat they are responsible for making productsmore competitive in the international productionchain, increasing the efficiency of allocation ofresources within specific sectors. Competition isthe foundation of all economic efficiency, andfair competition with only the fittest surviving iscrucial to ensure improved economic quality andefficiency. Order relates to maintaining economicorder, requiring the establishment of strict, fair,open and transparent market regulations, whichthen maintain effective order within markets.Only by establishing an integrated, open,

13.2 Key Pillars of Reform 307

competitive and orderly market system is itpossible to ensure that market factors are able toplay a full role, which in turn will result inresources being allocated in the most efficientmanner. This can be achieved via an overallincrease in the extent of reforms extending as faras 2030, which will result in the creation of anintegrated, open, competitive, orderly and mod-ern oil and natural gas market system formed of anumber of very large oil and gas companies inconjunction with other oil and natural gas pro-duction, transport and sales operators with dif-ferent ownership structures and of differing size.

Creation of pricing systems and a financialand taxation system that reflect the extent ofscarcity of resources, the market relationshipsof supply and demand and environmentalexternality: The system via which natural gasprices are set should be transformed from beinggovernment-dictated to being market-moderated,and this in turn will ensure that prices fall in stepwith those on the international natural gas mar-kets. The pricing parity relationships betweennatural gas and alternative energy sources mustbe reorganised, and a financial and taxation

system that takes into account ecology andenvironmental protection, reduction in green-house gas emissions and other such externalitiesmust be established.

Encourage the creation of a modern natu-ral gas market supervision system which isall-encompassing, where rights and duties areclearly delineated and which is both fair,transparent, efficient and capable of effectiveregulation: The manner in which the govern-ment implements supervision over the naturalgas industry, which relied in the past mainly onan application and approval system, should beconverted to one in which it has a strategic role inplanning and guidance. This will encourage thecreation and completion of a market regulatorysystem, improving the social accountability ofgovernment, the increased accountabilityencouraging fairer competition, preventing mar-ket monopolisation and protecting consumerrights at the same time as ensuring the safety ofproduction operations; it will also provideencouragement to reduce the levels of pollutantemissions in addition to providing an impetus forsustainable social and economic development.

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308 13 Regulatory System Reform to Support Natural Gas Market Liberalisation

14Roadmap for Natural Gas MarketLiberalisation and RegulatoryReform

14.1 Roadmap

At different stages of the development of thenatural gas industry, markets exhibit differentcharacteristics depending on the different levelsof competition and different problems encoun-tered, and thus the focus of reforms should alsodiffer. In general, no stage in the reform processcan be left out, as each key issue must be dealtwith effectively to ensure that policy and adoptionof measures keep step. This approach shouldachieve a balance between the three aspects oftiming, location and quantity. Attention shouldalso be paid to the special characteristics of thenatural gas industry sector and to the extent of theeffects of the reforms and the uncertainties relat-ing, for instance, to market conditions. Taking allthese factors into account, the increase in theextent of reform occurring in the natural gassector in China should take place at a gradualpace and to a moderate degree, so that the reformsare acceptable to society. Appropriate objectivesand measures should be determined based on thestage of development reached by the natural gasmarket and according to its specific characteris-tics. For the purposes of this paper we envisage agradual roll-out involving three stages.

14.1.1 Upstream Sector Roadmap

Currently the vast majority of oil and gas mineralrights are concentrated in the hands of four majorcorporations: China National Petroleum Corpo-ration, China National Offshore Oil Corporation,China Petrochemical Corporation and ShaanxiYanchang Petroleum Group. Resolving thisproblem of excessive centralisation of mineralrights, resulting in control over land beingawarded but no exploration taking place, is keyto advancing reform in the upstream field. As aresult, reforms need to start by looking at currentlegislative and administrative methods, concen-trating on promoting diversification of investors,encouragement of effective competition andcreation of a restriction list, in order to refine thesystem of market access, ensuring that a systemfor issuing tenders and bidding on quotas isimplemented for natural gas mineral rights; thisin turn will result in the orderly and effectiveencouragement of the creation of primary andsecondary markets for exploration rights andextraction rights, at the same time as ensuringthat basic data on natural gas resources is placedin the public domain.

1. By 2020, the preliminary creation of a min-eral rights primary and secondary marketshould have taken place. This will involve thecreation and refinement of a legislative sys-tem and framework with a “mineral resourceslaw” at its centre. Restriction list, industryadmission and competence baseline adminis-trative systems will be established, allowing

* This chapter was overseen by Xiaoming Wang fromthe Development Research Center of the State Counciland Mallika Ishwaran from Shell International. It wasjointly completed by Yusong Deng, Jiaofeng Guo,Shouhai Chen from China University of Petroleum andQingle Wu from Shell China. Other members of thetopic group participated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_14

309

companies that are viewed as “competent” toimport gas independently (pipeline gas andLNG) in addition to allowing freedom ofchoice of importer. This will also include thepreliminary creation of a public-domain nat-ural gas resources information managementsystem, which will also include newly dis-covered Chinese gas hydrates mineralresources, while also involving introductionand refinement of a system for tendering andbidding in relation to conventional naturalgas, shale natural gas, coalbed methane, gashydrates and other such mineral rights and thepreliminary creation of an exploration andextraction rights secondary market systemand trading mechanism. The natural gaswellhead (ex-works) price will be deregulatedand then decided by market competition,while the natural gas pricing method will bebased solely on calorific value pricing.Amalgamation and integration of the mainstate oil companies will occur, according toexperience gained overseas in terms of bal-ancing development upstream, midstream anddownstream, resulting in the creation of twoor three vertically integrated large interna-tional oil companies, the upstream, midstreamand downstream operations of which areequally balanced. This will allow the growthof an effective, competitive market structure,in addition to establishing and refining aspecialised independent regulator.

2. By 2025, establish the basic elements of aprimary and secondary mineral rights market.Establish a legislative system with an “oil andgas law” at its centre. Refine the restrictionlist and industry admission regime. Create apublic-domain natural gas resources infor-mation management system. Create a regimefor tendering and bidding on conventionalnatural gas, shale natural gas, coal bed gas,gas hydrates and other such mineral rights,including the preliminary creation of anexploration and extraction rights secondarymarket system and trading mechanism.Complete the honing and specialisation of theindependent regulator.

3. By 2030, primary and secondary mineralrights markets should be fully established.A comprehensive legislative system based onan “oil and gas law” should have beenestablished. A highly effective administrativeimplementation structure based on a restric-tion list and industry admission regime shouldhave been created. A strict supervisory sys-tem relying on an independent specialistregulatory body should have been estab-lished. An integrated, orderly but competitive,legal, trustworthy, effectively regulated natu-ral gas exploration and development marketsystem should have been established.

14.1.2 Midstream Roadmap

Currently, Chinese oil and natural gaslong-distance pipelines, branch pipelines andprovincial pipelines are mainly concentrated inthe hands of three major corporations (ChinaNational Petroleum Corporation, China NationalOffshore Oil Corporation and China Petrochem-ical Corporation). How to resolve the issues ofthe low numbers of participants involved inpipeline construction and operation, the bundlingof transport and sales and a lack of third-partyaccess are all key issues encountered in relationto overall reform of the midstream field. As aresult of this, it is necessary to commence workregarding current legal and administrative sys-tems, concentrating efforts in the areas of diver-sification of market participants (this in turn willencourage effective competition), creation of arestrictions list and improve market admissionmechanisms. In this way, the complete separa-tion of long-distance pipeline, branch pipelineand provincial pipeline transport services andsales operations will be ensured, so that thereform objective of third-party access to pipelinenetworks and open admittance to the industry canbe achieved. Admittance to sectors where naturalmonopolies exist, such as the pipeline networks,charging and cost supervision should also bestrengthened.

310 14 Roadmap for Natural Gas Market Liberalisation …

1. By 2020, allow preliminary pipeline capacitytrading in a primary market, including thetrading of storage capacity such as that withinLNG installations. Ensure that reforms areimplemented that make natural gas pipelinenetwork finances independent, with the trialintroduction of independence of productionrights from the natural gas pipeline network.Enforce third-party access and open industryadmittance. Completely separate long-distance pipeline, branch pipeline andprovincial pipeline transport and sales ser-vices. Establish and refine an independentspecialist regulator.

2. By 2025, the creation of a primary pipelinecapacity and storage trading market should bebasically complete, in conjunction with thepreliminary creation of a secondary pipelinecapacity and storage trading market. Ensurethat the independence of the natural gas pipe-line network from production rights has beenaccomplished and that the objectives ofthird-party access and open industry admit-tance have been achieved. In order toencourage the construction of pipelines andgas distribution networks and increase trans-port capacity, permit long-term natural gassupply and transport contracts (althoughgradual pricing regulation of transport anddistribution networks would be necessary).Implement policies giving pipeline investmentand construction projects that are of provenbenefit to society and that have a major socialinfluence immunity for limited periods (forinstance by not enforcing third-party access topipeline transport services for a specified per-iod of time). Ensure that a specialised inde-pendent regulator is fully in place and refined.

3. By 2030, ensure the formation of both pri-mary and secondary pipeline capacity andstorage trading markets. Implementthird-party access to distribution services,while allowing residential and commercialclients to seek out alternative suppliers orwholesalers other than their local distributor,either via the introduction of trials or as partof a compulsory process. Create a restrictionlist and an industry admission administrative

regime which will act as the foundation of aneffectual administrative implementation sys-tem. Create a strict supervisory system basedon a specialised independent regulator.Ensure that this results in an integrated,competitive, ordered, legal, trustworthy nat-ural gas pipeline and storage market systemwhich is effectively regulated.

14.1.3 Downstream Roadmap

China has already begun to establish downstreammarket structures, and in overall terms it is possibleto see the existence of market competition to dif-fering degrees. However, there are still a lot ofproblems, requiring solutions for issues such asirregularities in market regulation, incompletepricing mechanisms, poorly developed marketstructures and localised monopolies, all of whichare key areas of concern in ensuring thoroughreforms in the downstream sector. As a result,work needs to begin on the existing legislative andadministrative systems, concentrating efforts in thefollowing areas: the formation of market systems;encouraging effective competition; the creation ofa restrictions list and improving market admissionmechanisms; and the deregulation of natural gasterminal pricing, with prices then being estab-lished by market competition. This should finallyresult in the formation at the national level ofaround 10 regional oil and natural gas spot tradingmarkets, as well as establishing and refining anatural gas futures trading market, ending in theestablishment of a fully featured, modern marketand associated regulatory structures.

1. By 2020, ensure the deregulation of naturalgas terminal pricing, which will subsequentlybe determined according to market competi-tion. Establish natural gas spot trading mar-kets and wholesale markets at the mainnatural gas trading centres and provincialdistribution hubs. Establish a natural gastrading market within the Shanghai FuturesExchange. Create and refine an independentspecialised regulator.

14.1 Roadmap 311

2. By 2025, ensure the development of a naturalgas sales market system based on a combi-nation of producers, independent traders,large users, local distributors and end usersthat rely on a spot trading market. Create andrefine an independent specialised regulator(Fig. 14.1).

3. By 2030, a natural gas sales market systembased on a combination of producers, inde-pendent traders, large users, local distributorsand end users that rely on a combined naturalgas market system consisting of a natural gasspot trading market and a natural gas futuresmarket should have been established. Create aspecialised independent regulatory body aspart of a strict regulatory system. Ensure thatthis results in an integrated, competitive,

ordered, legal, trustworthy natural gas salesmarket system which is effectively regulated(Fig. 14.2).

14.2 Key Measures

The basic direction of China’s natural gas policyit that it “supports energy efficiency, strengthensChina’s position, encourages diversification, isconcerned about the environment, ensures thor-ough reforms, encourages internationalco-operation and improves the lives of every-body”. This approach promotes transformation interms of energy resources and modes of pro-duction and consumption, and forms the basis of

Gas sales Gas transport

Residentialusers

Producers

Commercialusers

Electricalgeneration

users

Industrialusers

Local gasdistributors

Pipelinecompanies

Spot-tradingmarket

Independenttrading market

Fig. 14.1 Diagrammatic representation of the natural gas markets after complete separation of sales and pipelinetransport. Source Xu (2015)

Natural gas trading Pipeline capacity trading

Pipeline company

Pipeline company

Pipeline company

Pipeline company

Major user

Local distributor

Independent seller

Producer

Spot trade market

Fig. 14.2 Diagrammatic representation of a spot trading market system. Source Xu (2015)

312 14 Roadmap for Natural Gas Market Liberalisation …

a clean, efficient, safe and sustainable modernindustrial system, placing complete reliance onthe sustainable development of energy resourcesto support the sustainable development of theeconomy and society as a whole.

14.2.1 Creation of Market Systems

Efforts must be made to ensure that by 2020, anintegrated, open, competitive and orderly naturalgas combined production/transport/sales marketsystem which encompasses “one network, diver-sifiedgas sources and10 regions”has beencreated.

A “one network” pipework transport system isrequired in order to allow connection of gasresources from different sources and regions tothe market, thus creating a national unified nat-ural gas market system, which will encourage theflow of resources between the markets of differ-ent regions, and allowing effective competition,helping to ensure the security of natural gassupplies. To be specific, it will be necessary tocreate a pipeline backbone by perfecting thecurrent “Western Gas Going East” system, thenew Guangdong-Zhejiang and Shaanxi-Beijingsystems, the “Sichuan Gas Going East” systemand the China-Burma pipeline networks,while the Lanzhou-Yinchuan (Lan-Yin) line,Lanzhou-Yinchuan-Ningxia (Lan-Yin-Xia) line,Huaiyang-Wuhan (Huai-Wu) line, Zhongwei-Guizhou (Zhong-Gui) line and the Ji-Ning lineact as connecting lines to create a “one network”pipeline transport system.

1. “Diversified gas source” gas supplyframework

China’s main natural gas market resource isstate-produced gas from the Xinjiang, Sichuan-Chongqing, Qinghai and Shaanxi-Gansu-Ningxia regions as well as from maritime areas,in addition to gas imported from Central Asia viapipelines located in the west, gas imported viathe northern China-Russia pipeline and importedLNG. Due to the need to concentrate on placingreliance on nearby supplies, more considerationneeds to be given to a framework relying on

“piping of western gas east, delivery of gas fromthe north to the south and bringing maritime gasashore”, ensuring that full use is made of avariety of market resources to satisfy the gassupply demands of various regions in order toensure security of supply.

2. “Top 10” regional markets

Due to the factors affecting the distribution ofnatural gas resources, the layout of the pipelinenetwork and existing socioeconomic conditions,the hope is to establish a seamless network inChina connecting imported pipeline gas to themarkets, connecting LNG receiving stations tothe markets, connecting producing regions to themarkets, connecting underground gas reservestorage to the markets and connecting producingregions with underground gas reserve storage.By around 2020, 10 large regional marketsbased on the Bohai Loop, Yangtze River Delta,Pearl River Delta, Sichuan-Chongqing, Yunnan-Guizhou-Guangxi, Central-Southern, Shandong-Henan-Anhui, Central-Western, North-Westernand North-Eastern regions will be created,including:

• a locally supplied market to feed local pro-duction and consumption in Sichuan-Chongqing and the North-Western region,with Shanghai and Guangdong acting asproduction-transportation-consumer centresfor the Yangtze River Delta and Pearl RiverDelta regional markets;

• Zhongwei in Ningxia, Wuhan in Hubei andYongqing in Hebei acting as logistical hubsin the creation of Central-Western, Central-Southern and Bohai Loop regional markets,while gas from the China-Russia pipeline andpipeline gas produced domestically will comemainly from the gas source for a North-Eastern regional market;

• gas from the China-Burma pipeline andimported LNG acting as the gas source for theYunnan-Guangxi-Guizhou regional market,with the underground gas storage groupingsof the Yellow River Plain and northern Chinaproviding support to locally produced

14.2 Key Measures 313

pipeline gas and imported LNG and gas fromother sources in the Shandong-Henan-Anhuiregional market.

These “Top 10” regional markets are notcompletely independent but are interconnectedand influence each other. This is achieved via a“single network” pipeline transport system con-necting different pipelines and different entities inaddition to effective market regulation, encour-aging effective competition, and ensuring thatmarket resources can spontaneously flow fromhigh-value areas to low-value areas, therebyestablishing a national pricing system based ondifferent regional prices and a flexible natural gasmarket framework, in turn ensuring the opti-mised allocation of resources.

The creation and developmental progressionof these “Top 10” regional markets should occursequentially, by policy-led trial introduction.From the point of view of market creation anddevelopmental progression, the relatively matureSichuan-Chongqing, Yangtze River Delta andPearl River Delta regional markets should beestablished within the time constraints of the13th Five-Year Plan. When compared at thenational level to other regional markets, theSichuan-Chongqing region was the earliestregional natural gas market established in China,relying mainly on the Sichuan Basin, which isrich in oil and natural gas resources as well ashaving a relatively well established pipelinetransportation network; this would make it mucheasier for a relatively mature market to becomeestablished. In light of this, it is recommendedthat a “Sichuan-Chongqing natural gas marketreform trial zone” be established as soon aspossible, with the results achieved in this trialallowing the creation of a mature regulatorysystem as far as market access and pricingmechanisms are concerned, which should becapable of overcoming inertia in the developingmarket and obstacles to effective competition,while allowing the market to play a definitiverole. This in turn will allow the creation of anatural gas market with a 100 billion m3 annualoutput capacity and a 70 billion m3 annual salesvolume.

Take full advantage of the economic advan-tages of the production-transport-sales centres ofShanghai and Guangdong and their ability tosustain prices and other such market advantages,which should allow for the rapid developmentand operation of a Shanghai oil and natural gastrading exchange. This will allow Shanghai andGuangzhou to act as pricing centres, making thecreation of relatively mature regional markets inthe Yangtze River Delta and Pearl River Deltadistricts possible within the time frame of the13th Five-Year Plan. At the same time, by rely-ing on the Ningxia Zhongwei, Hubei Wuhan andHebei Yongqing natural gas distribution hubsand making full use of the advantages offered bydistribution network nodes, it will be possible togradually develop logistical systems so that theyradiate out into surrounding areas, establishingthese as oil and natural gas circulation andlogistical centres, and allowing the formation by2020 of relatively mature Central-Western,Central-Southern and Bohai Loop regional mar-kets. Using this as the foundation, constructionof the Yunnan-Guangxi-Guizhou, Shandong-Henan-Anhui, North-Western and North-Eastern regional markets will then be possible.

This activity should take place in conjunctionwith the construction of the “Top Six” subter-ranean gas storage groups. These rely on depletedoil and gas reserves, and depend on suitable stor-age conditions existing within the oil or gasdeposits and create value from waste resources.The Central Plain, northern China, the North-East,Changqing, the North-West and the South-Westoil- and gas-producing regions will form six majorsubterranean gas storage groups. These groupswill gradually create and optimise a natural gasreserve peak adjustment system, which will be amajor factor in the creation of China’s “singlenetwork, with diversified sources and 10 regions”.

By harmonising planning, construction andusage of natural gas markets, resources andinfrastructure, it will be possible to create anintegrated national upstream-midstream-downstream combined production-transport-sales market system, ensuring that developmentof the natural gas industrial chain occurs evenlyat all levels.

314 14 Roadmap for Natural Gas Market Liberalisation …

14.2.2 Completion of a Natural GasPricing Mechanisms

1. Staged introduction of reforms to naturalgas pricing

Currently, preliminaryworkhas been carried outregarding the introduction of a dynamicmechanismfor pegging natural gas prices against alternativeenergy sources. Considering the special circum-stances of the natural gas industry, the widespreadimplications of reforms and the uncertainties con-cerning market conditions, it is recommended that,depending on the stage of development encoun-tered in the natural gas market, reforms to naturalgas pricing should advance steadily.

In the first stage, between 2015 and 2017, theemphasis should be on the creation of a pricingsystem. Application of the netback methodshould be introduced as soon as possible (in-cluding adjustment of the pricing coefficient Kfrom 0.85 to 0.70–0.75). Determine the costs andpricing of long-distance pipeline, branch pipe-line, provincial pipeline, urban pipeline and dis-tribution network pipework transport in ascientific and acceptable manner. Establish resi-dential gas pricing in the light of basic economicfactors. Refine implementation methods to allowfor seasonal price variations, peak and troughprice variations, interruptible supply pricing andgas storage pricing. Revise measurement stan-dards and valuation methods (conversion from aflow rate or mass valuation method to a calorificvaluation method), and increase administrativeand technical monitoring of illegal valuationactivities. Bring an end to the charging irregu-larities occurring at local government levels(such as the current natural gas pricing adjust-ment fund, with local governments exacting thisat rates that vary between 0.3 CNY and 1.0 CNYper cubic metre, which results in additionalburdens being placed on the consumer).

In the second stage, between 2018 and 2020,remove all regulation of gas source pricing,including all provincial gate station pricing.Enhance regulation over residential use gas pri-ces. Enhance the regulation of charging for use ofsuch infrastructure as gas transport pipelines and

gas storage, ensuring that there is effective reg-ulation in relation to sector admission.

In the third stage, between 2021 and 2023,charging for all gas transport pipelines except gasdistribution networks and for gas storage shouldbe completely determined by the market. Com-plete introduction of supervisory and adminis-trative systems with regard to pipeline networksand other infrastructure, ensuring that the objec-tives of allowing open, fair, orderly competitionwith regard to natural gas prices are achieved. Inaddition, policy should be formulated concerningthe introduction of a financial and taxation sys-tem relating to resource tax, environmental taxand carbon tax. This will ensure that a suitablescientific financial taxation system and pricingmechanism is put in place, which will reflect thegrowing scarcity of resources, the relationshipsof market supply and demand and the costs ofexternal environmental impact.

2. Accelerated creation of regional tradingcentres

In the short term, the Shanghai and Guangdongnatural gas trading centres could be established. Inthe mid to long term, new regional trading centrescould be established in Beijing, Sichuan, Hubei,Ningxia and Xinjiang. Efforts must be made toensure that the Shanghai natural gas trading centrebecomes both an Asian and international naturalgas trading centre, resulting in the Shanghai trad-ing centre system eventually becoming the centrefor trading of both internationally priced andregionally priced gas, thus effectively creating alink between domestic and international supplyand demand. The creation of natural gas tradingcentres should commence with spot trading, thenthe range and quantity of trading should beexpanded, finally developing into futures trading,increasing the depth of the market.

14.2.3 Removal of Pipeline TransportBottlenecks

The supervision of the operation of natural gasinfrastructure such as pipeline networks should

14.2 Key Measures 315

be extended, clearly establishing functional roles,to ensure that pipeline transport services andsales services are completely separate and thatthird-party access is facilitated.

The emphasis should be on reform to thenatural gas pipeline network construction andoperational systems, establishing functional roleswithin pipeline networks, and gradually resultingin a natural gas pipeline network to which fairaccess is provided, driven by supply and demandand which is both reliable and flexible. The for-mulation of policy in relation to market admit-tance in terms of pipeline network operation andservices should be accelerated; this shouldinvolve the introduction of an admittance systemof operator accreditation, ensuring the suitabilityof operators to undertake certain functions andduties. The basic requirements for operators willbe the existence of an independent legal bodycorporate, and implementation of independentfinancial accounting systems. In light of theactual circumstances of China’s natural gasindustry, the separation of provision of infras-tructure services could commence first with therelatively easily reformed long-distance pipelinenetwork and LNG receiving stations. As for howto approach separation, this could begin withfinancial and legal separation. Then, as the extentto which reforms are adopted increases, it wouldbe possible to institute trials in the easternregions, where there is a greater diversity of gassources, where competitive market structures aremore or less already in place and where there is arelatively high density in terms of gas transportpipeline networks. This would be followed by anationwide expansion. In addition to all this, anexploratory separation of the financial systemsand legal status of gas storage services from gasdistribution networks should be carried out. Sucha change would encourage varied investment inthe construction of gas storage capacity, allowingindependent storage operators to participate inthe natural gas market and profit from marketpeak and trough pricing differences.

Implementation of pipeline network inter-connectedness allowing connection of third-partyservices should occur rapidly, and more effortmust be put into the regulation of connection

contracts, service pricing and quality of service—this will encourage the creation of the condi-tions necessary for market competition.

In the gas transportation and LNG receivingstation sector, the scope of long-distance pipelineand LNG receiving station third-party accessshould be gradually expanded. Also, a permitadministration system should be introduced,allowing any accredited operator of natural gasservices to sign transport or storage contractswith pipeline networks and LNG receiving sta-tions. Under such circumstances, when excesscapacity in the distribution network systemsarises, operators of pipeline networks and LNGreceiving stations must offer this to any naturalgas supplier or user who has need of such ser-vices, thus providing a non-discriminatory ser-vice based on fair pricing. Within the mainpipeline backbone, all gas source input nodes andmarket terminals should be interconnected,removing any obstruction to the circulation ofnatural gas products. In terms of application,depending on the extent to which infrastructurehas been developed and the degree of separationthat has occurred between services and sales, itwould then be possible to gradually introducenegotiable and subsequently obligatory third-party access. At this point, it would be essentialto promote gradual deregulation (in terms ofannual natural gas consumption), allowing largeusers to choose their natural gas suppliersdirectly (“large users” being urban gas compa-nies, 200,000 kW power stations, combinedcooling, heating and power generation stations,large-scale industrial companies (including foruse as fuel and as a raw material) and LNG/CNGfuel suppliers, among others).

Regarding storage and urban gas distribution,third-party access mechanisms should be gradu-ally introduced to users at different scales ofconsumption. Start with non-residential cus-tomers with fairly high annual consumption; thisshould result in a timetable and establish annualconsumption scales. Then introduce freedom ofchoice of gas supplier to non-residential usersaccording to different annual consumption levelswhile adhering to this timetable and dependingon the extent of overall implementation of the

316 14 Roadmap for Natural Gas Market Liberalisation …

previous measures. Alternatively, it would bepossible to completely avoid urban pipeline dis-tribution networks, or such urban networkswould only be allowed to provide gas distribu-tion services according to government regulatedprices.

14.2.4 Further Regulatory Reform

Gradually set up a comprehensive, centralised,vertically unified, integrated, independent, spe-cialised regulatory system, with fully establishedregulatory functions, and put more effort intoestablishing regulatory powers.

At different stages in their energy develop-ment, the United States and European nationseach introduced an independent regulatorybody. The US established both an energyadministration and an energy regulator. Theenergy administration mainly has responsibilityfor fundamental policies relating to the devel-opment of energy resources and safety and forrelated policy research. The energy regulatormainly has responsibility for formulation andimplementation of specific regulatory policy. Interms of its market regulation, this includes astaged upstream-midstream-downstream regula-tory process. Although there is no regulatorycommittee for the upstream field, the federalgovernment’s Department of the Interior isresponsible for regulation relating to productionand use of energy sources, while individualstates carry out the regulation of certain types ofpermit in upstream manufacturing. There are,however, independent regulators at both themidstream and downstream levels, with FERCbeing responsible for the regulation ofstate-level pipeline transport and sales regula-tion, while state public utility regulatory com-mittees carry out regulation of downstreamenergy structures. These legally establishedregulatory bodies have adjudicative powers andare independent of the government, makingthem a more effective guarantee of the imple-mentation of government policy regardingenergy resources. Their open, fair, transparent,

legal principles make them more accessible topublic scrutiny.

Establish independent regulatory bodies andclarify their regulatory responsibilities. Fullyextend their regulatory functions, providinggreater regulatory functionality. The energy-related regulatory system should be establishedas soon as possible. Enhance energy-relatedregulation. Create and complete the structure ofregulatory organisations and related legislation,involving regulatory innovation, thus allowingimproved regulation efficiency and ensuring thefairness and stability of the markets. This willhelp to create a healthy environment withinwhich to develop the energy industry.

2015–2017: Complete and perfect harmoni-sation of the regulatory system. After establish-ing the relevant regulatory legislation, statutesand standards in conjunction with state energydevelopment planning and strategy and energyindustry policies, the different departments con-cerned should enhance communication inorder to harmonise their work and co-operation.During the course of the implementation ofthe regulatory system, all departments shouldensure enhanced sharing of information andco-operation. At the same time, it will be nec-essary to establish the functions and duties ofeach regulatory department in relation to centralgovernment and local organisations.

2018–2020: The State Council will deputisean energy regulation leadership group, whichwill be responsible for harmonising workbetween different departments and graduallyestablishing a relatively centralised regulationdepartment. Each department will retain itsoriginal regulatory legislation, standards andfunctions, while the main burden of regulatoryimplementation will gradually be transferred toone organisation, which will then provide a rel-atively centralised regulatory service. At the locallevel, government will only establish a regulatoryorganisation consisting of a single level ofadministration, which will then dispatch spe-cialist regulatory teams to various locations. Inaddition, the central regulatory department willbe responsible for monitoring and supervision oflocal regulatory organisations.

14.2 Key Measures 317

2021–2023: Complete and refine the functionsof a unified regulatory organisation. Apart fromits role of regulation of the environment andnational resources, this will gradually beendowed with full regulatory responsibility forthe economic and social aspects of the entireenergy industry chain. At this point a system ofinteraction between different departments will beclarified and their individual duties establishedand an independent, unified regulator will grad-ually be created. Finally, establish a system withan independent, unified, specialised regulator andvertical regulatory administrative organisations atdifferent levels.

Enhance reforms in terms of social account-ability and monitoring, with enhanced monitor-ing of present and future development andpromotion of a system of market supervisionbased on standardised and procedural regulatorymeasures. Impose a system of unified marketsupervision, eliminating and discarding all reg-ulations and practices that obstruct the creation ofa national unified market and fair competition.Make better use of the government, in order toensure that legal concepts and methods areapplied to the adoption of market regulatoryfunctions, with enhanced monitoring of presentand future development and promotion of asystem of market supervision based on stan-dardised and procedural regulatory measures.

1. Enhance the role of government regulation

Completion and optimisation of standards andnorms is vital. Accelerate the pace of work on theformulation and actualisation of regulatory leg-islation and technical standards and normsrelating to all aspects of natural gas development,transport, storage and distribution. Complete andrefine an environmental impact evaluation sys-tem, including evaluation of strategic environ-mental impact, evaluation of environmentalplanning impact and dynamic evaluation of theimpact of construction projects related to devel-opment, transport, storage and distribution of oiland natural gas.

Enhance the overall regulation of the com-plete oil and natural gas development process,

involving strict regulation in the pre-development stage, during development and inthe post-development stage. Pre-developmentregulation should include planning and prepara-tory work in relation to oil and natural gasdevelopment, ensuring that all safety and envi-ronmental hazards are rooted out. At the stagewhen companies or contractors draft oil andnatural gas development projects, they shouldalso draft an oil and natural gas environmentalimpact report, which should make proposalsrelating to implementing measures to avoid orreduce all types of pollution. At the same time,companies undertaking development projectsshould be required to establish baselines in termsof the main environmental indicators (such assubterranean water quality, surface water quality,air quality and so on) prior to commencing work,and continuous monitoring should be carried outduring the course of development. Well locationsmust be based on detailed geographical surveys,avoiding where possible densely populated areas,areas where environmental protection ordersapply and so on, all the while reducing damage tothe local land and using land more effectively.Where possible, pre-existing infrastructure shouldbe relied on, thus reducing the need for theconstruction of new roads and infrastructure.

Regulation during development mainly relatesto the drilling of oil and natural gas wells, theircompletion, gas extraction and normal operation.Contractors should be required to satisfy safetyand environmental regulation standards andnorms at all times and in all aspects of their work,adopting efficient, green, recyclable technology,all the while ensuring environmental protectionand safety. At the same time, they should ensurethat contractors are capable of responding effec-tively to prevent environmental pollution, thatthey have emergency protocols and that theyprovide anti-pollution equipment.

Post-development regulation mainly relates tothe evaluation of the long-term risks resultingfrom the development of oil and natural gas. Inthe course of development of oil and natural gasit is possible that environmental factors whichwere not easily perceived pre-development andduring development may arise. In the

318 14 Roadmap for Natural Gas Market Liberalisation …

post-production phases it is necessary to carryout analysis of subterranean water, surface water,soil and air and other such aspects of the envi-ronment. These samples should be comparedwith pre-development baseline levels, allowingan appraisal of the environmental impact of oiland gas development. Post-development regula-tion must be strictly enforced, and companiesthat do not satisfy standards should be punishedaccordingly.

Special consideration should be given tosafety and environmental protection as regardsmidstream pipelines:

• During pipeline construction, it is necessary toaudit the legality and qualifications ofprospective designers, suppliers and contrac-tors. During the pipeline design, supply andconstruction process, there should be closemonitoring for adherence to state safe pro-duction legislation and technical standards.Pipes and safety infrastructure should be sci-entifically selected and constructed, in order toroot out any safety flaws that may exist inpipework. Companies responsible for distri-bution and delivery of oil and gas should havea safety executive in place, and ensure thatsuitable personnel and equipment is provided,ensuring the step-by-step creation and opti-misation of a safe pipeline network and allo-cation of production safety responsibilities.

• Oil and gas pipeline safety work should beincluded within the scope of day-to-daygovernment administration, establishing acomprehensive, scientific and sensible regu-latory system, further enforcing specificresponsibility for safety management in rela-tion to pipeline installations. This shouldimplement a system whereby responsibilityfor this lies with local leadership, thusestablishing effective and enforceable proce-dures in relation to public safety. A systemharmonising the work of various departments,the government and pipeline companies needsto be established, such as a system of jointprogress consultations. The next level ofgovernment above will be responsible for

harmonising response in terms ofcross-boundary safety issues, and this willinclude establishing a system of responsibil-ities for all related government departmentsand pipeline companies, fully implementing asafety information sharing system and rapidsafety event response system.

• Those responsible for illegal appropriationand excavation and other actions that repre-sent a serious threat to the safety of oil andgas pipelines will be held accountable, andany organisations or persons found responsi-ble will be dealt with.

2. Enhanced enforcement of the safetyand environmental responsibilitiesof enterprises

Establish a comprehensive safe productionsupervisory and administrative body and regime.Enterprises must set up safe production com-mittees and safety management departments,which should be staffed with appropriate man-agerial staff. In addition, enterprises mustestablish a comprehensive production safetymanagement system, including a system of pro-duction safety duties, a system of safetyinstruction, a safety meeting system and a safetyequipment management system, including asafety incentive and penalty system and emer-gency response system.

Clarify production safety duties, providing acomprehensive production safety duty regime.Enterprises must establish a comprehensive pro-duction safety duty system, based mainly on jobresponsibilities, with the person with overallresponsibility at its centre, which establishes whohas overall responsibility for production safety andconsists of a system of production safety dutiesapplicable to staff involved in all departments andactivities, thus forming part of the overall pro-duction safety monitoring and duty system.

Strengthen safety management in relation tospecialist technology. Strengthen safety man-agement in relation to specialist technology onthe basis of production safety legislation, stan-dards and norms.

14.2 Key Measures 319

Institute a safety troubleshooting regime,thereby enhancing preparation for emergencies.Enterprises must carry out intermittent potentialaccident troubleshooting on the main aspects ofthe production process, the main points ofactivity and main items of equipment used.Where any potential accident areas are found,these should be subjected to specialist evaluation,categorisation and pre-emptive restrictions andspecial precautions. It is necessary to establish astrict potential accident reporting regime, stan-dardising potential accident control work. Whereaccidents occur, it is necessary to have aneffective emergency response organisation andspecifically formulated responses, which shouldbe practised in the course of day-to-dayoperations.

Introduce a health, safety and environment(HSE) management system and a pipelineintegrity management system. HSE managementis particularly concerned with the safety ofoperative activities, safeguards and operationalsafety, while pipeline integrity managementsystems are specifically concerned with equip-ment and technical management and preventativemaintenance in order to ensure the safe andreliable operation of equipment. By effectivelyintegrating the functions of these two roles,allowing them to complement each other, it ispossible to create a new pipeline managementsystem. This not only enhances HSE manage-ment systems, but also increases the level ofsafety management, supervision and the profes-sional skills of auditing personnel and is anextremely effective approach to safety.

3. Increased openness of information andpublic scrutiny

Openness of information and public scrutinyshould be standard throughout the entire processof oil and natural gas production, transportationand usage. Government departments shouldprovide effective guidance and carry out effectivesupervision of work on the openness of companydata and public scrutiny. This work should con-centrate on providing open, honest descriptionsof any environmental, safety or health issues

related with production, transport and usageprocesses, and the response of the companyconcerned to such risks. Furthermore, the gov-ernment should rapidly publish safety and envi-ronmental testing data, and should makecommunication with local residents a part of allstages of the development process, ensuring thatresidents are fully aware of any challenges, risksor benefits that may arise as a result.

NGOs and other civil society organisationsshould be active in carrying out public scrutiny,to establish whether or not the companies con-cerned respect environmental standards, whilealso holding regulatory bodies accountable. Thepublic should be aware of environmental issues,and have a full appreciation of the safety issuesand environmental risks associated with oil andnatural gas production, transportation and usage,thus allowing them to play a role in the publicscrutiny of oil and natural gas production,transport and usage. The media should play arole in the dissemination of environmentalknowledge and the exposure of illegal activities.Where media reports are critical, they shouldrequire companies to carry out investigations intothe veracity of the claims and resolve the issuesin question. In addition, companies should thenprovide reports within two weeks to the relevantdepartments and news organisations regardingthe results of rectification work they haveundertaken or the progress of their investigations.

14.2.5 Further Reformof the State-Owned Oiland Gas Companies

State-owned oil and gas companies played adominant role in The Netherlands before reform,making the situation very similar to thatencountered in China. Despite having created aunified energy market according to EU require-ments, due to path dependence, The Netherlandsadopted a different development approach. Thisapproach involved the retention of a number ofmajor state-controlled upstream, midstream anddownstream enterprises, while EBN, a com-pletely state-owned company with special

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characteristics, stepped in and took control overoperation of the oil and natural gas markets, astep which proved to be an effective measure.

The evidence proves that the presence ofstate-owned enterprises does not necessarilymean the presence of a monopoly or low effi-ciency. However, there does need to be spe-cialised supervision and management in order toimprove operational efficiency, which under fairmarket conditions will effectively promote theentry of social capital. The background of Chi-na’s development from a planned economy to amarket economy as well as features such as thestrategic position of gas resources and theirexploration and development, the high-risk nat-ure of pipeline transport and delayed returns oninvestment have determined that in order toensure the security and supply of oil and gas,involvement and investment by state-ownedenterprises is, at present, essential. Especiallyfrom the point of view of natural monopolies andimportant public goods and service sectors,dominance by state-owned enterprises shouldcontinue for a certain period of time. However, atthe same time it is important to encourageeffective competition through diversification ofinvestment and improvements in tendering andbidding structures.

There is a need to optimise the allocation ofresources afresh, while remodelling the corecompetitiveness of the enterprises concerned, inorder to create oil companies that satisfy basicrules of structural proportions in terms of theupstream and downstream sectors that applythroughout the global oil and gas industry. Thiswill result in the creation of international oil andgas companies that are more competitive inter-nationally, which will in turn improve thestanding of China’s oil and natural gas industry,as well as providing greater national energysecurity. Between two and three international oiland gas super-companies which have balanceddevelopment in terms of the upstream, mid-stream and downstream sectors should beestablished. At the same time, in order to ensurethat suitable conditions exist for effective marketcompetition to occur, after merging, such unifiedinternational super-companies should then hive

off part of their midstream and downstreambusinesses.

Simultaneously with this restructuring, ifstate-owned oil and gas companies are to con-verted into satisfactory market participants, thenthere will need to be a deepening of reforms.This process would mainly require the comple-tion and refinement of state-owned asset super-vision and administration systems andoperational systems, so that government’s vari-ous functions can be separated: social and eco-nomic, asset ownership management, state-owned asset management and state-owned assetoperation. This would achieve separationbetween government and business enterprisesand between government and assets, resulting inthe creation of efficient operational mechanismsand governance structures, which wouldencourage the management of state-ownedenterprises to conduct managerial activities andoperations based on market forces, thus encour-aging greater activity by state-owned enterprises.

14.2.6 Establish and Improvethe Services Market

The experience of the United States in its suc-cessful development of shale natural gas showsthat multiple investors and combined develop-ment systems for specialised services can mobi-lise the positive aspects of venture capital,technology research and development, upstreamextraction, infrastructure, market developmentand end applications, as well as put in place asystem for the implementation and improvementof the regulatory system to ensure the rapid andorderly development of the shale natural gasindustry. In an open and competitive environ-ment, there are advantages that may be exploited,such as increased specialisation and access totechnology within the technological servicesindustry, providing horizontal drilling, wellcompletion and cementing and multi-stagehydraulic fracturing services to rights ownersetc., as well as professional and technical ser-vices for engineering, logging and experimentaltesting. After a company completes a service in

14.2 Key Measures 321

relation to a specific aspect, it can then bereplaced by another company that specialises inthe next aspect. A high degree of division oflabour allows for splitting of shale natural gasextraction operations into individual aspects,requiring less investment, with shorter operatingcycles and a faster recovery of funds, attracting alarge amount of venture capital and private cap-ital into the shale natural gas field.

Market mechanisms must therefore beallowed to play a complete role. This will pro-vide a strong impetus for the development of oiland natural gas-related professional services andtechnology companies, in line with the principlesof “production requirements, advanced technol-ogy and a good reputation”. Market mechanismsand qualifying constraints can be used to regulateservice enterprises and their activities, organisingspecialist construction teams, while establishingnew systems founded on “exploration,

production, site operations, costing, safety andthe environment”. All the while, proceduralregulation of production processes and stan-dardised operations will ensure effective andorderly exploration and extraction.

At the same time, the training of professionalpersonnel needs strengthening. Sustainabledevelopment depends on the personnel of the oiland gas industry, so competition between enter-prises is ultimately competition using humanresources. It is therefore necessary to establishprofessional resources for China’s oil and gasmarket—and, indeed, for the international mar-ket. Not only is there a need for experts with agreat deal of management and technical exper-tise, they also need to be encouraged to expandtheir proficiency to legal matters and interna-tional trade, resulting in a relatively stable humanresource system which encompasses all the pro-fessions required.

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322 14 Roadmap for Natural Gas Market Liberalisation …

15Policy Measures and Safeguardsto Support Natural Gas MarketLiberalisation and RegulatoryReform

To promote the rapid and healthy development ofthe natural gas industry, completion and refine-ment of policy safeguards must take place assoon as possible.

15.1 Create and Complete a NaturalGas Legislative Framework

The fourth plenary session of the CommunistParty Central Committee proposed the creationand completion of a legislative system, consti-tuting a historical move towards the creation ofthe conditions necessary for legislative reform,laying the foundation for future legislativework. Thus legislative work should take aleading role in promoting economic and socialdevelopment, which will involve a transitionfrom “policy-guided action” to “legally guidedaction”, ensuring that reform and legislationkeep step, and that reforms occur according tothe law. Only by ensuring that development ofthe natural gas industry is realised according tothe law, and by increasingly establishing sci-entific and democratic legislation for the naturalgas industry, can good legislation and gover-nance be achieved, and a basic system for the

legal regulation of the natural gas industry putin place.

Although the initial framework for a legislativeand regulatory systemwithin the natural gas sectorin China is already in place, the existing legalsystem lacks co-ordination, consistency and sys-tematisation. For example, China still lacks aspecialist and comprehensive “oil and naturalgas law” that completely covers the entireupstream-midstream-downstream productionchain. In terms of exploration and development ofnatural gas, the existing mineral resources legis-lation is based on solid minerals, and deals withproblems that are common to the rights issuesencountered with mineral resources, making itunsuitable for resolving the specialised problemsarising in relation to natural gas, a gaseous min-eral. Moreover, most of the existing legislationwas created for a planned economy and restrictsthe rules of acquisition and transfer of mineralrights and is unable to fulfil the particular needs ofnatural gas and market liberalisation reform. Interms of natural gas pipeline networks, the endconsumer sector and environmental protection,the current regulatory legislation is incomplete,while the responsibilities and obligations of localgovernments and related businesses are not suffi-ciently clear in terms of transportation, gas storageand gas distribution. The technical specificationsand standards of the modern gas industry are stillnot sufficiently normalised and complete.

The law is the most important tool for gov-erning a country, and good laws are a prerequi-site of good governance. To form a completesystem of legal standards, first, key areas of

* This chapter was overseen by Xiaoming Wang fromthe Development Research Center of the State Counciland Mallika Ishwaran from Shell International. It wasjointly completed by Yusong Deng, Jiaofeng Guo,Shouhai Chen from China University of Petroleum andQingle Wu from Shell China. Other members of thetopic group participated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_15

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legislation must be strengthened, the systematicnature of laws and regulations must be enhancedand weaknesses in the legal system causing thelaws to contradict each other in terms of logicand value must be eliminated. Therefore, thelegal framework of the natural gas industryshould be improved as soon as possible. Thereshould be a comprehensive and effective naturalgas legal framework that consists of legislationspecific to the natural gas industry, with an “oiland natural gas law” at the core.

Improving the application of such legislationwill make it better suited to the characteristics ofnatural gas exploration, production, transporta-tion, storage, distribution and usage. Completionof improvements to relevant implementation rulesand supporting regulations should come first.Gas-specific legislation should be established assoon as possible, consisting of the formulation orrevision of the “oil and gas mining rights regu-lations”, “natural gas midstream and downstreamadministrative regulations”, “gas extractionenvironmental protection regulations”, “offshoreoil and gas pipeline protection regulations”,“natural gas reserves regulations” and otheradministrative regulations. Improvements to leg-islation in relation to resource rights, explorationand development contracts, infrastructure andoperational management, storage, sales andusage, safety alerts and emergency response,production safety and compensation for envi-ronmental impact, cross-border investment andimport and export trade are all vital as well.

Administrative regulations for natural gasmidstream and downstream should be researchedand drafted. The regulations should include, at thevery least: supervisory participants and duties atdifferent levels of government; the organisation,position, powers, duties, regulatory principles andoperating mechanisms of a natural gas regulatorybody; natural gas transportation administrationmodes and operational mechanisms; the rights,obligations and responsibilities of businesses inrelation to natural gas; the principles and mech-anisms which will determine the prices and dis-tribution charging rates for natural gas; pipeline

construction and authorisation; maintenance,security and open access to pipelines; and reso-lution of disputes.

Environmental protection regulations for gasextraction should be researched and formulated.Special provisions must be made for the fol-lowing aspects of natural gas exploitation: pol-lution prevention planning; environmentalimpact assessments; pollution permits; drillingfluids and exhaust gases; the recycling or pro-cessing of waste water and toxic gas; noisecontrol; management of radioactive sources;environmental monitoring; excessive pollution;and emergency response to pollution incidents.

Areas of conflict between the oil and gaspipeline protection law and other laws should bedealt with through by legal interpretation. Thereare various urgent needs: co-ordinating pipelinedevelopment planning and other specific plan-ning; dealing with the convergence betweenpipeline construction planning and urban andrural planning; legal determination of under-ground pipeline passage rights; restrictions onland use in relation to pipeline safety; and con-flicts between pipeline safety and road and railsafety requirements.

15.2 Deepen Reform of Oil and GasRegulations

The existing energy administration systems mustbe rationalised, and this will involve a gradualtransition to a high-level, centralised energyadministration. Industry administration should beenhanced by placing general industry-focusedplanning, market access approval and legislativefunctions under the control of one overalldepartment. More emphasis should be placed onstrategic planning in relation to energy develop-ment, implementing comprehensive planning,policies and standards in the administration ofthe industry. Increasing the rate at which relatedgovernance is simplified and deregulation occurs,further removing and deputising various admin-istrative duties and application approval

324 15 Policy Measures and Safeguards to Support Natural Gas Markets …

functions, and making a clearer distinctionbetween the role of government and the role ofbusiness, will reduce the extent of governmentinterference in microeconomic affairs. The sep-aration of government and business functionsshould be promoted further by separating natu-rally monopolistic businesses from competitivebusinesses, and opening up specific areas tocompetition, encouraging orderly access for alltypes of investor to all areas of the energyindustry, to allow fair access and encourageeffective competition.

Admission management should be imple-mented using a restriction list. A “restriction list”is a government-compiled list offields, businessesetc. to which prohibition or restrictions apply.Access to fields that are not included on the list iscompletely open, as a principle of “permissibleunless prohibited” applies. Give full play to themarket’s decisive role in resource allocation, andensure that where control is released this occurseffectively and reduces admission thresholds. Ifnot prohibited by law, activities should be open tomarket participants. If not authorised by law,government activity in activities is not permitted.This will provide greater space for the market toplay a determining role. A unified marketadmission system should be implemented, foun-ded on a restriction list regime, encouraging andguiding the access of various types of marketentity to participate in fields other than those lis-ted in the “restriction list” in accordance with thelaw. This will promote diversification of investorsin the energy sector.

However, in addition to relaxing marketadmission, there should also be certain large,significant changes involving deregulation ofboth large and small enterprises. For example, inthe oil and natural gas development and infras-tructure fields, where problems related toadministrative monopolies are particularly pro-nounced, allowing access to one or two majorcompetitors will result in more effective compe-tition. Consideration could be given to tenderingand bidding for conventional oil and gas mineralrights for the Sichuan Basin pilot scheme, to the

release to competition of construction and oper-ation of the provincial pipelines and to thecomplete deregulation of the oil and gas marketsfor Sichuan, Chongqing and other cities. Dereg-ulation of oil and gas importing would open upboth domestic and foreign markets and allowprivate enterprises to grow in influence.

15.3 Deepen Reform of the Fiscaland Tax Systems

1. Further improve fiscal policy

Action should be taken to take advantage ofmarket effects so as to expand funding for geo-logical exploration, with a focus on supportingand promoting unconventional and deep waternatural gas resource development and interna-tional co-operation. Government support mecha-nisms for fundamental, strategic and cutting-edgescientific research and research into generictechnology and mechanisms for funding majorequipment should be improved. The peak regu-lation, frequency modulation back-up and com-pensation policies should be refined.

The manner in which taxes are dividedbetween central government and local govern-ment needs adjusting. When compared to thermalpower generation and other such traditionalenergy sources, the financial discounts applied tonatural gas and other clean energy sources offerfew benefits in terms of local fiscal income, andas a result there is little stimulus for activity inthis area in local government. On the other hand,when compared to central taxes, the sources oflocal taxes are fairly dispersed, while collectionand administration presents greater difficulties,with unstable income affecting funding for thedevelopment of natural gas by local govern-ments. We suggest an appropriate adjustment ofthe proportions of VAT, company income taxand other taxes allocated from the natural gassector, increasing local government fiscalincome, which will act as an encouragement tolocal government to develop natural gas.

15.2 Deepen Reform of Oil and Gas Regulations 325

2. Extension of financial subsidies for shalenatural gas

Efforts to provide policy support for coalbedmethane as soon as possible should be intensi-fied. Financial subsidies to coalbed methanedevelopment companies should be increased to0.60 CNY/m3. The corporation tax exemptionpolicy should be extended to 2020, and thereshould be strict implementation of the VATrefund policy or implementation of an “imme-diate refund” policy.

Between 2012 and 2015, China’s centralgovernment gave a standard subsidy of 0.4CNY/m3 to shale natural gas businesses whosatisfied the relevant conditions. The period towhich the 13th Five-Year Plan applies will becritical for the launch, development and growthof China’s shale natural gas industry. Encour-agement of exploration and development of shalenatural gas will continue, despite the sharp dropin international oil prices and the likelihood thatthese will remain at between 60 and 80 $/barrelfor the next 3–5 years and the associated reduc-tion in global investment in shale natural gas. Inlight of this, the continuance and implementationof further shale natural gas exploration subsidiesis of major importance if shale natural gas is tocontinue to be developed on a large scale inChina. The standard subsidy for 2016–2018 iscurrently 0.3 CNY/m3; the standard subsidy for2019–2020 is 0.2 CNY/m3.

3. Accelerate resource tax reform

The objective of resource tax reform shouldbe the promotion of the rational development andutilisation of natural resources, the promotion ofecological and environmental protection and theacceleration of transformation of developmentmodes. It should be introduced in three stagesand cover three areas. In 2015–2016, preliminarycompletion of a resource tax system; in 2017–2018 the resource tax system should be more orless completed; and in 2019–2020 the objective

of the resource tax reforms should have beenfundamentally achieved, leading to an emphasison establishing the application of resource tax,determining appropriate taxation levels andextending the scope of tax collection, improvingcalculation and collection methods, and refininga system of resource commodity pricing, thisbeing achieved via integrated measures.

Research should be carried out on adjustingpetroleum product consumer taxation systemsand tax rates, promoting petroleum productconsumer tax reform using multifaceted taxationschemes. On the basis of improving the existingtax system, multifaceted collection schemes arerecommended, promoting petroleum productconsumer taxation reform. First, strict accredita-tion of wholesale businesses should be applied,through channels such as media monitoring andpublic oversight, to ensure that access is providedopenly, fairly and justly to approved wholesalers.Second, tax departments should focus on a newtax collection scheme, adjusting the regulatoryfocus to ensure that the transition between the oldtax system and the new one is smooth and suc-cessfully implemented. Third, the proportion ofoil consumption tax to be shared between localand central government should be determined ina scientific manner, encouraging the activeinvolvement of local government in collectionand administration. Fourth, thorough monitoringand improvement systems should be put in placein order to deal with new problems and situationswhich arise with the new tax system.

4. Establish and improve environmental taxand carbon trading policy systems

Environmental taxes are taxes levied forenvironmental purposes and include special taxesimposed or levies imposed as a form of pre-venting pollution or damage to the environment.The scope of such taxes ensures that they arelevied against and specifically target behaviourharmful to the environment. This form of taxa-tion (also known as “independent environmental

326 15 Policy Measures and Safeguards to Support Natural Gas Markets …

taxation”) is thus intimately connected withenvironmental protection, and generally includespollutant emission taxes, contaminant taxes andcarbon taxes. Pollution emission taxes are envi-ronmental taxes levied against pollutant emis-sions (such as waste gas, contaminated water andsolid waste). Contaminant taxes are environ-mental taxes levied against potentially contami-nating products (such as energy fuels, motorvehicles, ozone-depleting substances, fertilisers,pesticides, detergents containing phosphorous,mercury-cadmium batteries). Carbon taxes areenvironmental taxes levied against carbondioxide-generating fossil fuels such as coal, oiland natural gas.

During the period of the 12th Five-Year Plan,encouragement was given in particular to thebreakthrough in carbon trading which encouragedpilot schemes to realise a move from “voluntarytrading” to “mandatory trading”. In the long term,the aim is to establish a comprehensive primaryand secondary market which covers the entireeconomy and which integrates international mar-kets, with market mechanisms playing a decisiverole in the optimised allocation of all kinds ofenergy efficiency and emissions reductionresources, in order to achievemaximum emissionsreduction for minimum cost. Regarding carbontax, carbon tax legislation should be accelerated,making it possible to think about ways in whichcarbon trading can be used in conjunction withcarbon taxes, thus allowing implementation of avariety of policies. At the same time, enterpriseswhich actively use emissions reduction and car-bon dioxide recovery technology and which reachcertain standards should be given tax breaks.

Legislative work in relation to the transfor-mation from an environmental charge to anenvironmental tax system and the introduction ofpollutant emissions taxes should be accelerated.The objects of existing charges levied on pollu-tant emissions should all be included in the scopeof the pollutant emission taxation, and compre-hensive reform of the pollution charging systemshould be implemented. Further refinement of

energy efficiency and emissions reduction taxa-tion policy is required, as is the creation andrefinement of an environmental compensationmechanism, while the possibility of implement-ing a green tax system should be explored.

15.4 Establish and Completea Natural Gas DataManagement System

Refinement of a unified information managementsystem should occur as soon as possible. Sub-mission of oil and gas data should be linkeddirectly with mineral rights administration,allowing comprehensive integration and datasharing in the mineral rights administrative pro-cesses. Accelerate the establishment of a nationaldatabase. The main areas covered by this shouldbe the results of domestic oil and gas geo-graphical surveys and data relating to explorationand development, covering both domestic andforeign oil and gas resource data. Establish anational public information network for oil andgas resources, implementing concentrated anddynamic, publicly accessible data, mineral rightsadministration and raw data in an integrated oiland gas data management, publication and shar-ing service platform, in order to effectively pro-mote an open-door policy on mineral rights, withtruly equitable access, thus encouraging effectivecompetition.

15.4.1 Data Submission

Various types of data related to the explorationand development of conventional natural gas,shale natural gas and coalbed methane, includingoriginal geological data, outcome data and rele-vant geophysical information from geologicalwork, should be submitted to the departmentsresponsible for management of state-owned landresources, which will then be filed with the nat-ural gas mineral rights administration. Original

15.3 Deepen Reform of the Fiscal and Tax Systems 327

geological data and results data to be submittedshould include specialised information of aspectssuch as field geology, geophysics, geochemistry,geological remote sensing, experimental testing,engineering geology, drilling engineering andinformation technology. The complete dataset forthe previous year should be submitted by thesecond quarter for the previous year.

15.4.2 Standardised DataManagement

To strictly regulate the resource-based integrateddata management of conventional natural gas,shale natural gas and coalbed methane, submis-sion of natural gas resource raw data will belinked with gas mineral rights administration.This will establish mechanisms for natural gasresource data acquisition, processing, manage-ment and storage, promote the digitisation ofnatural gas resource raw data and establish andimprove new mechanisms for natural gas resourceraw data management and services, creating anintegrated management and shared services plat-form for natural gas resource raw data.

15.4.3 Database Developmentand InformationDisclosure

Resource information covering domestic con-ventional natural gas, shale natural gas andcoalbed methane should be set up, adoptingChina’s natural gas resource survey and explo-ration and development data as the basis of themain content of a national gas resource database.Implement comprehensive integration and datasharing in relation to the natural gas mineralrights administrative processes. Create a nationalpublic information network for oil and gasresources, implementing unified natural gasresources information management of concen-trated and dynamic data, public data, mineralrights administration and raw data.

15.5 Increase Reform and TechnicalInnovation in the Natural GasSector

State investment in gas development and utili-sation technology should be increased. The focusshould be on key technological breakthroughs,increasing investment in the areas of key tech-nology common to unconventional gas explo-ration, deep water gas development and LNGstorage and transportation. Strategic planningand expansion of research and developmentshould be instituted in the following eight keytechnology areas: shale natural gas exploration,deep water gas development, coalbed methaneextraction, gas hydrates extraction, coal-basedmethane, gas-powered vehicle (and ship) enginemanufacturing, combined cycle gas turbine gen-erators and carbon capture and storage, with afocus on achieving key technological break-throughs and early deployment of fundamentalresearch in the relevant fields.

The administrative system in relation toexisting technological investment needs to bereformed. The national energy departmentsshould organise and co-ordinate scientific, terri-torial resource, industry and information, finance,environmental protection and standardisationdepartments, defining the tasks and responsibili-ties of each different department with respect tosupport for natural gas technology innovation.With leadership from the State Council, uniformsupportive policies should be developed accord-ing to the shared features of technology. Rec-ommendations for improving the support systemfor natural gas technology innovation include:

• Establish a national major technology labo-ratory for unconventional gas, providingmanpower, resources and finance for researchbreakthroughs relating to key technology,should be established.

• Support business innovation and enhancingindustrial technological capabilities.

• Support businesses to transform themselvesand upgrade to clean, gas-based energy.

328 15 Policy Measures and Safeguards to Support Natural Gas Markets …

• Improve production efficiency through tech-nological innovation and investment.

• Assist backbone enterprises in adopting coretechnology, thus enhancing their technicalcapabilities and establishing their corecompetitiveness.

• Strengthen the links between producers andacademic research.

• Support research into shared technology anddevelop and implement independent projectspromoting autonomous, localised projectsrelying on clean gas based energy equipment.

• Encourage localised manufacturing of clean,gas-based energy technology.

• Intensify efforts to train personnel, supportingthe establishment of corporate research anddevelopment centres and post-doctorateresearch centres.

• Strengthen shale natural gas geologicalresearch, and accelerate the development andapplication of “factorisation” and “completesets” in the adoption and development oftechnology.

• Explore the formative process involved in thedevelopment of advanced practical shalenatural gas exploration and developmenttechnologies and business models.

• Foster in-house innovation and equipmentmanufacturing capacities.

• Encourage joint scientific advances andinternational co-operation, ensuring theintroduction, digestion, absorption and inno-vation of advanced technology.

• Adopt shale natural gas exploration, devel-opment and production technology suited toChina’s surface and subsurface geology.

• Accelerate the formation of environmentallyfriendly and cost-effective key technologyand equipment systems specific to China andimplement these in order achieve widespreadadoption.

In terms of equipment, the first step should beto increase the power rating of technology,reducing the number of devices necessary and

reducing the footprint of well-sites, making themmore suitable for mountainous settings. Next, theaim should be to bring about equipment modu-larisation, miniaturisation and portability so as tofacilitate work in complex surface configurations.To achieve cost reductions, design process opti-misation and research into low-cost hydraulicfracturing options should be actively pursued. Asregards environmental issues, environmentalprotection and the safety of additives should beensured, as should co-ordinated resource devel-opment and environmental protection. Over thenext 3–5 years, at the same time as digestion,absorption and innovation technologies areintroduced, key shale natural gas engineeringtechnology installations systems with Chinesecharacteristics should be adopted on a widerscale, and these should be environmentallyfriendly, economical and effective. After 2020,efforts should be made to ensure that localisedand mature proprietary shale natural gas tech-nology and equipment is available.

Large-scale coal gasification and methanationequipment, energy efficiency cascade technologyimprovements, microalgal biodiesel technologyas well as key sewage treatment technologiesshould be given priority and included in keynational basic research projects, while thereshould be increased investment in the develop-ment of technology and applications. Relying onexisting model coal methane projects, furtherinnovation and research should take place con-cerning the suitability of coal types andhigh-pressure gasification, increasing productioncapacity, improving gasification, reducing waterconsumption, promoting environmentally friend-lier new-generation coal gasification techniquesand key equipment and other such breakthroughsin proprietary innovations. In addition, researchand development of high-temperature methana-tion synthesis and reactor technology and equip-ment should take place, gradually resulting in thecreation of core production technology andautomated integrated systems suited to the char-acteristics of Chinese coal.

15.5 Increase Reform and Technical Innovation in the Natural Gas Sector 329

Research efforts into gas hydrates explorationand development technology should be rampedup, enhancing the research and developmentcapabilities in relation to core technology,thereby encouraging the development of coretechnology intellectual property.

• Investigation and evaluation of gas hydrateswill provide a basis on which the orderlydevelopment of gas hydrates can take place.Further improvements in resource surveying,exploration and evaluation techniques shouldbe applied to gas hydrates, prioritisingprospecting criteria and methods, allowingthe distribution of China’s maritime andtundra gas hydrates resources to be plotted—this will establish which gas hydrate landareas are commercially viable.

• Strengthening scientific and technologicalresearch into extraction technology will pro-mote a process by which gas hydrates couldbe developed in China. This should mainlyinclude:– research into methods that result in rapid

and efficient decomposition of gashydrates, such as depressurisation, heat-ing, chemical inhibition and carbon diox-ide substitution;

– research into key technology such asdrilling, completion, cementing, horizon-tal wells and fracturing and improved gascollection, storage and transportationtechnology, which will establish a rela-tively complete gas hydrates extractiontechnological system;

– research and development into extractionequipment and other key equipment,encouraging the introduction of locallymanufactured gas hydrates extractionequipment, enhancing the technical levelof China’s gas hydrates extraction equip-ment, strengthening the integration ofextraction techniques and methods, opti-mising extraction schemes and equipmentportfolios, and formulating practical gashydrates development technologicalsystems.

• Strengthening research into extraction safetyand environmental assessment, in order toestablish the likely impact of gas hydratesextraction on global climate change, seabedgeological disasters and deep-sea ecosystemsas soon as possible, will allow the introduc-tion of appropriate dynamic monitoring, dis-aster warning and control systems.

15.6 Expand International EnergyCo-operation

Co-ordinate the use of domestic and internationalresources and markets. Particular attentionshould be paid to ensuring that investment andtrade go hand in hand, while making use of bothland-based and maritime channels, in addition toaccelerating the development and implementa-tion of mid-term to long-term planning in relationto overseas energy resources, focusing onexpanding import channels, building the SilkRoad Economic Zone, the 21st Century MarineSilk Road, the BCIM Economic Corridor and thePakistan Economic Corridor, and actively sup-porting energy technology, equipment and engi-neering teams to “look outside”.

Strengthen the construction of the five keyenergy co-operation regions of Russia and Cen-tral Asia, the Middle East, Africa, the Americasand Asia-Pacific, and deepen bilateral and mul-tilateral international energy co-operation toestablish regional energy markets. Actively par-ticipate in global energy governance. Strengthenco-ordination and encouragement of enterprisesto “look outside” and to acquire or obtain sharesin foreign companies dealing with advancedshale natural gas and other unconventional gasdevelopment technologies in a systematic andtargeted manner, allowing China to accumulatetechnological experience relating to unconven-tional gas development.

• Further optimise the authorisation process toimprove authorisation efficiency. Competitionfor international oil and gas resources in the

330 15 Policy Measures and Safeguards to Support Natural Gas Markets …

mergers and acquisitions market has beenrelatively intense. Good projects often receivea lot of attention, while requirements relatingto deadlines have become stricter. In light ofthis, it is recommended that the relevantdepartments tighten up their overseas invest-ment authorisation procedures, reducing riskswhere possible and increasing authorisationefficiency in order to shorten the timerequired for authorisation to be granted.

• Take effective measures to solve the problemof the shortage of investment and financingfor overseas corporate mergers and acquisi-tions. First, policy banks can give the neces-sary support to enterprises for acquisitionfinancing. Second, China Investment Corpo-ration may be able to act as an investor forcertain projects. Third, some China-Africadevelopment funding and other such equityinvestments can play a role in overseasinvestment.

• From the long-term perspective, it is neces-sary to build a policy system which willencourage oil companies to “look outside”.First, co-ordinate the development of nationaloil security strategy and energy diplomacypolicy, creating an international environmentwhich is conducive to overseas investment inoil and gas, such as signing of investmentprotection agreements, securing relativelyreasonable fiscal terms on resources inregions like Latin America and Central Asiaand refinement of the government’s mecha-nism for rapid response to overseas emer-gencies. This will minimise the political,security and policy risks faced by oil com-panies due to overseas investment. Second,establish overseas venture exploration fundsfor projects approved by the state for whichoil companies can apply; after high-riskexploration pays off, a share of the proceedsis returned, or partly written off in the case offailure.

At the same time, the oil and gas futuresmarket being created in China must take intoconsideration the status and trends of the distri-bution of global resources, production develop-ment, trade flow and increasing consumption.A perfect, modern, international oil and naturalgas market system with foundation like these willhelp China attain a relatively favourable positionin the process of using global oil and natural gasresources to develop its economy. Therefore, onthe one hand China should respond to thedevelopments and trends in the market whileimproving the domestic oil circulation systemand price formation mechanisms, in order toestablish an oil and natural gas industrial systembased on diversified natural gas resources,diversified participants and open-market prices.On the other hand, though satisfactory marketadmission, foreign currency and customs policiesmust be put in place, in order to attract a largenumber of international investors to participate inbuilding a global international oil and natural gasfutures market.

The establishment of the China (Shanghai)free trade test area (the FTA) provides the con-ditions necessary to develop a Chinese oil andnatural gas futures market. Organisations such asthe People’s Bank of China have issued policiessuch as Suggestions on the Financial Support ofthe Shanghai FTA, under the principles of “firstrelease, then regulate” and “controllable risk,steady progress”. Capital account convertibility,CNY cross-border use and interest rate marketliberalisation have already been achieved in theFTA, indicating that China has entered a newstage of financial innovation and that the estab-lishment of an offshore financial market hasalready begun. Moreover, the Shanghai interna-tional energy trading centre will be specificallyresponsible for the construction of an interna-tional oil and natural gas futures platform, con-tract design and supporting mechanisms (such asforeign investor participation in transactions and

15.6 Expand International Energy Co-operation 331

bonded delivery), thus establishing a markettrading system based on three main principles:value-changing mechanisms, fair trading rulesand good credit systems. Solid progress on thiswork indicates that China expects to launchinternational oil and natural gas futures trading inthe near future, an event which will attract theparticipation of large numbers of internationalinvestors, which will allow us to take betteradvantage of both domestic and international

resources and markets. This will in turn help toimprove the international competitiveness ofChinese oil and gas companies on the openmarket, promoting the establishment of a Chi-nese oil and natural gas market system that isable to meet the ever-growing economic andsocial development needs for energy whileensuring national energy security.

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332 15 Policy Measures and Safeguards to Support Natural Gas Markets …

PART IV

International Experience from theDevelopment of Gas Markets Globally

Looking at the global energy system, natural gasconsumption is, on average, growing as a shareof the energy mix. This growth is driven by gasmarket liberalisation, a switch from other fuelsources and improved access to unconventionalnatural gas reserves. At the same time, the worldis increasingly being divided into regions thatconsume natural gas and regions that supply it.The imbalance in natural gas supply and demandhas in part driven the sharp increase in trade inliquefied natural gas (LNG) over the past decade.In this context, as an important part player in theglobal energy markets, China’s policy frame-work has a major influence on global natural gasmarkets.

Global natural gas pricing is in the process ofevolution, with oil-indexed long-term contractsincreasingly being replaced by market-basedpricing. For example, the US Henry Hub pricereflects current supply and demand conditions,seasonal variations, the impact of major disrup-tions, as well as long-term trends. In marketswith oil-indexed gas pricing, prices are lesssensitive to and reflective of market conditions.Historical links between natural gas and oil pri-ces are no longer relevant in many regions, andas the fundamentals of natural gas and oil mar-kets have diverged, so have natural gas prices inregions with competitive pricing compared toregions continuing with oil indexation. Theobjective of market-based pricing, such asthrough natural gas hubs, is to create a liquidmarket where natural gas is competitively priced.

A competitive natural gas market is key forachieving a more affordable, secure and envi-ronmentally sustainable energy system. In turn,this requires five core elements of a liberalisedmarket: creating institutions, ensuring openaccess to infrastructure, deregulating prices forthe competitive segments of the value chain,setting standards and ensuring market trans-parency and protecting end users.

The natural gas value chain can be broadlydivided into three segments: upstream markets,midstream infrastructure and downstream mar-kets. The upstream segment primarily refers todomestic exploration and production of naturalgas, where licensing regimes and fiscal policiesare important for incentivising and supportingproduction. The midstream segment refers toinfrastructure for the transport of natural gas—domestic and imported—through natural gastransmission networks and local distributioncompanies. The downstream segment refers towholesale and retail markets, including naturalgas trading hubs. A liberalised natural gas marketrequires deregulation of the upstream anddownstream segments, and third-party access tomidstream infrastructure.

As natural gas demand rises globally, securityof supply is becoming an increasingly importantissue. Key elements of natural gas securityinclude: diversity of natural gas supply sourcesand availability of alternatives, sufficient quantityof good quality supply and transmission infras-tructure such as storage facilities, pipelines and

LNG terminals, and institutions and policies tosupport the development of natural gas sourcesand infrastructure.

The energy system has implications forenvironmental pollution—for example, reduc-ing local air quality, which in turn produces

negative health outcomes and lowers the pro-ductivity of the economy. Substituting naturalgas for other fossil fuels in industrial applica-tions and residential heating can reduce localair pollution and provide significant benefits forthe economy.

334 International Experience from the Development …

16International Development Trends

Throughout the world, natural gas is gainingprominence in national energy systems. In manyeconomies its share of the energy mix is grow-ing. Major factors behind this global growthinclude market liberalisation, a switch from otherfuel sources and improved access to unconven-tional natural gas reserves. Environmental andenergy security considerations have addedimpetus to the trend.

In this chapter, we examine developments innatural gas supply and demand globally. We lookat developments and trends in international nat-ural gas markets in terms of supply, demand andprices. We also consider the experiences of manydeveloped economies of liberalising the naturalgas value chain. Given the increasing importanceof natural gas as an energy source, we examinethe effect of natural gas on national energysecurity. Finally, we consider the environmentalbenefits of a shift to natural gas, in terms ofboosting local air quality, improving health out-comes and increasing the overall productivity ofthe economy.

16.1 Global Natural Gas Markets

As global energy demand has grown, so has theimportance of natural gas in the energy system,both in absolute terms and as a share of theglobal energy mix. In 1980, natural gas accoun-ted for 19% of global energy consumption, andby 2010 that figure had risen to 23%. Duringthese two decades, natural gas consumption roseon average by 2.6% per year, compared to 2%for overall energy consumption, and is expectedto sustain a 2% annual increase until 2030. Whilemuch of the current demand for natural gascomes from developed markets, demand incoming years is expected to be driven byincreased consumption in emerging markets,particularly for power generation. Indeed, thebulk of this new demand is expected to comefrom Asia, and particularly China.

Demand for natural gas is driven primarily byswitching from other fuel sources, such as oil andcoal. In addition, increased economic intensity—which is pushing demand for all fuels—is con-tributing to growing consumption of natural gas.Reduced energy intensity (the amount of energyneeded for a given output) is mitigating thesegrowth pressures slightly. Perhaps surprisingly,our research finds that price differentials betweennatural gas and other fuels have a relatively smalleffect on fuel switching and demand growth.

The development of unconventional naturalgas has further stimulated natural gas demandgrowth. In the wake of recent success in theUnited States in exploiting shale natural gas, alarger portion of the world’s natural gas supply is

* This chapter was overseen by Jigang Wei from theDevelopment Research Center of the State Council andTaoliang Lee from Shell Eastern Trading Corporation. Itwas jointly completed by Yaodong Shi, Zifeng Song,Ren Miao from the Energy Research Institute of theNational Development and Reform Commission andCindy Wang from Shell China. Other members of thetopic group participated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_16

335

expected to come from unconventional naturalgas reserves. In 2030, shale natural gas andcoalbed methane are expected to account formore than half of North America’s natural gasproduction. Further, the US Department ofEnergy has estimated that China holds theworld’s largest reserves of technically recover-able shale natural gas, almost twice as much asfound in the United States. However, cost, thegeographic distribution of the natural gas fields,and the need for the appropriate capabilitiescould be obstacles to exploiting these reserves.

The global natural gas trade, and especiallythe flourishing LNG trade, has supported thecontinued growth in natural gas demand. Globaltrade in LNG doubled between 2003 and 2013.The increase in global LNG trade is expected tocontinue, leading to an increasingly linked andintegrated global natural gas market. Partly as aresult of the increased production of unconven-tional reserves in the United States and else-where, countries exporting LNG are likely tobecome more diversified in coming years, cre-ating a supply network with links to a broaderrange of demand centres. LNG shipping is alsomore flexible, adding further momentum to glo-bal LNG trade. Because they do not rely onimmovable pipeline networks, uncommittedLNG shipments can respond to price and bequickly directed to the best markets, based onprice. Energy security advantages and arbitrageopportunities also help LNG shipments tocompete with natural gas delivered overpipelines.

Pricing systems for natural gas are graduallyshifting away from oil-indexed contracts, espe-cially outside Asia. While natural gas contractshave traditionally been linked to the price of oil,the underlying economic fundamentals for thesetwo fuels have diverged. Oil-based fuels areprimarily used for transportation, with power andheat generation becoming a much smaller con-tributor to demand, while the use of natural gasin power and heat generation is increasing. Inaddition, the creation of natural gas hubs—no-tably in Europe and the United States—hasenabled natural gas contracts to be linked totransparent and readily available natural gas price

benchmarks, such as Henry Hub in the US andthe British National Balancing Point (NBP).

As part of this study, we examined the impactof different Chinese natural gas demand scenar-ios on global energy markets. The analysis sug-gests that an increase in China’s natural gasdemand is not likely to have a significant impacton global natural gas prices, as global supply isable to respond to increased Chinese demand.However, Chinese coal demand displaced by theincrease in natural gas demand is likely to have asignificant impact on global coal prices. Chinacurrently accounts for a large share of global coaldemand, and the decline in demand, combinedwith global coal supply being slow to respond tothe new market conditions, is likely to depressglobal coal prices. In the absence of any policiesto restrict coal use, regional economies such asIndia and Indonesia are likely to be the mainbeneficiaries of lower coal prices.

16.2 International Experiencesof Liberalising the Natural GasValue Chain

As part of our study, we examined the liberali-sation experience of natural gas systems in fivemarkets that have witnessed significant increasesin consumption in recent years. In all of thesemarkets—the United States, the European Union,the United Kingdom, Japan and South Korea—market liberalisation and increased competitionplayed a significant role in increasing domesticdemand for natural gas. The market developmentin each of these cases was unique, but there arenonetheless positive and negative lessons thatChina can learn from.

When it comes to increasing the share ofnatural gas in the energy mix, three keyenergy-related concerns for policy-makers are:

• providing affordable natural gas for business,residential and industrial end users;

• enhancing national energy security by diver-sifying supply networks and improving thecountry’s negotiating position in internationalnatural gas markets; and

336 16 International Development Trends

• delivering ancillary benefits, such asimproving air quality or supplying energy topoor households and regions.

Liberalising the natural gas value chain canhelp to balance and support these objectives. Forexample, increased competition in the extractionand sale of natural gas can drive down costs, andtherefore reduce the price paid by consumers andend users. It can also help to diversify sources ofsupply, increasing energy security.

The countries we studied followed similarpaths to liberalisation, although they differed inthe details and the level of success. The processof liberalisation helps to deliver competitivemarket outcomes—to provide end users with thegreatest choice at the lowest price. This can beachieved by opening markets to competition orthrough regulatory measures to limit or cap pri-ces where natural monopolies exist.

The natural gas value chain can be dividedinto three segments: the upstream explorationand production segment; midstream infrastruc-ture, including transmission and distributionpipelines and LNG terminals; and the down-stream wholesale and retail markets for naturalgas that bring the fuel to consumers and endusers. Competitive markets can exist at manypoints in this value chain.

Competition in the upstream segment can drivegreater efficiency and innovation in the explorationand production of natural gas, as a way to drivedown costs and develop greater volumes ofdomestic supply. For example, before the liberal-isation of natural gas markets in the EuropeanUnion, state-owned, vertically integrated naturalgas companies had little incentive to improve theefficiency of their operations, leading to increasesin the price of natural gas. Similarly, greater com-petition in the downstream segment can increasechoice and reduce the price paid by the end users ofnatural gas, for example by increasing competitionin the shipping and sale of natural gas. These seg-ments can be opened to competition, within aregulatory oversight framework that ensures andsupports competitivemarkets andwithout the needfor further regulatory interventions.

However, opening the midstream segment tomarket competition is typically not desirable, and

is likely to fail. Midstream infrastructure, such aspipelines, is highly capital-intensive. For exam-ple, in 2013, onshore oil and natural gas pipelineconstruction in the United States cost $4.1 millionper mile, while offshore pipelines cost $7.6 mil-lion per mile. High fixed costs and relatively lowoperation and maintenance costs point to largeeconomies of scale: the costs of delivery declinerapidly with volume. This fits the definition of anatural monopoly, where the lowest long-runaverage costs are realised when production andownership are concentrated in a single firm.Countries have dealt with the natural monopolycharacteristics of midstream infrastructure in anumber of ways: by mandating third-party accessto pipeline infrastructure; by regulating the tariffsthat pipeline infrastructure owners can charge foraccess; and/or by separating transport servicesfrom upstream and downstream businesses (aprocess known as unbundling).

To be more specific, countries that have suc-cessfully liberalised the natural gas value chainbegan by creating the necessary institutions, par-ticularly a strong and independent natural gasregulator. They then moved to ensure open accessto the natural gas network by, for instance,requiring large integrated companies to unbundletheir holdings, regulating network charges andoverseeing third-party access to transmission anddistribution networks. These countries alsoderegulated prices where appropriate, especiallyin the upstream and downstream segments of thevalue chain. They set market standards and man-dated transparency, for example by standardisingtrading agreements and supporting the develop-ment of natural gas hubs. And finally, they strivedto protect end users by overseeing competitionand managing adverse market impact.

16.3 Liberalisation of DifferentSegments of the Natural GasValue Chain

In addition to examining the evolution of naturalgas systems in selected markets, our study alsolooks at international experiences of liberalisingspecific parts of the natural gas value chain.

16.2 International Experiences of Liberalising the Natural Gas Value Chain 337

In the upstream segment, liberalisation hasfocused on encouraging new entrants andincreasing competition through appropriate fiscaland licensing regimes. International experiencesuggests that these measures are necessary tomeet national objectives, as well as to ensure thequality and quantity of natural gas production.

In the midstream segment, the natural mono-poly characteristics of natural gas transmissionand distribution infrastructure have meant thatliberalisation efforts have focused on providingthird-party access and unbundling. In setting theframework and terms for third-party access,governments need to balance the need for fairand open access with incentives for furtherinvestment in midstream infrastructure. Thisbalance varies by country and circumstance. Forexample, regulators in Japan have favouredmidstream investment over access. Thus, whileprovisions for third-party access exist in law,enforcement has tended to be lax.

In addition to third-party access, unbundlingis an important consideration with regard tomidstream assets. Often, as a country begins theprocess of liberalisation, the national market isdominated by one or a few companies that ownassets throughout the value chain. These com-panies have a strong incentive to restrict access tomidstream infrastructure in order to benefit theirown upstream or downstream businesses.Because of this natural tendency, countriesseeking to liberalise their natural gas marketsoften require these vertically integrated compa-nies to separate—or unbundle—midstream assetsinto autonomous businesses. Unbundling hastaken various forms. While countries like theUnited Kingdom and The Netherlands haveachieved full ownership unbundling, others likethe United States, Germany and France havechosen to stop one step short, at structuralunbundling. The experience of these lattercountries indicates that full ownership unbund-ling is not required, and that structural unbund-ling under a strong regulator can capture many ofthe benefits of full ownership unbundling.

Finally, with respect to the downstream seg-ment, our study examines the development ofcompetitive natural gas wholesale markets and

the establishment of natural gas hubs. Wholesalemarkets connect upstream sellers and retailbuyers and establish a basic price point for nat-ural gas in a country or region. Regulatory effortshere have often strived to encourage the devel-opment of natural gas hubs, national or regionalcentres that ease transactions between buyers andsellers. Hubs can push natural gas pricing awayfrom oil-indexed contracts, creating a morecompetitive pricing mechanism that is based onthe value of natural gas and is more responsive tochanges in market conditions.

Successful hubs enable competitive pricing ofnatural gas, more efficient market co-ordinationand increased market transparency, with con-sumers and end users benefiting from the moreefficient pricing of gas. By reflecting the true costand value of natural gas in the economy, hubpricing also ensures that trade and investmentdecisions are made on the basis of economicbenefits and efficiency. Hubs also create power-ful and self-reinforcing network effects, whichhelp to lower transaction costs and increasecompetition in wholesale gas markets. Finally, ahub also supports energy security objectives bysupporting the diversification of sources of sup-ply. Diversified and liquid hubs are better able torespond to changes in demand compared to theinflexibility of long-term contracts, for exampleby procuring LNG cargoes on the spot marketduring peak demand periods.

16.4 Natural Gas Energy Securityand Social Influence

As global energy demand has grown, so haspolicy-maker interest in the security of energysupply. Until recently, concerns about energysecurity centred mostly on safeguarding oil sup-plies, but as the global energy mix has diversi-fied, the scope of energy security has broadenedas well. Our study finds that while there are awide range of approaches that a country can useto achieve energy security, they can be distilleddown to three critical aspects of the supply chain:sources, infrastructure and institutions. Combin-ing imports, domestic supplies and access to

338 16 International Development Trends

alternative fuels results in a diversified supplywith readily available fuel substitutes. Ensuringthe quantity and quality of physical assets such asstorage facilities, pipelines and LNG terminalsmeans that sources of supply can be accessedreliably. Finally, proper market and politicalorganisations, as well as underlying incentives,are necessary along the supply chain in order todevelop these sources and infrastructure.

Assessing China against this framework, ourstudy finds that the country is in a good positionwith respect to natural gas energy security. Interms of sources, rising LNG trade, future pipe-line imports and significant availability of alter-native fuels provide a diversified source ofsupply compared to other large naturalgas-consuming countries and regions such asJapan, South Korea and the European Union.Rapid infrastructure development has meant thatChina has capacity (especially storage) to matchthe levels of other major gas-consumingcountries.

Since China became a net importer of naturalgas in 2007, import sources have rapidly diver-sified. Figure 16.1 shows, compared to the EU,Japan, and Korea, China’s rapid increase in thediversification of its natural gas imports, therebyincreasing its energy security. In 2007, China’sonly import source was Turkmenistan. TheHerfindahl Index was 1. Following the develop-ment of LNG trade, China’s import sources havediversified rapidly, and its Herfindahl Index has

correspondingly dropped. Today, China’s naturalgas import diversification is comparable to that ofthe EU. In 2010, it was even comparable tonations with the most diversified sources of nat-ural gas—Japan and Korea.

Compared to nations with high natural gasenergy ratios that rely more on natural gasimports, China’s imports are more diversified.China, the EU, Japan, Korea, and Turkey are thetop five importers of natural gas. These fivenations have very diversified sources for theirimports, and their Herfindahl Indexes are all verylow. However, as shown in Fig. 16.2, comparedto other countries, China’s natural gas energyratio is lower, and its reliance on natural gasimports is lower. In fact, other nations do nothave the import diversification that China enjoys,and their reliance on imports and on natural gasis significant. However, these nations rarely facemajor natural gas security issues, which indicatesthat China could safely raise the proportion ofnatural gas in its energy mix as well as its pro-portion of natural gas imports.

LNG enables not only China but also theentire world to achieve greater supply diversifi-cation. From 2003 to 2013, global LNG tradedoubled, with a huge influx of new buyers andsellers. Figure 16.3 shows Japan’s LNG tradenetwork. Japan’s LNG sources are in the innercircle, while the outer circle shows other coun-tries that Japan’s import sources supply. Thearrows show LNG trade direction. The coloured

19950.0

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0.4

0.6

0.8

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2000 2005 2010

EU

Japan

South Korea

China

In 2007, China becamea net importer ofnatural gas

Fig. 16.1 China’s natural gas import diversification. Source Vivid Economics, based on EIA data

16.4 Natural Gas Energy Security and Social Influence 339

arrows indicate how reliant each exporting nationis on Japan. Red arrows show relatively highreliance on Japan and yellow arrows show lowreliance. In 2003, there were relatively fewnations supplying LNG to Japan, and Japan wasone of the few consuming nations. By 2013,Japan had added more nations from which itimported LNG, diversifying its import sources.Moreover, these exporting nations had growntheir client base since 2003, though many stillrelied heavily on Japan for their LNG sales.

Figure 16.4 shows China’s natural gas tradingnetwork in 2013. In addition to LNG trade duringthis period, there was also one Turkmenistannatural gas pipeline. Compared to other nations,China’s imports of LNG were more diversified.However, compared to Japan in 2013, there is amarked difference. For exporting nations, Japanis a more important export destination.

In the future, new pipeline natural gas willimprove the security of natural gas for China.Figure 16.4 shows that currently China’s pipe-line trading has negotiating power. Turkmenistanhas only Kazakhstan and Iran as its other exportoptions. China, on the other hand, also plans toengage in pipeline trade with Uzbekistan, Kaza-khstan and Myanmar (the options for these

countries are limited as regards pipeline desti-nations) as well as Russia (East-West Siberian oiland gas field natural gas export destinations arelimited). Therefore, even though Japan’s LNGsupply is more diversified, China (leaving LNGto one side) still has the option to use pipelinenatural gas and can also engage in domesticproduction. This means that China does not needto have a strong relationship with naturalgas-exporting nations as Japan does, but caninstead use natural gas hubs to make exportingnations compete with one another.

Domestic natural gas production can greatlyimprove China’s natural gas security. Domesticproduction is a reliable option to replace imports,and can improve negotiating power. China’sdomestic production has great potential, andfeatures some of the world’s major unconven-tional natural gas reserves. However, currentproduction levels are low, and future productionremains uncertain. This uncertainty is a keyfactor in China’s natural gas security, sinceinternational experience shows that natural gassecurity of producing nations is entirely different.

There is a close relationship between naturalgas market liberalisation and whether a nationhas domestic production. Nations without

0.00 20 40

Proportion of imported natural gas

Her

finda

hl In

dex

60 80 100

Primary FSU andMENA nations

Proportion of natural gasin energy structure

(%)

0.2

0.4

0.6

0.8

1.0

UKR

SGP

TUR

KOR

0

20

40

60

80

100

JPN

EU

CHN

BRA

IND

USA

Primarynatural gasmanufacturingnations

Fig. 16.2 China’s import security as compared to major nations. Source Vivid Economics, based on IEA and EIAdata; natural gas proportions are from 2011, with remaining data from 2013

340 16 International Development Trends

JPN

IDNEGY

BRN

AUS

AGO

DZA

EU YEM

O.Am.

DOM

CAN

CHL

THAUSAISR

MEX

ARG

TWN

KWT

CHN

IND

BRA

TURKOR

TTO

RUS

QAT

PER

OMNNOR

MYS NGA

ARE

JPN

OMN

EU IND

DOM

O.Am.TWN

KOR

QAT

MYS

IDN

BRN

AUS USA

ARE

TTO

Fig. 16.3 Japan’s LNG supply sources are diversified. Source Vivid Economics, based on IEA data

16.4 Natural Gas Energy Security and Social Influence 341

domestic production such as Japan and Germanyand nations with large volumes of domesticproduction such as the United Kingdom andUnited Sates prove this point. For example,Japan’s market is more co-ordinated and thereare large companies with bargaining power withexporting nations. However, the United Statesand United Kingdom have more open marketsand their competitive pressures stimulate moredomestic production. Another factor is thatdomestic production improves bargaining powerwith exporting nations, since when import supplyis cut off, the nation has a reliable substitutesource. Figure 16.5 illustrates the consistentrelationship between domestic production andmarket liberalisation.

Currently, China’s natural gas market is aco-ordinated one. However, there is still majorpotential to develop domestic production.

International experience has shown that furtherdeepening of market liberalisation will increasedomestic production, which then improves nat-ural gas supply security. This would compensatefor any reduction in bargaining power that mightarise from moving away from the currentco-ordinated market system. Therefore, out ofconsideration for energy security, China couldstrive to increase domestic production, andmarket liberalisation is one means to stimulatedomestic production.

China has another abundant substitute fornatural gas that can further improve sourcesecurity. Natural gas can be used for powergeneration and supply of heating—and these areenergy services that China’s abundant coal orrenewable energies can provide. To a lesserextent, natural gas is also used for transport,where oil products can potentially be substituted.

CHN

EGY

JOR

ARG

KWT

TWN

EU

IND

ARE

TUN

MAR

BRA

KOR

TUR

JPNIRN

KAZ

O.Am.

DOM

OMN

CHL

CAN

THA

GHA

USA

ISR

SGPMEX

IDNMYS

NGA

QAT

TTO

TKMYEM

DZA

AGO

AUS

Proportion of sourceexports in China

0

20

40

60

80

100

Fig. 16.4 Sources of China’s natural gas. Source Vivid Economics, based on IEA data

342 16 International Development Trends

if the natural gas supply were disrupted,switching over to other fuels could limit thenegative repercussions. However, using otherfuels requires a variety of technologies, not all ofwhich are available to consumers, such as being

able to switch smoothly from natural gas to fueloil or other sources for heating. Moreover, usingcoal and petroleum as substitutes will have agreater impact on the environment and climate.For these two reasons, the priority should be to

Coordinated market

Dom

estic

pro

duct

ion

prop

ortio

n of

dom

estic

cons

umpt

ion

Breaking down the degree of marketisation of the levels represented(Years in the figure refer to the years at current level)

Marketised market

>100%

80% ~ 100%

60% ~ 80%

40% ~ 60%

20% ~ 40%

0 ~ 20%

2014

2012

2005

20001992

Fig. 16.5 Time points when major nations promoted market liberalisation reforms

Europe North America

South Korea

Japan China India EU nations

Other

Geological reserves

LNG reserves Currently planned 2020 China reserve ratio

MENASouthAmerica

2013

rese

rve

prop

ortio

n to

natu

ral g

as c

onsu

mpt

ion

Prior to the large increasein geological reserves in 2014, China’s reserves were always low

The IEA estimates that Chinaplans to have an additional 50 billioncubic metres of geological reserves by 2020, with LNG reserves of 4.2 billion cubic metres

Fig. 16.6 Gas reserve volume as a proportion of consumption, showing planned increase for China. Note 2013 Chinadata includes the 10.7 billion m3 of China National Petroleum Corporation Hutubi. Source Vivid Economics, based onIEA data

16.4 Natural Gas Energy Security and Social Influence 343

improve energy security through domestic pro-duction and diversification of imports.

China has the world’s sixth-largest natural gasimport capacity, and through the West-East pipe-line it also has major pipeline import capabilities.This infrastructure was developed after 2005, andChina is continuing to develop its infrastructure,with plans for major expansions in the future.Current plans indicate that by 2020, China willhave increased its pipeline import capacity by114 billion m3 over 2012, with 40 billion m3 ofLNG import capacity, which is forecast to satisfyplanned natural gas import demand.

In terms of reserves, China’s reserve volumeis on par with other major natural gas-consumingnations. For example, in 2014 storage facilityconstruction brought consumption reserve

volume on a par with Japan, as shown inFig. 16.6. In 2020 it is planned that reservecapacity will increase, even if demand grows asexpected, to the highest level worldwide, thelevel currently held by Europe.

Based on international experience, a lackof infrastructure, maintenance and promptpost-incident repairs are the main reasons fornatural gas supply cut-offs. Moreover, inmany nations, these problems are oftenoverlooked, viewed as operational issuesrather than policy issues. As China’s naturalgas industry develops, continued investmentin infrastructure and the establishment ofsufficient and reliable accompanying tech-nologies and incentive measures will beespecially important.

Open Access This chapter is licensed under the terms ofthe Creative Commons Attribution 4.0 InternationalLicense (http://creativecommons.org/licenses/by/4.0/),which permits use, sharing, adaptation, distribution andreproduction in any medium or format, as long as yougive appropriate credit to the original author(s) and thesource, provide a link to the Creative Commons licenseand indicate if changes were made.

The images or other third party material in this chapter areincluded in the chapter’s Creative Commons license,unless indicated otherwise in a credit line to the material. Ifmaterial is not included in the chapter’s Creative Commonslicense and your intended use is not permitted by statutoryregulation or exceeds the permitted use, you will need toobtain permission directly from the copyright holder.

344 16 International Development Trends

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_17

345

17The Global Natural Gas Market

Global natural gas consumption, both in absoluteterms and as a share of the energy usage mix, iscontinuing to grow. This growth has been drivenprimarily by changes in patterns of economicactivity, energy intensity and energy substitution.Of these, the primary driver has been the switchto natural gas from other sources, primarily oil.Natural gas prices have consistently remainedhigh in recent years, but despite this and the factthat gas has not been given any major preferen-tial advantage compared to other energies, therehas been no marked dampening of demand.

As global consumption volumes grow, thedivisions between regions that consume naturalgas and regions that supply natural gas willbecome more marked. The Asian OECD membernations1 and Europe have become the majornatural gas importers, with the former SovietUnion states, the Middle East and North Africadominating natural gas exports. The growth ofthe gap between natural gas production andconsumption is continuing to widen, and greatervolumes of trade are necessary to balance supplyand demand.

As natural gas supply hubs rise in promi-nence, natural gas prices are gradually breakingfree from their link to oil prices. In the UnitedStates and Europe, because the natural gas mar-ket has matured, supply hubs have sufficientliquidity for competitive trading, and natural gasis priced for its own value rather than beinglinked to oil prices. However, an Asian naturalgas trading hub is unlikely to develop soon, asthis region’s markets are still controlled by asmall number of larger buyers and sellers, andmarket liquidity is low. Given the imbalances inregional supply and demand, shipping costs andtrade restrictions, natural gas prices are likely tocontinue to vary by region rather than to con-verge on global unified price levels.

17.1 An Overview of the GlobalEnergy Market

Natural gas is a growing player in the globalenergy mix (Fig. 17.1). In 1980, natural gasprovided 57 EJ or 19% of the global total primaryenergy consumption volume of 300 EJ. In 2010,natural gas provided 124 EJ, representing 23% ofthe 525 EJ global total. Natural gas grew itsproportion of primary total energy at a time whenglobal energy consumption was itself risingrapidly. So natural gas demand grew at a fasterrate than total energy demand—since 1980,average annual growth rate for natural gas hasbeen 2.6%, compared to 2.0% for total energy.

Natural gas is increasing its share in global andregional energy mixes by displacing oil products

* This chapter was overseen by Jigang Wei from theDevelopment Research Center of the State Council andTaoliang Lee from Shell Eastern Trading Corporation. Itwas jointly completed by Yaodong Shi, Zifeng Song,Ren Miao from the Energy Research Institute of theNational Development and Reform Commission andCindy Wang from Shell China. Other members of thetopic group participated in discussions and revisions.

1Japan and South Korea.

60%40%

80%20%

0%100%Gas

Many regions are movingtowards gas, in particularEurope and regions with

large gas reserves

Many regionshave an energymix:

40–60% oil 20–40% coal 20–40% gas

Asia, and the world inaggregate, are moving

towards coal

40%60%

China’s energy mixcontinues to be

dominated by coal

Oilproducts Coal100%

0% 20% 40% 60% 80% 100%0%

20%80%

North AmericaChinaFSUMENAOECD AsiaAsiaCentral and South AmericaAfricaEuropeWorld

1980 2012

more gas, equal decline in oil and coal

more gas, less coal,

constant oil

constant coal,more gas,

less oil

Fig. 17.2 Changes in share in the energy mix between oil, gas and coal. Note Data is share of fossil fuel energy; eachcountry’s coloured trail along the matrix gets thicker over time; movement toward the apex illustrates increased share ofnatural gas at the expense of oil (lower left) or coal (lower right). Source Vivid Economics, based on EIA data

01980

5767

7986

95

108

124

Global Total Primary energy Consumption (exajoules)

1985 1990 1995 2000 2005 2010

100

200

300

400

500

600 Natural gas

Petroleum products

Coal

Renewable electricity

Other

Fig. 17.1 Natural gas’s share of global energy consumption. Note Data is global total primary energy consumption.Source Vivid Economics, based on EIA data

346 17 The Global Natural Gas Market

and, sometimes, coal (Fig. 17.2). Each regionuses differing amounts of oil products, natural gasand coal to supply its primary fossil fuel energyneeds each year, and the balance of these energysources changes over time. In the Middle East andNorth Africa and countries of the former SovietUnion, for example, natural gas has tended tosupplant oil, while in North America and Europeit has taken some of coal’s share. In general, theglobal trend has been toward natural gas con-sumption in lieu of oil use, with a parallelmovement toward coal as well in some regions.

Looking to the future, global energy demandwill continue to grow, and demand for naturalgas is expected to increase faster than demand forother fossil fuels, continuing the trend of recentyears. The IEA has noted that rapid populationgrowth, increasing prosperity and improvedaccess to reliable electricity are driving this trend.Average annual growth rate for natural gas isgenerally forecast to be 2% from 2012 to 2040.

The growth in natural gas demand in theperiod to 2040 is expected to be widely dispersedgeographically, with Asia and the Americasplaying an important role (Fig. 17.3). Asia isexpected to account for the largest proportion ofglobal natural gas demand growth during thisperiod (as well as production). In particular,natural gas demand in China is expected to growby 5.2% a year, accounting for 56% of Asia’snatural gas consumption growth. Natural gasdemand is expected to grow steadily in other

emerging economies as well, with India rising4.6% a year and Brazil 4.0%. However, OECDmember country growth should be slower, aver-aging about 1% a year.

Power generation will play a significant rolein increasing natural gas consumption, account-ing for 36% of total growth from 2012 to 2040(Fig. 17.4). Driven by the petrochemical indus-try, the industrial sector is also expected tocontribute strongly, with an annual growth ratereaching 1.9%. Although natural gas use intransportation is expected to grow strongly at3.3% a year, this sector will still continue toaccount for only a small share of total demand,about 9% by 2040.

During the same period, unconventional nat-ural gas (such as shale natural gas) will come toaccount for an increased proportion of the overallsupply mix. Global natural gas resources arewidely dispersed geographically, and at the cur-rent rate of production, there are 60 years ofproven reserves (Table 17.1). Even though USshale natural gas development has seen stronggrowth, there remain significant uncertaintiesabout the development of shale natural gas inother regions. Currently, there are essentially noother regions outside of the United States thathave successfully developed shale natural gas. InPoland, Sweden and Ukraine, resource discov-eries have been disappointing, while develop-ments in Algeria, France, South Africa and othercountries have met with public opposition.

6000

20123,432 BCM

NonOECDAsia41%

of Growth

OECDAmericas

15%of Growth

MiddleEast15%

of Growth

Rest ofWorld

20405,378 BCM

20123,432 BCM

20405,378 BCM

Unconv

Conve

2012 2020 2025 2030 2035 2040

5000

4000

3000

2000

1000

2012 20120

Fig. 17.3 Rising diversity in natural gas supply and demand up to 2040. Note bcm is billion m3. Source IEA

17.1 An Overview of the Global Energy Market 347

17.2 Factors Driving Demand

Driven by a number of factors, global natural gasdemand has continually risen in recent years, andis expected to maintain its upward momentum.The three major drivers for this growth are eco-nomic activity, energy intensity and switching tonatural gas, of which the last has played thebiggest role in most countries. On the supplyside, the availability of domestic natural gasresources has played an important role. Consis-tently high natural gas prices have not preventedthe fuel source from gaining substantial groundin recent years, albeit from a low base.

17.2.1 The Main Factors DrivingDemand

Based on research analysing the natural gas mar-kets in seven different countries (see Chap. 2), it isapparent that economic activity, energy intensity,switching to natural gas and the availability ofdomestic natural gas resources are the four majorfactors influencing natural gas demand.

As economic activity increases, so does energydemand, and thus natural gas consumptionincreases in line with its share of the overallenergy mix. From looking at the experiences ofvarious nations, it appears that residential usersand power utilities have seen the highest increases

Table 17.1 Remaining technically recoverable natural gas resources (end 2013)

Conventional Unconventional Total

Coalgas

Shale naturalgas

Cokegas

Sub-total Reserves Provenreserves

Eastern Europe/Eurasia 143 11 15 20 46 189 73

Middle East 124 9 4 – 13 137 81

Asia-Pacific 43 21 53 21 95 138 19

Americas OECD membercountries

46 11 48 7 65 111 13

Africa 52 10 39 0 49 101 17

Latin America 31 15 40 – 55 86 8

Asian OECD membercountries

25 4 13 2 19 45 5

Global 465 81 211 50 342 806 216

Note Data is in trillions of cubic metresInformation source IEA data

Power

Transport

Industry

Other

2012 2040

Fig. 17.4 Sources ofdemand for natural gas 2012versus 2040. Source IEA

348 17 The Global Natural Gas Market

in usage, probably because rising householdincomes allow people to spend more on heatingand power companies in turn increase their use ofnatural gas to meet the greater general demand forelectricity. In addition, natural gas demand frommanufacturing industry has also increased, pri-marily due to a rise in production volume and thecorresponding energy demand.

Under certain economic conditions, energydemand will fall in response to a fall in overallenergy intensity of economic activity, and naturalgas demand will decrease in line with its share ofthe overall energy mix. A drop in energy inten-sity is closely related to structural adjustments toindustry. The experience of several major naturalgas-consuming nations shows that when theservice sector rises as a proportion of a nation’soutput or when a move from heavy industry tolight industry occurs, energy intensity will exhi-bit a downward trend.

When a given industry chooses to replace oiland coal with natural gas, its natural gas con-sumption rises significantly. Global trend analysisshows that using natural gas to replace oil or coalis the major reason for the rise in natural gasdemand. In most markets studied, the change innatural gas demand between 1982 and 2012linked to switching fuel sources to natural gas wasequal to or greater than that attributed to increasedeconomic activity. Research into major naturalgas-consuming industries also shows that a largeproportion of consumption growth is accountedfor by switching from other fuels to natural gas.

As nations develop, the service industrybegins to play a larger role in the economy,urbanisation increases, and controls on air pol-lution become more stringent, leading to amarked tendency towards replacing oil and coalwith natural gas. Australia, Europe and the Uni-ted States have shifted a large portion of theirenergy mix from coal to natural gas, and China iscurrently considering similar measures. Manyother countries have switched from oil to naturalgas. These switches are significantly linked to theproportion represented by the service industry ineach country’s economy, with growth in theservice industry directly affecting demand,especially driven by the need for office heating.

Also, legislation aimed at greater urbanisationand improvement of air quality leads to naturalgas (thanks to its cleanliness) often being firstchoice as a substitute energy source.

Finally, the availability of domestic naturalgas resources is another factor that promptsenergy transition. Domestic reserves are gener-ally the cheapest source of natural gas for acountry, and analysis has shown that, regardlessof how big the reserves are, they always have aninfluence on the proportion of natural gas in thecountry’s energy mix. This is partly becausenations without natural gas reserves generallylack the infrastructure and systems to supportnatural gas imports. In addition, countries withdomestic supplies and existing infrastructure andinstitutions are also more open to trade in naturalgas, which may further increase the share ofnatural gas in the energy mix.

China currently is in a period of rapid devel-opment, becoming more urban, becoming moreconcerned with air quality and developingdomestic natural gas reserves. These are allcharacteristics of countries with a high propor-tion of natural gas in the marketplace. However,if China wishes to promote natural gas, it willneed to act to put measures in place that stimulatethe transition from coal to natural gas. Theexperience of other nations suggests that this ismore difficult to achieve than a transition from oilto natural gas, and currently only Europe hasaccomplished it.

17.2.2 Natural Gas Price Elasticityand China

International experience has shown that demandfor natural gas is not sensitive to price changes,and that rises in natural gas prices do not nec-essarily cause a reduction in levels of natural gasconsumption. From 1987 to 2000, global naturalgas prices remained stable at low levels andnatural gas demand in OECD countries grewrapidly. Beginning in 2000, natural gas pricesbegan to rise, but demand did not react to theprice changes, remaining stable in the majority ofcountries, and growing in others.

17.2 Factors Driving Demand 349

China’s market performance is consistent withinternational experience. Since the 1990s, Chi-nese natural gas consumption has grown rapidly.The rise in natural prices that began in 2000 hasnot had a marked effect, and growth rates haveremained relatively subdued.

Price competition between fuels appears tohave only a modest effect on natural gas demand.From 1987 to 2000, the natural gas priceremained a relatively constant fraction of theelectricity price and the coal price. During thatperiod, natural gas demand rose substantially.After 2000, even though natural gas prices rosesubstantially, there was no large decline globalnatural gas demand. During the period 2000–2012, OECD member country residential andindustrial natural gas demand only dropped by8%, despite a 60% price increase in real terms.

The main reason that price competitionbetween fuels has only a minor effect on naturalgas demand is that natural gas commands loyaltyamong its users. Once natural gas demand hasbeen established, it can adapt to a changingeconomic environment, and this is especially truein terms of residential usage. Once consumersstart to use natural gas, they tend not to switchaway, because of its quality. Natural gas is arelatively clean source of controllable heat that iseasily delivered and easy to use. In comparisonwith other fuels, such as coal, the characteristicsof natural gas may mean that once the infras-tructure is in place, residential and industrialusers are less troubled by the price.

In summary, the non-price characteristics ofnatural gas appear to be important drivers ofdemand, so high natural gas prices in China maynot hold natural gas demand back. However,China’s energy prices are controlled, whichmeansthat China’s situation could be different from othernations. In the majority of cases, major naturalgas-consuming nations have already implementedenergy price market liberalisation, with pricesfollowing changes in supply and demand. InChina, however, some energy prices are con-trolled, a situation which lacks responsiveness tochanges in supply and demand. The synergybetween demand and price in other nations couldresult in different scenarios in China.

17.3 Supply and DemandImbalances

Globally, natural gas-producing regions aregradually diverging from demand centres. Thisimbalance has triggered a boom in global naturalgas trade, with a proliferation of internationalpipeline and LNG projects.

17.3.1 Summary of Global Resources

Unconventional natural gas resources are likelyto account for a larger share of total gas supply asdevelopment continues. The IEA estimates thatglobal remaining conventional technical recov-erable natural gas resources have reached 465trillion m3 and unconventional resources, 342trillion m3. Between 1994 and 2013, globalproved reserves increased by 56%, and availableresources are expected to continue to grow. Eventhough unconventional gas production volumesare expected to increase, the majority of naturalgas production is likely to continue to be fromconventional resources.

According to current estimates, global naturalgas remaining proven recoverable natural gasreserves are approximately 186 trillion m3. Overthe past 30 years, proven recoverable natural gasreserves have grown by 3–4 trillion m3 a year,and the reserve-to-production ratio has stayedsteady at close to 60 years.

For the most part, these reserves are in threecountries: Iran (18%), Russia (17%) and Qatar(13%). Turkmenistan also holds a significantshare of the world’s proven recoverable naturalgas reserve, with the other 11 countries amongthe 15 with the largest reserves holding consid-erably less (Fig. 17.5).

1. Centres of demand

In 2013, global natural gas consumption,including LNG, rose by 1.1% from 2012. Duringthe same period, natural gas international tradevolume increased by 2.3%. Global internationaltrade in oil for the same period rose by only 1.7%.The top 10 natural gas-consuming nations

350 17 The Global Natural Gas Market

consumed a total of 2 trillion m3, accounting for61% of total global consumption. These largestconsumers were: the United States (22%), Russia(12%), Iran (5%), China (5%), Japan (4%),Canada (3%), Saudi Arabia (3%), Germany (3%),Mexico (3%) and the United Kingdom (2%).

The United States is the largest natural gasconsumer, and in 2013 consumed a total of 737billion m3. The largest natural gas-consumingindustry was power generation, accounting for33% (this proportion was 25% 10 years ago).The second largest user was industry, accountingfor 31% of total volume in 2013 (its share fellbelow that of power generation in 2008). Sharestaken by other uses in 2013 included residential(21%) and commercial (14%). In the next10 years, with the completion of various LNGliquefaction projects, primarily around the Gulfof Mexico, US natural gas production and thecountry’s LNG exports to Europe and Asia areexpected to further increase.

In the United Kingdom, natural gas con-sumption in the last decade has been more

volatile after a sustained period of growth, ledlargely by increased residential and power gen-eration use of gas. From 1990 to 2003, the shareof natural gas used for power generation in theUnited Kingdom rose from less than 1 to 38%,but this had dropped to 27% by 2013.

Prior to the 2011 Fukushima reactor incident,Japan was already the world’s largest importer ofLNG. The Japanese government’s response tothe incident, especially its closure of all nuclearpower plants, pushed natural gas consumption inthe country even higher. When nuclear power,which had previously accounted for 31% ofpower generation, was entirely halted, Japan’sLNG imports rose from 69 million tonnes to82 million tonnes. Even though Japan’s nuclearpower plants are expected to resume operations,continued domestic opposition and new stan-dards make the timing for this uncertain.

Consumption in Russia, the world’s second-largest natural gas market, has been volatile inrecent years. Use dropped sharply after the 2008global financial crisis, rebounded strongly, and

0

Iran

Russia

n Fed

eratio

nQata

r

Turkmen

istan US

Saudi

Arabia

United

Arab

Emira

tes

Venez

uela

Nigeria

Algeria

Austra

lia Iraq

China

Indon

esia

Norway

5

10

15

20

25

30

35

40TC

M

Fig. 17.5 The 15 countries with the largest proven recoverable natural gas reserves. Source BP Statistics 2014

17.3 Supply and Demand Imbalances 351

then softened again going into 2012 and 2013,echoing the country’s lower economic growth. InEurope, Germany’s 2012 and 2013 natural gasconsumption continued to grow despite areduction on average in EU member state con-sumption. In the Middle East, Iran, another largeconsumer, has seen natural gas consumptiongrowth moderate in recent years. Finally, Chinahas seen a brisk rapid growth in natural gasconsumption since 2000, placing it now amongthe world’s 10 largest natural gas-consumingcountries.

While India is not yet among the world’s topconsumers of natural gas, policy initiatives—especially in the power generation sector—haveled to remarkable increases in use. Domesticconsumption nearly doubled from 1995 to 2005,reaching about 37 billion m3 or 1.3% of totalglobal consumption. However, price controls, adrop in domestic production and issues sur-rounding LNG infrastructure access have damp-ened the natural gas market in recent years. Asthese problems are resolved, India’s natural gasconsumption will likely resume growth.

2. Centres of production

World natural gas production was 3.4 trillion m3

in 2013, an increase of 1.1% from 2012. Between1970 and 2013, global natural gas productiongrew nearly 3.5 times. The largest naturalgas-producing countries and their proportions oftotal global production volume were as follows:United States (20%), Russia (18%), Iran (5%),Qatar (5%), Canada (5%), China (5%), Norway(3%), Saudi Arabia (3%), Algeria (3%), India(2%) and Malaysia (2%). However, from theperspective of export totals for natural gas pipe-line and LNG, Russia was the largest exporter,accounting for 22% of the global total, primarilyin pipeline natural gas. Ranking second wasQatar (12%), primarily LNG, followed by Nor-way (10%), primarily in pipeline natural gas.

The United States is already the world’s lar-gest natural gas producer, and production is set toincrease significantly as several LNG projects

come online. The success of US shale natural gasproduction will soon turn the country from a netimporter to a net exporter. LNG exports areexpected to start in 2016 as Cheneire’s SabinePass facility begins operation. By 2020, theUnited States is expected to have 40 milliontonnes in annual liquefaction capacity. There areyet more LNG exports projects in planning, butnot all of them are expected to be completed.

The world’s second largest natural gas pro-ducer, Russia, has been operating a large-scalepipeline gas and LNG export business for a longtime. In 2013, Russia produced 605 billion m3 ofnatural gas, and pipeline exports to Europe wereabout 211 billion m3, with the main destinationsbeing Germany (40 billion m3), Turkey(26 billion m3) and Italy (25 billion m3). Russiaalso exported 14 million tonnes of LNG, pri-marily to Japan. It is expected that as the naturalgas pipeline between China and Russia entersoperation, and with new LNG facility operationcommencement, Russia will see further growthprior to 2020 in natural gas production volumesand export volumes.

A significant amount of pipeline natural gas isalso exported from Norway, The Netherlands andAlgeria to European markets. Dutch gas produc-tion is underpinned by production from theGroningen Field, northwest Europe’s largest nat-ural gas field and one of the largest in the world.The Netherlands exported 53 billion m3 by pipe-line in 2013, but in 2014 the government loweredthe production limit following an earthquake inthe region linked to natural gas extraction.

Qatar was the world’s largest LNG exporter in2013, exporting over 78 million tonnes of LNG.The world’s largest non-associated gas fieldstraddles the Qatar–Iran border, with some esti-mates placing the recoverable reserves at 900trillion cubic feet in the North Field (the Qatariportion) and 500 trillion cubic feet in the SouthPars (the Iranian portion). Since production fromthe North Field began in the early 1990s, Qatarinatural gas production has increased from 6.3billion m3 in 1991 to 158 billion m3 in 2013,with most destined for export. Qatar initially

352 17 The Global Natural Gas Market

developed its LNG export capacity to supplysignificant volumes to each major market—Asia,Europe and North America—but the NorthAmerican shale natural gas boom and strongLNG demand in Asia resulted in almost 70% ofits LNG going to Asia in 2013. Iranian gasproduction also increased significantly over thesame period, but all of its natural gas is con-sumed domestically.

Australia is expected to become an importantnatural gas producer and exporter soon.Although production volume in Australia was1% lower in 2012 than in 2012, a series of LNGliquefaction projects will become operationalover the next few years that will bring Australia’sproduction capacity up to 88 million tonnes,overtaking Qatar to become the world’s largestLNG exporter. However, some of these facilitieswill be the first in the world to use coalbedmethane to produce LNG, so some uncertaintyremains about these figures.

Even though 2013 production volume was notsignificant, Papua New Guinea began natural gasproduction in 2014 as the PNG LNG projectcame online. This project’s annual productioncapacity is 6.9 million tonnes of LNG, and pro-duction capacity expansion plans are beingassessed.

Canada is already a major producer of naturalgas, and even although its exports are currentlylimited to pipelines to the United States, thecountry plans to export more widely. Canada’swest coast has a significant number of LNGprojects in planning, hoping to take advantage ofthe region’s abundant unconventional natural gasand its access to large LNG importing countrieslike Japan, South Korea and China.

Based on their abundant natural gas resources,Tanzania and Mozambique are two more coun-tries that could potentially become major LNGexporters. For them, natural gas is a brand newindustry, and it is likely to take longer to beginoperations. For these—or indeed any—new nat-ural gas projects to attract the necessary financ-ing, they will need long-term commitments fromhigh-quality buyers at prices sufficient to provideadequate returns to both the host country and thedevelopers.

17.3.2 Regional Imbalances

Globally, supply and demand is unevenly dis-tributed between regions. The main producingregions are countries of the former Soviet Union,North America and the Middle East and NorthAfrica (Fig. 17.6). Countries of the former SovietUnion and the Middle East and North Africa arethe world’s largest exporters of natural gas. TheAsian OECD countries, China and Europe arethe main importers. In other regions, productionand consumption are basically balanced, with theexception of the rest of Africa, which is a rela-tively small, but growing, exporter.

Because global natural gas consumption hasgrown, and regional supply and demand areunbalanced, import and export trade volumes arealso growing. From 1990 to 2013, global naturalgas consumption volumes grew by approximately70%, but there were relatively large disparities ineach region’s supply and demand growth rates(Fig. 17.7). Nations exporting natural gasexpanded exports, and importing nations likewiseincreased imports. From 1990 to 2013, approxi-mately 20% of the newly added consumerdemand was realised through inter-regionalimport and export trade.

In recent years, production increases havebeen supported by large discoveries of conven-tional, and more recently unconventional, naturalgas. Since the late 1980s, there have also beenmajor discoveries of conventional natural gas,especially in the Middle East and North Africa,causing these regions rapidly to become majorproducers of natural gas. At the same time, pro-duction volumes even rose in regions where therehad been no major increases in reserves, indi-cating a preference for domestic sources overimports to meet demand.

While reserves of unconventional natural gasreserves, including tight natural gas, shale naturalgas and coalbed methane, are largely uncon-firmed, they are potentially huge. Theirexploitation in the United States since 2002 hasfundamentally changed the country’s natural gasmarket, although unconventional productionremains minimal in all other regions. However,the potential for unconventional natural gas to

17.3 Supply and Demand Imbalances 353

Production Net exports Consumption

Nat

ural

gas

(exa

joul

es)

0FSU North

AmericaMENA Asia Europe Central and

South AmericaAfrica China OECD Asia

5

10

15

20

25

30

35

Europe and OECD Asiaare the main importers,

followed by China

The FSU and MENA arethe main exporters

Fig. 17.6 The major natural gas producing and consuming regions. Note Data for 2013. Source Vivid Economics,based on IEA data

-5

MENA North America Asia Central andSouth America

Africa China FSU OECD Asia Europe0

5

10

15

20

Demand growth in Europeand OECD Asia was far

greater than supply growth

Production growth in MENAand the FSU was far greaterthan the change in demand

China’s increasein production has

been greaterthan its increase

in consumption

Change inproductionor consumptionof gas1990–2013(exajoules)

Fig. 17.7 Natural gas supply and demand growth rates of various regions, 1990–2013. Source Vivid Economics,based on IEA data

354 17 The Global Natural Gas Market

disrupt other regions is large. Unconventionalnatural gas reserves are mostly distributed incountries without major amounts of conventionalnatural gas (Fig. 17.8), and if these reservescould be commercially exploited, then theinter-regional imbalance between natural gasproducers and consumers would probably bereduced. Such a change would reduce demandfor natural gas from countries of the formerSoviet Union, the Middle East and North Africa.

As a result of the developments discussedabove, the world is increasingly becoming divi-ded into regions that supply natural gas andregions that consume it (Fig. 17.9). The naturalresult of this situation has been an increase ininter-regional trade.

17.3.3 Inter-regional Natural GasTrade

With the regional imbalances in natural gassupply and demand, inter-regional trade,

especially LNG trade, has been increasing. From1993 to 2013, natural gas trade over pipelinealmost doubled, while LNG trade—albeit from alower starting point—quadrupled (Fig. 17.10).Natural gas trade over pipeline, however, stilldominates the market, accounting for about twothirds of total trade.

1. Pipeline gas trading

Since 1993, the volume of natural gas tradedover inter-regional pipelines has almost doubled,though the network has not significantlyincreased its connectivity. In 1993, inter-regionalpipeline natural gas trade volume was 470 trillioncubic feet, and 86% of this was exported by theformer Soviet Union, with 94% imported toEurope. At the time, the natural gas pipelinenetwork was limited, with most natural gasflowing from the former Soviet Union, theMiddle East and North Africa (Fig. 17.11). By2013, 8.5 trillion cubic feet was being tradedannually over pipeline, with the share exported

Gas reserves (exajoules)

NorthAmerica

0

500

1,000

1,500

2,000

2,500

3,000

Centraland

SouthAmerica

China MENA Europe OECDAsia

FSU Africa Asia

Unconventional reserves (unproved, technically recoverable)

Conventional gas reserves (proved)

Europe and EOCDAsia, major

importers, havepotentially largeunconventional

reserves

China’s unconventionalgas reserves arepotentially x8 its

conventional reserves

Fig. 17.8 Unconventional natural gas reserves by region. Note Data is for 2013; unconventional reserves include tightnatural gas, shale natural gas and coalbed methane. Source Vivid Economics, based on EIA and IEA data

17.3 Supply and Demand Imbalances 355

by countries of the former Soviet Union falling to75%, and European imports to 65%. In the sameyear, Chinese imports accounted for 11% of

pipeline natural gas, exclusively from countriesof the former Soviet Union. Even though therehad been some small changes between 1993 and

increasedimports

increasedexports

00

5

10

15

20

25

30

35

Production of gas(exajoules)

China isincreasingimports

European gas demand hasdeclined since 2007 due tothe recession

North America isself-sufficient in gas

North America

ChinaFSU

MENA

OECD AsiaAsia

Central and South America

AfricaEurope

5 10 15 20 25 30 35

Consumption of gas(exajoules)

1971 2013

Fig. 17.9 The increasing polarisation of regions into suppliers and consumers of natural gas. Note Data is on a grosscalorific basis; each country’s coloured trail along the matrix gets thicker over time; the dotted midline representsequilibrium between production and consumption, with greater production above the midline and greater consumptionbelow it. Source Vivid Economics, based on IEA data

01993 1998 2003 2008 2013

Exports via LNG

Gas trade and consumption ofindigenous production (exajoules)

Exports via pipeline

Consumption of indigenousproduction

20

40

60

80

100

120

140

3

5

7

9

13

28

27

22

1516

Fig. 17.10 Types of globalnatural gas trade. Note Data isa global aggregate ofinternational trade. SourceVivid Economics, based onIEA data

356 17 The Global Natural Gas Market

2013 pipeline trade

Asia FSU

MENA Africa

OECDAsia

EuropeChina

NorthAmerica

Centraland SouthAmerica

1993 pipeline trade

NorthAmerica

Centraland SouthAmerica

OECDAsia

China

Africa

Europe

MENA

Asia FSU

Fig. 17.11 Global inter-regional pipeline natural gas trade. Note The thickness of the arrow represents the percentageof global pipeline trade flowing between two regions. Source Vivid Economics, based on IEA data

17.3 Supply and Demand Imbalances 357

2013, the inter-regional natural gas pipelinenetwork remained relatively limited, especially inlight of the global pattern of reserves, productionand demand.

2. LNG trading

The volume of natural gas traded through LNGhas more than tripled since 1993, and the net-work has significantly increased its connectivity.In 1993, inter-regional LNG trade volumereached 2.7 trillion cubic feet, of which 64% wasexported from Asia, and 70% was importedby Asian OECD member nations and 25% byEurope. Though networks facilities were limitedin 1993, primarily concentrated on trade betweenAsia and Japan and between Africa and Europe,by 2013 they had expanded significantly(Fig. 17.12). In 2013, inter-regional LNG tradevolume had reached 9.1 trillion cubic feet. Ofthis, 57% was exported by the Middle East andNorth Africa, while the major importers wereAsian OECD member nations (56%), Europe(15%) and China (9%). LNG trade in Asia,

excluding China and OECD countries, hasbecome more complex, handling imports andexports, and accounting for just 10% of netinter-regional LNG trade volume, compared to64% in 1993.

The degree of connectivity in LNG marketshas begun to form a global natural gas market.By 2013, the network of LNG trade had becomemuch denser, with many regions connected toeach other. The flexibility of LNG deliverymeans that LNG can be used to exploit arbitrageopportunities across a range of regions, con-necting markets together. However, LNG trade iscurrently dominated by a small number of par-ticipants in the Middle East and North Africa,and trade volume on some routes are still low. Inaddition, there are legal restrictions on exports,such as in the United States, and limitations dueto infrastructure capacity. Furthermore, LNGdevelopments remain capital-intensive and risky,and as a result interregional price differencesneed to be wide to motivate trade. Faced withsuch problems, even though regional markets arefar more connected now than in the recent past,

OBCDAsia OBCD

Asia

NorthAmerica

NorthAmerica

AsiaAsia

MENA

MENA

FSU

FSU

China

China

Centraland SouthAmerica

Centraland SouthAmerica

EuropeEurope

Africa

Africa

1993 LNG trade 2013 LNG trade

Fig. 17.12 Global LNG trade Note The thickness of the arrow represents the percentage of global pipeline tradeflowing between two regions Source Vivid Economics, based on IEA data

358 17 The Global Natural Gas Market

the degree of connectivity is still insufficient tosupport the formation of a global market.

3. The problems facing LNG trading

LNG capacity has increased rapidly, and theexpansion is expected to continue. In 2013, LNGliquefaction capacity, which is required forexport, was 2.25 times greater than in 2003,while regasification capacity, an import require-ment, was twice that in 2003. By 2023, lique-faction capacity is expected to grow almostthreefold, while regasification capacity is expec-ted to nearly double. This will bring global liq-uefaction capacity to almost 40 trillion cubicfeet/year by 2023, and regasification capacity toalmost 60 trillion cubic feet/year. (Regasificationcapacity is greater than liquefaction capacitybecause regasification capacity is distributedacross more locations and countries build importcapacity to meet peak demand, whereas the flowof exports tends to be smoother, requiring alower capacity for the same volume.)

However, LNG costs are volatile, and may notfall significantly in the future. In general, the costof liquefaction plants has increased by 50% overthe last decade, and some projects, primarily inAustralia, have cost at least twice normal levels.Costs have risen because of higher commodityprices, such as steel, and, in Australia in particular,higher labour costs. This pattern of high costscould persist. Even if commodity prices fall, LNGis likely to remain an expensive process, becausethe scope for technological breakthroughs is lim-ited, and the large amount of expensive capacityrecently added will lock in higher costs. Further-more, LNG is only competitive with overlandpipelines over long distances, such as from theMiddle East to Japan (Fig. 17.13).

These issues suggest that LNG is economi-cally limited. This fact could constrain invest-ment, or may require long-term contracts tomanage risk. Moreover, it is likely to mean thatLNG remains an expensive fuel, serving as amarginal source of supply in markets wheresupply fails to keep up with demand.

0

1

2

3

4

5

0 2,000Distance between export and import destinations (kilometres)

4,000 6,000 8,000

Excludesliquefaction andregasificationcosts for LNG

Transportcosts

$/mmBtu

China to Japan ~ 1,500 km,

pipeline

China to Japan ~ 1,500 km,could be linked by offshore

pipeline

Qatar to Japan~10,000 km

Qatar to Japan~10,000 km

Few suppliers andconsumers are

between 4,000 and6,000 km apart

Few suppliers andconsumers are

between 4,000 and6,000 km apart

Offshore pipelinescost will rise fasterand surpass LNGbefore 2,000 km

Offshore pipelinescost will rise fasterand surpass LNGbefore 2,000 km

10,000

US Gulf coast toJapan > 15,000 km

Onshorepipeline

LNG

Fig. 17.13 Comparison of competitiveness between pipeline natural gas and LNG. Source Vivid Economics based onSBI Energy Institute (2014)

17.3 Supply and Demand Imbalances 359

17.3.4 Unconventional Natural GasResources

Confirmed unconventional natural gas reservesaccount for approximately three-quarters of glo-bal technically minable reserves. In a 2012report, the IEA estimated that global confirmedtechnically minable natural gas reserves amoun-ted to 420 trillion m3, with 331 trillion m3

recoverable with unconventional technology.The unconventional resources were 208 trillionm3 in shale natural gas, 76 trillion m3 in tightnatural gas and 47 trillion m3 of coalbedmethane. In a separate report, the EIA assessedthe world’s recoverable reserves of shale naturalgas at 7299 trillion cubic feet, of which China’sshare was the largest, followed by Argentina,Algeria, the United States and Canada(Table 17.2).

Unconventional natural gas has transformedthe natural gas market in North America. In theUnited States alone, shale natural gas productionis expected grow from 9.7 trillion cubic feet in2012 to 19.8 trillion cubic feet in 2040, bringingits share of total US natural gas supply from 40 to53%. This increase in natural gas supply isexpected to give US manufacturers an addedadvantage over foreign competitors and has

already resulted in a significant number of pro-jects that seek to liquefy natural gas for export.

North America’s success in exploitingunconventional natural gas has inspired othercountries. According to IEA estimates, globalunconventional natural gas total productionvolume will reach 928 billion m3 in 2020,including 454 billion m3 of shale natural gas, 148billion m3 of coalbed methane and 294 billion m3

of tight natural gas.Despite the optimism, there nonetheless

remain significant uncertainties about howquickly unconventional resources can be broughtonline outside the US, especially in countrieswhere little or no production has been takenplace. Although China is estimated to haveunconventional resources totalling about32 trillion m3, the government recently reducedits near-term outlook for reaching these reserves.Problems cited included that the resources werespread across more than 500 basins and thegeography was difficult, as well as costs, inade-quate infrastructure, water disposal concerns,lack of channels for introduction of internationalcompanies and a lack of innovation as a result ofthe small number of participating companies.In another example, Argentina, with about23 trillion m3 in unconventional resources, has

Table 17.2 Top 10countries with technicallyminable reserves of shalenatural gas

Ranking Country Shale natural gas reserves

1 China 1115

2 Argentina 802

3 Algeria 707

4 United States 665

5 Canada 573

6 Mexico 545

7 Australia 437

8 South Africa 390

9 Russia 285

10 Brazil 245

Global total 7299

Units trillion cubic feetSource US Department of Energy

360 17 The Global Natural Gas Market

solid pre-conditions in place, but is constrainedby funding and non-technical risks.

17.4 Pricing

Natural gas prices and price-setting mechanismshave evolved over time. While long-term con-tacts linked to oil prices were once dominant,now price setting is taking different forms acrossmarkets, and prices vary by region. A 2014report from the International Gas Union(IGU) found that 43% of global wholesale vol-ume was based on competitive natural gas pric-ing, also known as gas-on-gas pricing, and wasnot indexed to oil prices,2 while 19% wasindexed to oil. The term of contracts is alsobecoming more diverse, compared to oil-indexedcontracts, which tended to be long-term agree-ments. Prices are being set more often based on

competition among natural gas suppliers, onhubs or on spot markets (Fig. 17.14).

In China, where energy price controls arerelatively stringent, the mechanisms of naturalgas pricing differ greatly from the way theyfunction internationally, with different pricingmethods depending on gas source and on use.However, China’s natural gas pricing is under-going reform, and is gradually moving towardnational natural gas pricing rules.

Natural gas hubs are an important factor innatural gas pricing mechanisms, given that theircore function is to provide a physical connectionwithin the natural gas system and to facilitatecompetitive pricing. Natural gas hubs break thelink between the price of natural gas and oilprices. The competitive pricing that the forma-tion of hubs allows becomes a kind of substituteplan for controlled prices linked to oil prices. Inaddition, natural gas hubs also form an importantcomponent of natural gas downstream markets.See the special discussion in Chap.19 for theprinciples, effects and practical cases of naturalgas hubs.

Competitive prices

Regulatedprices

0%

0% 100%

0%

20% 2005

more spot, equal decline in regulated and long-term

more spot, lesslong-term, constant

regulated

more spot, lessregulated, constant

long term

201380%

40%60%

60%40%

80%20%

20% 40% 60% 80% 100%100% Long-term

contracts

North America

Europe

Asia

OECD Asia

Central and South America

FSU

Africa

MENA

World

Gas in North America is almost entirely competitively priced

The world in aggregate, and particularly Europe, OECD Asia and the FSU

are moving towards prices determined by

competitive gas markets

Half of European gasis now competitively priced

The UK’s “dash for gas” in the 1990s rapidly changed its energy mix

Fig. 17.14 Changes in natural gas contract types. NoteEach country’s coloured trail along the matrix gets thickerover time; movement toward the apex illustrates increased

share of natural gas at the expense of oil (lower left) orcoal (lower right). Source Vivid Economics, based onIGU data

2Contracts connected to oil price can also be competitive,but gas-on-gas pricing contracts are normally morecompetitive, and are more reactive to changes in themarket fundamentals.

17.3 Supply and Demand Imbalances 361

Due to the great size and rapid developmenttrends of China’s natural gas market, as well asprevious experience of large-scale internationaltrade in other commodities, policy adjustmentsfor China’s natural gas market are likely to havea major impact on global natural gas markets.This study established a model to analyseChina’s natural gas demand growth in variousscenarios and its effects on global natural gasmarkets, including price, energy mix, and otheraspects.

17.4.1 Current Pricing Regulations

The development of a global natural gas marketis limited by geography, with most international

trade being over natural gas pipelines or by LNGshipping. Geographical limitations and highshipping costs—the construction of internationallong-distance pipelines, as well as the costs ofshipping and storing LNG—restrict tradebetween different regions, causing the natural gasmarket to develop distinct regional characteris-tics, particularly regarding how prices are estab-lished (Table 17.3).

Price levels across the regions have also var-ied significantly, reflecting the changes to thesupply and demand for each market (Fig. 17.15).In North America, the influential Henry Hubprice generally reflects the supply and demanddynamics in the United States, for example byreflecting seasonal variations, major incidents(such as hurricanes Katrina or Rita) and

Table 17.3 Regional market pricing characteristics

Region Market description Method of price formation

NorthAmerica

Natural gas market with competition-basednatural gas pricing. Interconnected infrastructurelinking storage, supply and demand hubs

Multiple natural gas indices, with Henry Hub thedominant openly-traded LNG index. Natural gasindex reflects North American natural gas supplyand demand

Europe Multiple natural gas markets with varyingdegrees of competition-based pricing. Marketsoperate and regulations are developed under aframework established under the EuropeanUnion, but strong national interests remain.Infrastructure is primarily interconnected, withsome bottlenecks

Long-term contracts connected to oil price or oilproduct prices are being increasingly challengedby competitive pricing, for example from NBP inthe UK and Title Transfer Facility (TTF) in theNetherlands

Japan, SouthKorea, andTaiwan

Markets primarily based on national monopoliesand supply in the region primarily underlong-term contracts, with some active spot LNGbuying to manage supply and demand or someportfolio optimising. Customs data for LNGimports publicly available and can be used todetermine the average import price

Strong oil indexation for long-term contracts tothe Japan Crude Cocktail (JCC), which isgenerally defined within individual contracts andlags current oil prices because they are typicallybased on recent average prices of crude importsinto Japan. These are prevalent in Asia and mayinclude price review clauses. Spot cargoes areprimarily based on a fixed price, typicallynegotiated bilaterally or based on tenders.Surveys by various reporting agencies seek tocapture this through the Japan Korea Marker(JKM). JKM is not a price for spot cargoes, but iscurrently the best estimate in the industry

China Market dominated by state-owned enterprises.Supply based on a mix of domestic production,pipeline imports from central Asia, Myanmarand, soon, Russia and LNG imports.Infrastructure development continuing. Marketreforms ongoing

Natural gas market pricing reform ongoing.Natural gas supplied under a mix of cost-plus fordomestically produced natural gas andoil-indexed pricing, primarily for imports. LNGprice formation similar to Japan, South Koreaand Taiwan. Natural gas sold at regulated pricesset by a National Development and ReformCommission formula linked to LPG and fuel oil

362 17 The Global Natural Gas Market

longer-term trends (such as the shale natural gasrevolution). Indeed, there were periods when USnatural gas prices were higher than the averageLNG import price in Japan, for instance when themarket expected the United States to need sub-stantial LNG imports.

In the past, the Henry Hub price was widelyseen as a benchmark for the US market, andmany natural gas liquefaction projects around the

world were begun targeting exports to the UnitedStates based on these prices, relying on theHenry Hub price for their export plan pricing,along with the belief that the United States wouldbe a long-term LNG importer. A significantnumber of regasification terminals in the UnitedStates were also proposed (Fig. 17.16).

The United States was expected to be along-term LNG importer, and developers were

0

Jan-00

JKM

Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15

3

6

9

12

15

18

21

Japan average import price

US$

/ M

MBt

u

China average import price

0

Jan-00

Henry Hub

Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15

3

6

9

12

15

18

21

NBP

US$

/ M

MBt

u

US$

/ bb

l

Brent (right axis)

S.Korea average import price

Fig. 17.15 Key price indices and Japan’s average import price. Source Platts, Energy Intelligence, IntercontinentalExchange, and Heren

17.4 Pricing 363

willing to price their export plans based on theHenry Hub largely because it was widelyaccepted as reflecting US supply and demandfundamentals. A significant number of regasifi-cation terminals were also proposed in the UnitedStates.

In markets in which pricing is predominantlylinked to oil indices, prices also respond tochanges in supply and demand, but not as effi-ciently as in competition-based pricing. Themechanism is also complicated by the supply anddemand of oil.

One example of this follows new LNG salesand purchase agreements in Asia-Pacific, whereprices gradually diverged from oil until around2005 and slowly retracted (Fig. 17.17). In theearly 2000s, project developers in the region hadto enter markets relatively new to LNG importsand had the alternative of exporting to the UnitedStates. Costs for building LNG projects werelower than current levels, and their oil price

outlooks were anchored around historical levels,which had generally been below $60 a barrel for15 years. After 2005, higher project costs andgreater demand for natural gas led to higherprices, in some cases reaching parity with crudeoil. The 2011 nuclear power plant accident inFukushima, Japan put additional upward pressureon natural gas prices in Asia. More recently,however, natural gas prices have begun to soften,partly a result of lower oil prices, weaker globaleconomies, additional capacity (both completedand proposed) and new projects, such asUS LNG exports to Asia.

Looking ahead, natural gas prices, especiallyLNG exports to Asia-Pacific markets, couldbecome particularly volatile with the onset ofLNG exports for the United States, which areprimarily indexed to Henry Hub prices. Compa-nies are hoping to capitalise on the US naturalgas boom by liquefying the fuel and trading it oninternational markets. Many projects have been

Existing marine terminal

Proposed marine terminal

Fig. 17.16 Current and proposed LNG regasification terminals in North America, 2004. Information source EIA

364 17 The Global Natural Gas Market

announced, but not all will be completed(Fig. 17.18).

In general, pricing of American LNG exportshas two components: one linked to Henry Hubprices representing the feed gas and fuel costs,and an annual fixed component representinginvestment in the liquefaction facility(Fig. 17.19). Based on currently available pur-chase and sale agreement terms, the “HenryHub” component is typically 115% of the HenryHub price, while the second component is basedon a fixed dollar amount, with about 15% of thislinked to US inflation rates.

Buyers gain supply diversity by procuringUS LNG exports, but they also acquire somerisk. Coupled with contracted destination diver-sity, which allows shipments to be rerouted to themost favourable markets, US LNG exports cancontribute to a beneficial diversified energy

supply network. However, US LNG supplies canbe less competitive than oil-indexed supplies,depending, among other factors, on movementsof global oil prices and Henry Hub natural gasprices (Fig. 17.20).

Compared to Asia, where natural gas contractprices are linked to oil, US natural gas exportshave a different risk profile. Many US LNGexport sales and purchase agreements include atolling agreement section, which means that thebuyer is responsible for procuring the natural gasto be liquefied, and lower plant utilisation rateswould lead to higher unit prices because thebuyer continues to pay the fixed component,except in extreme cases. The buyer is responsiblefor purchasing the natural gas to be liquefied,with the unit price rising with lower liquefactionfacility usage rates, because the buyer continu-ously pays a fixed fee portion, except in

200

2

4

6

8

10

12

14

16

18

20

22

6040 80 100 120

RasGas ROGAS SPA Execution (2006)

Brunei TEPCO SPA Execution (2012)PNG LNG TEPCO SPA Execution (2012)ExxonMobil Gorgon Petrochina SPA Execution (2012)

MLNG 3 KOGAS Price Revision (2014)

MLNG 3 KOGAS SPA Execution (2005)

Tangguh CNOOC Price Revision (2007)

NWS CNOOC SPA Execution (2002)Tangguh CNOOC SPA Execution (2003)

Yemen KOGAS Price Review (2013)

Yemen KOGAS SPA Execution (2005)

Tangguh CNOOC Price Revision (2014)

Oil Price (US$ / bbl)

US

$ / M

MB

tu

Fig. 17.17 Progressive divergence by different degrees from oil prices of Asian oil-linked natural gas prices. SourceWood Mackenzie and public information

17.4 Pricing 365

exceptional cases. In recent periods, oil priceshave dropped, and long-term oil price trends areuncertain, with recent Henry Hub prices seeingmultiple record lows, highlighting the relativerisk of US LNG supply and supplies whose pri-ces are linked to oil.

Even though natural gas pricing mechanismsare trending further toward competitive pricing,the formation of a global unified price is stillimpossible. However, the growth ininter-regional natural gas trade volume, as wellas rises in trading hub or spot market natural gassales volumes, are prompting the formation ofregional markets based on the original nationalfoundations, for example in Europe.

Even if trade and competitive pricing were topromote the formation of a globalised natural gasmarket, regional prices are likely to continue toexist, and inter-regional price variance couldeven exceed shipping costs. The reason for this isthat natural gas regional demand and supply isoften imbalanced: large consumers are not largeproducers, resulting in the signing of long-termcontracts to reduce energy security issues and thepotential concentration of market forces.

Likewise, formation of a global unified price isnot possible, since the flexibility of global tradecapabilities is likely to be insufficient, and will beunable to satisfy trade demands that can changeat any time. Finally, the potential for economi-cally recoverable unconventional natural gasremains unknown, but if it were to be unlocked ata low cost, as seen in the United States, thevolume generated would be more likely toinfluence prices in the immediate region of thesupply rather than in other regions.

17.4.2 The Relationship Betweenthe Price of Natural Gasand the Price of Oil

Natural gas, whether delivered over pipelines oras LNG, has historically been priced based oncompeting fuels in the receiving markets andsupplied under long-term agreements. Examplesinclude exports from the Groningen natural gasfield in The Netherlands, where pricing adjust-ments are tied to the market price of three majortypes of fuel, or LNG imports to Japan, which are

3

1

42 7 10

96

811

145

12

13

US Jurisdiction

FERC

MARAD/USCG

1516

17

Export TerminalPROPOSED TO FERC

1. Coos Bay, OR: 0.9 Bcfd (Jordan Cove Energy Project) (CP13-483)2. Lake Charles, LA: 2.2 Bcfd (Southern Union - Trunkline LNG) (CP14-120)3. Astoria, OR: 1.25 Bcfd (Oregon LNG) (CP09-6)4. Lavaca Bay, TX: 1.38 Bcfd (Excelerate Liquefaction) (CP14-71 & 72)5. Elba Island, GA: 0.35 Bcfd (Southern LNG Company) (CP14-103)6. Sabine Pass, LA: 1.40 Bcfd (Sabine Pass Liquefaction) (CP13-552)7. Lake Charles, LA: 1.07 Bcfd (Magnolia LNG) (CP14-347)8. Plaquemines Parish, LA: 1.07 Bcfd (CE FLNG) (PF13-11)9. Sabine Pass, TX: 2.1 Bcfd (ExxonMobil - Golden Pass) (CP14-517)10. Pascagoula, MS: 1.5 Bcfd (Gulf LNG Liquefaction) (PF13-4)11. Plaquemines Parish, LA: 0.30 Bcfd (I oulslana LNG) (PF14-17)12. Robbinston, ME: 0.45 Bcfd (Kestrel Energy - Downeast LNG) (PF14-19)13. Cameron Parish, LA: 1.34 Bcfd (Venture Global) (PF15-2)14. Jacksonville, FL: 0.075 Bcfd (Eagle LNG Partners) (PF15-7)

PROPOSED CANADIAN SITES IDENTIFIED BY PROJECTSPONSORS

15. Kitimat, BC: 1.28 Bcfd (Apache Canada Ltd.)16. Douglas Island, BC: 0.23 Bcfd (BC LNG Export Cooperative)17. Kitimat, BC: 3.23 Bcfd (LNG Canada)

Fig. 17.18 Proposed LNG export terminals in North America, February 2015. Source US Federal Energy RegulatoryCommission

366 17 The Global Natural Gas Market

priced based on Japan Crude Cocktail prices, anamalgamation of oil prices that is generallydefined within individual contracts.

For many years, natural gas contracts havebeen indexed to the oil price; when the oil pricechanges, the price paid for natural gas changes aswell, using a preset formula. Until about 2008,the link has led to a close correlation betweennatural and oil two prices (Fig. 17.21). The linkloosened in periods when oil price showed highvolatility, such as the oil crises, and natural gas

contracts tended to be renegotiated. Anticipatinga need to rebalance the long-term agreements,some natural gas contracts included clausesallowing price formulas to be reviewed based onan established set of factors.

The connection between oil and natural gasprices started to loosen in 2008, typified by thedivergence of Henry Hub prices from oil prices.The separation was partly a result of the USrecession and a boom in unconventional naturalgas supplies in the United States, which meant

LNG Sale and Purchase Agreements (SPAs)Sabine Pass Liquefaction

~20 mtpa “take-or-pay” style commercial agreements~$2.9B annual fixed fee revenue for 20 years

Annual ContractQuantity (MMBtu) 286,500,000 182,500,000 182,500,000 182,500,000 91,250,000104,750,000

(1) (1)

Annual Fixed Fees ~$723 MM ~$454 MM ~$548 MM ~$548 MM ~$314 MM ~$274 MM(3)(2)

Fixed Fees $ / MMBtu $2.25 - $3.00 $2.49 $3.00 $3.00 $3.00$3.00(2)

(4)

(5)

LNG Cost 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH

Terms of Contract 20 years 20 years 20 years 20 years 20 years 20 years

Guarantor BG EnergyHoldings Ltd.

Gas NaturalSDG S.A N/A N/A Total S.A. N/A

Fee During ForceMajeure

Up to 24 months Up to 24 months N/A N/A N/A N/A

Contract Start Train 1 + additionalvolumes with Trains 2,3,4 Train 2 Train 3 Train 4 Train 5 Train 5

Corporate / GuarantorCredit Rating A- / A2 / A- BBB / Baa2 / BBB+ A+ / A1 / AA- NR / Baa2 / BBB- AA- / Aa1 / AA A- / A3 / A-

BG Gulf Coast LNGGas Natural

FenosaKorea GasCorporation

GAIL (India)Limited

Total Gas& Power N.A Centric plc

(1) BG has agreed to purchase 182,500,000 MMBtu, 36,500,000 MMBtu, 34,000,000 MMBtu and 33,500,000 MMBtu of LNGvolumes annually upon the commencement of operations of Trains 1, 2, 3 and 4, respectively. Total has agreed to purchase91,250,000 MMBtu of LNG volumes annually plus 13,400,000 MMBtu of seasonal LNG volumes upon the commencement ofTrain 5 operations.(2) A portion of the fee is subject to inflation, approximately 15% for BG Group, 13.6% for Gas Natural Fenosa, 15% for KOGASand GAIL (India) Ltd and 11.5% for Total and Centrica.(3) Following commercial in service date of Train 4. BG will provide annual fixed fees of approximately $520 million during Trains 1–2 operations and an additional $203 million once Trains 3–4 are operational.(4) SPAs have a 20- year term with the right to extend up to an additional 10 years. Gas Natural Fenosa has an extension rightup to an additional 12 years in certain circumstances.(5) Ratings are provided by S&P/Moody's/Fitch and subject to change, suspension or withdrawal at anytime and are not a recommendation to buy, hold or sell any security.(6) Conditions precedent must be satisfied by June 30, 2015 or either party can terminate. CPs include financing, regulatoryapprovals and positive final investment decision.

(6)(6)

Fig. 17.19 Sabine Pass LNG sale and purchase agreement structure. Source Cheniere Energy Inc

17.4 Pricing 367

that the country no longer needed significantLNG imports. In Europe, an economic downturnalso triggered decreased natural gas demand,leading to ample supplies, which were

increasingly purchased through the natural gashubs without any link to oil prices.

Recently, the possibility of Russian naturalgas supplies that pass through Ukraine being

20 40 60

Oil Price (US$/bbl)

80 100 120

4.6

3.0

3.0

0.5

5.8

3.0

3.0

0.5

Henry HubUS$4/MMBtu

Henry HubUS$5/MMBtu

Shipping to Asia

Annual fixed feecomponent

Henry Hubcomponent

Other

Shipping to Asia

Annual fixed feecomponent

Henry Hubcomponent

0.0

4.0

8.0

12.0

16.0

20.0

US$/MMBtu

Example of oil indexed LNG Priceto North East Asia

Example of Henry Hub indexed LNG Priceto North East Asia

Fig. 17.20 Henry Hub natural gas prices could be higher than natural gas prices linked to oil prices

Oil crises

Financial crisisFinancial crisis

19600

2

4

6

8

10

12

1970 1980 1990 2000 2010

Oil

Gas

Rea

l pric

e in

dice

s (1

960

= 1)

Gas prices diverge from oilprices more in periods of high

and price revisions

Gas prices diverge from oilprices more in periods of high volatility due to contract churn and price revisions

Rapid and high price rises opened the market for unconventional gas

Rapid and high price rises opened the market for unconventional gas

Decoupling of pricesas gas supply on spotmarkets increases

Decoupling of pricesas gas supply on spotmarkets increases

Fig. 17.21 The relationship between natural gas price and oil prices. Note Data are indexes of global average prices.Source Vivid Economics, based on World Bank data

368 17 The Global Natural Gas Market

disrupted added market volatility, but pricesrecovered even as the supply to Europe wasreduced. Interestingly, the supply reduction waslinked largely to LNG imports to Europe, ratherthan Russian pipeline deliveries. Strong demandfor LNG in Asia-Pacific created arbitrageopportunities, and LNG delivered to Europeanbuyers was reloaded by the buyers for sale inAsia-Pacific. Faced with low gas index prices,low demand, or both, buyers in Europe chose toprofit by selling to Asia-Pacific buyers at higherprices. The arbitrage opportunity disappeared asoil prices and European natural gas hub pricesfell.

Historically, four rationales have supportedthe need for linking natural gas contracts to theprice of oil:

• Benchmark price: Natural gas exploration,production and transport are capital-intensiveand the industry often requires long-termcontracts. To share the risk between buyerand seller, the contract prices generally varyaccording to a benchmark, and the oil pricehas provided a transparent and robustbenchmark. Also, many of the costs of naturalgas development—for example, drilling rigsand skilled labour—are comparable in bothoil and natural gas production, and these costsare affected by oil prices. However, in somemarkets the fundamentals for pricing oil andnatural gas have diverged. For instance, in theUnited States and parts of Europe, sufficientlydeep and liquid natural gas benchmarks havebecome available.

• Co-production: Natural gas has been aby-product of oil extraction and sold onsimilar terms. Exclusive natural gas extrac-tion, however, is becoming more common,even though co-production remains impor-tant. In the United States, for example, naturalgas is a by-product of shale oil production.Low natural gas prices in the US market arepartially a result of high oil prices, whichhave offered significant incentives to shaleprojects. The low natural gas prices may notbe sustainable or easily replicated outside theUnited States.

• Similar routes to market: Natural gas andoil have similar transport infrastructure, andthe same companies have tended to deliverboth because of their expertise, market dom-inance or both. However, natural gas infras-tructure has increasingly become moreindependent.

• Competition for customers: Natural gas andoil products were used for power generationand heating, and natural gas was often pricedjust lower than oil to compete. However, oilproducts are increasingly used only used fortransportation, with other fuels used forpower generation.

As markets have evolved, however, only oneof these reasons—the need for a transparentbenchmark—remains relevant, but even here insome markets natural gas hubs are now moreable to provide a natural gas benchmark.

The fundamental economic rationale for thelink between natural gas and oil prices is whetherthe economic drivers behind the value of oil aresimilar to those behind the value of natural gas.When oil and natural gas were substitutes—forexample when they were both used in powergeneration—this was often true, and their valuewould change at the same rate. Now, however,oil is primarily used for transportation, and nat-ural gas is not. The value the market puts onthese two fuels is often driven by different forces,so the price of oil no longer reflects the value ofnatural gas as accurately. Because the uses fornatural gas and oil and their production costshave largely diverged, the fundamental economicrationale for a price link is unlikely to bere-established, especially in markets in whichnatural gas benchmarks are emerging.

17.4.3 Chinese Pricing Mechanisms

China’s natural gas is derived from domesticnatural gas, imported LNG and imported pipelinenatural gas from countries of the former SovietUnion. The different treatment of these resourcesfrom different source results in a three-strandpricing mechanism:

17.4 Pricing 369

• Domestic natural gas: Price is determined ona cost-plus basis.

• Imported LNG: Contract prices and linkedto Japan Crude Cocktail prices, with anS-curve-based ceiling mechanism that limitsexposure to oil price movements.

• Imported pipeline natural gas: In a pricingmechanism that the IGU has called a “bilat-eral monopoly”, price is based on intergov-ernmental negotiations and entails significantuncertainty.

The differences inherent in China’s pricingstructure have already caused a series of marketconvergence problems, especially in periodswhen oil prices are high.

Experience from North America and Europesuggests that prices for imported natural gas orLNG can be based on a natural gas index thatreflects the supply and demand of the recipientregion or country. A relevant natural gas index isonly possible, however, if the participants,infrastructure and regulations are in place to forma natural gas hub that is liquid, transparent andwidely used. The natural gas index must also beacceptable to financial institutions, which supplycredit to developers and buyers. Once in place, aChinese natural gas index could provide thenecessary price signals to attract additionalimports as required. Although natural gas marketreforms in China continue to gather momentum,international experience suggests that a naturalgas hub is not likely to develop soon and inter-mediate measures may be needed in the interim.

As China continues to reform its natural gasmarket, pricing mechanisms will need to beallowed to evolve. As an interim measure, thecurrent practice of offering end users natural gasat prices based on the prices of competing fuelscan continue. However, this approach exposesimporters, especially LNG importers, to risk.LNG imports to China would continue to bedriven by global supply and demand factors, andChina would have to compete with other buyerson the market. During this time, oil-indexedcontracts would continue, at the same time asLNG deals linked to Henry Hub prices gainmomentum. If the market is allowed to open

further to competition, the mismatch betweenimported natural gas prices and end-user pricesshould narrow.

17.4.4 The Influence of ChineseDemand on the WorldMarket

This section analyses the influence of China’snatural gas consumption on global energy mar-kets. We will explore three scenarios for Chinesedemand: the first where there are no new policiesto reduce consumption or stimulate natural gasconsumption, and then two scenarios that featureincreasing substitution of natural gas for coal,both in the power sector and in the widereconomy.

The key findings from the modelling are:

• Natural gas prices: Flexible global naturalgas supply would dampen any increase indomestic natural gas prices if higher naturalgas demand in China put upward pressure ondomestic prices.

• Coal consumption: Lower Chinese coalconsumption would be largely offset byincreased coal use in other countries, unlessthose countries adopt similar policies.

• Domestic coal: Policies that encourage onlythe power sector to reduce coal consumptioncould result in lower coal prices and a switchto coal from natural gas in industries notcovered by the low-carbon policies. Policiesaimed at reducing domestic coal productionshould have broad applicability in order tohave the greatest impact.

1. The three policy scenarios

Three scenarios for China were developed toillustrate the effects of a reduction in domesticcoal consumption—for power generation and forindustrial use more widely—and to analyse howreadily natural gas could be substituted for coaland what impact these changes would have onglobal energy markets. These three scenarios(Baseline, Power Generation Sector and All

370 17 The Global Natural Gas Market

Sectors) simulate the effects of varying degreesof restriction on coal consumption in China.Each scenario differs in the stringency of therestriction, as well as the sectors that are targeted.

• Baseline scenario: China does not introduceany new policy measures aimed at reducingcoal consumption or stimulating natural gasconsumption. Coal-fired generation capacityin the power sector continues to grow athistorical rates for the duration of the 13thFive-Year Plan, from 2016 to 2020. It con-tinues to grow steadily, albeit at a slightlyslower rate, after that. This scenario isbroadly consistent with recent IEA and EIAanalysis. However, given the momentum forchange in China’s energy policy, it should beviewed as a useful baseline against which tocompare the impact of the other two scenar-ios, rather than a realistic future pathway. Forexample, the scenario does not take intoaccount current commitments to LNGprojects.

• Power Generation Sector scenario: Chinarestricts coal consumption in the power sec-tor, reducing investments in coal-fired gen-eration capacity and increasing the effectiveprice of coal for power generation. This sce-nario is very similar to current policy trendsin China, and thus is considered to be themost realistic.

• All Sectors scenario: China restricts coalconsumption in the power sector, similar tothe Power Generation Sector scenario, butextending the restrictions to other sectors ofthe economy, reducing investment in allcoal-intensive capital stock and raising theeffective price of coal economy-wide.

2. The impact on Chinese energy supplyand demand

Restrictions on coal use would raise the effectiveprice of coal and reduce incentives for coal-intensive investments. Coal consumption wouldpeak in 2020 under the Power Generation Sectorscenario and in 2018 under the All Sectors sce-nario. The later peak in the Power Generation

Sector scenario reflects the leakage of coal usefrom the power sector to other sectors of theeconomy, most notably manufacturing, thatwould result from restricting coal use only in thepower sector.

The decline in coal consumption would beaccompanied by an increase in the consumptionof natural gas and electricity. Under both thePower Generation Sector and All Sectors sce-narios, the share of natural gas in China’s energymix would rise by 2030—to 17% in the PowerGeneration Sector scenario and to 21% in the AllSectors scenario (Fig. 17.22). The share of nat-ural gas in the power sector would rise to around15% in both scenarios. Against a backdrop ofrising energy demand overall, this would trans-late into a 70% increase in natural gas con-sumption in the Power Generation Sectorscenario over the Baseline scenario and a 100%increase in the All Sectors scenario.

China’s domestic natural gas production wouldremain below consumption levels in both thePower Generation Sector and All Sectors scenar-ios, despite an assumed tripling in domestic pro-duction by 2030. As a result, the share of naturalgas imports in total consumption is estimated torise to around 50% by 2025 in both scenarios.Given current and planned future pipeline capac-ity, the LNG share of natural gas imports is esti-mated to rise to more than 50%. The consumption/production gap would be larger in the All Sectorsscenario, where LNG imports are estimated toaccount for 73% of total natural gas imports.

Restricting coal use only in the power sector(as in the Power Generation Sector scenario)would lead to a leakage of coal use to othersectors, leading to natural gas-to-coal substitutionin these sectors. In turn, this would benefit othercoal-intensive sectors of the economy, such asmanufacturing, as lower coal demand in thepower sector would place downward pressure onthe price of coal paid by other sectors. On theother hand, an increase in natural gas demand forpower generation would place upward pressureon the domestic price of natural gas, putting othergas-intensive sectors, such as residential heating,at a disadvantage because their main substitutesfor natural gas are electricity and oil.

17.4 Pricing 371

3. The impact on the global energy market

The IEA estimates that emerging economies likeChina will account for most of the growth inglobal energy demand over the next two decades,and changes to the energy policies and the energymix in these economies will have implicationsfor global energy markets. Overall, the modellingindicates that while global coal consumptionremains relatively unchanged, natural gas con-sumption would increase in the Power Genera-tion Sector and All Sectors scenarios(Fig. 17.23).

(I) Impact on coal consumption

In the Power Generation Sector and All Sectorsscenarios, decreased coal use in China depressesthe coal price enough to stimulate coal con-sumption elsewhere, leaving total coal con-sumption largely undiminished at the globallevel. Both scenarios result in a decrease inChinese coal consumption, with a greaterreduction in the All Sectors scenario than in thePower Generation Sector scenario. However,

total global coal consumption by 2030 remainsrelatively undiminished and roughly the same inboth scenarios. This is because global coal sup-ply is relatively price-inelastic, that is, supply isrelatively unresponsive to falling demand andhence falling prices. While the reduction inChinese coal demand would put downwardpressure on the coal price, this would not lead toa significant reduction in price. Cheaper coalprices, on the other hand, would lead to increasedcoal consumption in other countries withoutsimilar restrictions on coal use.

Overall, in the Power Generation Sector sce-nario 96% of the decrease in China’s coal con-sumption is offset by an increase elsewhere, whilein the All Sectors scenario 89% of the decrease isoffset. One reason for the difference between thetwo scenarios is the nature of trade flows in thecoal market in each scenario. In the Power Gen-eration Sector scenario, some of the coal thatwould have been imported by China compared tothe Baseline scenario would no longer be neededand instead would be consumed closer to itssource. In the All Sectors scenario, however, bothdomestic coal production and coal imports would

Gas

Oil

Coal

Other

Manufacturing

Residential

Services

Transport

Power

Other

Solar

Oil

Biomass

Nuclear

Gas

Wind

Hydro

Coal

CHINA PRIMARY ENERGY(thousand Mtoe in 2030)

CHINA GAS CONSUMPTION(BCM in 2030)

CHINA POWER GENERATION(TWH in 2030)

45% 20%

21%

15%

3.9900

59% 19%

11%

11%

3.9

50% 19%

17%

14%

4.0

48%14%14%

10% 8%

10,052

47%15%15%

10% 8%

9,803

65%14%

5%

10%4%

9,567

205

493

80

760

86

503

76

452

100150

89

ALL SECTORS

LEGEND

POWERGEN SECTOR

BASELINE

Fig. 17.22 China’s 2030 energy mix, natural gas consumption and power generation energy mix, by scenario. SourceAurora Energy Research, Global Energy Model

372 17 The Global Natural Gas Market

be displaced, and China would become a netexporter of coal by 2025. However, countries thatconsume China’s surplus coal production wouldincur transportation costs, leading to a smallershare of China’s coal consumption leaking toother countries.

The coal leakage effect would be drivenpurely by the economics of lower coal prices—neither the Power Generation Sector nor the AllSectors scenario assumes comparable coalreduction policies in other parts of the world.This effect would be limited if comparable coalrestrictions were also in place in other Asiancountries. A key implication of this result is that,given the interconnected nature of global energymarkets, a meaningful reduction in global coalconsumption can only be achieved through aconcerted international policy effort.

(II) Impact on natural gas consumption

In contrast to coal, natural gas supply is relativelyprice-elastic, that is, global natural gas supplyincreases in response to rising demand and risingprices. The supply response mitigates some of

the increase in price, resulting in only a modestincrease in natural gas hub prices.

Restrictions on coal use in both the PowerGeneration Sector and All Sectors scenarioswould drive substantial substitution away fromcoal and towards natural gas in China. Thehigher demand would be met by production frommany different geographical regions, including asignificant increase in domestic production(Fig. 17.24). The rising share of LNG to meetdomestic consumption would push domesticnatural gas prices higher, nearing Japanese LNGprices, which would stimulate domesticproduction.

The modelling indicates that, while increasingChinese natural gas demand would put someupward pressure on natural gas prices, naturalgas-intensive countries like the United Stateswould not decrease consumption substantially inresponse. Thus global natural gas demand overallwould be higher under both the Power Genera-tion Sector and All Sectors scenarios, and theconsumption decrease outside China would onlybe enough to offset about 42% of the increaseseen within China.

0.5

0.5

0.8

0.8(17%)

1.8

2015 2030BASELINE

2030POWERGEN

SECTOR

2030ALL SECTORS

4.7

0.5

0.5

0.8

0.7(15%)

1.9

4.7

0.5

0.5

0.8

0.4(9%)

1.9

4.5

0.40.4

0.6

1.4

3.3

China

India

Japan

USA

EU Rest of world

Russia

China

India

Japan

USA

EU Rest of world

Russia

0.10.4

0.9

0.8

1.8(42%)

2015 2030BASELINE

2030POWERGEN

SECTOR

2030ALL SECTORS

4.3

0.10.4

0.8

0.7

2.0(46%)

4.3

0.10.4

0.7

0.6

2.3(53%)

4.3

0.20.4

0.6

0.4

2.1(52%)

4.0

Global gas demand (thousand Mtoe) Global gas demand (thousand Mtoe)

0.2(6%)

Fig. 17.23 Global natural gas and coal demand, by region and scenario. Source Aurora Energy Research, GlobalEnergy Model

17.4 Pricing 373

(III) Impact on primary energy consumption

Both the Power Generation Sector and All Sec-tors scenarios indicate a net increase in globalenergy consumption (Fig. 17.25). The world’soverall energy bundle would effectively becomecheaper as the coal price would drop by morethan the increase in the natural gas price. Thedecline in coal consumption in China would beoffset by increased coal consumption elsewhereand the increase in natural gas consumption inChina would not be offset. Moreover, in China,higher total primary energy consumption wouldbe driven by substituting coal with electricity.

(IV) Changes in energy prices

Substituting natural gas for coal in Chinawould have a large effect on global coal pricesand a relatively small effect on global natural gasprices. Global coal prices in 2030 would belower in both the Power Generation Sector andthe All Sectors scenarios compared to the Base-line scenario. In the Power Generation Sectorscenario, the difference would be 15% or

$12/tonne and in the All Sectors scenario, 26%or $20/tonne (Fig. 17.26). The main drivers forthe significant drop in global coal price would beChina’s exceptional position as the largest con-sumer in the international coal market—Chinacurrently consumes more than half of the world’scoal—and the high degree of global integrationin the coal market.

Natural gas prices everywhere would increaseas a result of rising Chinese natural gas demand,but this increase would be very modest at themajor international natural gas hubs: a 3% priceincrease on average in 2030 across three majornatural gas hubs: the NBP in the United Kingdom,the Henry Hub in the United States and the LNGimport price in Japan (Fig. 17.27). In all threescenarios, there would be considerable conver-gence between these hub prices, as global LNGtrade increases substantially and average LNGtransport costs fall. For instance, the differencebetween Japanese LNG prices and the Henry Hubprice would fall from just more than $12/MMBtuin 2015 to $7–8/MMBtu in 2030, as long-run EastAsian LNG prices become broadly equivalent tothe Henry Hub price, plus transport costs.

2015 2030BASELINE

2030POWERGEN

SECTOR

2030ALL SECTORS

Global gas production (thousand bcm)

1.0

0.20.2

1.1

0.8

0.7

0.8

5.1

1.0

0.20.2

1.1

0.8

0.4(8%)

0.4(8%)

0.7

0.85.0

1.0

0.2

1.0

0.8

0.3(7%)

0.7

0.8

3.6

0.7

0.1

0.7

0.7

0.6

0.20.1

0.6

0.1(4%)

0.8

5.2

34

28

25

27

37

94(36%)

0.8(bcm)

+0.3

56

Rest of world

Rest of Asia

China

Russia

OPEC

USA

Canada

Australia

Fig. 17.24 Trends in global natural gas production by region and scenario. Source Aurora Energy Research, GlobalEnergy Model

374 17 The Global Natural Gas Market

2015 2030BASELINE

2030POWERGEN

SECTOR

2030ALL SECTORS

2.1

2.2

0.8

5.0

14.4

China

India

Japan

USA

EU Rest of World

Russia

2015 2030BASELINE

2030POWERGEN

SECTOR

2030ALL SECTORS

14.4

Other renewables

Hydro

Nuclear

Biomass

Gas Oil

Coal

Global primary energy demand (thousand Mtoe)

3.0(21%)

2.0

2.4

1.4

6.5

17.6

3.9(22%)

2.0

2.4

1.5

6.6

17.9

4.0(22%)

2.0 4.6

4.0

3.3

1.20.7

17.6

5.2

4.3

4.5

1.61.1

17.9

5.2

4.7

1.7

1.1

4.3

5.2

4.7

1.7

1.1

4.3

18.0

2.4

1.6

6.6

18.0

3.9(22%)

Fig. 17.25 Global primary energy demand 2015–2030 by region and scenario. Source Aurora Energy Research,Global Energy Model

Other(18)

Restof Asia(38%)

India(44%)

Other(16)

Restof Asia(38%)

India(45%)

+303

-314

+280

-119

+406

-112

+463

518

96% LEAKAGE

89 % LEAKAGE

ALL SECTORS

POWERGEN SECTORBASELINE

2015 2030

POWERGENSECTOR ALL SECTORS

Coal Rest of world: GasChina: Gas Coal

100

80

60

40

20

0

Coal price(2014 USD/tonne)

Gas & coal consumption in 2030( Mtoe, relative to baseline)

Fig. 17.26 Decline in China’s coal demand and leakage of capacity. Note Price references ARA 6000 kcal per kg coal.From 2015 to 2018, displayed prices reference current futures prices. Source Aurora Energy Research, Global EnergyModel

17.4 Pricing 375

The increase in global natural gas priceswould be much smaller than the decrease inglobal coal prices for several reasons:

• The increase in Chinese natural gas con-sumption would be slightly less than thedecrease in Chinese coal consumption becausethere would be some substitution from coal tonon-natural gas fuels in China.

• China is a larger player in global coal marketsthan in natural gas markets, and its decisionslinked to coal would have greater implica-tions for global markets.

• Global trade in natural gas is much smallerthan that in coal, partly because the rigidity ofpipeline supply and the high transport costsfor LNG restrict global trade flows.

• Global natural gas supply is more price-elasticthan global coal supply, and natural gas pro-duction would increase to meet higher demand,while coal production would not fall signifi-cantly, creating excess supply and lower prices.

However, domestic natural gas price in Chinawould rise more substantially in both the PowerGeneration Sector and All Sectors scenarios. By2030, domestic prices would reach $12/MMBtuin the Power Generation Sector scenario and$13/MMBtu in the All Sectors scenario, com-pared to between $8/MMBtu and $10/MMBtu inthe Baseline scenario. The reason for the dis-proportionate effect on prices in China is that asChina starts substituting natural gas for coal, theincrease in natural gas consumption would bemade possible by increased natural gas imports,LNG in particular. As a result, natural gas pricesin China would converge towards the EastAsian LNG price.

4. A description of the model

The simulations of three possible energyscenarios for China were based on the AuroraEnergy Research global energy model, which is ahybrid of the computable general equilibrium

2015 2030 2015 2030

POWERGENSECTOR ALL SECTORS

18

16

14

12

10

8

6

6

2

0

Global gas prices (2014 USD/MMBtu)

1

12

1

Japan LNG

UN NBPChina

China - Japan2030 pricedifference

USA Henry Hub

4

21

BASELINE

Fig. 17.27 Global natural gas hub price change trend forecasts. Notes (1) For 2014–2018, prices shown take intoaccount current futures prices (as of December 12, 2014, converted to real 2014 US$). (2) For China, this is a weightedaverage producer gas price index (domestic, pipeline, LNG), which equates supply and demand in the AER-GLOmodel. It includes regasification costs for LNG. Weightings are based on the standard Armington assumption governingtrade in CGE model. As a consequence, this figure will not necessarily match wholesale prices at any particular regionin the Chinese market. Source Aurora Energy Research, Global Energy Model

376 17 The Global Natural Gas Market

model that the company had created to analyseglobal energy markets.

The model drew from three key buildingblocks: a global general equilibrium module torepresent energy demand and economic activity inall countries, a number of dynamic resourceextraction modules to model the supply of oil,natural gas and coal in a dynamic financial setting;and an electricity dispatch module, which emu-lates the Chinese power sector (Fig. 17.28). Themodel lets all three modules solve iteratively ineach year until an internally consistent solutionacross all three is found in every year. The hybridstructure combined the benefits arising from therobust structure of global general equilibriummodels with the added detail of partial-equilibriummodels of fuel extraction and electricity dispatch.Both types of modelling approaches are essentialfor understanding global energy markets.

The model was used to forecast the impact ofenergy policy changes on the global economy,as well as individual sectors. In addition, with

129 regions globally and 57 sectors within eachregion, the model could produce outputs thatincluded country- and industry-specific forecastsof demand and supply of all goods and services,changes in imports and exports, gross regionalproduct, consumption, investments, returns tocapital and emissions of greenhouse naturalgases and particulate matters.

For this study, the model was calibratedagainst recent economic and energy data, andenvisioned three illustrative energy policy sce-narios, in which key Chinese policy parametersrelating to coal consumption were changed.These scenarios simulate plausible changes inChina’s energy policy environment and theeffects these are likely to have on global coal andnatural gas markets.

A global general equilibrium structure wasnecessary for modelling the global markets forfuels because of the intimate linkage betweenenergy and future developments in moderneconomies, the substitutability between different

Prices of oil, gas and coal and input price indexPrices of oil, gas and coal and input price index

GLOBAL GENERAL EQUILIBRIUM MODEL

(World)

GLOBAL GENERAL EQUILIBRIUM MODEL

(World)

DYNAMIC RESOURCE

EXTRACTION MODULES

(1 per region and resource category)

DYNAMIC RESOURCE

EXTRACTION MODULES

(1 per region and resource category) ELECTRICITY

DISPATCH MODULE

(China)

ELECTRICITY DISPATCH MODULE

(China)

Power price and production for

China

Power price and production for

China

Capacity investment and

oil/gas/coal production for every region

Aurora’s global energy model (AER-GLO)Modelling approach

1. GGEM solves for prices given fossil fuel and electricity production

2. Fossil fuel and electricity production are optimised at given prices

3. Iterates until an internally consistent solution is found

4. Moves on to next year

Fig. 17.28 Hybrid computable general equilibrium (CGE) model used by Aurora for global modelling. Source AuroraEnergy Research, Global Energy Model

17.4 Pricing 377

fuels in final energy use, and the uneven distri-bution of resources across the world. As a result,the impact of China’s energy policy on globalenergy markets provided by the model were

driven to a large extent by the interaction ofdifferent markets under equilibrium and theresulting substitution between fuels in all geo-graphical regions in the model.

Open Access This chapter is licensed under the terms ofthe Creative Commons Attribution 4.0 InternationalLicense (http://creativecommons.org/licenses/by/4.0/),which permits use, sharing, adaptation, distribution andreproduction in any medium or format, as long as yougive appropriate credit to the original author(s) and thesource, provide a link to the Creative Commons licenseand indicate if changes were made.

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378 17 The Global Natural Gas Market

18An Overview of InternationalRegulatory Experience

As part of our study, we looked at the evolution ofnatural gas markets in five selected countries thatexperienced significant increases in gas demandover the last few decades. In general, these fivemarkets liberalised their natural gas systems inphases, allowing increased competition in theupstream and downstream segments, ensuring fairaccess to midstream infrastructure such as pipeli-nes and LNG terminals, and striving to ensure thatmarket changes supported overarching energygoals and benefited end users. To varying degrees,the experience of the United States, the EuropeanUnion, the United Kingdom, Japan, and SouthKorea shows that natural gas market liberalisationplays a key role in developing and maintainingwell-functioning natural gas markets.

Three key factors that determine the devel-opment and evolution of natural gas markets are:fundamentals, market regulation and ancillarypolicies:

• Market fundamentals: The fundamentals ofthe natural gas market include demand fornatural gas in the economy, the availability ofsources of supply, and the extent to whichsources of supply compete.

• Energy market regulation: Natural gasmarket regulation is a crucial factor in thedevelopment and evolution of natural gasmarkets. A clear and consistent regulatoryframework requires a strong and independentmarket authority and includes key provisionsfor the regulation of natural monopolies,safety and environmental rules, particularlyfor exploration and production, security ofsupply and market transparency, wherecompetitive markets can exist.

• Ancillary policies: These include policiesand regulations that affect natural gas marketsindirectly, for example, air quality and cli-mate change legislation that influences thecost-competitiveness of substitute fuels forpower generation, policies to encourage andsupport greater energy access for low-incomehouseholds, and subsidies for energy-relatedresearch and development.

Market fundamentals, energy market regu-lation and ancillary policies interact to deter-mine market composition. In addition, theentire energy system and even other sectors inthe national economy can influence natural gasmarket regulation and ancillary policies. Like-wise, the market fundamentals can be influ-enced by technological development or bygeopolitical events that reduce the relativecosts of indigenous and foreign sources ofsupply.

Turning for a moment to natural gas regula-tions, these generally have three goals:

* This chapter was overseen by Jigang Wei from theDevelopment Research Center of the State Council andTaoliang Lee from Shell Eastern Trading Corporation. Itwas jointly completed by Yaodong Shi, Zifeng Song,Ren Miao from the Energy Research Institute of theNational Development and Reform Commission andCindy Wang from Shell China. Other members of thetopic group participated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_18

379

• Affordable supply: Providing economicalnatural gas to end users.

• Secure supply: Making gas delivery moresecure, especially in the segments of thenatural gas value chain where naturalmonopolies exist.

• Secondary benefits: Formulating policiesthat provide knock-on benefits for society as awhole, for example, restricting air pollutionand carbon emissions, and providing energyto poor families.

The market liberalisation of natural gas canachieve these three goals. First, market liberali-sation can provoke competition, which helps toreduce consumption costs and thus provideaffordable energy to end users. Second, marketliberalisation opens the market to a more diverserange of suppliers, which can improve security ofsupply. Third, because market participants willreact promptly to any incentive measures con-tained in secondary policies, the entire naturalgas value chain will be able to respond moreflexibly to fulfil these policy objectives.

However, market liberalisation also bringsgreater risks to investment. For example, underfree market conditions, domestic natural gasenterprise buying power could be reduced ininternational markets. Market liberalisation willalso make it harder for poor families to obtainenergy. Case studies show that governmentsoften use targeted market liberalisation that isrestricted or controlled, so as to rein in theseadverse influences.

Natural gas market development does notsolely rely upon regulation, though. The funda-mentals of a market, such as the ready avail-ability of natural gas supplies and the level ofnatural gas demand, are primary forces in naturalgas market outcomes. For example, regardless ofthe regulatory regime, a country like Japan, withnegligible indigenous production, will alwayshave different natural gas market fundamentalsthan the United States with its large indigenousproduction. At the same time, competitionbetween natural gas and other fuels will alsoinfluence development of natural gas markets, aswill a wide variety of other factors such as air

quality, climate change, energy sufficiency andelectricity market structure, all of which willinfluence natural gas market development.

International experience suggests there is acore set of actions required to deliver competitivenatural gas market outcomes, across a range ofdifferent market fundamentals and ancillary pol-icy priorities. The analysis of gas market evolu-tion in different countries seeks to draw generallessons for natural gas market liberalisation,noting contrasts in each region that force differ-ent regulatory approaches. The Chinese contextwill be different again, but the common core ofactions across the case studies is likely to berelevant to China, although modified for thecountry’s unique characteristics. In short, inter-national experience offers important guidance toChina as it designs the composition and opera-tion of its natural gas market.

The political sequencing of regulatory reformsis as important to successful market liberalisationas correct implementation. Natural gas marketregulation impinges on a number of politicallyimportant issues, in particular energy affordabil-ity, the funding model for national infrastructureand energy security. When political momentum issupportive of liberalisation, regulatory reform hasdelivered competitive markets within 10–15years; for instance, in the United States starting inthe late 1970s or the United Kingdom starting inthe late 1980s. When political momentum is notsupportive, the process of regulatory develop-ment could require decades.

In countries with significant domestic natu-ral gas resources, such as Norway, TheNetherlands, the United Kingdom, and theUnited States, market liberalisation has drivenincreased competition and greater developmentof these resources. At the same time, theexperience of these countries shows that thecourse of market liberalisation requiresfavourable upstream licensing, fiscal or envi-ronmental policies. In the United States, privateownership of land and the resources under-neath it enabled rapid development of shalenatural gas exploration and production. Whereresources are owned by the government, suchas on the outer continental shelf of the North

380 18 An Overview of International Regulatory Experience

Sea in Norway, The Netherlands and theUnited Kingdom, processes are in place toenable effective and competitive leasing ofexploration and production rights.

Another lesson emerging from the case stud-ies is that interactions between ancillary policiesare often unpredictable, such as environmentaland technology policies on the one hand andliberalised gas markets on the other. Environ-mental policies—relating to carbon emissionsand local air pollutants—can increase the costs ofemissions-intensive coal relative to natural gas.While ambitious policies on climate change andair quality favour natural gas over coal in elec-tricity generation, the design of these policiescould produce some unintended consequences.This has been the experience in the EuropeanUnion, where the interaction between the two hasundermined environmental objectives and led tothe coal-renewables “energy paradox”. Similarly,the United States has supported energy-relatedresearch and development programmes for dec-ades, such as on unconventional natural gas andmicroseismic fracture monitoring, which even-tually proved instrumental in driving the USshale natural gas boom of the last decade.

In summary, market fundamentals, energymarket regulation and ancillary policies interact,and shape a country’s natural gas market overtime. International experience has shown thattechnical developments and geopolitical eventscan affect domestic and international supplycosts, and can influence the market fundamen-tals. Likewise, the market fundamentals have aninfluence on natural gas market regulation andancillary policies, and together they all form thenatural gas market. Natural gas market liberali-sation is thus ultimately dependent on the historyof the natural gas market, geography and thepolitical environment, and these major influencesare pivotal in the formation of natural gas mar-kets. For example, natural gas market regulationand ancillary policies are determined by politicaltrends and events. This chapter will introduceinternational experiences from natural gas marketregulation, market liberalisation and other per-spectives, analysing case studies of foreign nat-ural gas market liberalisation in depth in the hope

of providing a reference point for, and insightinto, China’s natural gas market liberalisationreforms.

18.1 Regulatory Reform

18.1.1 The Reasons for Regulation

Policymakers regulate the natural gas value chainin order to balance three major policy goals:

• Economic supply: Providing affordableheating to households and competitive naturalgas prices for power generation andenergy-intensive industries.

• Security of supply: The maintenance of ahigh-quality supply of natural gas to endusers. Policymakers also often consider nat-ural gas supply infrastructure to be part ofcritical national infrastructure required for thefunctioning of the country and the delivery ofthe essential services.

• Safe and clean supply: This objective pre-supposes that natural gas supply should poseminimum risk to public health and safety. Italso captures the notion that increased naturalgas supply can replace alternative fuels thathave a higher direct environmental impactand higher greenhouse natural gas emissions.

These policy goals can conflict on multiplelevels, and are often referred to as the energypolicy “trilemma”. For example, within economicsupply, ensuring affordable natural gas prices forend users has often led countries to subsidiseend-user prices, either through cross-subsidisationof one class of users by another or directly fromthe state budget. Further, delivering economicsupply may not always be compatible the withgoals of safe and clean supply.

Liberalising natural gas markets can helpdeliver across the energy trilemma objectives,but may need to be supplemented by a broaderpolicy framework to manage some of theremaining trade-offs. For example, market liber-alisation increases competition, which in turnhelps to drive down costs for consumers over the

18 An Overview of International Regulatory Experience 381

long term, delivering an economical supply. Italso opens the market to a diverse range ofsuppliers, increasing security of supply. Finally,policies to encourage natural gas use andincrease its share in the energy mix can reducethe risk to public health and safety, for exampleby reducing indoor and outdoor air pollution andgreenhouse gas emissions caused by coal use.

However, liberalisation can also makeinvestment riskier, and fragmented domesticnatural gas firms can face reduced buying poweron international markets. It can also raise costs inthe near term, reducing the ability of low-incomehouseholds to access energy, unless other poli-cies are put in place to compensate. The five casestudies below demonstrate that gas market lib-eralisation is often limited, or complemented byother policies, in order to manage these impacts.

18.1.2 The Process of MarketLiberalisation Acrossthe Natural Gas ValueChain

Liberalisation refers to the process by whichcompetitive market outcomes are delivered:providing end users with the greatest choice atthe lowest price. This can be achieved either by

opening markets to competition or through reg-ulatory measures to limit or cap prices wherenatural monopolies exist. To achieve the goal ofnatural gas market liberalisation, the structureand economics of the natural gas value chainneed to be considered (Fig. 18.1). With theexception of some segments where naturalmonopolies exist, market competition existsthroughout the value chain.

The natural gas value chain can broadly bedivided into three segments—upstream markets,midstream infrastructure and downstream mar-kets. The upstream segment refers to domesticexploration and production of natural gas. Themidstream segment refers to infrastructure for thetransport of natural gas—domestic and imported—through transmission pipelines, LNG terminalsand local distribution networks.1 The

Retail market

Wholesalemarket

Domesticexploration and

production

Upstream Midstream Downstream

LNG importsTransmission

network

Distributionnetwork

Storage

City gate

PipelineImports

Fig. 18.1 The natural gas value chain. Note Natural monopolies, where markets fail, are mainly in the midstreamsegment

1For the purposes of this study, LNG terminals areclassified as midstream infrastructure rather than upstreamassets. Whether to treat LNG terminals as upstream assetsor midstream infrastructure depends largely on the natureof competition in a market. In the United States, LNGterminals compete with domestic production, and arehence considered equivalent to domestic well heads andclassified as upstream assets. In Europe, most of thecompetition is with imported natural gas, and hence LNGterminals are considered part of the transmission networkand classified as midstream infrastructure. The appropri-ate treatment of LNG terminals in China is not yet clear

382 18 An Overview of International Regulatory Experience

downstream segment refers to wholesale andretail markets supplying gas to end users.

Competitive markets can exist at many placesacross the natural gas value chain. Competition inthe upstream segment can drive greater efficiencyand innovation in exploration and production ofnatural gas, as a way to drive down costs anddevelop greater volumes and sources of domesticsupply. For example, before the liberalisation ofnatural gas markets in the European Union, ver-tically integrated and state-owned natural gascompanies had little incentive to improve theefficiency of their operations, leading to increasesin natural gas prices. Similarly, greater competi-tion in the downstream segment can increasechoice and reduce the price paid by the end usersof natural gas, for example by increasing com-petition in the shipping and sales of natural gas.These segments can be opened to competition,within a regulatory oversight framework to ensureand support competitive markets and without theneed for further regulatory interventions.

Opening markets to competition is typicallynot desirable and can fail in the midstream seg-ment. Midstream infrastructure, such as pipeli-nes, are highly capital-intensive. For example, in2013, onshore oil and natural gas pipeline con-struction in the United States cost $4.1 millionper mile, while offshore pipelines cost $7.6 mil-lion per mile. High fixed costs and relatively lowoperation and maintenance costs point to largeeconomies of scale: the costs of delivery declinerapidly with volume. This fits the definition of anatural monopoly, where the lowest long-runaverage costs are realised when production andownership are concentrated in a single firm.

However, enterprises in positions of naturalmonopolies tend toward using their marketposition to harm consumers and will collect pri-ces higher than those formed by market compe-tition. In addition, natural gas transmissionpipelines and other midstream infrastructureowners are generally vertically integrated, andthey provide various services throughout the

value chain. Such enterprises will generally takeactions to restrict competition, for example col-lecting excessively high fees from third-partynatural gas suppliers and shippers using theinfrastructure so as to maintain their leadingposition in upstream sectors, or else raise theirprofits in downstream sales business. This resultsin US and European natural gas market regula-tory bodies requiring transmission pipelineowners to open their facilities to third parties, orto regulate the fees collected from customers bythe pipeline infrastructure owners. They alsoinsist on the separation of transmission servicesand upstream or downstream business—thisprocess is called deregulation.

Liberalisation of natural gas markets requiresidentifying the competitive and natural mono-poly segments of value chain, and applyingappropriate regulatory approaches. For example,between 1954 and 1978, the United States ineffect treated the entire value chain as a naturalmonopoly, with prices from the wellhead onwardfully regulated to protect consumers. As a con-sequence, US natural gas investment failed torespond adequately to the 1970s oil crisis. Therecognition in 1978 that only pipelines are nat-ural monopolies, requiring regulation to ensureopen access, marked the start of a period of lib-eralisation. The reforms unbundled the naturalgas industry, separating transportation and salesbusinesses, and ensured open access to interstatepipeline infrastructure for third parties. By 1992,after 14 years, the fundamentals for a competi-tive and efficient market had been established,and they supported a 40% increase in natural gasconsumption from around 500 billion m3 in1990 to 700 billion m3 by 2010.

A review of international case studies showsthat a competitive, responsive, liquid natural gasmarket is characterised by:

• Critical mass: Many players that compete forsubstantial upstream business and access tomidstream infrastructure, serving many buy-ers with large volumes and financed byresponsive investors.

• Competitive pricing: Competitive price for-mation at the wholesale and retail levels.

(Footnote 1 continued)because a competitive natural gas market has yet todevelop.

18.1 Regulatory Reform 383

• Open access: Non-discriminatory openaccess to natural monopolistic midstreaminfrastructure, as well as regulated tariffs.

Overall, a competitive market can optimallyallocate resources in many stages of the valuechain, within an oversight framework to ensurewell-functioning competitive markets. However,pipelines are natural monopolies and requiremore direct regulation. Getting the right combi-nation of competitive markets, regulatory over-sight and direct market regulation is essential forunlocking the benefits of liberalisation.

18.2 Market Liberalisation

18.2.1 Core Initiativesfor Liberalisation

Market regulation is crucial to achieving andsecuring the liberalisation of natural gas mar-kets. A regulatory framework, codified in law,

defines the principles of regulation along thenatural gas value chain. It determines whichsegments of the value chain should be openedto competition and establishes the institutionalarrangements to ensure free and fair competi-tion. It also determines which infrastructure isto be treated as a natural monopoly and setsthe basis for access to the infrastructure, aswell as the level of unbundling for verticallyintegrated players. The regulatory frameworkalso includes rules around safety, security ofsupply and environmental standards, whichapply throughout the value chain. Implement-ing the framework requires a strong, indepen-dent regulatory authority.

The natural gas market liberalisation experi-ence of the United States, the European Union,the United Kingdom, Japan and South Korea haslessons that might be relevant to China. Eachcountry has different characteristics. For exam-ple, the United States has by far the greatestindigenous supply, while the European Union isthe biggest importer (Table 18.1). Understanding

Table 18.1 Market traits of five natural gas markets plus China

Natural gasindicator

Type US EU UnitedKingdom

Japan Korea China

Supply (bcm perannum)

Indigenous 689 269 38 3 0.5 115

Net imports 37 231 39 123 53 49

Consumption (%of total)

Power 40 30 30 65 50 15

Industry 20 20 10 5 20 45

Transmission pipelines (km) 500k 200k 8k 5k 4k 50k

Wholesale competition Limited(oligopolies)

Limited(oligopolies)

Open access Upstream

Transmission

Distribution Varies Varies

Ownership unbundling of transportand sales

Varies

Independent (federal) marketauthority

Liquid market centres/hubs

Note Data for 2013, except China’s shares of power and industry in natural gas consumption for 2011. bcm is billioncubic metresSource Vivid Economics, based on IEA, EIA, Chinese government and ENTSOG data

384 18 An Overview of International Regulatory Experience

these differences can help identify experiencesthat best fit China’s circumstances.

The case studies suggest five core actions forliberalisation that can deliver a competitive out-come in the natural gas market, as shown inFig. 18.2. Creating institutions allows for a fun-damental natural gas legal framework and astrong, independent regulatory agency. Enablingopen access focuses on assuring fair and rea-sonable access to infrastructure owned by a nat-ural monopoly. Deregulating prices enablesmarket forces to determine prices and providesclearer signals about supply and demand. Settingstandards and ensuring transparency offers reg-ulatory mechanisms to ensure fair market prac-tices. And finally, protecting end userssafeguards the interests of commercial and resi-dential natural gas users and seeks to manage anynegative consequences of market liberalisation.

These measures take into account the broadercontext of natural gas market liberalisation: theneed to balance the positives and negatives ofliberalisation; interactions with fundamentals and

ancillary policies; the importance of naturalmonopolies in the value chain; and the legacy ofstate intervention in the natural gas market.

1. Creating institutions

Institutions, including a natural gas law and astrong, independent regulator, form the funda-mental building blocks of liberalised natural gasmarkets. Regulators are most effective when theyhave statutory independence from political,government and industry influence to ensureappropriate decision-making and equal treatmentof market participants, as well as to avoid amyopic approach to long-term infrastructureinvestment decisions. The regulator’s authorityand tasks should be laid down in a regulatoryframework codified in law.

The case studies below underscore theimportance of regulatory institutions beingindependent of political influences and operatingtransparently. They illustrate that decisionsshould be made in a consultative and transparent

1

2

3

4

5

Create institutions:

n a clear gas lawn a strong, independent gas regulator

Ensure open access:

Deregulate prices (for competitive segments of the value chain)

Set standards and ensure transparency:

Protect end-users:

n regulated third-party access

n improve transparency in markets for network use

n standardise trading arrangements

n support market centre development

n competition authority to oversee competitive markets

n manage impacts on end users (consumers, power, industrials) with suitable support

n unbundle and release parts of dominant players’ business if necessary

n regulate network charges (and provide investment commitments)

Fig. 18.2 Five steps to successful natural gas market liberalisation. Source Vivid Economics

18.2 Market Liberalisation 385

manner by involving stakeholders, publishingevidence and final decisions, and allowing appealin court. The regulator should have access toadequate financial and human resources to carryout its tasks satisfactorily.

The US Federal Energy Regulatory Commis-sion (FERC) is a classic example of a natural gasmarket system foundation operating well. FERCwas established in 1997 and is charged withoverseeing industries including electricity,hydroelectricity, oil and natural gas. In all ofthese industries, participants often hold signifi-cant market power. FERC regulates the marketsto ensure that companies do not misuse theirmonopoly positions, and its regulatory objectivesrange from preventing discriminatory service andunfair pricing to promoting environmentallysound infrastructure. FERC’s main responsibili-ties in the natural gas industry are regulating therates and services offered by interstate pipelinecompanies, certifying and permitting new pipe-line construction, enforcing competition andpreventing market manipulation where marketsexist, and handling related environmental issues.

2. Ensuring open access

Owners of natural monopoly infrastructure,such as pipelines, have an incentive to misusetheir market power, particularly when they arevertically integrated across the natural gas valuechain. Regulatory action is generally required infive specific areas:

• Third-party access: This requires owners ofnetworks with natural monopoly characteris-tics to grant access to their assets to interestedthird parties. (A detailed review of third-partyaccess experience is presented in Sect. 19.2.)

• Regulating network charges: To preventmonopolistic pricing of transportation ser-vices, the tariffs that a network owner andoperator can charge for transportation shouldbe regulated. The allowable tariff should beset at a level that encourages investment, butdoes not price shippers out of the market.

• Unbundling ownership: A vertically inte-grated company that has natural gas

extraction, sales and transportation businesseshas an incentive to engage in anti-competitivebehaviour, such as charging excessive ratesfor transportation services, to prevent thirdparties from competing with its upstreamextraction, downstream sales units or both. Toenable non-discriminatory open access tonetworks, the interests of any extraction orsales business should be separated from thetransportation services business. This is ide-ally achieved by unbundling or separatingbusinesses operating in different segments ofthe natural gas value chain. (A detailedreview of unbundling experience is presentedin Sect. 19.3.)

• Transparency on capacity availability andthe terms and conditions of infrastructureuse: Open access and unbundling alone arenot sufficient to deliver liberalised markets,and provisions to ensure transparency aroundmidstream transport infrastructure use arevital in enabling competition, both upstreamand downstream.

• Release parts of dominant players’ busi-ness: Dominant players tend to havelong-term contracts with suppliers and cus-tomers. The regulator should intervene tobreak up these contracts so that sufficientmarket volume is available for entrants.

Granting open access to networks is ofteninitially attempted through negotiated third-partyaccess or voluntary arrangements, leaving net-work owners free to negotiate terms and condi-tions for access. All five jurisdictions that werereviewed adopted this approach at first. How-ever, negotiated agreements consistently fall preyto market power abuse by network owners thatare vertically integrated with interests throughoutthe value chain, for example in production,import capacity or local distribution. Such firmshave a clear incentive to use their power to pre-vent entry of competitors.

Third-party access should be regulated care-fully, with provisions for allowable network usecharges that provide incentives for investment,terms and conditions of use, and transparencyaround capacity availability, tariffs and terms of

386 18 An Overview of International Regulatory Experience

use. Even with regulated third-party access,incumbent market supply dominance may needto be proactively broken by the regulator. Forexample, the United Kingdom regulator forcedBritish Gas, the dominant incumbent in the UKnatural gas market, to release parts of itslong-term supply contracts in the 1980s so thatnew entrants could start to compete and serve themarket instead.

In terms of establishing fee rates, regulatorybodies should satisfy the requirement to permitopen usage of gas transmission infrastructurewhile also ensuring that gas transmission infras-tructure is able to receive ample investments.There are essentially two methods of establishingfee rates: one is the sum of costs method, settingtotal revenue as equivalent to investment andoperating costs plus a reasonable return. Anotherapproach is the incentive-managed pricing uti-lised by the European Union and United States inrecent years, in which pipeline operator costs andpermitted revenue are separated and, based oncost baselines or cost analysis models, a baselinerevenue is established, along with an additionalpermitted revenue to incentivise supply qualityand other set goals. Together with these twogoals, the controlled rates of return always pro-mote investment as an important factor, with setlevels both encouraging investment and also notleading to excess investment or insufficientinvestment. Sometimes, in order to encourageinvestment, infrastructure need not be required toprovide open usage, for example with LNG ter-minals in the United States and Britain.

Unbundling is a key element in ensuringnon-discriminatory access to infrastructure.Owners of pipelines have an incentive to offerfavourable terms to their own upstream extrac-tion and downstream sales businesses over otherthird parties. Authorities observed thisanti-competitive behaviour by incumbent firms inthe United States in the 1930s and in the UnitedKingdom in the 1980s. The response in bothcountries was to require significant unbundling inaddition to open access, which facilitated theentry of gas shippers and brokers into wholesaleand retail markets. The European Union allowsfor different forms of unbundling. It allows

member states to keep networks under incumbentvertically integrated ownership, with strictarrangements to ensure independentdecision-making about transmission systemoperations. This reflects the desire of EU memberstates to retain control over who owns andoperates vital infrastructure and to maintain acertain degree of buyer power with major importsources. It also reflects the reality that somemember state markets may be too small toachieve real competition, and the costs of liber-alisation could outweigh the benefits.

Provisions to ensure transparency aroundmidstream transport infrastructure use are vital inenabling competition. Open access andunbundling, even when required by law, are notin themselves sufficient to deliver liberalisedmarkets. In the 1980s, the liberalised UnitedKingdom natural gas market was slow to attractentrants and generate competition because mar-ket participants were not able to acquire essentialinformation on capacity availability and theterms and conditions of infrastructure use. Sincethen, the United States and United Kingdomhave mandated that information about storageavailability and capacity and rates for pipelinetransport be published on bulletin boards.Compliance is monitored and enforced by therelevant market regulators and competitionauthorities.

In Japan, open access to LNG terminals hasnot yet resulted in third-party use, partly becausemarket participants do not have sufficient infor-mation. Moreover, following the Fukushimanuclear plant disaster, liberalisation lostmomentum in Japan as the country moved tosecure increased LNG imports. Japan nowencourages collective LNG purchasing by itsnatural gas importers to protect the economyagainst volatile LNG prices, although the debatearound further natural gas market liberalisation,including third-party access to LNG terminals,resumed in 2014. Similarly, in South Korea,winter peak natural gas demand concerns andvolatile LNG prices have led to the protection ofits vertically integrated and publicly ownedmonopoly supplier, Korea Gas (KOGAS), tosustain its buying power on global markets.

18.2 Market Liberalisation 387

Finally, it is important to recognise andaddress any existing long-term contracts held bythe incumbent that create barriers to entry bylimiting available capacity and restricting accessto midstream infrastructure. These legacy con-tracts are generally long-standing, reducingcapacity available for third parties and thereforepreventing competitive forces from taking effect.Regulators can intervene to break up long-termcontracts incumbents may have with suppliersand end users, to reduce incumbents’ marketshare, and to open the market for new entrants.Breaking up existing long-term contracts was akey step in liberalising markets in the UnitedStates and United Kingdom: dominant marketplayers were forced to release capacity fromcontracts to enable market entry and competition.

3. Deregulating prices

Prices should be deregulated where conditionsexist for the establishment of competitive mar-kets, for example in upstream exploration andproduction and in the downstream wholesale andretail markets. Deregulating prices is necessary toensure that economic signals about supply anddemand fundamentals are transmitted betweenmarket participants. Markets tend to fail whenthey exhibit natural monopoly characteristics,and in these stages of the value chain—namelytransmission and distribution—prices need to beregulated. Elsewhere, however, participants areable to allocate resources efficiently when pricesare left to respond freely to changes in supplyand demand fundamentals.

Wholesale prices are key transmitters of eco-nomic signals because they form the linkbetween upstream exploration and productionand the rest of the value chain. Achieving acompetitive natural gas market involves a phasedliberalisation of wholesale prices. The UnitedStates evolved from cost-plus wellhead prices,using netback2 and oil-linked contracts, to asystem in which spot and futures contracts arethe dominant types, traded by a diverse set of

participants. The UK market evolved from aprice-setting single buyer—British Gas—linkingcontracts to substitute fuels and inflation to reg-ulated caps and, finally, to more competitivehub-based trading. The end point of pricederegulation in these markets has been a liquidand responsive wholesale market.

These market-based prices imply a moveaway from long-term contracts, which tie theprice of natural gas to that of another commodity,or regulated prices, which are set by the gov-ernment. This has been changing as the volumeof natural gas traded, particularly LNG trade, hasexpanded. In the United States, natural gas isnow almost entirely based on market prices,whereas in the European Union it is split evenlybetween market-based prices and long-termoil-indexed contracts.

Long-term contracts linked to prices of sub-stitute fuels, spot markets prices or other indicesoffer a degree of certainty for investors to supportupstream development. For example, when com-bined with netback pricing, a take-or-pay clause,which provides a penalty payment if natural gasdeliveries are cancelled, can ensure a steadyincome stream for decades and enable investmentin exploration and production. Such clauses arecommon in the contracts for the Groningen nat-ural gas in The Netherlands. However, long-termcontracts may lead to low spot market liquidityand price uncertainty. Moreover, as discussedpreviously, breaking up existing long-term con-tracts is crucial to ensure open access, enablinggreater third-party access to midstream infras-tructure and market entry and competition in theupstream and downstream segments.

Reaching a stage of highly liquid wholesalespot markets can also support upstream devel-opment. For example, in the European Union,once natural gas hubs gained sufficient liquidity,contracts were increasingly linked to natural gasspot markets rather than oil prices. In the UnitedStates, shale development relied on the existenceof liquid spot markets. Developers of US shaleplays depended on spot markets because theywere unable to secure attractive long-term con-tracts because of the high uncertainty aroundfield production.

2Cost back value pricing uses a price equation based onthe actual price collected from end users.

388 18 An Overview of International Regulatory Experience

4. Setting standards and ensuringtransparency

To enable new entrants to enter the market,transparency around market rules is essential, asis a regulator with appropriate legal authority andindependence from political parties, governmentbranches and industry in order to enforce trans-parency requirements. This includes transparencyaround the terms and conditions for third-partyaccess to networks and disclosure of availablecapacity on networks. It may also include mea-sures to enhance competition and increase marketliquidity in the upstream and downstream seg-ments and, as a result, improve transmission ofeconomic signals between market participants.For example, the regulator can increase upstreamcompetition through the design and implemen-tation of licensing and fiscal regimes usingmeasures such as allowing trade in upstreamlicences or setting beneficial fiscal terms forexploration and production. The regulator canalso standardise trading arrangements in down-stream wholesale markets, for example through anetwork code or other guidelines that help buildtrust among market participants, or by standard-ising contracting arrangements to support thecreation and development of a natural gas hub.

The regulator can also promote the use ofmarket centres, such as in the case of Henry Hubin the United States and the National BalancingPoint (NBP) in the United Kingdom. In theUnited States, FERC has supported the devel-opment of market centres by requiring marketplayers to provide certain services and by stan-dardising trade arrangements. In the UnitedKingdom, a virtual hub, the NBP, emerged as aresult of the Network Code in 1996, whichrequired a location where its balancing mecha-nism could be implemented by the regulator. TheCode was complemented by a set of natural gastrading arrangements that established contract

standards, allowing parties to trade natural gaswith confidence in contracts.

5. Protecting end users

To maintain a competitive natural gas market,regulatory oversight needs to include a compe-tition authority and provisions for managingimpacts on end users. A competition authoritywould be responsible for ensuringwell-functioning markets that provide end userswith the greatest choice of suppliers at the lowestprice. It could also protect consumers, powergenerators and industrial users that may be dis-proportionally or inequitably affected by anymarket reform or resulting market outcome.

Consumer and end-user protection requiresthe appropriate legal, financial and politicalsupport. In the United States, from the 1950suntil the late 1970s, consumer protection and, byextension, welfare distribution influenced pricesetting for natural gas. However, policies toprotect consumers and other end users should bedisconnected from the gas market liberalisationprocess. In the long term, liberalised marketsgenerate competition that drives down costs forconsumers and delivers sustained low prices.During the transition period, as natural gasmarkets liberalise, social welfare and equityconsiderations may result in additional supportbeing provided to the most exposed sections ofsociety and sectors of the economy. The mosteconomically efficient approach would be toallow natural gas markets to liberalise, includingprice deregulation, and to provide income orother support separately to consumers and endusers, for example using social welfare paymentsor lump sum subsidies. Such an approach wouldnot interfere with the efficient functioning of thenatural gas market, while ensuring that the mostvulnerable businesses and individuals areprotected.

18.2 Market Liberalisation 389

18.2.2 Political and Economic Factorsof Market Liberalisation

The sequencing and timing of liberalisation issignificant, and international experience suggestsa sequence of reforms that includes key mile-stones and potential points of tension (Fig. 18.3).

Initially, vertically integrated incumbents tendto supply all or most natural gas, acting as themonopoly producer and supplier of natural gas.Supply and demand are unresponsive as there isno free price formation that enables transmissionof economic signals. The first step of the liber-alisation process is to create a natural gas law andestablish a natural gas regulator to implementmarket reforms, including open access to theexisting infrastructure and networks for thirdparties.

Alongside measures to encourage newentrants and facilitate greater competition in theupstream and downstream markets, the liberali-sation process requires that a start is made onderegulating prices to that they reflect marketsupply and demand conditions, for examplewholesale markets moving from simple cost-pluspricing to more responsive approaches, such asnetback pricing. For midstream infrastructure,network charges need to balance increasedthird-party access with incentives to invest in

maintenance and new network capacity. In theinitial stages of liberalisation, incumbents tend tobattle to retain their market power, by putting upbarriers to entry, contesting regulatory interven-tions and retaining their long-term contracts.They may also withhold crucial information fromthe market, such as the capacity available on theirnetworks and information on terms and condi-tions of third-party access.

The next step in the liberalisation process is toincrease market transparency, for example byrequiring network owners to disclose networkcapacity and the terms and conditions for access.In addition, at this stage the regulator mayintervene to break up long-term contracts held byincumbents with suppliers and customers. A ma-ture market is one with a strong regulator that canensure and secure competitive market outcomesand a diverse set of players across the valuechain. These players include some integratedfirms, but also new entrants, such as pure naturalgas shippers, marketers and brokers. If liberali-sation is extended to cover distribution networks,natural gas retailers may also emerge to competefor smaller end users. Building on this, the nextstep would be the establishment of standardisedtrading arrangements, a balancing mechanismand service requirements to support the devel-opment of market centres or hubs as platforms to

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390 18 An Overview of International Regulatory Experience

trade short-term contracts. This allows marketliquidity to build and economic signals to betransmitted between the demand and supply sidesof the market.

As the market matures, the emphasis of reg-ulatory oversight shifts to end-user protectionand the competition authority takes on the role ofensuring fair competition. The focus of policyalso shifts to mitigating undesirable impacts ofthe reforms on end users.

However, a key observation from the casestudies is that the reform of natural gas markets isa lengthy and difficult process and is likely to failif the political context, fundamentals and ancil-lary policies are not aligned favourably. TheUnited States in the 1970s and 1980s exemplifiesa context conducive to natural gas market reform.At the time, there were many upstream producersand network infrastructure was well developed.In addition, there was strong political pressure tomake the market more efficient, especiallydownstream wholesale and retail markets, fol-lowing the failure of natural gas supply torespond during the 1970s oil crisis. Similarly, inthe United Kingdom in the 1980s, the politicaland market context were conducive to reform.The conservative government of MargaretThatcher strived to resolve poor governmentfinances by privatising publicly owned indus-tries, including vertically integrated electricityand natural gas companies. Further, the govern-ment allowed natural gas to be used in powergeneration, an opportunity for investors becauseof the emergence of cost-effective combined-cycle natural gas turbine technology.

On the other hand, liberalisation processes inthe European Union, Japan and South Koreaprovide examples of protracted and incompleteefforts to open up the natural gas value chain.Even today, the European Union faces politicalopposition in its attempt to liberalise continentalnatural gas markets, a process that began in 1998.Opposition focuses on concerns over supplysecurity as a result of greater import dependence,as well as over ownership of infrastructure that isin the national interest. Increased global tensioncentred on Russia, Europe’s main natural gassupplier, and the Ukraine illustrates the risk.

Recently announced proposals for a EuropeanEnergy Union seek to balance these concernswhile continuing to push for greater liberalisationof natural gas markets.

Similarly, in Japan, energy security consider-ations following the 2011 Fukushima nucleardisaster have caused a setback to the liberalisa-tion process, driving towards more co-operation,rather than competition, among the regionalmonopoly suppliers in securing long-term LNGcontracts. However, in 2014, further liberalisa-tion appears to have returned to the agenda.South Korea has also faced difficulties over thepast two decades as it tried to liberalise its naturalgas markets, largely because of the power of theKOGAS labour union and reluctance by KOGASto give up its buying power on world LNGmarkets.

18.2.3 The Impact of MarketLiberalisationon Domestic Mining

The experience of countries with significantdomestic natural gas resources, such as Norway,The Netherlands, the United Kingdom and theUnited States, has been for market liberalisationto drive greater development of these resources.These countries have tended to liberalise earlierand more comprehensively than countries with-out significant domestic natural gas resources.Before liberalisation, upstream exploration andproduction tended to be dominated bystate-owned vertically integrated monopoly pro-ducers. Opening the sector to competition helpeddrive greater efficiency and innovation in explo-ration and production of natural gas, reducingcosts and facilitating the development of greatervolumes and sources of domestic supply, as seenin the European Union. In addition, access tomidstream infrastructure and competitive whole-sale and retail markets have attracted new entrantsand fostered greater competition in upstreamexploration and production. With such access,new upstream entrants can be confident of beingable to transport natural gas to wholesale andretail suppliers, and eventually to end users.

18.2 Market Liberalisation 391

Liberalisation of the natural gas value chainhas also been supported by favourable upstreamlicensing, fiscal or environmental policies inthese countries. In the United States, privateownership of land and the resources underneathit enabled rapid development of shale natural gasexploration and production. Where resources areowned by the government, such as on the outercontinental shelf of the North Sea in Norway,The Netherlands and the United Kingdom, pro-cesses are in place to enable effective and com-petitive leasing of exploration and productionrights. For example, licensing arrangements inthe United Kingdom are designed to encourageexploration and production and penalise hoard-ing; UK licences can be taken away if companiesdo not follow the work programme proposed intheir bid for exploration and production rights.The Netherlands developed its large Groningennatural gas field through a 50:50 public-privatepartnership arrangement, which provides asteady income stream to encourage new entrantsand greater investment in upstream explorationand production, while also ensuring that theinvestments were economic and competitive.Specific fiscal incentives and other support poli-cies are also provided, such as in the UnitedKingdom, to incentivise exploration and pro-duction in more-challenging areas.

18.2.4 Market Liberalisationand Ancillary Policies

There are many interactions between liberalisedgas markets and ancillary policies. Ancillarypolicies, relating to the environment or to tech-nology development, affect the evolution ofnatural gas markets. Analysis of the case studiesshows that while some of these interactions havebeen anticipated, others have been unpredictable.

Environmental policies—such as the USClean Air Act Amendments in the 1990s, themore recent US Environmental ProtectionAgency carbon emission standards, the EuropeanUnion’s emission trading system to price incarbon emissions, and the EU air quality direc-tives and regulations—can increase the costs of

emissions-intensive coal relative to natural gas.While ambitious policies on climate change andair quality favour gas over coal in electricitygeneration, the design of these policies couldproduce some unintended consequences. Thishas been the experience in the European Union,where the interaction between climate policy andenergy markets has undermined environmentalobjectives and led to the coal-renewables “energyparadox”.

While the European Union has an overalltarget to reduce greenhouse gas emissions by20% by 2020 over the 1990 level, it also has aseparate target for a 20% share of renewables inthe energy mix by 2020. The separate renewablestarget and the large subsidies provided to achieveit have dampened wholesale energy pricesbecause of the low—and at times negative—marginal cost of renewables. This has, in turn,reduced incentives to invest in back-up fossil fuelcapacity, which is required to compensate for thepotential of intermittent supplies from renewablesources. Moreover, flaws in the design andimplementation of the EU Emissions TradingScheme—the European Union’s primary mech-anism for meeting its overall greenhouse gasemissions target—combined with recent weakeconomic conditions and the relatively low priceof coal, have shifted the energy mix towards coaland renewables at the expense of natural gas.

These unintended consequences of energy andclimate policies have undermined the profitabil-ity of power suppliers and destabilised theirbusiness models. The problem is illustrated bythe challenges faced by companies like E.ONand RWE in Germany, whose marginal costpricing-based business model has been put at riskas subsidised and distributed sources of renew-able energy of significant size enter the energymix. Going forward, Europe renewables arelikely to remain a significant part of the energymix to 2030 if Europe is to meet its climatepolicy ambitions, and electricity market regula-tion will need to evolve alongside climate poli-cies. In turn, this will have knock-on impacts fornatural gas demand and markets.

The natural gas market has also benefitedfrom ancillary interventions, such as

392 18 An Overview of International Regulatory Experience

energy-related research and development supportand subsidies. This has been particularly signif-icant in the context of US shale natural gasdevelopment. Various research and developmentprogrammes related to unconventional naturalgas were set up by the US Energy Research andDevelopment Administration in the 1970s andcontinued by the Department of Energy. Theseprogrammes, along with other research anddevelopment programmes, such as those centredon microseismic fracture monitoring, haveproved instrumental in driving the US shalenatural gas boom of the last decade.

18.3 Case Studies of Natural GasMarket Liberalisation

Careful study of individual national natural gasmarkets makes clear the precise nature of themarket liberalisation that has occurred as the

natural gas value chain has developed. Eachmarket’s liberalisation has its own characteris-tics, but the ultimate goal is always to establish amore vibrant natural gas system that supports thenation’s strategic goals. Understanding thedevelopment of these markets can provide valu-able reference points as China formulates itsenergy system objectives.

18.3.1 Case Study 1: United States

The development of a dynamic and competitivenatural gas market in the United States (Fig. 18.4)reveals three main phases of regulation. Thesephases are set against a backdrop of events, suchas the shale natural gas boom and key regulatorychanges, as well as varying levels of gas supplyand gas prices between 1960 and 2013.

The pre-liberalisation phase was marked bygradually increasing levels of regulation over

Indigenous production Net pipeline imports

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Fig. 18.4 Phases, development and key regulations in the establishment of a liberalised natural gas market in the US,1978–1992. Note Nominal natural gas prices paid at power plant, national currency converted to average GDPpurchasing power parity. Source Vivid Economics, based on IEA data

18.2 Market Liberalisation 393

15 years, which began as early as 1938 andreached full wellhead price regulation in 1954.These price controls were justified on the basis ofthe perceived natural monopoly characteristics ofthe natural gas value chain, warranting heavystate intervention to protect consumers fromabuse of market power. These interventionsechoed earlier interventions in the oil value chainto counteract the anti-competitive practices ofStandard Oil and other companies. The pricecontrols suppressed investment and led to sig-nificant supply shortages, particularly during the1970s oil crisis, which were only ameliorated bythe subsequent recession.

In response, a new market authority, FERC,was established and several orders to reform themarket were enacted from 1978, marking thestart of a period of liberalisation. The reformsunbundled the natural gas industry, separatingtransportation and sales businesses, and ensuredopen access to interstate pipeline infrastructurefor third parties. By 1992, after 14 years, theliberalisation programme had largely been com-pleted. The post-liberalisation phase saw theenactment of various orders to refine theunbundling and open access arrangements, butthe fundamentals for a competitive and efficientmarket had been established and they supported a40% increase in natural gas consumption fromaround 500 billion m3 in 1990 to 700 billion m3

by 2010.

1. Before market liberalisation

The natural gas market in the United Statesstarted in the early 1900s. Before then, naturalgas produced from coal was used locally. In theearly 1900s, the discovery of large natural gasbasins in the Southwest triggered the construc-tion of large-scale natural gas transmission net-works to reach the population and industrialcentres of the United States. Vertically integratedcompanies started selling natural gas from basinsin the Southwest to end users on the East Coast,the Mid-Atlantic Coast and the West Coast.

A 1935 Federal Trade Commission investi-gation found high levels of market concentrationand abuse of market power by vertically

integrated companies in the exploration, pro-duction and transportation of natural gas. Inresponse, the Gas Act of 1938 established theFederal Power Commission (FPC) to regulateinterstate pipelines and ensure “just and reason-able” wholesale prices. Regulation of intrastatepipelines was left to state regulators. Any pur-chase of natural gas for interstate transport andsale to a local distributor now required a certifi-cate from the FPC, which set a maximum pricefor the natural gas. This price allowed pipelinecompanies to recover some of the costs incurredin pipeline construction and operation. Theexploration and production of natural gasremained exempt from federal regulation: well-head prices remained unregulated. The final saleprice to end users was also unregulated. The FPCfurther gained authority to approve the con-struction and operation of facilities and the pro-vision of services used in interstate natural gastransmission.

The industry defended deregulated wellheadprices provided for under the 1938 Gas Act.However, by the 1950s, consumer groups werechampioning a system of regulated prices forboth producers and pipelines based on the per-ceived natural monopoly characteristics of natu-ral gas supply and fear of market power abuseamong vertically integrated companies. Thisdebate culminated in the Phillips Decision, whichestablished full wellhead price control byextending the powers of the FPC to “the rates ofall wholesales of natural gas in interstate com-merce, whether by a pipeline company or not andwhether occurring before, during, or after trans-mission by an interstate pipeline company.”

Throughout the 1950s and 1960s, the FPCstruggled to find a satisfactory methodology forsetting wellhead rates. Following the PhillipsDecision, the FPC initially aimed to establish acost-of-service rate for wellhead natural gas foreach producer. It was administratively challeng-ing and a large backlog developed, complicatedby the wide variety of producers, contract typesand cases. In 1960, the FPC adopted an averagedapproach based on a regional pricing strategy,setting provisional price ceilings based on theaverage costs of exploration and development in

394 18 An Overview of International Regulatory Experience

24 producing regions. There were many hurdles,including a wide variety of production cost pro-files within the established regions, and as aresult the process was protracted and it was notuntil eight years later, in 1968, that the firstpermanent price was established.

This approach to setting prices led to signifi-cant natural gas shortages in the 1970s. Risingenergy prices, particularly during the oil crisis,led to increased demand for comparativelyinexpensive natural gas. Unfortunately, as aresult of wellhead price regulation, there was noincentive to invest in exploration and productionand, as a result, the supply response was verylimited. Significant shortages prevailed by themid-1970s, and often supply was curtailed forsome customers and new customers were refusedconnections. The Southern states were theexception to these shortages: consumers in thesenatural gas-producing states remained able tosource the natural gas they wanted because theseintrastate markets were not subject to interstatewellhead price controls.

2. Market liberalisation

The Natural Gas Policy Act of 1978 sought toimprove the functioning of natural gas marketsby phasing out price controls and establishing anew natural gas market regulator, FERC. TheUnited States had found itself vulnerable to theoil crisis, partly because of the way it regulatedupstream wellhead and interstate pipeline pricesof natural gas. The new act sought to increasesecurity of supply by improving incentives toinvest in indigenous natural gas production. Italso aimed to establish a single national naturalgas market, with producers allowed to choosetheir own wellhead prices. Producer marketpower would be addressed through competitionwithin this new single market.

The act also established a complex transitionalsystem of escalating wellhead price ceilingsacross more than 30 categories of “old” and“new” natural gas. To encourage new supply, butprevent producers of already-committed naturalgas from benefiting from increasing prices, theact established higher initial price ceilings and an

accelerated schedule of wellhead price decontrolfor new contracted natural gas, which did notapply to old natural gas supplies. The actscheduled the full phase-out of all price controlsby the end of the century. But after just 10 years,regulators reviewed the wisdom of market andregulated prices coexisting for such a long per-iod, and the Gas Wellhead Decontrol Act of 1989hastened the phase-out schedule, dictating that allprice ceilings were to be removed by January 1,1993.

A single market required a single price, so thedifferential inter- and intra-state pricing had to beended. The act replaced the FPC with FERC,which was granted authority over interstate nat-ural gas trade (see box “Overview of the USFederal Energy Regulatory Commission”).

Overview of the United States FederalEnergy Regulatory CommissionThe US Federal Energy Regulatory Com-mission (FERC) was created under the1977 Department of Energy OrganizationAct as a government agency independentfrom political party influence or affiliation,other branches of government and industryparticipants. It has a staff of about 1500and an annual budget of $300 million. It isgoverned by five commissioners, nomi-nated by the president and confirmed bythe US Senate. Each commissioner servesa five-year term, and no more than threecan come from the same political party.The commission operates by majority rule.

In a testament to FERC’s independence,the commission’s decisions are reviewedby a court, rather than Congress or anyother branch of government, and privatediscussions during case proceedings areprohibited. In addition, there is a cleardistinction between FERC authority, com-prising interstate business and infrastruc-ture, and authority held by stategovernments on intrastate business andinfrastructure.

FERC oversees electricity, hydropower, oil and natural gas. Its activities

18.3 Case Studies of Natural Gas Market Liberalisation 395

centre on ensuring that companies withnatural monopolies do not misuse theirmarket positions, and its regulatory objec-tives include:

• preventing discriminatory or preferen-tial service;

• preventing inefficient investment andunfair pricing;

• ensuring high-quality service;• preventing wasteful duplication of

facilities;• acting as a surrogate for competition

where competition does not or cannotexist;

• promoting a secure, high-quality, envi-ronmentally sound energy infrastruc-ture through the use of consistentpolicies;

• where possible, promoting the intro-duction of well-functioning competitivemarkets in place of traditionalregulation;

• protecting customers and market par-ticipants through oversight of changingenergy markets, including mitigatingmarket power and ensuring fair and justmarket outcomes for all participants.The primary responsibilities of FERC in

the natural gas industry are regulating therates and services offered by interstatepipeline companies, certifying and permit-ting new pipeline construction and han-dling some closely-related environmentalissues.

The 1978 Natural Gas Policy Act led to risingprices, and an increase in long-term take-or-paycontracts. This moved FERC to intervene in1984 as market conditions drove natural gasprices down, but left buyers paying high pricesunder long-term contracts. Natural gas contractsin the 1970s were typically multi-year purchas-ing agreements with take-or-pay clauses obligingbuyers, including interstate pipelines and localdistribution companies, to pay for a contract

volume, whether or not they took the natural gas.The contracted sales allowed upstream compa-nies to recover their investments in explorationand production and provided buyers with a hedgeagainst further expected price increases as aresult of shortages.

For a few years following passage of the act,many contracts tied prices to the escalating reg-ulated price ceilings. This became problematic inthe early 1980s, when natural gas demand andpetroleum market prices declined under prevail-ing market conditions, diverging from the priceceilings. As a result, some buyers were lockedinto long-term contracts under which they werepaying prices far above spot market prices. In1984, FERC Order 380 alleviated the burden oftake-or-pay contracts by eliminating minimumbill obligations for local distribution companies.The minimum bill represented the amount ofnatural gas that had to be paid for whether or notthe natural gas itself was received. However,although local distribution companies werereleased from this requirement, pipeline compa-nies remained locked into take-or-pay contractswith natural gas producers.

In 1985, FERC moved to unbundle pipelineand sales services with Order 436, introducingvoluntary third-party access to interstate pipe-lines. This unbundling of transportation and salesservices enabled alternative sales arrangements tothe merchant package, or the sale of natural gasplus its transportation, which had traditionallybeen offered to local distribution companies. Theorder provided incentives to interstate pipelinecompanies to offer standalone transportationservices, in the form of blanket certificates thatallowed them to engage in new activities such asopening new facilities without prior authorisationfrom FERC. Third-party access to pipelinesremained voluntary and was to be offered on thebasis of negotiated rates. The order did notaddress open access to other services, such asstorage facilities. The changes to voluntarythird-party access did not resolve the high cost oftake-or-pay contracts of the 1970s, which stillhaunted pipeline companies. These wereaddressed by FERC two years later, by Order500, which allowed interstate pipeline companies

396 18 An Overview of International Regulatory Experience

to shift some of the take-or-pay liabilities to otherbusinesses in the value chain, leading to thevoluntary renegotiation of most remainingliabilities.

FERC Order 636 of 1992, known as theRestructuring Rule, marked the final stage ofnatural gas market liberalisation, fully imple-menting the third-party access regime. The orderrequired interstate pipeline companies to unbun-dle their sales and transportation services,ensuring that natural gas of other suppliers couldreceive the same level of service as previouslyenjoyed by the pipeline company’s own naturalgas sales. It diminished the market power ofpipeline companies and increased competitionamong natural gas sellers.

The major provisions of Order 636 were:

• A requirement that interstate pipeline com-panies provide open access to transportationand storage services that are equal in quality,regardless of whether the natural gas is pur-chased from the pipeline company or else-where. This included a provision forcompanies to create an internal firewall toprevent exchange of information betweenmarketing and transportation divisions. It alsoincluded provisions for legal unbundling,requiring companies operating pipelines,storage and LNG facilities to restructureproduction and marketing branches asarm’s-length affiliates and cease all-merchantservices.

• Encouragement of market centres whereseveral pipeline systems interconnect,including mileage-based rather thanfixed-tariff or “postage stamp” rate setting fornatural gas transportation.

• Establishment of a capacity release market intransportation and storage, with a requirementfor pipeline companies to maintain electronicbulletin boards to provide information aboutavailability of services on their systems.

• Redesign of regulated rates for pipelinetransportation, shifting all fixed-cost recoveryonto firm customers with a daily capacityreservation and not onto interruptible cus-tomers without a daily capacity reservation.

Variable costs were to be recovered through ausage fee based on the natural gas trans-ported. This was intended to eliminate anydistortions in purchasing behaviour inresponse to the previous design, which allo-cated certain fixed costs to the usage fee.

• Requirement for pipeline companies to offer“no notice” firm transportation services tolocal distribution companies, allowing cus-tomers to receive natural gas on demand up totheir maximum contract level.

Order 636 represented a watershed moment inUS natural gas market development. It intro-duced competition among natural gas suppliersand greater efficiency in the use of natural gasindustry infrastructure. The industry restructuringwhich began with voluntary third-party accessunder Order 436 and led to mandatory unbund-ling under Order 636 fundamentally changednatural gas transportation rates and patterns.According to the US EIA, the higher level offlexibility and resulting increased competitionamong natural gas suppliers “has contributed tochanges in regional production, transportation,and consumption patterns, and to greater effi-ciency in the use of the natural gas industryinfrastructure.”

As a result of the new regulatory regime,entities purchasing at the wellhead can negotiatefor spot, short-term and long-term contracts atvarious rates. The market can operate with firmand interruptible delivery of spot natural gas on acontract-by-contract basis rather on the previ-ously prevailing long-term contract obligations.The electronic bulletin boards facilitate offers andbids for natural gas and for pipeline space.Marketers and brokers trading on spot andfutures markets collectively clear the market,with higher prices leading to increased wellheadand pipeline capacity supply.

3. The impact of market liberalisation

Liberalisation of the US natural gas markethas created a system with unique characteristics.

In the upstream market, regulation of explo-ration and production is mostly within the

18.3 Case Studies of Natural Gas Market Liberalisation 397

jurisdiction of states, and therefore highlydiverse. At the end of 2013, the United Stateshad 9.3 trillion m3 of proved natural gasreserves, and a wide range of state regulatoryprovisions covering licensing, ownership andsafety and the environment of exploration andproduction across the country.

Key elements of upstream regulation in theUnited States are:

• Ownership of resources resides with owner-ship of land. In the United States, land ismostly owned by private entities. Onshoreand offshore resources owned by the federalgovernment are governed by the Departmentof the Interior and the EPA, which controland administer leases, revenues, land useplanning and environmental standards.

• States generally have regulatory commissionsthat deal with all aspects of the energy valuechain within the state. Development of pri-vately owned and federal resources needs tocomply with state regulations on safety andthe environment to ensure that resourcedevelopment is safe and environmentallyresponsible and therefore in the publicinterest.

• Exploration and production rights for federalresources are auctioned to private entities onan open and competitive basis once land useplanning has been determined. Prospectivelease holders bid for exploration and pro-duction rights. They pay an initial bonus, andthen rent for the right to develop the resour-ces. Leases are valid for 10 years or as longas there is at least one producing well.

In terms of regulation of midstream assets,FERC has continued to refine the regulatoryframework since 1992 to promote market effi-ciency and increased levels of competition.Notable further improvements in setting rates andregulating unbundling include:

• In 1999, FERC published a cost-of-servicemanual, listing transparent guidelines forFERC’s determination of allowable projectcost recovery by pipeline companies on the

basis of a reasonable rate of return, operatingand maintenance costs, depreciation chargesand tax recovery mechanisms. This rate ofreturn regulation is a general model for thetreatment of natural monopoly utilities,including pipelines.

• The 2000 FERC Order 637 refined andupdated pipeline transport regulations relatingto rates, including the suspension of pricecaps on capacity release sales of less than oneyear, to achieve a greater transparency andefficiency in the use of pipeline services.

• FERC’s Hackberry Decision of 2002 estab-lished that LNG import terminals would beexempt from open access requirements toencourage more LNG site development. Itallowed the owner of the Hackberry LNGterminal to agree to terms of use with itsaffiliates rather than under regulatedcost-of-service rates. This effectively definedLNG terminals as an upstream supply source,part of the competitive sector, rather than partof the natural monopoly transportation chain,with individual project approval dependingon FERC assessment of the general need forthe project as well as its economic and envi-ronmental impacts.

• The 2003 FERC Order 2004 introduced newfunctional unbundling regimes applicable toboth electricity and natural gas industries,requiring that marketing, transmission andaffiliated energy employees of electricity andnatural gas companies function indepen-dently. The order established the Office forMarket Oversight and Investigations tomonitor the implementation of functionalunbundling, which has since been absorbedinto FERC’s Office of Enforcement.

• The 2008 FERC Order 717 further reinforcedfunctional unbundling. It included specificprovisions for the physical separation offacilities and staff, for example the separationof occupational functions, which meant thatemployees can be responsible for work onmarketing or on transport, but not both.

Downstream policy is generally subject tolocal regulations, and remains inconsistent across

398 18 An Overview of International Regulatory Experience

states. For example, intrastate natural gas com-merce is subject to state regulation, and retailunbundling is at the discretion of the state regu-lator. Only four jurisdictions—New Jersey, NewYork, Pennsylvania and Washington, DC—haveunbundled retail markets. Unbundling is deliv-ered by means of natural gas residential choiceprogrammes in these four jurisdictions. The res-idential choice programmes allow consumers topurchase the components of natural gas supplyseparately, rather than relying on the bundledproducts offered by a single local distributioncompany.

The regulatory framework has ensured thatpipeline companies transport natural gas, but nolonger buy and sell it, so they cannot abusemarket power based on the natural monopolycharacteristics of pipeline infrastructure. This hasenabled the construction of 305,000 miles oftransmission pipelines and the establishment of ahigh number of competing market participants.The US interstate and intrastate transmissionnetwork comprised more than 210 separate

pipeline systems (Fig. 18.5). This system issupported by ancillary infrastructure, including1400 compressor stations, 24 hubs or marketcentres, 400 underground storage facilities, 49pipeline import and export locations, eight LNGimport facilities, and 100 LNG peaking facilities.This has also enabled competitive markets in theupstream and downstream segments. It has led to6300 natural gas producers producing from morethan 480,000 wells, including 21 companiesconsidered major producers. There are 160 dif-ferent pipeline companies, 123 storage operatorsand 1200 local natural gas distributioncompanies.

The liberalisation process, particularly the1992 FERC Order 636, created the conditions forthe rapid growth of natural gas trade throughmarket centres such as Henry Hub as pipelineinfrastructure improved and competitionincreased. Henry Hub, a physical trading hub insouth Louisiana, has emerged as the mostprominent market centre, with spot and futurecontract prices based on competitive natural gas

Legend

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= Intrastate pipelines

Fig. 18.5 US natural gas transmission pipelines. Note Data for 2009. About two thirds of the length is interstatetransmission pipelines. Source US EIA

18.3 Case Studies of Natural Gas Market Liberalisation 399

pricing rather than oil indexing. It was estab-lished by Sabine Pipe Line LLC, a subsidiary ofChevron, in 1989. In 1990, the NYMEX selectedHenry Hub as the basis of its natural gas con-tracts because of its central location and liquidity.Henry Hub now sets the benchmark price for theentire North American trading area. It hasemerged as the most liquid natural gas market inthe world, trading more than 100,000 natural gascontracts a day, compared to 918 contracts on itsfirst trading day. The scope of NYMEX futurescontracts has extended from terms of up to threeyears in 1997 to up to 10 years at present.

Other hubs have emerged since, such as Opalin Wyoming, where price differentials comparedto Henry Hub are determined by regional dis-parities in production and transport costs. Thearbitrage opportunities between regional hubprices drive investment in pipeline capacity.Notably, the recent shale natural gas boom hasled to trade volumes shifting to hubs that arecloser to shale natural gas fields, such as theDominion South hub, a key supply point in the

Marcellus shale in southwest Pennsylvania. Thiscould result in a fundamental shift of the mainprice reference point in the United States awayfrom Henry Hub.

The liberalised regulatory framework hasenabled the market to transmit economic signals,and encouraged the rapid expansion of shalenatural gas production once extraction technol-ogy became competitive. On the supply side,price signals led to a surge in shale natural gasproduction since the mid-2000s. Once drillingand hydraulic fracturing technologies werecost-effective, many firms adopted the technol-ogy and secured acreage. Economic growth andprice hikes of substitute fuels led to rising naturalgas prices in the 2000s and, in response, heavyinvestment in shale natural gas drilling byincumbents and new entrants alike. On thedemand side, market liberalisation coincidedwith increasing levels of natural gas consumptionthroughout the economy (Fig. 18.6). Theincrease was greatest in electricity generation,where natural gas competes directly with

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400 18 An Overview of International Regulatory Experience

alternative fuel inputs, especially coal, but alsonuclear and renewables. Increased shale naturalgas supply and falling natural gas prices led to arapid increase in natural gas use for electricity inthe last decade.

4. Ancillary policies

The natural gas market has not only benefitedfrom the regulatory framework directly govern-ing it, but also from ancillary intervention,including research and development subsidiesand environmental policy.

On the supply side, various research anddevelopment programmes related to unconven-tional natural gas were set up by the US EnergyResearch and Development Administration in the1970s and continued by the Department ofEnergy. These have been important for shalenatural gas development. Other research anddevelopment programmes, such as those centredon microseismic fracture monitoring, have alsocontributed to shale natural gas development.Fiscal incentives including tax credits for theproduction of unconventional fuels under theCrude Oil Windfall Profits Tax Act of 1980further enhanced the financial viability of shalenatural gas extraction.

On the demand side, the competitiveness ofnatural gas compared to substitute fuels—mainlycoal—is a key driver. Emission standards, suchas those imposed under the Clean Air ActAmendments (“CAAA”) of 1990, improved thecompetitiveness of natural gas relative to coal.With effect from 1995, 110 power plants wererequired to surrender CAAA emissions allow-ances. The programme was extended in 2000.More recently, in June 2014, the EPA proposed anew plan to cut carbon emissions from powerplants, which is likely to further improve thecompetitiveness of gas.

18.3.2 Case Study 2: Europe

Liberalisation of the natural gas market in theEuropean Union began as part of the creation ofan internal energy market with the First Gas

Directive in 1998. Regulatory efforts in theEuropean Union have evolved over decades,passing through various milestones (seeFig. 18.7).

In 1988, the European Union articulated thegoal of creating an internal energy market. It thentook a decade for the European Commission(EC) to draft legislation that was acceptable tomember states. The First Gas Directive passed bythe European Parliament in 1998 includedrequirements for third-party access and unbund-ling, although these provisions had been muchdiluted in negotiations during the precedingdecade. The Second Gas Directive, adopted in2003 and complemented by further regulation in2005, focused on implementation of third-partyaccess and unbundling provisions introduced inthe First Gas Directive. This was achievedthrough strengthening market oversight across allmember states, allowing market authorities toestablish cost-of-service tariffs for monopolisticinfrastructure, and other mandates. The ThirdGas Directive, commonly known as the ThirdPackage, was passed in 2009 and focused onincentivising infrastructure development, pro-viding for stricter unbundling, network planningand supply security. Despite the provisions of theThird Package, the European natural gas market—apart from the United Kingdom market—isnot yet fully liberalised.

1. Before market liberalisation

Similar to the US experience, before liberali-sation most EU member states had blanket reg-ulatory regimes that treated the entire natural gasvalue chain as a natural monopoly. The naturalgas industry structure in each country was similaracross the bloc, with the upstream segment of thevalue chain often dominated by one or a fewstate-owned, vertically integrated natural gascompanies engaged in exploration and produc-tion as well as transportation and sales. Thedownstream segment was dominated by localdistribution companies, which controlled distri-bution and retail monopolies.

As state-owned enterprises, these verticallyintegrated national natural gas companies had

18.3 Case Studies of Natural Gas Market Liberalisation 401

little incentive to improve the efficiency of theiroperations, which led to increases in natural gasprices. Natural gas markets were governed bynational law and were generally exempt from EUcompetition law, which granted special status topublic natural gas companies on the basis thatapplication of competition rules might obstructthe supply of natural gas. The national lawsgoverning public natural gas companies withinmember states were generally based on similarprinciples, including exclusive rights to build andoperate networks, prohibition of entry, verticallyintegrated operations, compensation on the basisof historical costs and a high degree of centralplanning.

2. Establishing energy policy objectives

The EC established the creation of an internalenergy market as a policy goal in 1988. Theinternal market is a foundational principle of theEU, codified in the 1986 Single European Act,and aims to facilitate the free movement ofgoods, persons, services and capital, with com-petitive markets in all sectors. Although notexplicitly part of the Single European Act, acompetitive energy sector was deemed a pivotalelement in a well-functioning internal market: acompetitive energy sector, and the associatedenergy cost reductions, contributes directly toimproved competitiveness of European

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Fig. 18.7 Phases, development and key regulations in the establishment of a liberalised natural gas market in Europe,1971–2013. Note Nominal natural gas prices paid at border, national currency converted to average GDP purchasingpower parity; the average German import price and United Kingdom NBP prices have followed similar paths, apartfrom a more pronounced drop in the United Kingdom price as a result of the 2008–09 economic recession; TPAThird-party access. Source Vivid Economics, based on IEA data

402 18 An Overview of International Regulatory Experience

industries. This position was elaborated in a 1988EC green paper, The Internal Energy Market,which set out procedures for the creation of aninternal energy market, including harmonisationof rules and technical norms, the opening up ofpublic procurement markets and the removal offiscal barriers.

The EC then set out to develop severaldirectives3 targeting a common carrier system,under which consumers could purchase naturalgas from any supplier, regardless of the owner-ship of pipeline infrastructure. However, thedirectives faced strong opposition in the Councilof Ministers, and the EC had to change itsapproach to a more staged, bottom-up approach.Complex negotiations ensued, and in 1993 theEuropean Parliament took an active role infinding a compromise that was acceptable to boththe EC and the Council. The development of thefirst Electricity Directive was given priority overa directive covering natural gas. The ElectricityDirective was adopted in 1996, with provisionsfor electricity market liberalisation.

3. The beginning of market liberalisation

The First Gas Directive was adopted in 1998.It established a framework for liberalisation formember states, with provisions for third-partyaccess and account unbundling. The directivesought to create a single internal market fornatural gas in the European Union, but was asignificantly diluted version of the initial ECproposals for a common carrier system. Memberstates were left free to choose their preferred paceand regulatory measures for natural gas marketliberalisation.

The directive required owners of naturalmonopoly infrastructure, including transmissionnetworks, storage and LNG facilities, to provideopen access to third parties. However, memberstates could still choose between negotiated and

regulated third-party access.4 Vertically inte-grated companies were required to separate theaccounts of natural monopoly infrastructure andsales businesses, but not necessarily to realisefull functional unbundling. The directive furtherprovided that power generators and end usersconsuming more than 25 million m3 of naturalgas a year should be able to choose theirsuppliers.

The concessions made for political reasons inthe First Gas Directive hindered the opening ofnatural gas markets. The Madrid Forum, anannual meeting of natural gas market stakehold-ers, was established in 1999 with a remit toidentify further harmonisation needs. With 9 outof 15 member states planning to open their nat-ural gas markets fully by 2008, the EC moved toadopt the Second Gas Directive in 2003 andcomplementary regulations in 2005, establishingrequirements for cost-of-service calculations andmarket oversight by regulatory authorities toexpedite the creation of an internal energy mar-ket. This time, a new electricity sector directivewas adopted alongside the Gas Directive.

The main provisions of the Second GasDirective were:

• Stronger unbundling: Mandatory functionaland legal unbundling for the transportationand distribution sectors and voluntary func-tional and legal unbundling for storage andLNG facilities, to address issues associatedwith lenient account unbundling in the FirstGas Directive and sluggish development ofthe third-party access regime.

• Stronger third-party access: A right of thirdparties to non-discriminatory access to net-works and LNG facilities, with the aim ofenabling new suppliers to enter the marketand providing consumers with a range ofsuppliers to choose from.

3EU directives have to be transposed into national lawwhereas EU regulations apply directly to market partic-ipants. Both types of EU law—directives and regulations—govern the natural gas market.

4Under negotiated access, network operators are free tonegotiate terms of network use in good faith withprospective users. The main commercial conditions ofthese agreements must be published ex-ante. In contrast,under regulated access the commercial conditions ofaccess are determined by the regulator.

18.3 Case Studies of Natural Gas Market Liberalisation 403

• National regulatory authorities: Mandatoryestablishment of regulatory authorities in allmember states, with responsibility for com-pliance with non-discriminatory networkaccess principles, ensuring appropriate levelsof transparency and competition, setting tar-iffs and the methodology for calculating them,and settlement of disputes. Establishment ofthe Agency for the Co-operation of EnergyRegulators, which co-ordinates the imple-mentation of Gas Directive provisions bynational regulators.

• Principles of network tariff calculation:The establishment of the principles of tariffcalculation for natural monopoly networks.These principles should allow pipeline trans-mission companies to recover costs andreceive a return on investments while at thesame time providing incentives to maintainexisting infrastructure and construct newinfrastructure.

• Exemptions for new infrastructure: Anexemption for interconnectors, LNG andstorage facilities from third-party accessrequirements and cost regulation, subject tovarious conditions, in order to reduce andmitigate risks associated with new infras-tructure build.

4. The Third Package

The 2009 Gas Directive, known as the ThirdPackage, further developed unbundling andopen-access arrangements. It sought to create acompetitive, secure and environmentally sus-tainable market in natural gas. To achieve thesegoals, the Third Package offered member states achoice between ownership unbundling on theone hand and setting up an independent systemoperator (ISO) or becoming an independenttransmission operator (ITO) on the other.The ISO and ITO models are essentially lessstringent forms of unbundling. Unlike ownershipunbundling, setting up an ISO or ITO would letthe transmission network remain under theownership of vertically integrated firms. Underan ISO model, the transmission networks remain

under the ownership of vertically integratedenergy companies, but an ISO would beresponsible for operation and control ofday-to-day business. Investment decisions wouldbe jointly made by the ISO and the owner of theinfrastructure. Under an ITO model, verticallyintegrated energy companies retain ownership oftheir transmission networks. The ITO would be alegally independent joint stock subsidiary oper-ating under its own brand name, with strictlyautonomous management and under stringentregulatory control. Investment decisions wouldbe made jointly by the parent company and theregulatory authority.

The directive recommended ownershipunbundling as “the most effective tool by whichto promote investments in infrastructure in anon-discriminatory way, fair access to the net-work for new entrants, and transparency in themarket”. Nonetheless, it also stated that settingup an ISO or ITO that is independent fromsupply and production interests should enable avertically integrated company to maintain own-ership of network assets while ensuring aneffective separation of interest. The Third Pack-age thereby implied that there is more than oneway to achieve the necessary alignment ofincentives along the gas value chain to delivergas at least cost while still maintaininginvestment.

In addition, the Third Package furtherstrengthened the independence of regulators fromprivate or public interests to achieve equallyeffective regulatory supervision across memberstates. It set out various roles and responsibilitiesfor regulatory authorities, including setting tar-iffs, ensuring that tariffs are non-discriminatoryand cost-reflective, and issuing binding decisionsand penalties in relation to natural gasundertakings.

Finally, the Third Package and complemen-tary regulations focused on providing incentivesfor investment in natural gas infrastructure andensuring security of supply. The Third Packageupheld the exemption from third-party accessrequirements and cost regulation in the SecondGas Directive for particularly risky new infras-tructure, such as cross-border pipelines and LNG

404 18 An Overview of International Regulatory Experience

terminals. It also introduced new requirementsfor long-term infrastructure planning, in terms of10-year network development plans to bedeveloped by transmission network owners andoperators. These plans are to be developed at thenational as well as European level. National-levelplans are binding, and investments by indepen-dent transmission operators over a three-yearhorizon can be enforced by national regulators.The package also allowed member states toimpose public service obligations on entitiesoperating in the natural gas sector, mainly in theareas of security of supply, regularity and qualityof service, price, environmental protection andenergy efficiency. These entities can refuseaccess to their systems if it compromises theirability to meet these obligations.

In 2010, EU regulations further strengthenedsecurity of supply considerations within thecontext of the internal market. The aim of theseregulations was to ensure trade and supply evenunder extreme and emergency conditions. Theregulations put emphasis on infrastructuredevelopment to increase internal natural gasflows and external LNG imports. They providedfor increased co-operation among member states,introduced supply obligations for companies andestablished minimum supply and infrastructurestandards.

The European Union gas directives weakenedstate ownership rights in the natural gas valuechain, especially in terms of wholesale and retail,as well as promoting transnational pipelinedevelopment. Even though the European Union’snatural gas is in the process of being liberalised,and some countries such as The Netherlands andthe United Kingdom have already privatised thenatural gas wholesale business, nonetheless themajority of infrastructure is still in the hands ofthe state so as to ensure undifferentiated treat-ment of third-party access. In contrast to this arethe independent company operations by naturalgas shippers in The Netherlands and the UnitedKingdom. In France and other countries, naturalgas transmission is operated by vertically unifiedcompany subsidiaries, and natural gas transmis-sion companies are very active among thetransnational pipelines.

The relationship between the distribution andretail business is becoming increasingly slack.With regard to transmission, the British distri-bution network is operated by independentcompanies, while France’s is operated by verti-cally unified company subsidiaries. Verticallyunified companies were traditionally the compa-nies building and controlling reserve capabilities,but after market liberalisation took its first steps,all private entities within Europe began devel-oping underground reserve equipment. In addi-tion, Europe’s various merchants have begundeveloping LNG facilities.

At the same time, the European Union’s nat-ural gas market liberalisation and natural gasinfrastructure planning has been extended,resulting in higher natural gas prices and reducednatural gas consumption volumes. Throughstrong natural gas network development and theexpansion of transmission infrastructure mea-sures and plans, the European Union has stimu-lated increases in trade with neighbouringregions, as well as the construction of transna-tional pipelines and LNG terminals.

5. The impact of market liberalisation

Since the 1970s, the European Union’s naturalgas consumption volumes have grown fivefold.However, in the first 10 years of the 21st century,growth stagnated (Fig. 18.8). The recent drop-offin gas consumption has been as a result of therecession and subsequent low economic growthrates, increasing competition from coal andrenewables in power generation, particularlylinked to EU climate policies, rising natural gasprices since the onset of liberalisation, anddiversion of LNG shipments to Asia as demandrose following the Fukushima disaster.

The European Union has a well-developednatural gas network, with plans to expand thetransmission infrastructure to ease increasedtrade with neighbouring regions, includingcross-border pipelines and LNG import terminals(Fig. 18.8). The EC natural gas directives haveled to reduced public ownership within the nat-ural gas value chain, particularly at the wholesaleand retail levels, and increased cross-border

18.3 Case Studies of Natural Gas Market Liberalisation 405

pipeline development. The European Union hasgood natural gas networks, and plans to furtherexpand its gas transmission network to promotenatural gas trade development with regions sur-rounding the European Union. This includescross-border pipelines and LNG import terminals(see Fig. 18.9). The natural gas directives issuedby the European Union have reduced the pro-portion of state-owned assets in the natural gasindustry, especially in the wholesale and retailsegments, which has greatly accelerated thedevelopment speed of transnational pipelines.

As the European Union’s largest natural gasproducers, Norway and The Netherlands com-plemented the liberalisation and increased accessto midstream infrastructure with upstream poli-cies to increase competition. At the end of 2013,Norway had confirmed natural gas reserves of2 trillion m3, while The Netherlands had900 billion m3.

Norway developed its reserves by mandatinga 50% stake for publicly owned Statoil in eachexploration and production licence. The part-nership arrangement enabled Statoil to acquire

exploration and production capabilities to com-plement its operational capabilities. Statoil waspartly privatised in 2001, and the partnershipstransferred to Norway through a newstate-owned company, Norway Oil and GasRevenue Management Company. In 2003, Nor-way began a series of licensing rounds for newproducing areas and further exploration in matureareas on its continental shelf. This has introduceda new set of players to the upstream explorationand production segment.

The Netherlands developed its large Gronin-gen natural gas field through a 50:50public-private partnership. The state expected thisownership structure to lead to rapid developmentof the reserves, while maximising the benefits tosociety. The partnership was based on netbackpricing, with natural gas prices regulated at 65–85% of the price of a basket of fuel oils. Thisarrangement provided a steady income stream toencourage new entrants and greater investment inupstream exploration and production, while alsoensuring that the investments were competitivecompared to alternative fuel sources.

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406 18 An Overview of International Regulatory Experience

6. Ancillary policies

To achieve the energy trilemma goals ofenergy affordability, security and sustainability atthe same time as employing liberalised energymarkets, Europe has a relatively well-developedset of climate and environmental policies.

Under the Kyoto Protocol, in 1997 the Euro-pean Union-155 committed to reducing green-

house gas emissions by 8% by 2008–2012 from1990 levels. (Actual reductions were between 12and 15%.) Since then, it has since adopted a 20%reduction target by 2020 and a 40% target for2030. In addition, wider environmental policies,such as European clean air policies, have playeda significant role in shaping the energy mix in thepower sector. The recently proposed air policypackage sets ambitious air quality objectives for2030.

However, the design and implementation ofclimate policies interacts with electricity markets,affecting the outlook for gas-powered generation.While ambitious policies on climate change andair quality favour gas over coal in electricity

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Fig. 18.9 European Union transnational pipelines and LNG terminal distribution. Source Euronatural gas

5In 2004, prior to the eastern expansion, the EuropeanUnion had 15 member states: Austria, Belgium, Denmark,Finland, France, Germany, Greece, Ireland, Italy, Lux-embourg, The Netherlands, Portugal, Spain, Sweden, andthe United Kingdom.

18.3 Case Studies of Natural Gas Market Liberalisation 407

generation, the design of these policies couldproduce some unintended consequences. Forexample, by setting a separate 2020 target forrenewable energy, the EU Renewable EnergyDirective has dampened wholesale energy prices,since the marginal cost of renewables has beenlow, and even negatives at times. This has, inturn, reduced incentives to invest in back-upfossil fuel capacity, which is needed to com-pensate for the potential of intermittent supplyfrom renewable energy sources. Moreover, flawsin the design and implementation of the EUEmissions Trading Scheme, the EuropeanUnion’s primary mechanism for meeting itsgreenhouse gas emissions target, combined withrecent weak economic conditions and the rela-tively low price of coal, has led to the “energyparadox”: a shift of the energy mix towards coaland renewables at the expense of natural gas.

These unintended interactions between energymarket and climate policies have undermined theprofitability of power suppliers and destabilisedtheir business models. The problem is illustratedby the challenges faced by companies like E.ONand RWE in Germany, whose marginal costpricing-based business model has been put at riskas subsidised and distributed sources of renew-able energy of significant size enter the energymix. Going forward, Europe renewables arelikely to remain a significant part of the energymix to 2030 if Europe is to meet its climatepolicy ambitions, and electricity market regula-tion will need to evolve alongside climate poli-cies. In turn, this will have knock-on impacts fornatural gas demand and markets.

18.3.3 Case Study 3: United Kingdom

From 1986 to 2002, the United Kingdomimplemented natural gas market liberalisation,contributing to the “dash for gas” in the powersector in the 1990s. The process comprised threedistinct phases: pre-liberalisation, liberalisationand post-liberalisation (Fig. 18.10).

The UK natural gas market took off in the late1960s, when domestic coal gas started to bereplaced by natural gas from North Sea basins.

At that time, the newly formed Conservativegovernment had just come to power and wasfacing a weakened economy in 1979. They for-mulated policies to privatise state-owned indus-tries, using this approach to promote investmentwithout requiring actual financial support fromthe government. By selling assets, the revenuescould be used to prop up government finances, toinvigorate business and to weaken the influenceof unions.

In the 1980s during the asset sales, the first setof sales included a vertically unified company—British Gas. After the implementation of the GasAct 1986, British Gas began a process of pri-vatisation, opening access to its pipelines for itscompetitors, and establishing a natural gas reg-ulator, Ofgas. With the new third-party accessagreements, the privatised British Gas was forcedto abandon a portion of the content of its existingnatural gas supply contracts, unbundling thecompany’s business to independent subsidiariesand providing space for entry into the market bycompetitors. The Gas Act 1995 made furtherprogress by promoting retail competition. In1996, the Network Code was implemented,fine-tuning third-party access rules while build-ing a system for managing daily settlements andnational balancing points. In 2002, the newlyestablished settlement mechanisms entered theirfinal stage. In that same year, British Gas sold itstransmission business to achieve complete own-ership rights spinoff. As an independent Britishtransmission operator, Britain’s National Gridestablished a national gas transmission network.Following market liberalisation, because ofexcessive exploration in the North Sea naturalgas fields, domestic natural gas production vol-umes in Britain declined. Further changes aftermarket liberalisation primarily consisted ofalterations to the terms of third-party access,improved settlement agreement efficiency andimproved supply security.

1. Before market liberalisation

In the 1970s, as natural gas supplies continuedto increase, the United Kingdom established astate-owned natural gas company. In the late

408 18 An Overview of International Regulatory Experience

1960s, self-produced North Sea Basin natural gasgradually replaced domestic coal gas, and theUnited Kingdom’s natural gas market began toflourish. The Gas Act of 1972 merged the 12existing area natural gas boards and the GasCouncil to create the British Gas Corporation.British Gas was the sole buyer of natural gasproduced in and around the United Kingdom. Italso held a statutory monopoly on the supply ofnatural gas to end users. The company relied onflexibility in its long-term natural gas purchasingcontracts to provide reliable balancing of inputand output volumes on its network. Natural gaspurchase prices varied greatly as British Gasnegotiated individual contracts with producers.Downstream pricing was based on the weightedaverage cost of these natural gas purchase prices,a margin to cover transportation and distributioncosts, and a profit margin.

In the 1970s, in face of high inflation andunemployment rates, the United Kingdomapplied for loan financing from the InternationalMonetary Fund. Poor labour relations and risingoil prices led to the Winter of Discontent in1978–79, a period of widespread strikes. Mar-garet Thatcher was elected prime minister of anew Conservative government in 1979. Sheimmediately faced difficulty funding the nation-alised energy sectors, which needed to invest tosecure supply. The government developed plansfor the privatisation of the nationalised indus-tries, to generate income and enable newinvestment by the new private entities. At thetime, privatisation was not driven so much by adesire to increase competition as by the imme-diate challenge of government finances thatcould not support the necessary investments inenergy infrastructure.

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Fig. 18.10 Phases, development and key regulations in the development of the British natural gas market. NoteNominal natural gas prices paid at power plant, national currency converted to average GDP purchasing power parity.Source Vivid Economics, based on IEA data

18.3 Case Studies of Natural Gas Market Liberalisation 409

A first move towards privatisation of thenatural gas sector was made with the Oil and Gas(Enterprise) Act of 1982, which removed BritishGas’s statutory right of first refusal on purchasesof upstream natural gas. This effectively openedthe market to third parties, although in reality itremained challenging for new entrants to pur-chase, transport and eventually sell natural gas.

2. Market liberalisation

The Gas Act 1986 introduced real competitionby sanctioning the privatisation of British Gasand requiring third-party access to transmissionand distribution networks. The privatisation ofthe British Gas Corporation led to the formationof the similarly named British Gas Plc, and thenew entity lost its monopoly to supply the largestcustomers: those using more than 25,000 therms(around 730 MWh) of natural gas a year. The actalso obliged the newly incarnated British Gas togrant third-party access to its pipeline infras-tructure. Finally, the act established the firstnatural gas regulator, the Office of Gas Supply orOfgas.

Competition was slow to develop under thenew arrangements. In 1988, a Monopolies andMergers Commission inquiry found that BritishGas’s practices were anti-competitive and thatprice discrimination prevailed. This led to therecommendation that company be barred frompurchasing more than 90% of new natural gas onthe market. The company was also instructed topublish prices charged to industrial and com-mercial customers. The government viewed theinitial stages of natural gas market liberalisationto be a political success, and used it as a templatefor the power sector privatisation that followed in1989 and 1990.

Competition in the natural gas sector wassubject to close government scrutiny in subse-quent years, leading to British Gas being asked in1992 to further reduce its market share to 40% ofthe natural gas market by 1995. The threshold forBritish Gas’s large consumer supply monopolywas further reduced to 2500 therms. British Gasalso undertook to release some of its natural gasunder existing contracts by selling it to other

suppliers. Further inquiry into the company bythe Monopolies and Mergers Commission in1993 resulted in the recommendation that BritishGas unbundle its divisions into separate sub-sidiaries. This took place in 1994. It led to thecreation of Transco, which had responsibility fortransport and storage.

The Gas Act 1995 started a phased introduc-tion of full competition in the natural gas market,including retail competition, which establishedcomplete supplier choice in the market. The actestablished a new licensing system for desig-nated pipeline operators, wholesale companies orshippers, and retail companies. As a result, Bri-tish Gas lost its majority market position. InOctober 1990, British Gas controlled all ofsmall-firm supply and 93% of large-firm supply,but by June 1996 these had shrunk to 43% ofsmall-firm supply and 19% of large-firm supply.

The 1996 Network Code established the rulesand procedures for third-party access to pipelinesand introduced a regime for daily balancing.Transco gained responsibility for securing thephysical balance of the system, capacity plan-ning, the forecasting of demand and distributionarrangements, and the overall operation of thesystem. The code also created the NBP as avirtual location where the transmission systemoperator could balance the system on a dailybasis. The NBP quickly became the UnitedKingdom’s most liquid natural gas transmissionsystem, and was adopted by traders for nomi-nating their buys and sells on a standardisedbasis. This was followed by the introduction ofnatural gas trading arrangements in 1996, whichsimplified natural gas trading procedures. Furthersignificant reforms in 1999 introduced anon-the-day commodity market to help with bal-ancing and to incentivise to Transco to minimiseoverall balancing costs. In 1998, an intercon-nector pipeline between Belgium and the UnitedKingdom was opened, for the first time allowingnatural gas to flow between grids in Britain andcontinental Europe.

British Gas was restructured several times. In2000, it broke up into two companies: BGGroup, holding upstream assets, and Centrica,encompassing a mixture of upstream and

410 18 An Overview of International Regulatory Experience

downstream assets. Transco was sold to NationalGrid in 2002. These combined businesses makeup the United Kingdom’s independent transmis-sion system owner and operator for natural gasand electricity markets (Fig. 18.11). In addition,National Grid owns and operates four distribu-tion networks, as well as the Grain LNG importterminal and the Avonmouth LNG storagefacility.

3. After market liberalisation

The end of the liberalisation phase in 2002was marked by full unbundling of the natural gas

business. It also signalled the successful transi-tion to competitive and liquid wholesale markets:daily balancing by shippers, with penalties forout-of-balance portfolios, and a role for thetransmission system operator to maintain safebalance in the transmission system. In 2005, theUniform Network Code replaced the NetworkCode, adding clarity and detail to enable shippersand the transmission system operator to balancemore effectively. This included identifying typesof capacity held along the natural gas value chainand obliging owners of that capacity to providestock data to the transmission system operator.The Uniform Network Code has continued to be

GAS TRANSMISSION

St Fergus

Aberdeen

Glasgow

To Ballylumford

To DublinBorrow

Warwick

*Milford Haven London Grain LNG

Bacton

Theddlethorpe

Zeebrugge

Holland

Ta/tram

To/fromEardington

From Ormen LangeTeesside

Reception terminal

High pressure gastransmission system(National Grid)

Interconnector

LNG storage

LNG import terminal

Fig. 18.11 National Grid completely owned and operated British transmission networks. Source National Grid

18.3 Case Studies of Natural Gas Market Liberalisation 411

updated and amended over time to improvepractices and ensure the safe and efficient func-tioning of the United Kingdom’s natural gassupply.

More recently, security of natural gas supplyhas emerged as a key priority in the UnitedKingdom. This is governed by several additionalcodes, including:

• the Fuel Security Code (2007), which grantsthe Department of Energy and ClimateChange the option to instruct power stationsto use alternative fuels;

• the National Emergency Plan for Gas andElectricity, which sets out the response toemergency situations—such as supply defi-cits, storage safety breaches, transportationconstraints and the loss of supply to morethan 50,000 customers—and describes theroles and responsibilities of market partici-pants; and

• the Transmission Network Planning Code,which is maintained by the National Grid andidentifies weaknesses in the UK natural gas

transportation system, based on long-termdemand and supply forecasts. The coderequires a security margin to cover uncer-tainties in forecasts and a design margin formaximum demand, subject to approval to theregulator.

4. The impact of market liberalisation

The liberalisation of the UK natural gasmarket triggered the “dash for gas” in powergeneration during the 1990s (Fig. 18.12). Thepower sector had access to new combined-cyclenatural gas turbine technology, which was rela-tively quick to build. The liberalisation of thenatural gas and electricity sectors, along withabundant supply and a lifting of the ban on use ofnatural gas for power generation, drove a rapidrise in gas consumption as the number ofcombined-cycle turbines used by power genera-tors increased. The decline in natural gas use inpower generation in recent years has been theresult market forces which have made natural gasless competitive compared to coal.

Power generation Non-power transformation Industry Residential Other

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Fig. 18.12 UK natural gas consumption by sector, 1960–2012. Note Excludes transport, non-energy use, energyindustry own use and losses; non-power transformation includes CHP and natural gas to liquids plants; other includesthe services, agriculture and fishing sectors. Source Vivid Economics, based on IEA data

412 18 An Overview of International Regulatory Experience

Upstream regulation in the United Kingdom isbased on principles of transparency and openaccess. The United Kingdom had 200 billion m3

of proven natural gas reserves at the end of 2013.The Petroleum Act of 1998 sets out the rulesaround upstream natural gas exploration andproduction. Natural gas resources are owned bythe state, and the Secretary of State of theDepartment of Energy and Climate Change isresponsible for granting licences for explorationand production rights.

As exploration and production efforts on theUnited Kingdom’s continental shelf havebecome increasingly difficult, licensing tenureshave lengthened. The Department of Energy andClimate Change assesses bids, focusing on pol-icy objectives including environmental risk andinfrastructure quality. If the winner of a licence

does not keep up with the agreed work pro-gramme or does not meet safety and environ-mental standards, the department may revoke thelicence.

18.3.4 Case Study 4: Japan

Vertically integrated businesses delivered allaspects of Japanese natural gas supply until lib-eralisation began in 1995. The development ofJapan’s natural gas market has gone throughthree distinct phases, with liberalisation stillincomplete (Fig. 18.13).

From 1954 to 1995, prior to Japan’s naturalgas market being liberalised, it was managedthrough the 1954 “Natural Gas Business Law”.Under this law, the natural gas industry was

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nationalisationof TEPCO

Fig. 18.13 Phases, development and key regulations in the development of the Japanese natural gas market. NoteNominal LNG cost, insurance and freight (CIF) import prices converted to US$. Source Vivid Economics, based onIEA data and BP Statistical Review of World Energy 2013

18.3 Case Studies of Natural Gas Market Liberalisation 413

monopolised by vertically unified entities.Beginning in 1995, Japan’s government began toimplement natural gas sector market liberalisa-tion gradually. Powerful opening up of userrights systems in natural gas transmission,including functional spin-off and outside accessof controls, permitted large clients to choosesuppliers. LNG infrastructure incorporatednegotiated third-party access systems.

In 2011, the Fukushima nuclear disaster had amassive impact on Japan’s energy systems,causing the re-nationalisation of the nation’smajor LNG importer, Tokyo Electric Power, in2012. This marked the end of the Japanesegovernment’s liberalisation plans for the energymarket. However, in public debate, natural gasmarket reforms are continually a focus, and thegovernment has been forced by this pressure toadd energy sector competition. After the rise inoil prices due to the Fukushima disaster, becausedemand grew, and LNG price fluctuations weresignificant, the Japanese government was forcedto change policy to weaken controls on long-termcontracts linked to oil. The government has alsotaken other measures weakening the influence ofoil markets on natural gas, including proposingthe construction in 2015 of a LNG futures mar-ket. The futures market would determine naturalgas prices based on domestic demand factors.

1. Before market liberalisation

Prior to liberalisation, Japan’s natural gasmarket was governed by the 1954 Gas UtilityAct. Under this act, the natural gas industry wasregulated as a vertically integrated monopoly.Companies wishing to enter the natural gasmarket needed licences from the Ministry ofEconomy, Trade and Industry. The verticallyintegrated natural gas companies were responsi-ble for importing LNG, and the city natural gascompanies were responsible for distribution.Tokyo Gas, Osaka Gas and Toho Gas were majorvertically unified natural gas companies respon-sible for the import of natural gas, operation ofLNG terminals, the storage of LNG, operatingnatural gas transmission distribution networks, aswell as retail business. The smaller-scale city

natural gas companies also provided distributionand retail services, reselling natural gas pur-chased from the vertically integrated companies.Power generators were allowed to import LNGfor their own use, including large users such asTokyo Electric Power (TEPCO) and KansaiElectric Power.

2. Market liberalisation

The Japanese government gradually intro-duced liberalisation in transmission, distributionand LNG facilities beginning in 1995. Naturalgas prices in Japan have long been higher thanthe average in OECD countries, and the Japanesegovernment sought to reduce prices by intro-ducing competition, with open access to infras-tructure and unbundling. The first two phases ofliberalisation, in 1995 and 1999, focused on thetransportation and distribution sectors.

People believed that these two stages were notsuccessful. Since 2003, oil prices have remainedhigh and, compared to oil products, natural gashas become more attractive, with subsequentrises in natural gas demand. Therefore, beginningin 2003, the government started to implementmore unbundling measures. Although there not acomplete opening of LNG infrastructure tothird-party access, nonetheless this stage beganto implement open access.

The Gas Utility Act of 1995 attempted tointroduce negotiated third-party access andunbundling, but was unsuccessful. The actintroduced mandatory negotiated third-partyaccess, allowing large natural gas consumerswith an annual natural gas consumption of morethan 2 million m3 to buy natural gas fromnon-incumbent natural gas suppliers. Tokyo Gas,Osaka Gas and Toho Gas were required tounbundle their services. However, almost a dec-ade later these three companies still accountedfor more than 70% of domestic sales(Fig. 18.14).

This regime was not considered successful inopening the natural gas market as terms and con-ditions for access were not sufficiently standard-ised and transparent. The companies usingor seeking access to other companies’ pipeline

414 18 An Overview of International Regulatory Experience

complained of entry barriers and non-transparencyin the wheeling system which moves natural gasfrom one system to another. Many of the com-plaints related to the lack of information on theavailable capacity of pipelines, non-transparentstandards and procedures for assessing fees, andother compensation mechanisms.

The Gas Utility Act was revised in 1999 tointroduce regulated third-party access, expandingfrom the three largest vertically integrated com-panies to include a fourth, Saibu Gas. Thethreshold for eligible consumers was reduced byhalf, to 1 million m3 in natural gas consumptiona year. Natural gas companies were also requiredto publish the terms and conditions for use oftheir transportation and distribution pipelines.

When the first phase of liberalisation did notachieve an effective open-access regime, furtherunbundling and market transparency measureswere adopted from 2003 onwards. High oil pri-ces provided added impetus, making natural gasmore attractive compared to oil products andsubstantially raising demand. In 2003, accountand functional unbundling were introduced toseparate natural gas transportation businessesfrom sales businesses by requiring separate fil-ings of accounts and a separation of day-to-daymanagement. The reforms also sought to openLNG terminals. The threshold for customers tobe eligible for third-party access was furtherreduced to 500,000 m3 a year in 2003 and again

to 100,000 m3 in 2007 (Fig. 18.15). By 2007,61% of the natural gas market by volume wasderegulated, and this was unchanged in 2013.

In addition, open access was extended to allnatural gas companies with eligible customers.Natural gas companies were required to preparestandardised third-party access contracts withterms and conditions for transportation servicesthat were to be approved by the energy authority.

Japan does not have a well-developedlong-distance natural gas transportation net-work. There are no cross-border natural gaspipelines and the high-pressure transmissionnatural gas pipeline length is only around2500 km (Fig. 18.16), compared to 500,000 kmin the United States. Although there are around43 main interconnection points between areas,the trunk line networks are not necessarily con-nected to each other as they have separatelydeveloped around LNG terminals. The lack ofinterconnection between regions may limit thescope for competition through third-party access.

Starting in 2003, there were calls in Japan todelay the development of national high-pressurenatural gas pipeline networks, on the grounds thatmanaged third-party access terms could reducethe incentivising effect of natural gas infrastruc-ture investment, and hinder energy security.

In 2003, there were natural gas legal reforms,with LNG infrastructure sectors implementingnegotiated third-party access plans.

Osaka Gas

Tokyo Gas

Toho Gas

Saibu Gas

Others

25%

35%11%

2%

28%

35,912million m3

Fig. 18.14 Japan natural gas market sales volume, 2012. Source Osaka Gas (2012)

18.3 Case Studies of Natural Gas Market Liberalisation 415

The need for open access in LNG infrastruc-ture was included in the 1999 US-Japan ThirdJoint Status Report under the Enhanced Initiativeon Deregulation and Competition Policy, anoffshoot of economic co-operation effortsbetween the two countries. The issue was par-ticularly relevant as LNG terminals are the entrypoints for imported natural gas, and without freeaccess to LNG terminals and storage facilities,only a limited degree of competition, if any,would be possible in Japan. In response, theJapanese government amended the Gas UtilityAct in 2003 and introduced an open-accessscheme for LNG facilities. Under this scheme,

natural gas companies were to define precondi-tions for negotiated access. Further transparencyrequirements related to the capacity informationfor LNG storage and facilities were also applied.However, by 2012, no third-party access hadbeen effectively granted to any company at aJapanese LNG terminal.

3. Prospects for continued liberalisationpost-Fukushima

After the Fukushima nuclear disaster in 2011,the appetite for further liberalisation in naturalgas markets in Japan diminished further. The

Market deregulation (2013.3)

Annual contracted gasconsumption volume

Large factories, etc.

Large factories,and large commercial

facilities, etc.

Retail liberalisation of customerswith annual consumption over2 million m³

Retail liberalisation of customerswith annual consumption over1 million m³

Retail liberalisation of customerswith annual consumption over500,000 m³

1995.3 1999.11 2004.4 2007.4

Deregulatedareas

Regulatedareas

Retail liberalisation of customerswith annual consumption over100,000 m³

Medium-sized factories,hotels, etc.

Small factories,no-frills hotels, etc.

Residential housing, smallbusinesses, etc.

2 million m³

1 million m³

500,000 m³

100,000 m³

61% Deregulated Regulated 39%

Fig. 18.15 Japan’s natural gas market liberalisation progress. Source Osaka Gas

416 18 An Overview of International Regulatory Experience

renationalisation of TEPCO, a significant LNGimporter, in 2012 epitomised the change inmomentum regarding energy sector liberalisationthat followed the Fukushima disaster. However,in 2013, a plan for reforms to deregulate theelectricity market was passed, signalling arenewed interest in energy sector reform. Theelectricity sector is particularly important toJapan’s natural gas market because it accountsfor about two-thirds of the country’s total naturalgas consumption and that share has grownrapidly since the Fukushima disaster(Fig. 18.17).

Japan’s 10 regional electricity utilities havesought to increase regulated electricity tariffspaid by end users to help cover their costs. Since2012, the Ministry of Economy, Trade andIndustry has approved tariff increases of between7 and 11% for six utilities. In 2013, the first of

three electricity market reform packages waspassed, to reduce LNG procurement coststhrough competition between electric utilities.The measure established an Organization forCross-Regional Co-ordination of TransmissionOperators to promote the development of elec-tricity transmission and distribution networks andto enhance the nationwide function of adjustingthe supply-demand balance of electricity. Thesecond reform measure would fully liberaliseentry to the electricity retail business and thethird would require legal unbundling of thetransmission and distribution sector.

As Japan depends heavily on LNG imports tomeet its electricity generation needs, the gov-ernment has sought to ensure diversified LNGsupply based on cost-efficiency and energysecurity. The key elements of Japan’s overallenergy security policy are diversifying its

Existing pipelines

Pipelines under planning or construction

Pipelines under consideration

LNG terminals in operation

LNG terminals under const./planned

Ishikari Hokkaido

Hachinohe

Shin-Minato

JAPANShin-Sendai

Niigata

Hitachi

TokyoSodegaura

Futtsu

NaoetsuJouetsu

Yoshinawa

Okinawa0 40km

KmN

0 100 200

Kagoshima

This document and any map included here are without prejudice to the status of or sovereignty over any territory, to thedelimitation of international frontiers and boundaries and to the name of any territory, city or area.

Nagasaki

FukuokaHibiki

Tobata ShikokuSakaide

Wakayama

SenbokuSakai

Yanai

HatsukaichiMizushima Himeji Kawagoe

Yokkaichi Chita Midorihama

OhgisimaHigasi-OhgisimaChita

Honshu

Toyama

Sodeshi

OhitaKyushu

Pacific Ocean

Fig. 18.16 Japan LNG terminals and high-pressure pipelines. Source IEA (2013)

18.3 Case Studies of Natural Gas Market Liberalisation 417

long-term supply contract portfolio, ensuringcontractual flexibility to increase imports in anemergency and using voluntary commercialLNG stocks in industry. Japan’s largest naturalgas supplier, Australia, represented just 21% oftotal imports of the country in 2013, illustratingthe diversity of Japan’s natural gas suppliers(Fig. 18.18).

In recent years, Japan’s proportion of importsfrom Malaysia and Indonesia has dropped, whileimport proportions from Australia and Qatarhave increased.

4. Focus: Japanese natural gas pricing

Traditionally, Japan’s natural gas contractshave been linked to oil prices, but the govern-ment has already begun to weaken the influenceof crude oil prices. In the 1970s and 1980s,long-term LNG import contracts were closelylinked to international crude oil prices. Thesecontracts are about to expire, and importers arebeing forced to renegotiate contracts or else lockinto shorter-term supplies. Crude oil price

increases have led to dual increases in cost andelectricity prices in obtaining LNG.

Japan’s METT encourages electricity compa-nies to negotiate in order to obtain LNG at pricesthe same or lower than previous contracts, as aprerequisite to collecting higher fuel fees fromelectricity consumers. Japan’s natural gas andelectricity companies also carry out negotiationsfor LNG contracts, and these contracts are notrestricted by crude oil prices that are lower thannatural gas market prices in the United States.For example, Kansai Electric Power came to along-term agreement in 2012 with British Pet-roleum, and this agreement was governed by theUS Henry Hub price. In 2012, Japan’s govern-ment proposed establishing a LNG futures mar-ket in March 2015, with the futures marketdetermining natural gas prices based on domesticdemand factors. Japan released its latest strategicenergy plans in April 2014, encouraging naturalgas and electricity companies to carry out tar-geted loosening of LNG long-term contractterms. Beginning in 2012, many companies werealready carrying out US upstream liquefaction

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Fig. 18.17 Major components of Japanese natural gas consumption. Note Excludes transport, non-energy use, energyindustry own use and losses; non-power transformation includes CHP and natural gas to liquids plants; other includesthe services, agriculture and fishing sectors. Source Vivid Economics, based on IEA data

418 18 An Overview of International Regulatory Experience

projects, and this will account for 20% of Japan’stotal natural gas demand.

Furthermore, Japan’s LNG importers haveformed partnership relationships with theregion’s other LNG purchasers in order toincrease negotiating power and reduce purchaseprices. For example, Tokyo Electric Powerformed a full alliance in October 2014, coveringthe entire energy supply chain, with ChubuElectric Power. Their co-operation incorporates awide arrange of activities, whether it be inupstream investments and procurement of fuelfor power plants, or carrying out a series of jointprojects, including natural gas upstream invest-ment on a global scale, construction of newthermal power plants and procurement of LNG.

18.3.5 Case Study 5: South Korea

Since 1997, South Korea’s efforts to liberalisethe natural gas sector have led to partialunbundling and open access, but progress hasbeen slow in the wake of political resistance thatbegan in the early 2000s (Fig. 18.19).

Prior to market liberalisation in 1997,KOGAS (a state-owned corporation) was theexclusive owner of LNG infrastructure and nat-ural gas transmission facilities. In 1997, thegovernment attempted to break KOGAS’s importmonopoly. Even though some large-scale naturalgas users could directly import natural gas fortheir own use, KOGAS still maintained its sub-stantive monopoly in LNG, transmission and

AustraliaAustralia IndonesiaIndonesia MalaysiaMalaysia QatarQatar

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40%

35%

30%

25%

20%

15%

10%

5%

0%

Per

cent

of t

otal

LN

G im

ports

Fig. 18.18 Four major country suppliers of LNG gas imports to Japan since 2000. Source Vivid Economics, based onIEA data

18.3 Case Studies of Natural Gas Market Liberalisation 419

wholesale supply. In the first 10 years of the 21stcentury, after the natural gas supply crisis, mar-ket liberalisation progress halted. Moreover,California’s major power cuts not only increasedworries about the compatibility of electricitymarket liberalisation and energy security, butalso weakened political determination. Finally,opposition from trade unions at KOGAS furtherimpeded the implementation of governmentreform plans.

1. Before market liberalisation

Before liberalisation began in 1997, thestate-owned utility, KOGAS, was the sole ownerof LNG infrastructure and natural gas trans-portation facilities. KOGAS is a vertically inte-grated state-owned natural gas company formedby the Korea Gas Corporation Act in 1982.Similar to the vertically integrated regional

monopolies in Japan, KOGAS was primarily animport-oriented company, given the lack ofindigenous natural gas production in SouthKorea, and it controlled and operated LNG ter-minals, storage and natural gas transportationpipelines.

The City Gas Business Act of 1983 estab-lished city natural gas companies and introduceda regulatory framework comprising licensingrequirements for the supply of natural gas, theconstruction of natural gas facilities andthe terms and conditions of natural gas supply.The main business of the city natural gas com-panies was to buy natural gas from KOGAS orliquefied petroleum natural gas from oil compa-nies and distribute it to customers. This localdistribution system has remained largely in place,and there are 30 privately owned city natural gascompanies, each of which enjoys exclusive retailsales rights within its areas.

2003

Indigenous production Net pipeline imports Net LNG imports Index of wholesale prices

Formation ofKOGAS; the CityGas Business act

First phase of privatisationof KOGAS; negotiatedTPA in KOGASinfrastructure

Pre-liberalisationM

arke

tph

ase

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latio

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Main frameworkfor gasprivatisation andliberalisation

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Fig. 18.19 Phases, development and key regulations in the establishment of a liberalised natural gas market in Korea.Notes Index of wholesale prices is the natural gas sub-index of the producer price index; 2010 = 100. Source VividEconomics based on IEA data

420 18 An Overview of International Regulatory Experience

2. Market liberalisation

In response to the 1997 Asian financial crisis,the South Korean government announced plansto liberalise the natural gas sector by introducingcompetition and privatising KOGAS. The 1997National Energy Plan set the main framework fornatural gas liberalisation and privatisation, butdid not specify detailed regulatory changes. In1999, the South Korean government developedthe Basic Plan for Restructuring the Gas Indus-try. The assets and staff of KOGAS were to bedivided into two groups: infrastructure, includingreceiving terminals, pipelines and storageinfrastructure; and import and wholesale func-tions. KOGAS would retain ownership of theinfrastructure group, while the import andwholesale divisions were to be further split intothree natural gas supply subsidiaries by the endof 2001. Of these three trading entities, onewould remain a subsidiary of KOGAS and theother two would be independent.

The government succeeded in partially pri-vatising KOGAS, and 39% of the equity was

sold by the government by the end of 1999.However, the plan to further privatise andunbundle KOGAS was not completed because offierce opposition from the company’s labourunion. Additionally, the country faced a domesticnatural gas supply crisis at the time whendetailed privatisation plans were being discussed.Natural gas demand from the residential, indus-trial and power sectors rose sharply, raisingconcerns over energy security (Fig. 18.20). Theelectricity blackouts in California further fuelledconcerns about whether liberalisation and energysecurity were compatible. These factors togetherundermined the political appetite for electricityand natural gas sector liberalisation.

Although the 1999 Restructuring Plan stalled,a voluntary service unbundling initiative and anegotiated third-party access regime were intro-duced for KOGAS infrastructure. In 1999, theCity Gas Business Act abolished part ofKOGAS’s monopoly on importing LNG andoperating LNG infrastructure. The act set out aregulated third-party access regime, but it lastedonly a short time before being suspended in 2000.

Power generationPower generation Non-power transformationNon-power transformation IndustryIndustry ResidentialResidential OthersOthers

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Fig. 18.20 Korean natural gas consumption by sector. Note Excludes transport, non-energy use, energy industry ownuse and losses; non-power transformation includes CHP and natural gas to liquids plants; other includes the services,agriculture and fishing sectors. Source Vivid Economics based on IEA data

18.3 Case Studies of Natural Gas Market Liberalisation 421

Despite the reform efforts, third-party accessto LNG storage facilities, the transmission net-work and LNG terminals owned by KOGAS hasbeen limited. In 2002, KOGAS remained thedominant natural gas player, even while largeusers like Pohang Iron and Steel Companyoperated their own LNG import terminals andimported LNG for their own use (Fig. 18.21).

Energy security concerns over LNG marketvolatility and meeting peak winter demand havehampered progress in natural gas market liber-alisation. The importance of diversified LNGsupply sources, ensuring LNG supply on thebasis of long-term contracts, and expansion ofstorage capacity to meet high seasonal demandare perceived to outstrip the potential benefits ofliberalisation. The government promotes theparticipation of KOGAS in upstream natural gasproduction abroad and strives to preserve itsposition on world LNG markets, where KOGASis the single largest buyer of LNG. For example,the Tenth Long-Term Gas Supply and DemandPlan, published in 2010, proposed that KOGAS

secure oil-indexed long-term contracts withimproved flexibility and conditions from 2015.This makes it unlikely that plans to privatiseKOGAS will be revived soon, and the govern-ment is likely to continue to exert a direct,commanding influence on South Korea’s naturalgas sector.

KOGAS owns and operates Korea’s nationalpipeline network and three quarters of thecountry’s LNG terminals. Korea currently has notransnational natural gas pipelines. Its nationaltransmission pipelines stretch for 3588 km(Fig. 18.22). According to plans announced, thiswill be extended to 4928 km by 2027.

The majority of Korea’s contracts are linkedto the price of crude oil. KNGC has signedmid-term and long-term contracts linked to crudeoil for the import of 80–90% of its LNG, with theremainder being through spot market purchases.In 2012, Qatar was the largest supplier of naturalgas to Korea, followed by Indonesia, Oman,Malaysia and Yemen (Fig. 18.23). Among the 10long-term natural gas supply and demand

Direct import for own use

Wholesale supply contractRetail supply

Discount supply contract

Direct supply contract

LargeConsumers

GeneralDemand

LargeConsumers

City GasCompany

Korea GasCorporation

LNG Exporters

Fig. 18.21 Korean natural gas industry structure. Source Asia Pacific Energy Research Centre

422 18 An Overview of International Regulatory Experience

Chongju

Yumsan

Kunsan

Poryong

Sosan

Taechan

Yusang

ChonanAsanChongju

Jungchan

Kimchon

Kwanum

Samchok

Ulchin

Hoengsong

YojuSeoul

Namyangju

Chunchan

Sokcho

Ilsan

Ildo

Pyeong-Taek

Incheon

Suwon

Yeungjang

YellowSea

N

Km0 40 80

Yongin

REPUBLIC OF KOREA

Kwangju

Haenam

Sunchon

Gwangyang

Yosu

Mokpo

Tong-Yeong

Pusan

MassanKimhae

Ulsan

Pohang

Existing pipelines

Planned underconstruction pipelines

LNG import facilities

Planned LNG import facilities

Fig. 18.22 Korean LNG terminals and pipeline networks. Source IEA (2011)

18.3 Case Studies of Natural Gas Market Liberalisation 423

policies announced in 2010 was the proposalthat, beginning in 2015, KNGC should ensurethat oil-linked long-term contracts increasetheir degree of flexibility and terms. Further

co-operation between Korea and its LNGimporting neighbours (such as Japan) couldimprove buying power as part of new long-termcontract agreements.

7%

30%

18%

12%

12%

Qatar

Indonesia

Omen

Malaysia

Yemen

Fig. 18.23 Major importers of natural gas to Korea, 2012. Source Vivid Economics, based on IEA data (2012)

Open Access This chapter is licensed under the terms ofthe Creative Commons Attribution 4.0 InternationalLicense (http://creativecommons.org/licenses/by/4.0/),which permits use, sharing, adaptation, distribution andreproduction in any medium or format, as long as yougive appropriate credit to the original author(s) and thesource, provide a link to the Creative Commons licenseand indicate if changes were made.

The images or other third party material in this chapter areincluded in the chapter’s Creative Commons license,unless indicated otherwise in a credit line to the material. Ifmaterial is not included in the chapter’s Creative Commonslicense and your intended use is not permitted by statutoryregulation or exceeds the permitted use, you will need toobtain permission directly from the copyright holder.

424 18 An Overview of International Regulatory Experience

19A Close Look at the Natural GasIndustry Chain

The previous section set out international expe-rience in the development and evolution of nat-ural gas markets. A key insight from the fivecountry case studies is that liberalisation requiresdifferent regulatory approaches for different partsof the natural gas value chain.

This section draws from international experi-ence and takes a closer look at regulatory effortsat specific points of the value chain. In theupstream segment, countries have encouragedexploration and production by increasing com-petition, including through fiscal and licensingregimes, to encourage new entrants into theindustry. In the midstream segment, where nat-ural monopolies exist, third-party access totransmission and distribution infrastructure hasbeen crucial. In addition, some degree ofunbundling of companies integrated across thevalue chain has been essential, both to reduceanti-competitive behaviour with respect to mid-stream infrastructure and to encourage competi-tion across the natural gas value chain. In thedownstream segment, countries have encouragedgreater competition in the wholesale and retail

markets supplying end users. Countries withsignificant domestic natural gas resources haveliberalised their wholesale markets by encour-aging greater competition and the establishmentof natural gas hubs.

19.1 The Upstream Segment: FiscalPolicies and Licensing Systems

In addition to furthering a government’s fiscalobjectives, these regimes have important impli-cations for the development of a country’s oil andnatural gas resources, the natural gas regulatoryenvironment, the relationship between variouslevels of government and various agencies, and theoverall nature of the oil and natural gas industry.

Upstream fiscal and licensing regimes play acritical role in the development of a country’s oiland natural gas resources. The two of themwork inunison to offer benefits by incentivising invest-ments and strengthening market competitiveness.Through an analysis of the experiences of theUnited States, Australia, Argentina and Mexico,this section carries out an in-depth exploration ofnatural gas upstream sector financing and taxes,permit system arrangements, and co-ordinationand contact between various levels of government,all of which can be useful as references as Chinaformulates similar policies.

* This chapter was overseen by Jigang Wei from theDevelopment Research Center of the State Council andTaoliang Lee from Shell Eastern Trading Corporation. Itwas jointly completed by Yaodong Shi, Zifeng Song,Ren Miao from the Energy Research Institute of theNational Development and Reform Commission andCindy Wang from Shell China. Other members of thetopic group participated in discussions and revisions.

© The Editor(s) and The Author(s) 2017Shell International and The Development Research Center (Eds.), China’s Gas Development Strategies,Advances in Oil and Gas Exploration & Production, DOI 10.1007/978-3-319-59734-8_19

425

19.1.1 International Taxationand Licensing SystemsRegulating UpstreamProduction

Our analysis of international experience in fiscaland licensing regimes to regulate the upstreamproduced four overarching observations.

• Unconventional resources: Internationalexperience in crafting fiscal and licensingregimes shows that policy makers need toconsider the fundamental differences betweenthe exploration and development of conven-tional natural gas reserves and that ofunconventional reserves. Unconventionalnatural gas developments have an ongoingneed to explore, develop and produce onorder to find the most productive areas, theso-called “sweet spots”. These are charac-terised by shorter plateaus and more rapiddepletion of reserves than conventional nat-ural gas wells. As a result, unconventionaloperations require ongoing capital expendi-tures, whereas the majority of capital costs forconventional operations occur at the start of adevelopment. Moreover, unlike conventionaloperations, unconventional natural gasdevelopments typically require significantquantities of water, potentially affecting wateravailability for other users in the area, as wellas water quality from the run-off and dis-charge of water used in processes such ashydraulic fracturing. This requires appropri-ate policy frameworks and processes tomanage and minimise these impacts.

• Co-ordination across government tiers:Fiscal and licensing regimes should also takeaccount of the interplay between national andregional authorities. Each level of govern-ment has an important role to play in thedevelopment of a country’s energy resources,in terms of taxation and wider policy devel-opment. A review of experiences in theUnited States, Australia and Argentina shows

that national and regional governments typi-cally share the revenues generated, bothdirectly and indirectly. Co-ordinationbetween national and regional authorities isalso required in terms of regulatory policies.For example, in the United States and Aus-tralia, access to midstream infrastructure—essential for encouraging competition in theupstream and downstream segments—re-quires policy co-ordination and alignmentbetween the national and state governments.

• Looking across the value chain: Fiscal andlicensing regimes have a direct impact onpromoting upstream developments, but theyare just one part of an overall energyapproach. Efforts to stimulate other parts ofthe value chain, especially demand, can havea profound influence on upstream activities.In Australia, for example, regulatory supportfor a switch to natural gas in power genera-tion created momentum for greater domesticexploration and production.

• Balancing the need for foreign investmentand expertise with domestic interests:Investment in upstream exploration and pro-duction is often supported by foreign directinvestment (FDI). However, at times,increased FDI can also create tensions withnational oil companies or concerns thatnational interests are being neglected. Theexperience of Mexico and its Bid Round Zeroillustrates how countries can balance theseinterests, providing opportunities andsafeguards for domestic companies whilebringing in foreign funding and capabilities.

19.1.2 Case Study 1: The UnitedStates—Leasing, Taxationand Developmentof Information Sharing

Under the United States federal system, mostregulations for the oil and natural gas industryare enacted and enforced by the individual states.

426 19 A Close Look at the Natural Gas Industry Chain

The US upstream investment regime uniquely isunderpinned by ownership of mineral resourcesby the owner of the land. This means thatonshore ownership of the resources is by privateindividuals, and private leases can be negotiatedwithout a licensing authority. The exception tothis norm concerns federal and state land, wherethe relevant government authority issues leasesthrough tenders. For federal land, the Bureau ofLand Management is responsible for issuingleases (Fig. 19.1). For federal waters—typicallybeyond three miles of the coastline—the Bureauof Ocean Management is responsible for issuingleases. Federal leases typically have a term of5–10 years and can be renewed as long as pro-duction attributable to the lease continues.

With regard to the mining of natural gas,federal and state governments in the United Statesprimarily use a tax and royalty regime. Onshorerates range from 12.5 to 30%, while the offshore

rate is 18.75%. Most states also charge a sever-ance tax, with its structure and level varying bystate. For example, the Texas severance tax is7.5% of the market value of the natural gas, whilein neighbouring Louisiana, the severance tax isset each year based on NYMEX Henry Hub set-tled prices and on spot prices in the state. In 2014,this was 16.3 cents per thousand cubic feet.

The regime in the United States is also char-acterised by significant information sharingaround the development of tight and shale naturalgas, often cited as a reason behind the country’ssuccessful development of unconventional oiland natural gas resources. Data on permits, dril-ling, testing and production is required to bemade available in a timely manner, although thedetails vary from state to state. Interested partiescan obtain the information directly from the stateor from consulting companies that collect suchdata. In addition to legal disclosure requirements,

Legend

TX

OKAR

MS

LA

AIGA

FL

SC

NC

VAMDDENJ

VTNHMA

CTRI

PA

NY

ME

MI

OHINIL

IA

WI

MN

ND

SD

NE

KS MO

TN

KY

WV

NM

CA

AZ

AK

HI

UTCO

WYNV

WA

MTID

OR

StatesSurface & Subsurface Federal Ownership

All Federal Lands

Fig. 19.1 US federal public land surface and underground levels. Source US Bureau of Land Management

19.1 The Upstream Segment: Fiscal Policies and Licensing Systems 427

companies also have incentives to discloseinformation—occasionally including details onindividual wells—to support their share price andtheir efforts to raise capital. Publicly tradedcompanies are also required to submit detailedquarterly and annual reports to the federal gov-ernment, which are publicly available. In addi-tion, several federal government agencies,including the US Geological Survey, theDepartment of Energy and the Energy Informa-tion Administration, monitor and publish keystatistics weekly, quarterly and annually. Addingto the data flow, industry associations, technicaland business journals, investment reports andconferences provide a platform for upstreamcompanies, investment banks, academics andgovernment to exchange information.

19.1.3 Case Study 2: Australia—Licensing, Financeand Taxation,and Third-Party Access

According to forecasts, in the near future Aus-tralia will become the largest LNG exporter in theworld. It has liquefaction capacity of about26 million metric tonnes a year in operation, andis expected to add about 62 million metric tonnesin additional capacity over the next several years.The new projects include three projects inQueensland, primarily using coalbed methane toproduce LNG. A diverse range of companies areinvolved in onshore Queensland natural gas pro-duction, including PetroChina, Sinopec and theChina National Offshore Oil Corp. (CNOOC).

Australia’s domestic natural gas systemcomprises the East Coast market, coveringQueensland, New South Wales, South Australia,the Australian Capital Territory and Victoria, andthe Western Australian market, covering the restof the country. Australia does not have anextensive pipeline network, especially comparedto Europe or the United States, because demandis highly concentrated in the various state andterritory capitals and because supply has

historically come primarily from two basins,Cooper and Gippsland (Fig. 19.2).

Alongside fiscal and licensing measures tostimulate upstream exploration and production,Australia also provided demand incentives toincrease the share of natural gas in the energy mix.The Queensland Gas Scheme illustrates the suc-cess of such measures in driving coalbed methaneproduction. Introduced by the Queensland gov-ernment in 2005, the scheme required all electricityretailers to acquire 15% of the power they soldfrom natural gas-fired generation plants. Accred-ited power producers generated Gas ElectricityCertificates (GEC) for each MWh of eligible nat-ural gas-fired electricity they produced. TheseGECs are then sold to the electricity retailers,providing an alternative revenue source for powerproducers to offset the higher cost of naturalgas-fired power generation compared to coal. Thescheme ended in 2013 when the state governmentdeclared that its goals of promoting the state’snatural gas industry and reducing greenhousenatural gas emissions had been achieved. Duringthis time, natural gas-fired power generation hadgone from 5% of total power in 2005 to 20% in2013, and the state’s unconventional natural gasproduction had grown from 1 billion m3 in2004–05 to 6 billion m3 in 2010–11 (Fig. 19.3).

Australia has three levels of government—federal, state or territory, and local—and has aconcessionary fiscal regime. The federal govern-ment and state and territory governments sharejurisdiction over petroleum resources, and thereare no private ownership petroleum resources.

State and territory governments manage thelicences for development onshore and within3 miles of the coastline. They collect royalties ofbetween 10 and 12.5%, based on the wellheadvalue of the petroleum resource. Licences inQueensland are issued and managed by theDepartment of Natural Resources and Mines, andthe published royalty rate is 10%.

The federal government manages licences foroffshore development beyond 3 miles of thecoastline. It levies a Petroleum Resource RentTax of 40% for both onshore and offshore oil and

428 19 A Close Look at the Natural Gas Industry Chain

15

14

13

12

11

1098

7

6

5

4 3 2

1

DARWINBonaparte Basin

Browse Basin

Camarvon Basin

Perth Basin

PERTH

Amadeus Basin

Cooper Basin

ADELAIDE

MELBOURNE

Otway Basin

CANBERRA

HOBART

SYDNEY

BRISBANE

CANBERRA

NSWbasis

BassBain

SuratBowenBasin

Gippsland Basin

WesternAustralia

NorthernTerritory

Queensland

SouthAustralia

Victoria

Tasmania

New SouthWales

Gas basins

Uncovered pipelinesCovered pipelinesLight regulation pipelines

PipelineMoomba to Sydney PipelineEastern Gas Pipeline (Longford to Horsley Park)NSW–Victoria InterconnectVictorian Transmission SystemTasmanian Gas PipelineSEA Gas PipelineMoomba to Adelaide PipelineQSN LinkSouth West Queensland Pipeline (Baliera to Walumbilla)Roma to Brisbane PipelineQueensland Gas Pipeline (Wallumbilla to Gadstone/Rockhapton)Amadeus Basin to Derwin PipelineBonaparte PipelineDampier to Bunbury Natural Gas pipelineGoldfields Gas Pipeline

No.123456789

101112131415

Fig. 19.2 Australia’s natural gas basins and major transmission pipelines. Source Australia Energy Regulator

Conventional gas

1990Prod

uctio

n (B

CM

per

yea

r)

Unconventional gas

1995 2000 2005 20100

2

4

6

8

10

Fig. 19.3 Natural gas production in Queensland, Australia. Source Queensland Department of Natural Resources andMines

19.1 The Upstream Segment: Fiscal Policies and Licensing Systems 429

natural gas, with state and territory royaltiesdeductible from the amount due.1 In addition, thefederal government levies a corporate tax of30%. It also levies a value added tax, known as aGoods and Services Tax, of 10% on mosttransactions, with receipts redistributed to thestate and territory governments.

The three levels of government in Australiaco-ordinate to develop natural gas resources andmarkets. The Council of Australian Governmentsis the main intergovernmental forum that pro-motes policy reforms with national relevance orthose that require co-ordinated action at alllevels. Members of the council are the primeminister, the premiers or chief ministers of eachstate or territory respectively, and the president ofthe Australian Local Government Association. Inaddition, the Standing Council on EnergyResources (SCER) was founded in 2011 andcomprises federal, state and territory ministersresponsible for energy and resource matters. Thecouncil’s responsibilities include oversight of thenatural gas and electricity markets, energy lawsand regulations, energy security and emergencymanagement, and promoting the economicdevelopment of Australian resources.2

Companies developing new upstream infras-tructure may be granted exemptions fromthird-party access requirements if they satisfycriteria outlined in the legislation.

Access to third-party infrastructure is estab-lished under the federal Competition and Con-sumer Act. The National Competition Council(NCC) is established through consensus by theSCER and is responsible for recommending reg-ulations on third-party access to monopolyinfrastructure, including natural gas transmissionpipelines. Factors taken into consideration includewhether access would increase competition in amarket, the economics of developing competinginfrastructure, and whether the infrastructure isalready subject to an effective access regime.

For example, 15-year exemptions have beengranted to cover the pipelines being built to

transport natural gas from the three Queens-land LNG projects to the liquefaction plants inGladstone. The NCC concluded that third-partyaccess “would not promote a material increase incompetition in any likely dependant market”.3

Even though the developers can obtain a waiver,nonetheless the Australian Competition and Con-sumer Commission (which also has jurisdictionbeyond energy) and the Australian Energy Regu-lator (AER) both carry out significant oversight,strictly executing energy market rules and pro-viding protection for competition and consumers.

19.1.4 Case Study 3: Argentina—TheSpecial Licensing Systemand EncouragingInvestment

Argentina is a significant producer and consumerof natural gas. According to data from the USEnergy Information Administration, the coun-try’s technically recoverable shale natural gasreserves are second only to those in China, andits shale oil resources are the world’s fourth lar-gest, after Russia, the United States and China.According to forecasts, Argentina’s natural gasdemand will have been 44 billion m3 in 2015,accounting for 45.7% of its energy structure.Currently, the domestic shortfall is met by LNGpurchased primarily from the spot market andimported through two floating regasification andstorage units. Natural gas prices are regulatedand subsidised below cost, but prices have begunto be deregulated—mainly through bilateralnegotiations—to encourage upstream investmentand to raise revenues for the government.

Argentina’s concession-based licensing sys-tem replaced a system based on risk servicecontracts. State-controlled Energía ArgentinaS.A. (ENARSA), which is 35% publicly owned,owns all unlicensed federal offshore explorationacreage more than 12 nautical miles from shore.Any activity in these blocks must be done inpartnership with ENARSA. Provincial govern-ments issue tenders for onshore projects.1Australian Taxation Office website.

2Jurisdictional scope of the Standing Council on Energyand Resources. 3NCC website.

430 19 A Close Look at the Natural Gas Industry Chain

All licences are subject to royalties, incometax, provincial sales tax and other signaturebonuses and rentals, as well as possible exportduties on oil and natural gas. The Oil and GasLaw, passed in 2014, centralises implementationof the royalty system and licensing, but leavesthe administration to provincial regulators.Before this law was enacted, provincial govern-ments had jurisdiction on oil and natural gaslicensing and operations, and many provincialgovernments took equity interests in licences.From this it is clear that provincial-level gov-ernments can become involved in relevantlicensing matters through their various oil andnatural gas departments (Figs. 19.4 and 19.5).

Due to growing energy needs, governmentshave begun to focus on stimulating investment.In October 2014, the Oil and Gas Law waspassed. This contained a series of measuresproviding incentives for investment in uncon-ventional oil and natural gas exploration andproduction, including:

• distinguishing between conventional andunconventional resources, for example byproviding unconventional assets with anexploitation period of 35 years compared to25 years for conventional resources (explo-ration periods are 13 years);

• plans to allow higher prices for natural gasproduced using unconventional means;

• creating an unconventional productionlicence, providing five years for a pilot pro-ject to become commercially viable, withroyalties to be dropped by 25% for uncon-ventional projects after the pilot phase iscompleted; and

• allowing 20% of production to be exported.

However, obstacles remain to building anunconventional natural gas industry in Argentina,including a shortage of trained labour. Theopening of the Unconventional Fields Technol-ogy Center in Neuquén Province is a step for-ward, but more is needed to build capabilities inshale natural gas technology. In addition, currentregulations do not address environmental con-cerns adequately, which could become

problematic for unconventional developmentsnear population centres.

19.1.5 Case Study 4: Mexico—Reopening the Marketand Round Zero Tender

Mexico’s oil industry is one of the world’s old-est; oil was first discovered in Mexico in 1904.By 1921, Mexico’s oil production had reached530,000 bod, accounting for 25% of the world’soil production. Following labour disputes, inter-national oil company assets in Mexico werenationalised in 1938, which led to the creation ofthe national oil company Petróleos Mexicanos(Pemex). Pemex held exclusive rights to thecountry’s oil and natural gas fields.

In the following decades, Pemex largely ranits own oil and natural gas operations, aided byinternational service companies. As a statemonopoly, its budget and financial managementwere heavily controlled by the Ministry ofFinance and Public Credit, leading in part to itsgradual stagnation. Its production volume con-tinually dropped, beginning in 2004 (Fig. 19.6).Its production volume peak was between 2004and 2005, with approximately 2.6 millionbarrels/day, as well as 3 billion ft3 of natural gas.Rapid further decline is projected for the comingyears.

In an attempt to halt production declines, in2013 the political party known as PRI beganimplementing energy reforms after 71 years.President Enrique Peña Nieto proposed anEnergy Reform Act in August 2013. The act waseventually passed in December 2013, allowinginternational oil companies and other investors toinvest once again in Mexican oil and natural gasbusinesses through three possible legal arrange-ments: service contracts, production- orprofit-sharing contracts, or licences.

To protect the national interest in Pemex, thegovernment ran a unique tender in 2014, BidRound Zero. Under the tender, Pemex had tosubmit applications for which fields and blocks itwanted to keep and relinquish the rest. Thesubmission had to demonstrate technical,

19.1 The Upstream Segment: Fiscal Policies and Licensing Systems 431

financial and operational capabilities to operateproductive assets, and, for exploration acreage,Pemex had to show it had either drilled explo-ration wells, conducted sub-surface studies or

both. The Energy Secretary and the ComisiónNacional de Hidrocarburos (National Hydrocar-bons Commission) made the final decisions onthe applications.

0 150 300 600 900 1,200kilometres

0 150 300 600 900 1,200miles

ParanaBasin

ChacoBasin

NeuquenBasin

La Paz Brasilia

Asunción

MontevideoBuenos Aires

Santiago

Sources:Wiens, 1995USGS, 2000

Golfo San JorgeBasin

Australi-Magallanes

Basin

Fig. 19.4 Argentina’s primary basins and LNG receiving stations

432 19 A Close Look at the Natural Gas Industry Chain

As a result of Bid Round Zero, Pemexretained about 83% of proven and probable oiland natural gas reserves (Fig. 19.7) and 21% ofthe prospective resources, based on commissionestimates (Fig. 19.8). Pemex was also allowed to

invite foreign investors to join in the exploration,development and production of assets it retained.

A measure like Bid Round Zero could be anattractive option for China. Such a tender wouldallow existing state oil companies to nominate

01990

200

400

600

800

1000

1200

1400

1600

1800

Billion cubic feet

Production

Consumption

Depression andfinancial crisis

Net trade

1993 1996 1999 2002 2005 2008 2011

Fig. 19.5 Argentina’s natural gas production and consumption. Source Energy Information Administration,International Energy Statistics

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Gas (kboed)

Oil (kbod)

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015E2016E2017E2018E2019E2020E

Forecast

Fig. 19.6 Oil and natural gas production in Mexico. Source Wood Mackenzie

19.1 The Upstream Segment: Fiscal Policies and Licensing Systems 433

assets they would like to retain, freeing upother assets for new entrants. The move couldattract greater energy investment and acceler-ate the development of unconventional shalenatural gas production. Increased domesticproduction would reduce the country’s depen-dence on foreign natural gas, which rose fromzero in 2005 to 32% of domestic consumptionin 2013.

In late 2014, the National HydrocarbonsCommission began Bid Round One, which willbe a staged tender and include shallow waterexploration, shallow water development, onshoreprojects, enhanced production for the Chiconte-pec field, unconventional oil and natural gas, anddeepwater projects (Fig. 19.9).

Without question, the most important factor inthese events has been the speed and determina-tion of the Mexican government in taking clearand transparent steps toward energy reform,including the 20%+ of discovered oil/natural gasfields provided to international oil companiesfollowing the final Round Zero Tender. It isworth considering which of these measures couldsuit China’s situation, especially in the acceler-ated exploration and development of unconven-tional natural gas and shale natural gas, as well as

in attracting suitable international oil companiesand private investors to accelerate the trials inthis process. It is also worth considering whetherMexico will continue on its path of open policiesafter the six-year term of President Enrique PeñaNieto.

19.2 The Midstream Segment:Building Infrastructureand Managing Access

Midstream assets—transmission pipelines, LNGregasification terminals and storage facilities, anddistribution networks—are natural monopolies.They have high fixed capital costs of investmentbut low, and decreasing, marginal costs ofoperation. As a result, it is economically moreefficient if fewer of these assets are built and fullyutilised, rather than assets being duplicated anddividing volumes among them throughcompetition.

Natural gas pipelines—both transmission anddistribution—have more significant naturalmonopoly characteristics than LNG terminals orstorage facilities. The economies of scale forLNG terminals and storage facilities are not as

2P Reserves Perspective Resources

Available to IOCs through2015 or future Bid round

Available to IOCs through2015 or future Bid round

21%

17%

79%

83%

1) Deepwater Gulf of Mexico

2) Shallow water Gulf of Mexico

3) Unconventionals onshore

Including enhanced oilrecovery of mature fields

Potential JVwith IOCs

Fields/blocks awarded in Round 0

Fig. 19.7 Pemex reserves analysis after bid round zero

434 19 A Close Look at the Natural Gas Industry Chain

Region awarded to Pemex

New region awaiting sale

SabinasOaxaca

Name of the basinState name

YucatanPlatform

Leased region and labourcontract transfer region

Mexico: Round 0 bidding results and first round tender possible regions

Yucatan

Chihuahua

Coahulas

Sabinas

Nuevo Leon

Tamaulipas

Durango

Zacatecas

San Luis Potosi

Oaxaca

Campeche

QuintanaRoo

Chiapas

Tlaxcala

Puebla

Aguascalientes

Nayarit

Tampico Misantla

Burgos

Deepwater

Vera Cruz

Southeastern Basin

Upstream assets for sale –reserves and assets

Leased

New Regions

Total

1,557

3,782

5,339

14,606

14,606

-

Confirmedreserves(mmboe)

Unconfirmedreserves(mmboe)

Fig. 19.8 Pemex unconfirmed resources, 2014. Information source HIS, PFC Energy

Shall water:Exploration

Shall water:Development

Onshore Chicontepec andUnconventionals

Deepwater

Publicationof terms

December2014 January 2015 February 2015 March 2015 April 2015

Opening ofdata rooms January 2015 January 2015 March 2015 April 2015 May 2015

Fig. 19.9 Suggested timeline for a new round of tenders

19.2 The Midstream Segment: Building Infrastructure and Managing Access 435

great as those for pipelines. Hence, for a givenmarket size, the optimal number of facilitiesrequired will be greater compared to the numberof pipelines required to serve a market of similarsize. Moreover, LNG terminals and storagefacilities can compete with other similar assetsonce they are connected through a pipelinenetwork.

In the United States, LNG receiving stationsare viewed as upstream assets, because they areseen as extensions of upstream wells. However,in Europe, LNG receiving stations are midstreamassets. The difference in perception depends onthe degree of competition in the market. In theUnited States, LNG receiving stations competewith domestic products, and thus they seen ascomparable to domestic wells. In Europe, themajority of competition comes from importednatural gas, and thus LNG receiving stations areviewed as part of the transmission network.If LNG receiving stations are seen as upstreamassets, then regulatory measures will be different,and there will be fewer concerns about themonopolistic nature of the receiving stations. InChina, there is uncertainty regarding the charac-ter of LNG receiving stations, because develop-ment is lacking in competitive natural gasmarkets.

The natural monopoly characteristics of mid-stream infrastructure mean that governmentoversight and regulation is required to preventaccess being restricted and monopoly rents beingcharged. A monopoly owner of midstreaminfrastructure has an incentive to charge veryhigh prices to maximise its profits, reducingpipeline utilisation in the process. It may there-fore be necessary to unbundle midstream assetsfrom vertically unified companies. Examples ofthe options for accomplishing this can be foundby looking at the international experiences seenin the case studies.

Even if midstream assets do not belong to agiven vertically unified company, if no oversightis implemented, there is still the possibility ofproblems arising. On the one hand, independentowners need upstream and midstream partici-pants to use their midstream assets. On the otherhand, independent owners also have an incentive

to collect the highest price possible to maximisetheir profits. Regulation is the solution, to ensurethat usage rights to midstream assets are avail-able to all parties (in other words, third-partyaccess).

Regulatory institutions will often need tounbundle and re-establish third-party access. Inpractice, even if there are rules for third-partyaccess, there are still many means to excludethird parties, such as lack of transparency overpricing. Using regulatory institutions to imple-ment strict regulation of third-party access canprevent such anti-competitive behaviour. At thesame time, many regulatory institutions believethat through unbundling such motivations can beeliminated, which is an effective supplement tothird-party access rules.

In a growing market in need of investment,such as China, regulatory frameworks shouldensure that investments can receive sufficientprofits, encouraging capital investment. Regula-tion of the collection of usage right fees can helpasset owners to recover their capital. Regulationof fee collection can employ either a “regulatedreturn” system or a “regulated tariff” system.These two methods are very similar, but havediffering risk allocations in terms of midstreamasset users and owners. Under a “regulatedreturn” oversight approach, the owner of themidstream is authorised to receive a high enoughrate of return to act as a motivation for futurepipeline construction. Under the “regulated tar-iff” regime, such tariffs should likewise be suf-ficiently high to provide an incentive for futureasset investments.

The challenge therefore faced by governmentdepartments is to achieve a balance betweenmaking usage rights available and encouraginginvestment in midstream assets. This balance canbe achieved through a precisely designed regu-latory framework, which will need to include thefollowing key factors: rules for liability andstandards, a consensual pricing framework forthird-party access and a mechanism to assurereturns for investors. In some frameworks, whenregulatory institutions solve downstream marketstructure or legacy issues, these mechanisms canbe used to balance out two different goals.

436 19 A Close Look at the Natural Gas Industry Chain

When a country’s regulatory mechanismsreflect various domestic factors, such evolutionsand influences can be referenced by China. Weexamine three case studies below: the third-partyaccess arrangements of the United Kingdom inthe North Sea; Singapore and Japan’s LNGexperience; and Shell’s IPO of its Shell Mid-stream Partners enterprise in the United States.These case studies yield five primary lessons:

• if it is to promote usage rights and invest-ment, regulation must strike a balancebetween the economic interests of midstreamasset users and owners;

• regulatory frameworks must be stable, reli-able and clear, thereby facilitating generalrisk minimisation and stimulation ofinvestment;

• mechanisms based on rules can provide ameans of resolution for this;

• at the same time as generating revenue, reg-ulations such as mandatory third-party accessrequirements can ensure that midstream assetsare used efficiently;

• even while balancing usage rights andinvestment, regulatory institutions can alsoconsider market structure in addition to thevalue chain. Current regulatory policy willinfluence future economic opportunities.

19.2.1 Balancing Third-Party Accessand InvestmentIncentives

Third-party access needs to be balanced againstincentives for further investment in midstreaminfrastructure, especially in growing marketssuch as China. While allowing for third-partyaccess, the regulatory framework also needs toprovide adequate incentives—and returns—onfuture investment in the midstream. For example,access charges can be regulated to enable assetowners to recover fixed costs.

Regulated charging regimes can be of twotypes: either regulating the rate of returnachieved by midstream infrastructure owners orregulating the tariff charged for access to mid-stream infrastructure. Under a regulated returnregime, the owner is granted a rate of return onits midstream asset value that is high enough toprovide incentives for future investment inmaintaining and extending the infrastructurenetwork. Under a regulated tariff regime, thetariff is set at a level that provides incentives forfuture asset investment. Both approaches aresimilar, but vary in the distribution of risk amongthe users and the owners of midstream assets.

While an individual country’s regulatoryregime reflects a variety of domestic factors, areview of the evolution and impact of theseregimes can offer insights for China in achievinga balance between returns to investment andaccess to midstream assets. The oversight ofnatural gas infrastructure reflects a country’sexperience in the realm of natural gas marketliberalisation, as well as its systemisation andgovernment and policy priorities. There is nosingle oversight system that can be transplantedfrom one jurisdiction to another. In fact, ifresidual issues, systems and political factors arenot taken into consideration, replicating anothercountry’s oversight structure will result in failure(United Nations Economic Commission forEurope 2012). However, it is possible to learn bycomparing existing oversight frameworks thatthe key is to balance the attainment of public andprivate goals.

Regulatory institutions often need to unbundlethird-party access. In reality, even if there arethird-party access rules, there are still manymeans by which to exclude third parties—forexample, a lack of transparency over pricing ofcapacity. Regulatory institutions can preventsuch anti-competitive behaviour by rigorousoversight of third-party access rules, but manyregulatory institutions believe that unbundling isan effective solution that eliminates the incentivefor anti-competitive behaviour.

19.2 The Midstream Segment: Building Infrastructure and Managing Access 437

In growing markets in need of investment,such as China, regulatory frameworks shouldalso allow for sufficient profits, thereby providingmomentum for future midstream investment.Using a “regulated return” system, owners ofmidstream assets are allowed sufficiently highrates of return that there is an incentive for futurepiping construction. Under a regime of “regu-lated tariffs”, such tariffs should likewise besufficiently high to provide an incentive forfuture asset investments.

The challenge for government departments istherefore to achieve a balance between mid-stream asset usage rights and investment, asshown in Fig. 19.10. Within a carefully designedregulatory framework, it is possible to achievethis goal. Many countries have achieved suchsuccess, and the regulatory mechanisms that maybe of interest to China as precedents include:

• Rules: Regulators establish and enforce ruleson liability and standards.

• Prices: Regulators provide a framework forinvestors and users to agree on prices in boththird-party-access and regulated-returnregimes.

• Mechanisms to reduce risk: Regulatorsminimise risk for investors and users.

19.2.2 International Experienceof Managing MidstreamAsset Access

The case studies provide five overarchinginsights:

• Regulation balances the economic interestsof users and owners of midstream assets tofacilitate access and investment. Economicopportunities drive demand for access to andinvestment in infrastructure. However,demand by itself is an insufficient conditionfor access and investment, as users andowners often cannot agree terms, oftenbecause of the asset owner’s natural mono-poly power. Thus, players require a strongregulatory framework that grants access to themidstream and provides incentives forinvestment. For example, experience in Sin-gapore and the United Kingdom in estab-lishing third-party access shows that strongregulation can assist users of assets in theirnegotiations with midstream operators.The experience of the United States and Japanhas shown that in terms of risk/reward forinvestors, oversight is beneficial in creatinginvestment opportunities and encouraging

Rules

Prices

Risk reduction

Regulatorymechanisms

Incentivesto invest

Access toassets

Fig. 19.10 The balance of factors needed in the regulatory framework

438 19 A Close Look at the Natural Gas Industry Chain

more funds to be channelled to the construc-tion of midstream infrastructure.

• Regulation can ensure that the midstreamasset is used efficiently. Regulation, such asmandatory third-party access requirements,can ensure that players upstream and down-stream can access the pipeline and that the feescharged and returns made by the owner of themidstream asset are fair. Regulation can takevarious forms, such as negotiated or regulatedaccess, but all forms of regulation are aimed atincreasing access while ensuring reasonablereturns to the asset owner and supporting suf-ficient investment to maintain energy security.Controls implemented according to specificcircumstances can utilise agreement negotia-tions or controls to achieve third-party access.The British North Sea owner and user nego-tiations successfully implemented third-partyaccess, with new companies able to developsmall-scale gas fields without needing toinvest in the construction of new piping.Midstream asset owners can obtain revenuefrom amortised assets, and the governmentcan obtain relevant oil and natural gas pro-duction taxes related to asset development.However, in the rapidly growing market ofChina, the experience from the North Sea isof limited use. There is very little need fornew investment in piping in the North Sea,and this made it easier for midstream facilityowners and users come to an agreement. Thisis not the case in China, and the facilityowners tend to look to use their position tocollect monopolistic lease amounts. As a

result, China’s rapidly growing emergingmarket should give greater consideration tousing mandatory third-party access systems tostimulate investment in midstream facilitiesby promoting recovery of capital and rea-sonable risk returns.

• The regulatory framework should bestable, credible and clear to minimise riskand encourage investment. The success ofthe master limited partnership in the UnitedStates has been in large part the result ofgovernment providing a statutory basis forpartnership treatment: federal rules on quali-fying income and assets gave all parties thenecessary certainty to proceed. In the UnitedKingdom, the combination of a statutory,rules-based framework and the threat ofarbitration ensures that when negotiatingthird-party access, parties have similarexpectations and incentives, with it beingvery rare that events end in disagreement. Theregulatory layers collectively help to reduceuncertainty for participants (see Fig. 19.11).In contrast, the absence of enforcement hasmeant that third-party access rules are notcredible, and midstream infrastructure is forthe most part not open to third parties.

• Regulators should take into account mar-ket structures along the value chain whenbalancing access and investment. The nat-ure of competition along the entire valuechain influences regulatory choices. Forexample, Japan has a fragmented marketwhere all natural gas is imported by LNGshipments and there is limited interconnection

Regulatoryframework

Voluntaryframework

Disputeframework

• Energy Act 2011

• Departmental regulations on the development of gas resources

• Infrastructure Code of Practice (ICOP)

• ICOP Guidelines

• Process for dispute resolution

• Referral to Secretary of State

Fig. 19.11 The three layers of agreements supporting North Sea usage rights

19.2 The Midstream Segment: Building Infrastructure and Managing Access 439

between regional markets. This means thatcompetition is hard to achieve and brings fewbenefits, and as a result third-party access islimited.In the United Kingdom, the natural gas mar-ket was originally created upstream, withcompetitive downstream markets only start-ing in the 1980s, and thus its regulatoryframework design focus is on the promotionof midstream usage rights.In Singapore, private funding for anopen-access LNG terminal fell through as aresult of sufficient pipeline gas supply to meetdemand and liberalised downstream markets,which favoured cheaper pipeline gas overmore expensive LNG imports. The govern-ment stepped into develop the LNG terminalas a means of diversifying sources of supplyand enhancing energy security. Ownership isdeliberately separated from operation of themulti-user LNG terminal, and the governmenthas developed a framework to open the ter-minal to third-party access. At the same time,the government has also sought to securedownstream demand for LNG by restrictingnew pipeline imports (Table 19.1).

• The regulatory framework a country pur-sues affects the set of available policychoices. The regulatory legacy can affect thelevel of utilisation of infrastructure, the levelof activity by new entrants and the form ofprivate contracts. The private sector’s

capacity to identify and develop economicopportunities is a function of how a country’sregulatory regime and its infrastructure haveevolved.In the first years of development of North Seagas, large companies obtained permits fromthe government and independently investedto develop the oil and gas fields. In the past12 years, because of drops in yields, these oiland gas fields have seen reduced rates ofreturn, and there is less interest from largecompanies. However, the amortised assetsthat they possess can be transferred to smallerenterprises to develop small-scale oil fieldsthat pay the larger companies for usage oftheir assets. Therefore, from the 1960s to the1990s, the United Kingdom’s regulationsystem has increased the opportunities today.In Japan, even though on the surface LNGreceiving stations seem to be accessible,regulators have chosen to use negotiatedapproach a third-party access, rather thanmaking it mandatory. This approach givesfacility owners a powerful negotiating posi-tion. Combined with a lack of competitionupstream and downstream, there is a push forsuppliers and upstream facility owners to signlong-term supply agreements. Without reli-able access systems, new entrants to themarket generally build new LNG receivingstations in order to take advantage of down-stream business opportunities.

Table 19.1 The influence of the nature of competition on midstream infrastructure regulation choices

Market Nature Challenges for asset owner/user Consequence for regulation

United Kingdomupstream anddownstream

Liberalised markets Ease of entry, but investmentcosts high

Framework for asset ownersand users to negotiate terms ofaccess

Japandownstream

Monopolisticgeographic markets

Lack of interconnection createsconcern over security of supply

Facilitate construction of newLNG terminals with limitedthird-party access

Singaporedownstream

Liberalised marketbut fragmentedinfrastructure

Uncertainty that downstream canbe accessed given pipeline naturalgas supplies

Pipeline natural gas moratoriumand midstream third-partyaccess

440 19 A Close Look at the Natural Gas Industry Chain

19.2.3 Case Study 1: The UK NorthSea—The Frameworkfor NegotiatedThird-Party Access

The United Kingdom’s North Sea experienceillustrates one approach to arranging access tomidstream infrastructure. In particular, it focuseson the government’s efforts to develop a regu-latory framework that grants new entrants accessto the pipelines built by earlier North Sea fielddevelopers.

Several key lessons emerge from thisexperience:

• A liberalised market with clear rulesencourages new investment. Output fromthe North Sea was declining and costs wererising. However, new firms that specialise indeclining fields were able to enter the liber-alised market, which has provided assetowners with new business and the govern-ment with greater tax revenue.

• Users of assets have been favoured overowners to some extent. As midstream assetswere already in place as a legacy of pastexploration of the North Sea, and faceddeclining utilisation, new users seekingaccess had greater bargaining power as assetowners had few alternative customers. Inaddition, by encouraging access, the govern-ment could benefit from greater hydrocarbonproduction tax revenues associated withresource development.

• Where interests between midstream assetowners and users are broadly aligned, avoluntary agreement on access provisionbetween the parties is feasible. The UnitedKingdom had a layered regulatory frameworkto access. Parties were encouraged to reachvoluntary agreements, with clear rules fordispute resolution and, ultimately, a legalframework if voluntary agreements could notbe reached. This system has worked well,with many parties reaching voluntary agree-ments, because interests are broadly alignedand the rules are clear and credible.

China faces a different gas market contextthan seen in the North Sea example. China’snatural gas market is growing rapidly, whereasoutput from the North Sea was declining. As aresult, the economic pressures felt by UK assetowners that supported negotiated third-partyaccess—specifically, existing assets with declin-ing utilisation—would not be as prevalent inChina, where limited midstream capacity givesasset owners more bargaining power. Neverthe-less, the North Sea experience demonstrates howa credible regulatory framework can help achieveagreement and avoid disputes.

1. Background

The regulatory regime for natural gas explo-ration in the United Kingdom from the mid-1960sthrough to the 1980s was characterised by liber-alisation and increasingly competitive markets.When the first licences were offered by govern-ment, major companies chose to develop oil andnatural gas fields as stand-alone installations.Upstream pipelines and offshore processingfacilities were usually built by field owners toprocess and transport output from specific oil andnatural gas fields. However, since then, recoveryrates—and returns—from these fields have fallen,and larger enterprises have been less interested indeveloping the remaining resources.

As spare capacity became available inpipelines and terminals, opportunities arose. Theexistence of their depreciated pipeline assets hasallowed smaller players to enter the industry andexploit smaller fields, paying larger companies touse their assets to transport oil and natural gas tothe mainland. A liberalised downstream marketmeant there was a ready market for small-fielddevelopers if they could access midstream assets.There were benefits to infrastructure owners, too,in terms of additional revenue from grantingthird-party access to new users and from defer-ring the costs of decommissioning these assets.The government saw opportunities in terms ofadditional job creation, maximising recovery ofNorth Sea oil and gas resources, and continuedproduction tax revenues.

19.2 The Midstream Segment: Building Infrastructure and Managing Access 441

The 1996 Network Code established the rulesand procedures for third-party access to pipelinesand introduced a regime for daily balancing,while the Petroleum Act of 1998 set out the rulesaround upstream exploration and production. Bythe early 2000s, liberalisation of the sector wascomplete, with the creation of the National Gridas a fully unbundled, independent transmissionsystem owner and operator of the United King-dom’s natural gas and electricity markets in2002.

However, the legal framework by itself wasinsufficient and left room for commercial dis-putes between owners and users of the infras-tructure. Through the 1990s, there were concernsthat the tariffs to access infrastructure were toohigh compared to costs and risks of developingsmall fields. This led to a new process fornegotiating access. The legislative and regulatorychanges provided a statutory basis for arules-based framework, including a process forarbitration of disputes, which helped co-ordinateactivity and create common expectations.

2. The framework for negotiated third-partyaccess

Working with government, the natural gasindustry sought to develop voluntary frameworksfor third-party access. The first industry offshoreCode of Practice was introduced in 1996. It soughtto establish a timely process for seeking, offeringand negotiating third-party access to natural gasinfrastructure in the North Sea. It also sought toensure that access was easy and fair, with termsoffered on a negotiated, non-discriminatory basis.

In 2004, market participants agreed to astrengthened code, the Infrastructure Code ofPractice. The code outlined best practice andexpected behaviour in conducting negotiationsfor access to infrastructure. According to theindustry group Oil & Gas UK, the code wasintended “to facilitate the utilisation of infras-tructure for the development of remaining UKCS[United Kingdom continental shelf] reservesthrough timely agreements for access on fair andreasonable terms, where risks taken are reflectedby rewards”. Its main tenets are:

• Parties uphold infrastructure safety andintegrity and protect the environment.

• Parties follow the Commercial Code ofPractice.

• Parties provide meaningful information toeach other before and during negotiations.

• Parties support negotiated access in a timelymanner.

• Parties undertake to settle disputes if neededthrough the Automatic Referral Notice pro-cess which involves the UK ministerresponsible for energy.

• Parties resolve conflicts of interest.• Infrastructure owners provide transparent and

non-discriminatory access.• Infrastructure owners provide tariffs and

terms for unbundled services, where reques-ted and practicable.

• Parties seek to agree on fair and reasonabletariffs and terms, where risks taken arereflected by rewards.

• Parties publish key commercial provisionsfrom the agreements.

Companies seeking access to infrastructurefalling within the scope of the third-party accessprovisions of the Energy Act 2011 must apply firstto the owners. However, the act also allows thegovernment minister responsible to take the ini-tiative and set the terms in cases where there is norealistic prospect of reaching an agreement. If theparties are unable to agree to satisfactory terms andconditions, the prospective user may apply to theminister to resolve the dispute. The minister canrequire access to pipelines, associated offshoreproduction facilities, and onshore natural gasprocessing facilities, and dictate the appropriateterms. In most cases, these terms will be in linewith those offered by infrastructure owners ina competitive environment. In such cases, thelegislation stipulates that appropriate noticesbe issues to the parties to implement the terms.While a dispute resolution procedure exists and theminister can intervene to adjudicate, the third-party access framework is essentially self-enforcing and has rarely resulted in dispute.

A crucial factor in the success of the frame-work is that it reduces commercial risk by giving

442 19 A Close Look at the Natural Gas Industry Chain

stakeholders guidance on tariffs and a varietyof other terms. Terms of agreements tend to bequite specific with regard to liability, trans-parency and technical standards. Terms coveredoften include:

• the basis for modification of infrastructure, ifnecessary;

• the duration of service;• identifying which party has ownership and

risk exposure to the natural gas while it iswithin the infrastructure owner’s facility;

• capacity terms and the ability of the owner tochange them;

• charges for providing the service;• rights of both parties to terminate the agree-

ment; and• liabilities covering damage and loss relating

to people, property and pollution.

Within the regulatory framework, both ownerand user considerations are important in deter-mining terms of access. Competition and other

market forces, the user’s ability to pay and con-tract flexibility are all key considerations to betaken into account when agreeing the terms ofaccess (Fig. 19.12).

Owners and users have flexibility when nego-tiating access. For example, when agreeing toprovide access, the infrastructure owner reservescapacity in its system for the shipper. The shippergains certainty that the required capacity will beavailable, subject to normal operational avail-ability, and the infrastructure owner will notmarket reserved capacity to others. In turn, theinfrastructure owner will want to mitigate the riskof the user booking more capacity than required,such as through send-or-pay provisions, whichguarantee minimum payment regardless of theextent to which the reserved capacity is used. Indeclining fields, such as in the North Sea, terms ofaccess are often based on operating costs, plus arisk premium. This contrasts with the approach fornewer fields, where the terms of access also tend toinclude operating costs, as well as capital costrecovery.

Owner considerations User considerations

The cost and risks of providing the service

User ability to pay

Whether they are competing against other owners

Whether an escalation formula can beadded for long-term contracts

Whether existing business will be affected by theprovision of a service

Whether the owner’s tariff is reasonablerelative to the user’s risk and reward

Whether there are competing owners

Flexibility required for long-term contracts

Regulatory frameworkLegislative basis | Voluntary code | Arbitration process

Fig. 19.12 Analysis of regulatory frameworks

19.2 The Midstream Segment: Building Infrastructure and Managing Access 443

19.2.4 Case Study 2: Japanand Singapore LNG—National Powerand the Influenceof Oligopoly

Singapore and Japan have had entirely oppositeexperiences in the development and control ofmidstream infrastructure, especially in terms ofLNG regasification receiving stations (Table 19.2).However, the experiences of the two countrieshighlight that for a balance to be struck betweenaccess to and investment in midstream infrastruc-ture, both a streamlined industry chain and con-sideration of the influence of the market structureare necessary.

1. Singapore LNG: national power involved ininfluencing construction of infrastructure

Singapore has no domestic natural gasresources and is dependent on imports. Naturalgas consumption grew rapidly in the 2000s, from1.3 billion m3 in 2000 to 8.7 billion m3 in 2010.

Into the early 2000s, the island-state’s naturalgas market was characterised by governmentownership along the value chain through Singa-pore Power Group and SembCorp, limited or nounbundling in commodity and transportationactivities, significant price controls on electricity,and generally homogeneous supply throughpipelines deliveries from Malaysia and Indone-sia. In 2004, the country began progressive

liberalisation, resulting in a competitive mid-stream and downstream natural gas market,including regulated open-access networks, asignificant number of primarily private marketparticipants, unbundled commodity and trans-portation activities, and oversight entrusted to anindependent energy regulator, the Energy MarketAuthority (Fig. 19.13). The government’s role islimited to ensuring fair access to infrastructure.

In 2006, the government decided to develop anLNG regasification terminal to enhance energysecurity by diversifying sources of supply awayfrom existing pipeline gas. However, meeting thepolicy objective on energy security was not con-sistentwithSingapore’s liberalised and competitivewholesale and retail markets. Singapore had awell-functioning domestic natural gas market, withsufficient supply frompipelines, and therewas littlemarket demand for an LNG regasification terminal,despite the energy security benefits it offered.

The country originally granted a licence to aprivate consortium of PowerGas and GDF Suez tomake the necessary investment, but this arrange-ment collapsed in 2009 because of a fundingshortfall.While the problemwas linked to the 2008global financial crisis, it also reflected the compet-itive nature of the downstream market, whichdampened the commitment among potential cus-tomers of the LNG facility. The benefits of diver-sifying supply were outweighed by the risks ofbeing a first mover to a more expensive anduntested source, reducing the incentive for energycompanies and end users to switch supply sources.

Table 19.2 Differing LNG management systems resulting from different market traits in Singapore and Japan

Influencing factor Singapore Japan

Industry organisations Separation of midstream fromdownstream assets

Vertically integrated supply chains

Downstream market Liberalised except for moratorium onpiped natural gas

Monopolistic due to lack of geographicintegration

Shipping andcommercial activities

Functional unbundling No mandatory functional unbundling

Midstream assetownership

Public utility (terminal) Private

Access mechanism Third-party access Bilateral access arrangements, but with nocredible enforcement

Support mechanisms Rules-based framework and arbitration Ease of regulation on construction of newterminals

444 19 A Close Look at the Natural Gas Industry Chain

In 2009, the government announced it wouldtake over the development and ownership of theLNG terminal. It established the Singapore LNGCorp. to develop and operate the terminal.The facility, which opened in 2013, was regu-lated by the Energy Market Authority. It was

open access, with third-party access arrange-ments underpinned by a rules-based regulatoryframework, including a dispute-resolution pro-cess, and public ownership of the infrastructurewas deliberately kept separate from commercialoperation.

Industrialend usersEnd Users

Retail

Wholesale

Transmission& distribution

Importer

Upstream

SembCorp(49.5%)

End users

Retail

Wholesale

Transmission& distribution

Importer

UpstreamIndonesia

(pipeline imports)Malaysia

(pipeline imports)BG

(LNG)PavilionEnergy

SembCorp (49.5%)

LionPower

Keppel(20%)

SingaporePowerGroup(100%

governmentownership)

Indonesia(pipeline imports)

Malaysia(pipeline imports)

LNGterminal

SLNG(100%)

Singapore Power Group (100%)

PavillionEnergy(100%) Singapore Gas Green

Energy Supply

Industrialend users

SembCorpKeppel

Lion PowerYTL

Huaneng Int’lPacific Light

Hyflux

2014

2015

Fig. 19.13 Market diversification in Singapore, 2004 versus 2014

19.2 The Midstream Segment: Building Infrastructure and Managing Access 445

The regulatory framework established by thegovernment and the Energy Market Authoritywas designed to guarantee fair and transparentaccess to midstream infrastructure while reducinginvestor risk. It comprised three key elements:

• Aggregator: A private company, BG, wasappointed natural gas aggregator to securesupplies. By pooling demand from largeusers, Singapore maximised its negotiatingpower on global markets and secured com-petitively priced supply.

• Framework: Terminal access rules agreedbetween BG and Singapore LNG provided acommercial framework for other third partiesthat sought access and enabled a greaterdegree of forward planning by energycompanies.

• Support: The government offered a purchaseagreement with any power-generation com-pany that committed to LNG supply and atariff structure that allowed companies to passthrough the cost of LNG.

The terminal had the capacity to handle threetimes as much natural gas as the country con-sumed. While it initially opened with a 3 mil-lion tonnes per year capacity, the opening of itsthird tank in 2014 doubled capacity to 6 mil-lion tonnes. A fourth tank is expected to open by2017, which would bring total capacity to9 million tonnes. The terminal could eventuallyaccommodate seven tanks, for a total capacity of15 million tonnes.

Because capacity was planned to exceeddomestic requirements, the government has alsosought to secure downstream demand for LNG.To do this, the government introduced controlson new pipeline imports in 2006. These controlsallow existing contracts to be honoured, but newcontracts were subject to approval from theEnergy Market Authority. The decision movedSingapore away from its free market approachand introduced a measure of uncertainty aboutthe evolution of Singapore’s natural gas markets.While the moratorium on new pipeline imports islikely to be lifted, it remains unclear whether the

government will continue to limit direct compe-tition between pipeline natural gas and LNG.

Key lessons from Singapore’s experience ofdeveloping and regulating its midstream LNGinfrastructure include:

• Markets can face challenges when invest-ing to achieve policy objectives. Singaporehad a well-functioning domestic gas market,with sufficient supply from pipelines. Giventhis, there was little market demand for anLNG terminal, despite the energy securitybenefits it offered.

• Regulation is needed to deliver policyobjectives. As the market would not providethe investment, the government had to step inand invest in the LNG terminal itself. At thesame time, the government also sought tosecure downstream demand for LNG byrestricting new pipeline imports. However, inrecognition of the efficiency of market forces,the government operated the terminal as amulti-user access terminal to enable compe-tition downstream between importers.

• Regulators have an important role in set-ting up the commercial framework foraccess. The terms of access were clear andcredible, allowing private companies to makelong-term plans despite the uncertainty thatcomes from an open access terminal, such asavailable docking times and capacity.

2. Japanese LNG: oligopoly restrictingthird-party access

Japan imports most of its natural gas, and itsimports are exclusively LNG. The country has 30operating LNG terminals, with a total capacity of172 million tonnes a year, a level well abovedomestic demand. However, Japan remains con-strained by howmuch LNG it can receive, based onberthing, ship size and other infrastructure limita-tions. Five additional terminals are currently underconstruction and expected to become operational by2016, adding capacity of at least 7 million tonnes.

The majority of LNG terminals are near mainpopulation centres and manufacturing hubs around

446 19 A Close Look at the Natural Gas Industry Chain

Tokyo, Osaka and Nagoya (Fig. 19.14). They areowned by local power companies, either aloneor in partnership with natural gas companies, andthe same companies own much of Japan’s LNGtanker fleet.

Japan has unique energy fundamentals thatmake midstream assets particularly important.Japan has no domestic production of natural gasand few other domestic sources of energy.

The country also does not have a well-developed or integrated domestic long-distancenatural gas transportation network, partly becauseits mountainous geography limits the developmentof a network. Instead, LNG regasification terminalshave proliferated along the coastline and take thevital role of a transmission network. However, as aresult of these conditions, downstream markets arefragmented and dominated by regional monopo-lies. Domestic natural gas transport and distribu-tion infrastructure, including LNG terminals, is

owned and operated by vertically integrated privatenatural gas and power companies. The natural gasmarket remains largely uncompetitive, with fourcompanies supplyingmore than 70% of natural gasand almost all LNG terminals owned by a smallnumber of companies and no actual third-partyaccess.

Open access in LNG infrastructure was dis-cussed in the US-Japan Third Joint Status Reportunder the Enhanced Initiative in 1999, an eco-nomic co-operation agreement between the twocountries. In response, the Japanese governmentamended the Gas Utility Act in 2003 and intro-duced an open-access scheme that obliged natu-ral gas companies to define preconditions fornegotiated access. Further transparency require-ments related to the capacity information forLNG storage and facilities were also introduced.The changes were intended to act as a guide forinfrastructure users, but did not go far enough:

Existing pipelines

Pipelines under planning or construction

Pipelines under consideration

LNG terminals in operation

LNG terminals under const./planned

Ishikari Hokkaido

Hachinohe

Shin-Minato

JAPANShin-Sendai

Niigata

Hitachi

TokyoSodegaura

Futtsu

NaoetsuJouetsu

Yoshinawa

Okinawa0 40km

KmN

0 100 200

KagoshimaNagasaki

FukuokaHibiki

Tobata ShikokuSakaide

Wakayama

SenbokuSakai

Yanai

HatsukaichiMizushima Himeji Kawagoe

Yokkaichi Chita Midorihama

OhgisimaHigasi-OhgisimaChita

Honshu

Toyama

Sodeshi

OhitaKyushu

Pacific Ocean

Fig. 19.14 Japanese LNG facilities and their proximity to large cities and manufacturing hubs. Note This documentand any map included here are without prejudice to the status of or sovereignty over any territory, to the delimitation ofinternational frontiers and boundaries and to the name of any territory, city or area. Source IEA

19.2 The Midstream Segment: Building Infrastructure and Managing Access 447

third-party access to terminals was characterisedas “desirable” and LNG terminals were notclassified as “essential facilities”. As a result,while a mechanism for access exists, the regu-latory framework does not promote ease ofaccess. Users face a lengthy application process,the timing, flexibility and tariffs are unclear, andthere is no arbitration or dispute resolutionprocess.

Since the changes were introduced, no com-pany has effectively negotiated third-partyaccess. Incumbents have successfully arguedagainst third-party access, claiming that regulatedthird-party access, such as in Singapore, maycreate disincentives for investment in natural gasinfrastructure and hamper energy security. As aresult, regulators have tended to promoteinvestment over access. Lack of downstreamcompetition has also led to LNG shippers andLNG terminal owners signing long-term supplycontracts, which make it more difficult for new-comers to enter the market.

Natural gas market liberalisation in Japan hasbeen ineffective. The country has rules in placefor market liberalisation, such as retail priceliberalisation for the non-household sector andthird-party access rules. However, natural gasmarket reform has been piecemeal. Third-partyaccess rules have not been complemented bymandatory unbundling or by other measures toincrease competition in downstream retail mar-kets. If the market were to be liberalised, reformis needed on all fronts: while effective third-partyaccess facilitates competition, the lack of down-stream competition has prevented third-partyaccess from being effective.

Energy security remains the primary policypriority. Japan’s regulatory regime cannot focuson minimising costs as vigorously as that ofcountries with more favourable fundamentals,such as China, which has greater energy securityand can build a national transmission network.

Key lessons from Japan’s experience ofdeveloping and regulating its midstream LNGinfrastructure include:

• Japan has unique energy fundamentalsthat make midstream assets very impor-tant. The country had no domestic productionof gas and few other domestic sources ofenergy, and its mountainous geography lim-ited the development of a national transmis-sion network. As a result, energy security wasa high priority, and LNG terminals played therole of a transmission network by providingaccess at points along the coastline.

• Japan has experienced large investments inmidstream assets. Japan has invested in alarge number of LNG terminals, which werewarranted from an energy security andgeography perspective. Incumbents havesuccessfully argued against third-partyaccess, claiming that regulated third-partyaccess, such as in Singapore, may createdisincentives for investment in natural gasinfrastructure and hamper energy security. Asa result, regulators have tended to promoteinvestment over access.

• Gas market liberalisation in Japan hasbeen ineffective. Japan had rules in place formarket liberalisation, such as retail price lib-eralisation for the non-household sector andthird-party access rules. However, in practicethe market remained uncompetitive, with fourcompanies supplying more than 70% of nat-ural gas and almost all LNG terminals ownedby a small number of companies with nomeaningful third-party access.

• The failure of liberalisation demonstratesthe importance of regulating across thevalue chain. Gas market reform in Japan hasbeen piecemeal. Third-party access rules havenot been complemented by mandatoryunbundling or by other measures to increasecompetition in downstream retail markets. Ifthe market were to be liberalised, reform isneeded on all fronts: while effectivethird-party access facilitates competition, thelack of downstream competition has pre-vented third-party access from beingeffective.

448 19 A Close Look at the Natural Gas Industry Chain

19.2.5 Case Study 3: The UnitedStates—Master LimitedPartnerships

In the United States, a unique corporate struc-ture, master limited partnerships, enables own-ership of midstream assets to be reallocated toowners with appropriate risk profiles. Thestructure facilitates the transfer of midstreamassets from organisations focused on high-risk,high-return activities, such as oil and gasexploration and development to organisationsseeking low-risk, low-return assets, such aspension funds. While the case study focuses onoil pipelines, it is applicable to midstreaminfrastructure more generally.

Key lessons from the US experience withmaster limited partnerships include:

• Midstream assets are low-risk, low-returnassets and can attract significant invest-ment. Once constructed, midstream assetssuch as pipelines have a relatively simplebusiness model, especially in markets withhigh demand and regulated charges, such asthe United States. Such assets were attractiveto investors comfortable with low-risk hold-ings and a regular return, such as pensionfunds.

• Greater capital liquidity enables betterallocation of capital. Many midstream assetswere constructed by companies with a greaterappetite for risk and higher return expecta-tions, such as domestic and international oilcompanies with upstream assets, as a way oftransporting wellhead natural gas to con-sumers. However, these companies spe-cialised in higher-risk, higher-returninvestments. Instruments such as master lim-ited partnerships enabled these companies tosell midstream assets to investors with moreappropriate risk profiles and recycle the pro-ceeds into new investment more consistentwith their own risk-reward profile.

• Tax efficiency is important in attractinginvestor interest. A master limited partner-ship is a particular form of business entity thatis not liable for US federal income tax.

Allowing midstream assets to be structuredinto a master limited partnership reduced taxliability and improved the returns, thereforeincreasing investor interest.

• Regulation gives clarity and certainty,further enhancing capital liquidity. Beyondthe corporate structure, master limitedpartnerships in the United States have ben-efited from a clear, credible and stableregulatory regime, which has created con-fidence among investors less familiar withthe energy industry. Regulated accesscharges, a history of long-term contracts,and a stable regulatory and tax regimehelped lower the risk of an investment andattract new capital.

1. Background

The United States is the world’s largest oilconsumer. The level of domestic crude oil pro-duction has increased over the past few years,reversing a decline that began in 1986. Accord-ing to the IEA, crude oil production increasedfrom 5 million barrels a day in 2008 to just lessthan 5.7 million barrels a day in 2011 and 6.5million barrels a day in 2012. This increase in oilproduction was largely brought about by newseismic and horizontal drilling technology andhydraulic fracturing, bringing domestic resourcesthat were previously considered non-viable intoproduction.

Pipelines are the common transport mode forshipping crude oil and refined products. In total,the country has more than 275,000 km ofcrude-gathering and distribution pipelines, oper-ated by 2338 companies. The top 10 operatorsalone run almost 90,000 km of pipeline. In 2011,this network delivered 514.3 million barrels aday of crude oil between regions. The highestconcentration of pipelines is in the Gulf Coast,which is also home to almost half the country’srefining capacity.

Because of the capital-intensive nature ofpipeline operations, many companies havesought to structure these units as master limitedpartnerships, publicly traded businesses that aretaxed as partnerships. Unlike a corporation, a

19.2 The Midstream Segment: Building Infrastructure and Managing Access 449

partnership in the United States is classified as apass-through entity and is not liable for federalincome taxes. Instead, partners pay tax based ontheir allocated share of the partnership. Thestructure offers two significant advantages. First,tax is levied only at a single level of federalincome tax, which is applied individually on thetotal income of each member of the partner-ship. The master limited partnerships do not paycorporation tax. The other advantage is thatfavourable tax treatment allows a master limitedpartnership to access lower-cost capital than if itwere taxed as a corporation.

These advantages make the master limitedpartnership approach an especially attractive

option for capital-intensive pipeline infrastruc-ture transmission enterprises.

2. Benefits to infrastructure owners

One example of the structure was Shell Mid-stream Partners, a master limited partnership thatheld onshore and offshore oil infrastructure.Three of the four pipelines in its portfolio servedthe Gulf Coast, while the fourth reached into theNortheast (Fig. 19.15).

For the infrastructure owner, a particularadvantage of this corporate structure is that thebusiness retains control of the pipelines. Unlikeshareholders in a publicly traded company,

TEXASLOUISIANA

MISSISSIPPI

COLONIAL SYSTEM

ColonialColonial

Zydeco (Ho-Ho)

Mars

Pasadena

Houston

GULF OF MEXICO

Bengal

St. James

Lake Charles

Clovelly

Baton Rogue

CallouIsland

Erath

Houma

Channelview

AlliancePort Neches/

Nederland

TXLA

OK

KS

NE

MS

AR

MO

IA

ALGA

FL

SC

KY

TN

WV

OH

MI

INIL

PANJ

MDDE

NC

VA

Fig. 19.15 Shell midstream partners pipelines

450 19 A Close Look at the Natural Gas Industry Chain

unitholders—investors holding shares of masterlimited partnerships—are not entitled to elect thegeneral partner or any directors. Instead, theybenefit from a stream of income in accordancewith their ownership interest, while the partner-ship itself is managed by a board of directors andexecutive officers appointed by a general partner,in this case Shell Pipeline Company LP, anaffiliate of Shell. The distribution of ownershipinterests varied across the pipelines in the port-folio (Table 19.3).

Launching an initial public offering for ShellMidstream Partners allowed Shell to releasecapital for investment elsewhere in its valuechain and optimise its risk profile. It also allowedShell to divest itself of low-return, non-coreassets and to improve its focus on other activities.At the same time, investors in Midstream Part-ners, such as pension funds, were attracted by itslower risk-return profile.

3. Importance of the regulatory framework

The regulatory framework provided certaintyfor investment by detailing eligible assets andactivities. Master limited partnerships were onlypossible as a result of the regulatory authoritiesproviding rules for partnership treatment: federalrules on qualifying income and assets gave Shellthe necessary certainty to proceed. It also enabledShell to offer stable and predictable cash flows toinvestors. Rules on access meant that MidstreamPartners’ assets generated stable revenue underFERC-based tariffs and long-term transportationagreements. In addition, ship-or-pay contractsmitigated volatility in cash flows by limiting

exposure to changing market dynamics thatcould reduce production and affect shipperdemand. Finally, life-of-lease agreements, someof which have a guaranteed return, reduced cashflow exposure to volume reductions.

19.3 Unbundling MidstreamInfrastructure

Midstream infrastructure unbundling is a criticalstep in natural gas market liberalisation progressand in the promotion of natural gas marketcompetition. This section analyses the effects ofunbundling with the background of natural gasmarket liberalisation as well as related goals ofunbundling. In addition, a comparison of fivepartition models is carried out using case studiesfrom the United Kingdom, the European Unionand Japan. These case studies offer experienceand a reference point to China in its futureunbundling work.

Natural gas markets have historically beendominated by large vertically integrated compa-nies operating across the various segments of thevalue chain. Vertically integrated pipeline own-ers face particularly strong incentives to engagein anti-competitive behaviour, charging exces-sive rates to third-party natural gas shippers foraccess to midstream infrastructure to protectprofits in their own production or retailbusinesses.

Unbundling seeks to separate the incentivesfacing midstream operations from those ofupstream and downstream operations and toreduce the opportunity and incentives for

Table 19.3 Shell Midstream Partners ownership rights allocation

Entity Shell Midstream Partners(%)

SPLC retained ownership rights(%)

Length(km)

Capacity(kbpd)

Zydeco (Ho–Ho)

43.0 57.0 563 375

Mars 28.6 42.9 262 400

Bengal 49.0 1.0 254 515

Colonial 1.6 14.5 8851 2500

Notes SPLC is Shell Pipeline Company Limited Partners; kbpd is thousand barrels per day; ownership interests may notadd to 100%

19.2 The Midstream Segment: Building Infrastructure and Managing Access 451

anti-competitive behaviour. Without this, ownersof midstream assets will retain an incentive tooperate in a way that favours their upstream ordownstream businesses. Unbundling focuses onthe midstream segment because of its naturalmonopolies and the potential for misusing mar-ket power (Fig. 19.16).

Full ownership unbundling is the most com-plete form of unbundling, although some modelsof unbundling seek to change these incentiveswithout separation of ownership. For example, ifa single vertically integrated firm participates inthe upstream segment, transportation and retailsales, but regulation effectively prevents it fromoperating its midstream assets to the advantageits upstream or downstream businesses, verticalintegration does not threaten efficient marketoperations.

Unbundling is a key step in natural gas marketliberalisation, as part of a broader effort to createopen access to midstream infrastructure, partic-ularly to pipelines which have stronger charac-teristics of natural monopolies. Unbundling isrequired in addition to third-party-access

regimes. Third-party access requirementsaddress the incentive of a natural monopolyowner to charge very high prices to maximise itsprofits, reducing pipeline utilisation in the pro-cess. Unbundling requirements, on the otherhand, address the incentive for vertically inte-grated owners to make monopoly profits byfavouring their vertically integrated partners andexcluding third parties.

Vertically integrated companies can misusetheir market power even if third-party access tomidstream assets is allowed, for example througha lack of transparency over available capacityand prices or through onerous contracting ortechnical studies requirements for third parties.Such anti-competitive behaviour can be remediedby strict policing of third-party access rules, butremoving the incentive for this behaviourthrough unbundling has been seen by manyregulators as a part of the solution. Unbundling isnot itself the goal, but rather a means to ensurethat third-party access is effective. The success ofan unbundling regime should be measured by theultimate effectiveness of an open access reform

Upstream(exploration, production,

import)

Midstream(transmission, distribution

and storage)

Downstream(retail to end users)

Vertically integratedgas company

UnbundlingMidstream

(transmission, distributionand storage)

There are degrees ofunbundling, so the midstream

may remain connected in someway to the original company

Fig. 19.16 Unbundling is the separation of midstream business from that of upstream and downstream business

452 19 A Close Look at the Natural Gas Industry Chain

package in supporting an efficient and competi-tive gas market.

19.3.1 Models of Unbundling

Five unbundling models are defined and exam-ined using case studies from the United King-dom, the European Union and Japan. They are:

• Service unbundling: Businesses must offeruse of their midstream assets as a distinctservice separate from the wholesale supply ofnatural gas.

• Account unbundling: Midstream businessesmust maintain separate accounts fromupstream and downstream businesses to pre-vent cross-subsidisation and distortingbehaviour.

• Legal unbundling: Midstream assets areplaced into a separate legal entity, such as awholly-owned subsidiary, to reinforce theoperational separation of these assets fromother assets within a vertically integratedentity.

• Structural unbundling: Strict regulatoryrequirements are placed on how a midstreambusiness is operated to ensure that it supportsthe efficient operation of the natural gasmarket, rather than to the benefit of relatedupstream or downstream interests.

• Ownership unbundling: The legal entity thatowns midstream assets does not have com-mon ownership with upstream or downstreaminterests, fully separating their economicincentives.

Each of these models builds sequentially oneach other, alongside an overarching processknown as functional unbundling, which canreinforce each of these models. Functionalunbundling restrictions can vary from beingfairly mild to quite onerous. They could include,for instance, requiring separate management,locations, support units and logos, prohibiting thesharing of information, and imposing additionalcompliance and reporting requirements. Func-tional unbundling is a critical element of any

unbundling process. To illustrate, a legallyunbundled midstream business that shared man-agement or offices with a related upstream ordownstream business could be less effective than,say, a midstream business that legally remainedpart of a vertically integrated entity, but had morerigorous separation of staff and management.

Each of the five models of unbundling servesdifferent purposes and follows sequential chan-ges in moving from service unbundling to own-ership unbundling (Table 19.4).

19.3.2 Key Insights from the CaseStudies

Our review of international experience inunbundling midstream assets from upstream anddownstream businesses produced three generalinsights that might be valuable to China’s policydiscussions.

• Complete ownership unbundling is notnecessary under a strong regulator. Thecase studies indicated that there are viablemodels that don’t require full ownershipunbundling. In particular, structural unbund-ling under a strong regulator could capturemany of the benefits of full ownershipunbundling. Of the country case studies, onlythe United Kingdom and The Netherlandspursued full ownership unbundling. Franceand Germany argued for structural unbund-ling that fell short of full ownership unbund-ling, and the latest EU Gas Directive includedthis option along with strong regulatorymeasures to enforce a well-developed struc-tural unbundling model. Experience in theUnited States also suggested that a competi-tive natural gas market can be supportedwithout mandatory ownership unbundling,provided the operations of transmissioncompanies are tightly prescribed. Each ofthese cases followed a unique path tounbundling (Fig. 19.17).In general, structural unbundling can beeffective if the regulator is strong. However,anything less than structural unbundling is

19.3 Unbundling Midstream Infrastructure 453

likely to be inadequate in delivering liber-alised natural gas markets. The experience ofthe United Kingdom and Japan indicated thatservice unbundling alone offered few benefitsand that service and account unbundling,combined with meaningful functionalunbundling, was the minimum viableunbundling models. However, this combina-tion of unbundling models should be seen asa stepping stone to deeper unbundling, ratherthan an end point. The European experiencealso indicated that legal unbundling offered

little without moving to deeper structuralunbundling, complemented with functionalunbundling.These observations suggest a streamlinedunbundling process consisting of three steps(Fig. 19.18). Functional unbundling supportsthis process at key junctions, principally inthe account, legal and structural unbundlingphases.

• Domestic production can increase thebenefits of unbundling. A key benefit ofunbundling was to open upstream activities to

Table 19.4 Operational changes resulting from five types of unbundling

Model Change Goal Relation to previous changes

Servicepartition

Midstream service (primarilymanagement services) must beindependent from natural gaswholesale business

If natural gas transmissionservices are not separatedfrom the wholesale business,then anti-competitive activitieswill occur, since natural gassuppliers will be unable to sellnatural gas through pipelineowners

N/A

Accountpartition

Midstream business operationbusiness revenue and costsmust be separated fromupstream and downstreambusiness

The goal is to preventmidstream business frombenefiting from overlappingsubsidies in upstream ordownstream business

If midstream services are notmade into independentservices having independentfees, independent accountscannot be possessed

Legalpartition

Midstream business becomesan independent legal entity,but is still within the verticallyunified corporation, forexample as a wholly-ownedsubsidiary

The subsidiary company is thelegal person assuming legalobligations. Usingindependent legal entitiesachieves better managementseparation

Independent legal entitiesmust manage independentaccounts and provide separateservices

Structuralpartition

Midstream businessformulates strategies toeffectively separate itseconomic incentives fromupstream or downstreambusiness incentives

Separating the economicincentives of midstreambusiness from relatedupstream or downstreameconomic incentives cansupport obtaining effectivemarket results by removingincentives to hinder thecompetition

Midstream business must bean independent legal entityand adhere to existingprocedures and assumeobligations

Ownershiprightspartition

Midstream business separatesfrom the vertically unifiedenterprise and transitions to bean entity with independentownership rights

Complete ownershipseparation is the most effectivemeans of separating theinterests of midstreambusiness from relatedupstream and downstreambusiness

For independently ownedcompanies, they must beindependent legal entities thathave independent accountsand provide independentservices

Note Structural unbundling encompasses the independent transmission operator model within the EU’s Third GasPackageSource Vivid Economics, based on Gao

454 19 A Close Look at the Natural Gas Industry Chain

competition and efficient production. In mar-kets that had few indigenous natural gasresources and were heavily reliant on imports,unbundling and other open-access measures

promoted the efficient delivery of natural gasto market, but had only a limited impact onupstream activity. In contrast, in countrieswith substantial indigenous resources,

SERVICEUNBUNDLING

ACCOUNTUNBUNDLING

LEGALUNBUNDLING

STRUCTURALUNBUNDLING

OWNERSHIPUNBUNDLING

1998 2004

1994 1996 2000

2005

1986

1998

1998

1995

2003

2005

2012

2012

2004

1992

Only the UK andThe Netherlandshave undertaken

ownershipunbundling

Fig. 19.17 The path of unbundling (ultimate ownership rights unbundling might not be necessary)

SERVICEUNBUNDLING

ACCOUNTUNBUNDLING

LEGALUNBUNDLING

STRUCTURALUNBUNDLING

OWNERSHIPUNBUNDLING

OWNERSHIPUNBUNDLING

LEGAL AND STRUCTURALUNBUNDLING

SERVICE ANDACCOUNT

UNBUNDLING

Slowunbundling

process

Streamlinedunbundling

process

1

1

2

2

3

3

4 5

Fig. 19.18 Streamlined unbundling process (three steps only)

19.3 Unbundling Midstream Infrastructure 455

unbundling and other open-access measurescould promote domestic production byenhancing access to downstream wholesaleand retail markets. Indeed, countries withmore domestic production have tended tounbundle earlier and more comprehensively(Fig. 19.19).The Netherlands and United Kingdom, withtheir indigenous North Sea resources, pursuedunbundling more rapidly than nations such asFrance and Germany with limited domesticreserves. The United States, with its sub-stantial and geographically diverse upstreamresources, was the world leader in unbundlingefforts, requiring legal and other structuralunbundling measures as early as 1992. Japan,with its negligible domestic natural gasresources, pursued unbundling only tenta-tively. This suggests that countries with sig-nificant domestic resources perceive higher

economic benefits from unbundling—interms of promoting a dynamic and competi-tive upstream sector and unlocking the eco-nomic and energy security benefits ofdomestic production—and are more willingto pursue these reforms.

• LNG and storage facilities tend to face lessstrict unbundling regimes than pipelines.Unbundling requirements for LNG terminalsand storage facilities were generally lessstringent than for pipelines, reflecting thegreater potential for competitive pressure onthese facilities, as well as the relatively newdevelopment of this type of infrastructure. Thepotential for LNG regasification terminals orstorage facilities to exercise excessive marketpower depends on the number of alternativeproviders of similar services. In a physicallywell-connected market, LNG terminals areone source of supply competing alongside

Dom

estic

pro

duct

ion

as a

% o

f dom

estic

cons

umpt

ion

(200

0–20

13 a

vera

ge) >100%

80 - 100%

60 - 80%

40 - 60%

20 - 40%

0 - 20%

2004

2012

2005

20001992

SERVICEUNBUNDLING

ACCOUNTUNBUNDLING

LEGALUNBUNDLING

STRUCTURALUNBUNDLING

OWNERSHIPUNBUNDLING

Fig. 19.19 Correlation of domestic natural gas production volumes and levels of and timing of unbundling. NoteCharacterising 1992 reforms in the United States as structural unbundling is based on the strong non-discrimination,transparency and capacity release requirements of FERC Order 636, reinforced with extensive functional unbundlingmeasures. Source Vivid Economics, based on Gao and IEA

456 19 A Close Look at the Natural Gas Industry Chain

many others and have limited market power.Similarly, a diversified and well-connectedmarket may have multiple storage providers,as well as other options such as pipelinelinepack (in which natural gas is stored in thepipeline), flexible production capacity anddemand curtailment. Other than in very smallor fragmented markets, the potential for LNGterminals and storage facilities to exercisemarket power is likely to be limited. As aresult, both unbundling and third-party accessrequirements tended to be more lenient forthese facilities.

19.3.3 Case Study 1: The UK—TheLong and Difficult Roadto Spinoff

Despite the United Kingdom’s position today asan exemplary case of full natural gas supplychain unbundling, the process has been far fromsmooth. Regulatory arrangements were reviewedand amended on numerous occasions before thepresent market structure was largely reached in2000. Unbundling was not always synchronisedwith liberalisation, and with measures to intro-duce competition in the broader gas market. Fullownership unbundling was only achieved in2000 when the then British Gas Plc separated itsTransco subsidiary into the separately ownedLattice Group Plc, well after the emergence ofsubstantial gas market competition through theearly and mid-1990s.

By that time, substantial competition hadalready emerged in large parts of the UK naturalgas market. British Gas had already lost signifi-cant market share before major reforms under theGas Act of 1995 were implemented. The GasRelease Scheme, for instance, had forced BritishGas to release natural gas contracts to competingsuppliers. A compounding factor was that manyof British Gas’s legacy North Sea natural gascontracts were priced higher than prevailingmarket prices, pressuring the company’s marketposition.

The first phase of reform was marked by theGas Act of 1986. The act privatised thestate-owned British Gas Corp. as British Gas Plcand provided a limited form of service unbund-ling of the company’s pipeline operations. Theact allowed larger natural gas customers tosource natural gas from any authorised supplierand required British Gas to allow these suppliersto use its pipelines. In effect, British Gas was toldto offer a standalone pipeline service to com-petitors seeking to supply large customers.However, this service unbundling was not sup-ported by account or functional unbundling andproved to be largely ineffective. The Monopoliesand Mergers Commission found in 1988 thatBritish Gas had been abusing its market positionby engaging in price discrimination and sought toaddress this by requiring the company to publishcommon carriage terms to support pipelineaccess. The change, however, was still largelyineffective.

Subsequent reviews by the Office of FairTrading in 1991 and the Monopolies and Merg-ers Commission in 1993 suggested that furtherunbundling was necessary to promote competi-tion. The Office of Fair Trading review addresseda range of other structural elements of the naturalgas market other than unbundling. It led to Bri-tish Gas undertaking to make supply available tocompetitors under the Gas Release Strategy,which triggered a substantial reduction in itsmarket share with large industrial customersbetween 1991 and 1993. It was these provisions,rather than its unbundling recommendations, thatwere instrumental in driving a decline in BritishGas’s market share.

In response to the critical 1993 Monopoliesand Mergers Commission review, British Gasbypassed the account unbundling phase andvoluntarily moved directly to legal unbundling in1994. A transportation and storage subsidiary,Transco, was created and separated from BritishGas’s trading and sales activities. Despite thecommission’s recommendation for full owner-ship unbundling, in response to regulatory andcommercial pressures, the unbundling of BritishGas progressed in two further phases.

19.3 Unbundling Midstream Infrastructure 457

The Gas Act of 1995 required Transco toestablish a Network Code to govern the nationaltransmission system, which effectively consti-tuted structural unbundling of the network busi-ness. The code was published in 1996,establishing the rules and procedures forthird-party access to pipelines and introducing aregime for daily balancing. The code strength-ened access to the pipeline system for natural gasmarket players, supporting competition eventhough Transco remained a British Gassubsidiary.

However, this business structure did not last,as competitive pressures built around BritishGas. The 1995 Gas Act extended the scope ofcompetition to include the smallest, residentialcustomers, and full retail competition wasimplemented across the United Kingdom by1997. As competition in both large and smalluser markets deepened, the relatively high priceof British Gas’s legacy upstream contracts forNorth Sea gas weighed on its business. Thepressure prompted British Gas to voluntarilydivest its trading and sales businesses. BritishGas was unbundled into two entities: Centricaplc, which held sales and retail units, as well asupstream assets in Morecombe Bay, and BG plc,which retained Transco, the midstream unit, aswell as domestic and global upstream assets.

This structural unbundling model appears tohave been effective, even though Transcoremained a subsidiary of BG, a major upstreamplayer. Transco held some ownership ofupstream assets, and its separation from BG wasmaintained by the Network Code.

The final step in full ownership unbundlingcame in 2000, when BG split into the BG Groupand the Lattice Group, which took ownership ofTransco. The split meant that Transco wasentirely separated from all upstream and down-stream assets. Further ownership changes saw theLattice Group merge with the operator of theUnited Kingdom’s electricity grid, National Grid,in 2002 and sell off some local distribution net-works in 2005. While Transco initially includedstorage assets, these were spun off into a storagesubsidiary, which was privatised in 2001 andpurchased by Centrica in 2002.

19.3.4 Case Study 2: Europe—TheStep-by-Step ProgressionTowards Spinoffand the Multitudeof Choices

The EU regulatory regime has evolved towardsgreater unbundling over the course of three majorregulatory packages since 1998. These stagesbroadly comprise account and functionalunbundling in 1998, legal unbundling from 2003and more detailed structural and ownershipbundling approaches since 2009. Some memberstates have moved to comply with EU directivesmore swiftly than others, and several have gonebeyond the minimum requirements of EUregulation.

Differences on the merits of unbundling haveled to a diversity of approaches among EUmember states and an EU regulatory approachthat offers a menu of unbundling options ratherthan a single prescriptive model. Development ofthe Third Gas Directive was contentious andultimately led to a political and regulatory com-promise that offered two main unbundling mod-els: structural unbundling and ownershipunbundling.

The characteristics of the member states thattook different positions within this debate illu-minate the motivations and concerns of thosearguing for and against ownership unbundlingmodels. For example, countries with domesticnatural gas resources, such as the United King-dom and The Netherlands, appear to be moreenthusiastic proponents of unbundling. Thebenefits of unbundling are greater in such coun-tries, promoting competition among natural gasproducers. Conversely, in countries like Ger-many, where there are limited domestic naturalgas resources and the primary physical assetsheld by natural gas businesses are pipelines,unbundling was more hesitant. These funda-mental differences could, in part, explain varyingregulatory attitudes toward unbundling.

The First Gas Directive successfully achievedaccount unbundling, but does not appear to havehad substantial effects on gas market competi-tion. The directive required separate accounts for

458 19 A Close Look at the Natural Gas Industry Chain

transmission, distribution and storage activities tosupport transparency and competition in theseactivities. A 2003 benchmarking report by theEuropean Commission found that all memberstates had complied with minimum accountunbundling requirements and several had gonefurther to legal or ownership unbundling. How-ever, the same report noted that prospects forcompetition in the natural gas market were lag-ging significantly behind those for electricity inmany member states, citing Germany in partic-ular. Around 2001, the European Commissionitself began arguing that the first package ofmeasures had been ineffective and that furtherreforms were needed.

One weakness of the First Gas Directive mayhave been limited functional unbundling in sup-port of the core model of account unbundling.While the directive included some broad provi-sions against discriminatory behaviour and ageneral requirement for transmission providersnot to abuse commercially sensitive informationobtained from third parties, it did not includedetailed and enforceable provisions to separateinformation and management systems betweentransmission and other business units. Somemember states, including The Netherlands andIreland, voluntarily adopted functional unbund-ling measures to separate management of trans-portation businesses. Others, such as Austria,Belgium, Denmark and Italy, went further,adopting legal unbundling. Meanwhile, Spainand the United Kingdom moved to ownershipunbundling. However, some major memberstates, notably France and Germany, onlyimplemented the directive’s minimum require-ment of account unbundling and appear to havebeen slower in progressing natural gas marketcompetition during this period.

The Second Gas Directive, adopted in 2003,mandated the legal separation of transmissionbusinesses, reinforced with functional unbund-ling measures. The directive required transmis-sion system operators to be “independent at leastin terms of legal form, organisation, anddecision-making from other activities not relatingto transmission”. Specific functional unbundling

measures required entirely separate management,effective independent decision-making rights anda compliance programme to maintain indepen-dence. Member states adopted elements of theSecond Gas Directive at different speeds and todiffering degrees. By 2005, for example, TheNetherlands had established full ownershipunbundling, while Germany had only imple-mented minimum regulatory requirements for alegal unbundling regime.

Policy-makers and market observers quicklyconcluded the Second Gas Directive was alsoineffective in promoting competition and arguedfor further reform. A 2007 European Commis-sion report found that “wholesale gas trade hasbeen slow to develop, and the incumbents remaindominant in their traditional markets”. It con-cluded that the level of unbundling in place wasinadequate to “resolve the systemic conflict ofinterest inherent in the vertical integration ofsupply and network activities”. In the same year,an IEA review of German energy policies con-cluded that legal unbundling was ineffective andthat the involvement of traders in pipeline busi-nesses had limited the liquidity of wholesalemarkets. A similar 2009 IEA review of Frenchenergy policies identified the dominance ofGDF-Suez, especially in the bilateral trade ofwholesale natural gas, as constraining the abilityof other market players to supply the Frenchmarket.

Earlier reform efforts had targeted mandatoryownership unbundling. For example, the Euro-pean Commission argued in 2007 that “fullownership unbundling is the most effective meansto ensure choice for energy users and encourageinvestment.” However, nine member states—in-cluding France and Germany—opposed fullownership unbundling, saying that it would notimprove competition or reduce prices. Theyargued that breaking up large, vertically integratedenergy companies would weaken their negotiatingpower in international markets—for example withpowerful external suppliers such as Russia’sGazprom—with no benefit to consumers.

The adoption of the Third Gas Directive wascontentious, with several large member states

19.3 Unbundling Midstream Infrastructure 459

arguing against mandatory ownership unbund-ling. The compromise captured in the ThirdDirective presented ownership unbundling as theideal model, but allowed member states tochoose from two alternative structural unbund-ling models. The directive recommended fullownership unbundling as “the most effective toolby which to promote investments in infrastruc-ture in a non-discriminatory way, fair access tothe network for new entrants, and transparencyfor the market”. It also argued that the twoalternative models, the independent transmissionoperator (ITO) model and the independent sys-tem operator (ISO) model, “should enable avertically integrated undertaking to maintainownership of network assets while ensuring aneffective separation of interests, provided that…extensive regulatory control mechanisms are putin place”.

The ISO and ITO models were essentially lessstringent forms of unbundling. Unlike ownershipunbundling, setting up an ISO or ITO would lettransmission networks remain under the owner-ship of vertically integrated firms.

EU member states have adopted either fullownership unbundling or the ITO model. TheUnited Kingdom, The Netherlands, Denmark andSpain have ownership unbundling models,though these regimes were in place before theThird Gas Directive was adopted. Elsewhere, theITO model has been adopted, complemented bya range of strong functional unbundlingrequirements. By mid-2014, 21 natural gastransmission operators had been certified.

No country had pursued the ISO model bymid-2014. The core element of the ISO modelwas that network ownership remains with a sub-sidiary of the vertically integrated entity, butsystem operation and investment decisions aremade by a legally separate entity with separateownership. Vertically integrated companiesseemed unconvinced by an approach that wouldrequire them to fund investments made by entirelyseparate entities, while the ITO model allowedinvestment decisions to be made jointly by theparent company and the regulatory authority.

The choice between the full unbundling andthe ITO model may reflect different evolutionary

stages in the development of natural gas markets.Countries that embraced full ownershipunbundling started their reform processes earlierand progressed more rapidly along the spectrumof unbundling models. The progress made inmarkets such as the United Kingdom and TheNetherlands may reflect the maturity of theirunbundling efforts, rather than the advantage ofownership unbundling over alternative models.Indeed, an effective and mature structuralunbundling model may be sufficient to supportand enable competition in the upstream anddownstream segments of the natural gas valuechain.

19.3.5 Case Study 3: Japan—MarketCharacteristicsRestricting Unbundling

Japan’s two tentative attempts at unbundlingappear to have had only a modest effect on itsnatural gas market, although the lack of compe-tition may also reflect the fundamentals of theJapanese markets as much as the merits of itsregulatory efforts. One of the benefits ofunbundling appears to be a dynamic upstreammarket, but since Japan has no domestic naturalgas resources, this incentive is less compelling.Minimal pipeline interconnectivity further limitsthe potential for regulation to unlock competi-tion. In general, the limitations of Japan’sunbundling efforts since 1995 may be both asymptom and a cause of the lack of competition.

Japan began its unbundling measures in 1995with a service unbundling regime. The 1995reform required Japan’s three largest natural gascompanies to offer pipeline services to competi-tors seeking to supply large consumers, under-pinning the emerging third-party access regime.These requirements were extended to additionalcustomers in 1999. They were reinforced in 2000with functional unbundling requirements thatdirected companies to separate the transportationfunction from other elements of their business.However, the measures were lenient and did notmaterially change the behaviour of incumbentnatural gas suppliers. A second wave of reform in

460 19 A Close Look at the Natural Gas Industry Chain

2003 and 2004 introduced account unbundlingsupported by new and more stringent functionalunbundling requirements. The functionalunbundling measures required separate physicaloffice locations, staff functions, and decision-making and prohibited information sharing.Compliance improved, but was not uniform.

The overall reform programme has been onlymodestly successful, with markets remaininghighly concentrated. As of 2012, three large,vertically integrated players together suppliedaround 70% of the market. Companies wantingto use pipelines owned by other companies havecomplained of entry barriers and opaque accessrequirements. In particular, many complainedof insufficient information on the availablecapacity of pipelines and on standards and pro-cedures for assessing fees and other compensa-tion mechanisms.

The Japanese experience suggests thataccount and functional unbundling can deliverbenefits, but its value may have been limited bythe fundamentals of the Japanese natural gasmarket. Service and account unbundling, com-bined with meaningful functional unbundling,appears to be the minimum viable unbundlingmodel, acting as a stepping stone to moreadvanced unbundling model.

19.3.6 Unbundling LNG Terminalsand Gas StorageFacilities

Unbundling requirements for LNG terminals andstorage facilities are generally less stringent thanfor pipelines, reflecting the greater potential forcompetitive pressure on these facilities, as well asthe relatively new development of this type ofinfrastructure. The potential for LNG regasifica-tion terminals or storage facilities to exercisemarket power depends on the number of alter-native providers of similar services and thedegree of interconnection between them. In mostmarkets, there are likely to be a larger number ofLNG terminals and storage sites than pipelineroutes because of the smaller economies of scale.Moreover, in a physically well-connected

market, LNG terminals will compete with eachother and with other sources of supply, limitingtheir market power. Similarly, a diversified andwell-connected market may have multiple stor-age providers, alongside storage services pro-vided by pipeline linepack, flexible productioncapacity and demand curtailment.

Except in very small or fragmented markets,the potential for LNG terminals and storagefacilities to exercise market power is likely to belimited, and regulations mandating unbundlingand third-party access requirements will not tendto be as stringent as for pipelines. For example,Japan requires only account unbundling for LNGfacilities and places no requirements on storagefacilities. Unbundling requirements in the Euro-pean Union are stronger than those in Japan forboth LNG regasification terminals and storagefacilities, with both types of facilities required tohave unbundled accounts. In addition, storageoperators cannot participate in company struc-tures of vertically integrated natural gas compa-nies, imposing an additional functionalunbundling requirement.

A range of European LNG and storage facil-ities have gone beyond the minimum regulatoryrequirements for account unbundling, adoptingeither legal or ownership unbundling. In somecases, particularly for LNG terminals, legalunbundling has been adopted for practical rea-sons associated with forming joint ventures.Ownership unbundling has been adopted ininstances when transportation assets faceunbundling requirements, and since storagefacilities or LNG terminals are held by trans-portation owners, they become unbundled fromupstream and downstream interests by default. Inother cases, legal unbundling throughwholly-owned subsidiaries has occurred on avoluntary basis, possibly pre-empting regulatoryrequirements to unbundle or other regulationslimiting the benefits of vertical integration.Finally, new LNG terminals can receive anexemption from third-party requirements if,among other things, they are unbundled.

Examples of LNG facilities and storagefacilities and their prevailing level of unbundlingshow a wide range of approaches (Table 19.5).

19.3 Unbundling Midstream Infrastructure 461

Overall, the range of experience suggests thataccess to LNG or storage terminals is not a keyregulatory concern in the European market andthat legal unbundling of these facilities is not animposition on normal commercial behaviour.

19.4 The Downstream Segment:Natural Gas Trading Hubsand the Liberalisationof Wholesale Natural GasMarkets

The downstream segment of the natural gas valuechain includes wholesale and retail marketssupplying gas to end users. Greater competition

in the downstream segment can increase choiceand reduce the price paid by the end users ofnatural gas, for example by establishing naturalgas hubs and increasing competition in wholesalemarkets. Competitive wholesale markets, in turn,are important for ensuring effective retail com-petition and delivering benefits for consumersand end users. Whether focused on a physicallocation, such as Henry Hub in the United States,or a virtual platform, such as Britain’s NBP,activity on wholesale markets is the dominantfactor in pricing and delivering natural gas toretailers and, eventually, end users.

This section analyses the experience of theUnited States, the United Kingdom and conti-nental Europe in constructing natural gas trading

Table 19.5 European LNG receiving stations and gas reserve facilities and their voluntary unbundling

Facility Country Ownerposition

Unbundlingtype

Owner Operating entity

Dragon LNGreceiving station

UnitedKingdom

Upstream Legal BG Group (50%), Petronas(50%)

Dragon LNG (JV)

South Hook LNGreceiving station

UnitedKingdom

Upstream Legal Qatar Petroleum (67.5%),Exxon Mobil (24.15%),Total (8.35%)

South Hook LNG(JV)

Montoir andFos-Tonkin LNGreceiving station

UnitedKingdom

Verticallyintegrated

Legal GDF-Suez Elengy (LNGsubsidiary)

Fos Cavaou LNGreceiving station

France Verticallyintegrated

Legal GDF-Suez (70%), Total(30%)

Fosmax LNG (JV)

Grain LNGreceiving station

UnitedKingdom

Midstream Ownershiprights

UK National Grid Grain LNG (LNGsubsidiary)

Zeebrugge LNGreceiving station

Belgium Midstream Ownershiprights

Fluxys Fluxys LNG (LNGsubsidiary)

Gate LNGreceiving station

TheNetherlands

Midstream Legal Gasunie (47.5%), Vopak(47.5%), receiving stationuser holdings 5%

Gate terminal B.V(JV)

Rough gas reservefacilities

UnitedKingdom

Upstreamanddownstream

Legal Centrica Centrica Storage(gas reservesubsidiary)

6 gas reservefacilities

Germany Verticallyintegrated

Legal VNG AG VNG GasspeicherGmbH (gas reservesubsidiary)

14 gas reservefacilities

France Verticallyintegrated

Legal GDF-Suez Storengy (gasreserve subsidiary)

Note Gate LNG could be characterised primarily as ownership unbundling as 95% of the company is held by partieswith no upstream or downstream interests, and, formally, the 5% ownership held by terminal users could justify itsclassification as legally unbundled

462 19 A Close Look at the Natural Gas Industry Chain

hubs, providing a reference point to China inpromoting its own natural gas downstream mar-ket liberalisation.

19.4.1 Pros and Cons of Natural GasHubs

There are two basic types of natural gas hub:physical hubs, such Henry Hub in the UnitedStates, and virtual hubs, such as the NBP in theUnited Kingdom. The IEA defines a physical hubas a geographical point in the network where theprice is set for natural gas delivered to thatspecific location. A virtual hub, on the otherhand, sets the price for natural gas across a widergeographic area. Unlike a physical hub, the NBPprice reflects the price in the entire area withoutgeographic differentials linked to transport costs.In general, a natural gas hub cannot be bothphysical and virtual, but it can evolve over time,for instance, starting as a physical hub and thenexpanding to become a wider virtual hub.

A natural gas hub has two core functions. Thefirst is to physically connect buyers and sellers ina natural gas system. Before the creation of ahub, a gas system may already have many or allof the individual elements required for a hub, andsome of them may already be connected. A hubstrengthens these connections by linking physicalflows between buyers and sellers across the

entire system (Fig. 19.20). The second is tocompetitively determination natural gas prices.A gas hub provides a point or area in the gasnetwork where demand and supply are balancedby a price. This balancing price is determinedthrough competition between many buyers andsellers in the marketplace. In this way, hub pricesreflect the fundamental market conditions fornatural gas rather than prices tied to other com-modities such as oil-indexed prices or regulatedprices set by the government.

Natural gas hubs also provide a set of insti-tutional rules, standardised contracts and pricebenchmarks. Hub prices serve as a focal point formarket participants, ensuring that natural gasmarket conditions are widely known. In this way,hubs increase market transparency and lowertransaction costs. Hub prices can also be used asreferences in contracts without delivery throughthe hub itself.

The creation of a natural gas hub comes with avariety of benefits, but also has potential draw-backs. The benefits include:

• Market-based price signals raise the eco-nomic efficiency of trade and investmentdecisions. The competitive trading of naturalgas sets a price that reflects the true cost andvalue of gas in the economy. These compet-itive prices direct natural gas to where it ismost needed from whoever can supply it most

Storage

Gaspowerplant

LNGterminal

Cityheatingsystem

PipelineTraders

Gashub

Storage

Gaspowerplant

LNGterminal

Cityheatingsystem

PipelineTraders

Fig. 19.20 The position of natural gas hubs in connecting buyers and sellers

19.4 The Downstream Segment: Natural Gas Trading Hubs and the Liberalisation … 463

cheaply. Trade takes place only when it iseconomically efficient, maximising the over-all gains from trade. Such co-ordination isdifficult to achieve other than through marketmechanisms, especially in large and complexgas systems. In the longer term, the signalsfrom competitive prices raise the quality ofcapital allocation as they drive natural gasmarket players to make investments onlywhen they can create real economic value.

• Hubs benefit from powerful and oftenself-reinforcing network effects. Bettermarket co-ordination, contact standardisationand greater transparency facilitate trading byreducing the costs of transactions. A hublowers market participants’ costs in searchingfor trading partners, who can now be easilyfound at exchanges or over the counter at thehub. A hub also reduces bargaining over theterms of the trade: a reference price andstandardised contracts avoid wasted time andresources in negotiation over the terms ofbespoke bilateral contracts. By reducingtransaction costs, a hub makes it easier fornew players to enter the natural gas market,widening market participation and increasingcompetition.

• A natural gas hub can improve a country’ssecurity of energy supply. Hubs help todiversify sources of supply; for example, byconnecting regions within a country. More-over, efficient price signals mean that, whenmarkets are tight, additional supply isencouraged to come to market while alsoinducing reductions in gas demand. Thishelps to reduce the likelihood of unantici-pated natural gas shortages.

However, natural gas trading hubs also havesome potential drawbacks:

• Hubs can disrupt pre-existing arrange-ments in a country’s natural gas industry.In particular, hub prices are determined bycompetitive forces, not by the government ora dominant incumbent. A transition to hubpricing puts pressure on incumbent playersand leads to a shift in the structure of natural

gas markets. Hub pricing also puts pressureon regulated prices, as well as any remainingoil-indexed contracts. For example, theinternational trend since 2005 towards hubpricing, most notably in Europe, has reducedthe role of long-term, oil-linked contracts.Natural gas in North America is almostentirely priced on hubs, while half of Euro-pean natural gas is priced on hubs, rather thanthrough oil-indexed contracts.

• There is no guarantee that prices willdecline with the emergence of hub pricing.At any particular time, hub prices may behigher or lower than oil-indexed contractprices. However, there appears to be a ten-dency for hub prices to be lower. For exam-ple, NBP prices were below Europeanoil-indexed prices 77% of the time between2000 and 2014. An increase in prices mayhave adverse impacts on broader statedevelopment objectives, especially in poorerregions, for example putting upward pricepressure on domestic heating. However, hubstend to develop when the oil-indexed contractprice fails to clear the market, that is, whensupply is available in excess of contractedvolumes and demand for this extra supplyexists at prices below oil-indexed contractprices. As a result, the hub price paid fornon-contracted volumes will be below theoil-indexed contract price, and the potentialsavings between oil-indexed prices and hubprices encourage buyers to switch fromoil-indexed contracts to hubs.

• Hub prices have tended to be more volatilethan oil-indexed contract prices. Because ofaveraging and time lags, oil-indexed contractstend to be less volatile than hub prices. Thevolatility of hub prices may be perceived ascostly by natural gas buyers, although expe-rience suggests that such price risks can bemanaged, especially in well-developed hubmarkets with a wide array of financial con-tracts for natural gas.

A China natural gas hub is likely to createlong-lasting benefits, while its drawbacks arelikely to be temporary. China’s large and

464 19 A Close Look at the Natural Gas Industry Chain

complex domestic gas market could benefit fromvalue-based pricing, market co-ordination andlower transaction costs. China’s market sizemeans that valuable network effects could alsooperate more strongly. A natural gas hub couldfurther encourage local gas production, includingfrom shale natural gas, and improve energyimport diversity and responsiveness. Consumergas prices could fall following the establishmentof hub pricing, although they could rise againlater.

19.4.2 The Important Inspiration ofInternational Experiencein the Developmentof Natural Gas TradingHubs

A successful natural gas hub can only developand be successful under a clear set of physical,market, and institutional conditions (Table 19.6).These conditions follow from the functions that anatural gas hub performs, informed by theexperience from countries that have developedhubs.

Since the 1990s, the world has accumulatedconsiderable experience in creating and devel-oping natural gas hubs. This experience centreson US and European markets. The US naturalgas market was restructured in the 1980s and1990s, and its Henry Hub price has become the

world’s leading natural gas price indicator.A similar process of liberalisation began in theUnited Kingdom in the 1990s, leading to creationof the NBP, the leading hub in Europe. In con-tinental Europe, market liberalisation began laterand has proceeded more slowly as part ofEuropean Commission’s plans for an InternalEnergy Market.

Insights from the experience of the UnitedStates, continental Europe and the United King-dom could benefit China. Indeed, China sharessome structural features with the United States—in particular, both are geographically vast, withdomestic production far removed from centres ofdemand. These characteristics suggest that, likethe US Henry Hub, China may need a physicalhub to accommodate significant differences intransmission costs to various dispersed destina-tions. Essentially, a physical hub prices naturalgas at a single physical point of the network,after which transmission costs are added. Thiscontrasts with a virtual hub, such as the NBP,which sets the price for natural gas within aregion and imposes a fixed transmission cost fornatural gas delivered within that region. A virtualhub is appropriate for a market with a relativelysmall delivery region and fixed transmissioncosts. The situation in China may be best servedby multiple hubs that follow the pricing of a mainhub, a structure similar to that seen in the UnitedStates.

The process of building a hub in Europe alsohas relevance for China. Hub development in

Table 19.6 Necessary preconditions in three areas for the successful development of a natural gas hub

Area Precondition Description

Physical Well-developed natural gastransmission network

Connection of domestic and foreign natural gas supply to demandOpen-access to pipeline network by suppliers

Market Large numbers of participants Sufficiently large number of market participants, both as buyers andsellers

Low market concentration No dominant supplier or consumerPossibility of natural gas imports

Trading activity Entrepreneurial activity to arbitrage prices, requiring third-partyaccess, part of supply uncontracted and part of demand contestable;price reporting agencies

Institutional Liberalisation of pricedetermination

Liberalised prices for wholesale natural gas and along the supplychain

Stable regulatory framework Competition policy and market regulation ensures level playing field

19.4 The Downstream Segment: Natural Gas Trading Hubs and the Liberalisation … 465

continental Europe and the United Kingdom tookplace against a backdrop of domestic productionand imported natural gas, both through pipelineand as LNG. In contrast, US hub developmenttook place without LNG playing an importantrole. Continental European natural gas marketshave also been undergoing a gradual transitionfrom a highly regulated, state-dominated systemin the 1990s towards a fully liberalised system.Finally, potentially analogous to Asian markets,Europe has been home to several regional hubsthat coexist on the EU natural gas market.

Overall, a robust and credible liberalisationprocess, along with favourable market condi-tions, has been instrumental in the developmentof natural gas hubs. The US experience showsthat open access to pipelines is critical formarket-based pricing, and that liberalisation canhelp wholesale markets shift away fromlong-term contracts and towards market-basedpricing in 5–10 years. The experience of conti-nental Europe is of hubs being established as aresult of favourable market conditions enabled bythe regulatory reform process. In these cases,market forces created a buyers’ market in naturalgas, which, combined with the liberalisation ofnatural gas markets, accelerated hub develop-ment. The UK experience is one of market andregulatory changes working in parallel toincrease competition in wholesale markets,leading to the establishment of the NBP. Stan-dardisation of contracts played a key role indriving hub success in the United Kingdom.

19.4.3 Case Study 1: The UnitedStates—Regional PriceBalancesand Short-Term Pricing

The US natural gas market underwent funda-mental reform beginning in the 1980s, with theemergence of ample natural gas supplies andregulatory changes to liberalise the market. In the1980s and early 1990s, the US regulator, FERC,implemented reforms to decouple the productionand trading of natural gas from its transportationby pipeline. The economic argument was that the

production and consumption of natural gas caninvolve many different buyers and sellers and hasthe potential to be competitive. Meanwhile,pipeline transport services were often highlyconcentrated, as a result of their natural mono-poly characteristics, and should be regulated. Asan alternative, guaranteed open access for allmarket participants on a non-discriminatory basiscould create greater competition among produc-ers and natural gas shippers and better allocationof economic resources.

The empirical evidence shows that reforms inthe United States had substantial impact quickly.In the early 1990s, movements of natural gasprices in different regions were weakly corre-lated, with significant price divergence. By thelate 1990s, wholesale price correlations had risento very high levels with the application of the lawof one price, an approach that equalised pricesacross locations, excluding transport costs. Evi-dence suggests that regulation to ensurenon-discriminatory open access to pipelinesplayed a key role in driving the move to acompetitive, national natural gas market.

In parallel, the underlying contract structure ofthe industry shifted from long-term contracts toshort-term pricing. Existing long-term contractswere either renegotiated in light of the changedmarket environment or terminated. Spot andfutures prices emerged as the key co-ordinatingmechanisms within the US natural gas sector,with pricing centred on Henry Hub. Marketconcentration fell, with the 20 largest playersaccounting for 44% of physical and financialtransaction volumes in 2014. More recently, theHenry Hub price, plus a mark-up for transport,has been used in LNG contracts between USexporters and foreign buyers.

19.4.4 Case Study 2: ContinentalEurope—MarketConditions for NaturalGas Hub Development

European natural gas hubs began developingonly in 2008, reflecting the slow progress of EUnatural gas market liberalisation. Northern

466 19 A Close Look at the Natural Gas Industry Chain

Europe is more advanced than southern Europein terms of natural gas trading and hub devel-opment. The legacy system of bilaterally nego-tiated oil-indexed natural gas contracts remainsmore prevalent in the south.

Several factors drove deepened natural gastrading and hub development in Western Europeafter 2008. The 2008 global financial crisisdampened European natural gas demand, incontrast to the boom that had been expected.Increased shale natural gas production in theUnited States meant that the country no longerimported LNG, with much of the freed supplydiverted to Europe. These two factors created abuyers’ market in natural gas, and traders andbrokers in key European markets—especiallyGermany and France—began to enjoy access touncontracted pipeline natural gas. Low naturalgas demand and greater LNG supply coupledwith high oil prices meant that oil-linked contractprices rose above market-based natural gas pri-ces, creating powerful incentives for buyers torenegotiate long-term contracts with upstreamnatural gas suppliers, such as Norway and Rus-sia. Within a few years, long-term contracts hadeither been terminated or renegotiated to reflectmarket-based hub prices rather than oil prices.

The Dutch Title Transfer Facility (TTF) iswidely seen as the most successful of the conti-nental European natural gas trading hubs. Thefacility was deliberately designed as a virtualhub, based on its physical pipeline and LNGconnections, its geographic location and the largedomestic natural gas supply from the DutchGroningen field. Development of the TTFaccelerated in the late 2000s, and it has overtakenNBP as Europe’s most liquid hub. In contrast, theBelgian Zeebrugge hub is generally seen as amuch less successful natural gas trading centre.Conditions at Zeebrugge—its location and rela-tively early development—once suggested that itcould become the leading European natural gashub, but local trading restrictions limited thenumber of market participants and slowed thedevelopment of its trading platform.

Overall, the move towards more active naturalgas trading has increased the correlation of nat-ural gas prices across European countries, similar

to the US experience in the 1990s. Spot prices inthe European Union now account for about halfthe natural gas trade.

19.4.5 Case Study 3: The UK—TwoNatural Gas MarketReform Bills

Natural gas market liberalisation began in theUnited Kingdom in the 1990s, following a waveof privatisations in the previous decade. TheUnited Kingdom was the first country in Europeto begin natural gas market reform, and aspectsof first-mover advantage remain.

Two pieces of regulation were especiallyimportant to the reform effort in the UnitedKingdom. The Gas Act of 1986 removed the defacto monopoly of British Gas in serving largenatural gas customers, while also requiring openaccess to its pipelines for its competitors. TheGas Act of 1995 set out a statutory timetable forfull competition in the British natural gas market,including at the residential level. As a result, themarket share held by British Gas declinedrapidly, from nearly 100% in 1990 to 29% by1996. These institutional and regulatory changesled to a surge in the number of market partici-pants and trading activity during the mid-1990s.Among the new entrants to the natural gas mar-ket were merchant banks, electricity companiesand foreign and domestic trading houses. Thenumber of participants in the wholesale marketrose from fewer than 15 in 1995 to more than 50within about two years.

The 1995 Gas Act also established the Net-work Code, a key element in the development ofnatural gas trading. The code is a set of rules andprocedures governing third-party access to theUK natural gas pipeline network. The code alsoenabled a system of daily balancing, whichrequired short-term natural gas trades.

These regulatory developments were accom-panied by shifts in the country’s demand andsupply of natural gas. On the demand side, the“dash for gas” in the British electricity industrysaw the growth of generation capacity using flex-ible combined-cycle natural gas turbines. On the

19.4 The Downstream Segment: Natural Gas Trading Hubs and the Liberalisation … 467

supply side, natural gas was available fromdomestic production in the North Sea. The regu-latory changes introduced by the Gas Acts of 1986and 1995 meant that new participants were able toaccess natural gas segments across the value chain.

The regulatory and market factors combinedput pressure on the old system of bilateral con-tracts, which were typically indexed to othercommodities, such as gas oil or fuel oil.The NBP was created within the code as a virtualhub to promote the balancing of the natural gassystem. From the late 1990s, the NBP evolvedquickly as a trading point and was used as thebasis for the standardised NBP97 contract, whichbecame the cornerstone of British over-the-counter contracts. The NBP also became thedelivery point for the Intercontinental Exchangenatural gas futures contract.

With the deepening of UK natural gas tradesince the late 1990s, NBP has become a leadingnatural gas hub in Europe. A number of factorshelped its ascension, including the existence ofdomestic natural gas reserves, periods of highdemand for natural gas and a stable regulatoryframework that enabled open-access marketparticipation via open access and offered a clearset of rules and standardised contracts.

19.4.6 Establishing Natural Gas Hubsin China

Natural gas hubs are market institutions, and thusto create a successful hub in China, the marketstructure of the natural gas industry in China willneed to be changed. This will generate efficiencyand generate costs, while also creating winnersand losers. However, the long-term benefits ofChina establishing a hub are clear, as it will raisedomestic natural gas production, raise energydiversification and also have major significanceto response capabilities. Construction of naturalgas hubs in China is therefore critical to thedevelopment of natural gas. This section willdiscuss the overall prospects for construction ofnatural gas hubs in China and the factors thatmust be considered in hub development, andanalyse the potential steps.

1. The overall outlook for construction ofnatural gas trading hubs in China

Insights gained from international experiencein establishing natural gas hubs, combined withan assessment of China’s circumstances, lead tofive key conclusions.

• China is in a good position to develop moremarket-based natural gas trading with hubpricing. Key positive factors include domesticgas production, exposure to both pipeline andLNG imports, and its size within Asianenergy markets.

• China’s large and complex domestic naturalgas market would benefit from value-basedpricing, market co-ordination and lowertransaction costs. It is likely that these effi-ciency gains from hub pricing will bring largeand long-lasting benefits, while any adverseeffects, particularly disruption of currentmarket arrangements, would be short-lived.

• A successful hub would require significantfurther liberalisation of the natural gas sectorin China, which would reduce the influenceof state-owned incumbents, improve markettransparency, and create a level playing fieldfor new market entrants through third-partyaccess arrangements.

• China canmove towards hub pricing in a seriesof small steps, backed by government policy.Beginning with pilot natural gas trading in aparticular region, these steps may graduallysatisfy the pre-conditions for a successful huband ease the transition for incumbents.

• China is likely to develop the leading hub inAsia. Even though international experiencesuggests that first-mover advantages exist inthe development of gas hubs, it is likely that aChina hub would become the Asian marketleader even if it emerges later than hubs inother countries in the region.

2. Factors for consideration when developinghubs

Based on international experience, the pri-mary conditions for creating a successful hub are

468 19 A Close Look at the Natural Gas Industry Chain

a well-developed physical natural gas transmis-sion network that market participants can accessunder non-discriminatory conditions; a largenumber of independent buyers and sellersactively engaged in arbitrage, but without sig-nificant market power; and a government com-mitment to liberalising wholesale gas marketsand a stable, transparent and credible regulatoryframework.

Many of these preconditions for a successfulhub are not currently met in Asian countries,including China. For instance, in China trans-mission infrastructure remains under develop-ment, markets are concentrated, prices are widelyregulated and regulations such as third-partyaccess rules that support the smooth operation ofa market with many buyers and sellers are not yetin place.

A plan to develop a Chinese natural gas hubcould begin by securing the preconditions throughliberalisation of the natural gas sector in China.A hub is a market institution and requires marketliberalisation to function well. Liberalisation facil-itates a hub by enabling prices to be set competi-tively, reducing the influence of state-ownedincumbents, improving market transparency andcreating a level playing field for new marketentrants through third-party access arrangements.

Hub pricing creates winners and losers alongthe natural gas value chain. Some players, pro-tected under the previous regulatory regime,could lose revenues. Improving market signalscould undermine the main rationale for verticalintegration and for co-ordinating action across asupply chain. Other players, on the other hand,could benefit from greater market connectivityand the ability to optimise asset portfolios moreactively.

Who wins and who loses, and by how much,is also affected by the oil price. Historically,natural gas prices have been driven by oilindexation. A higher oil price would mean highernatural gas contract prices, and moving to hubpricing would create strong downward pressureon natural gas prices. Midstream utilities that arelocked into long-term oil-indexed contracts butunable to pass through their higher costs toconsumers would be among the losers. However,

in a world with lower oil prices, as seen since late2014, legacy oil-linked natural gas contract pri-ces would lie below the market-determined pricefor natural gas, thus potentially reversing theroles of winners and losers were a hub estab-lished, and slowing the adoption of hub pricing.

International experience shows that naturalgas hubs are formed in response to marketpressure coming from domestic sources orinternational market developments. In the past,the development of hubs has often been drivenby large additional supplies of natural gas seek-ing access to consumers. This supply has eitherbeen domestically produced, as in the case of theUK’s NBP hub development in the 1990s, oravailable from global LNG markets, as in thedeepening of continental European hub marketsfrom the late 2000s.

At least three supply-side factors are exertingmarket pressure to form a hub in China:expanding domestic gas production, includingfrom unconventional sources; supplies from theglobal LNG market not already contractuallycommitted to particular export markets; andadditional gas imports from Russia from existingor planned pipelines.

The development of natural gas hubs else-where in Asia could also challenge China’sdomestic natural gas pricing arrangements andcreate momentum for a Chinese natural gas hub.For example, Singapore has put itself forward asan LNG hub, with limited trading since 2014.Japan has begun to publish spot LNG prices andhas proposed the creation of a futures market.Although the European experience suggests thatthere are first-mover advantages in hub creation,a potential Chinese hub is likely to become theprincipal Asian hub even if it is not the first.China’s economy is much larger, with largeindustrial consumers of natural gas. China alsohas significant domestic production and hasbegun to develop a national pipeline network.China’s natural gas imports come over pipelinesas well as LNG, unlike the rest of Asia, whichrelies heavily on LNG. These factors suggestthat, supported by the appropriate regulatoryenvironment, a Chinese hub is likely to emergeas the leader in Asia.

19.4 The Downstream Segment: Natural Gas Trading Hubs and the Liberalisation … 469

3. Potential steps for developing hubs

International experience shows that successfulhub development takes time—at least 5–10 years—even in countries with energy sectors that weremuch more liberalised than that in China.

Taking an incremental and phased approachwould allow China to address the preconditionsfor full hub pricing, within the broader marketliberalisation process. Rushing to establish a fullhub by government mandate in the early stagesof liberalisation is likely to fail because of ashortage of participants and institutions.A phased approach, on the other hand, wouldallow market participants to learn and buildinstitutions concurrently with a liberalisationprogramme. A phased approach would alsoallow for the gradual creation of a support net-work among participants, as various players havetime to adjust to the new liberalised markets andthe benefits of market-based pricing becomemore apparent.

The evolution of China’s natural gas sectortowards hub pricing could be phased over 5–10 years and cover six specific aspects(Fig. 19.21).

• Pilot trading market: Within an individualregion, such as Shanghai, the governmentcould create a pilot trading market with con-testable natural gas demand and someuncontracted natural gas supply. The marketwould be connected through a natural gasnetwork with third-party access. Entrepre-neurs would also be encouraged to trade theuncontracted natural gas supply to meetdemand among the customers, who are free tochoose their supplier.

• Price transparency: The government couldrequire publication of prices of natural gassold under all types of contracts. The mandatewould help reveal opportunities for arbitrageto entrepreneurial buyers and sellers, vitalcomponents of a successful market-basedarrangement.

• Government recognition: Once significanttrading activity develops within the pilotregion—for example, a shift to standardisedover-the-counter trading—the governmentcould explicitly endorse the market byestablishing a regulatory body. This bodywould standardise contracts further and seekto reduce transaction costs.

1

Pilot tradingmarket

2

Pricetransparency

3

Governmentrecognition

4

Maturingtrading

5

Renegotiation:traded gas prices

lower thanlegacy contracts

6

Renegotiation:traded gas prices

lower thanlegacy contracts

Gashub

Fig. 19.21 Hub development and its support from regulatory measures and their market effects

470 19 A Close Look at the Natural Gas Industry Chain

• Maturing trading: As exchange-based trad-ing develops, the government would increasethe scope of the pilot region to cover a largergeographic area or more types of buyers andsellers. At this stage, market regulation mayhave to become more stringent to reflect thegrowing system-wide role of natural gas trade.

Following these steps, a natural gas hub couldthen become self-sustaining with two finalchanges:

• Renegotiation: If traded natural gas pricesare lower than legacy oil-indexed natural gascontract prices, companies paying legacy

prices would be put at a disadvantage andmay incur losses if they cannot pass along theprice difference to their customers. Withaccess to the liberalised trading on the naturalgas hub, such companies would have a strongincentive to renegotiate legacy contracts,recalibrating prices or volumes, and buy tra-ded natural gas instead.

• Network effects. As more and differentorganisations join hub trading, the benefits ofthe natural gas hub would increase as a resultof network effect. The use and scope of hubpricing would tend to grow until it reaches thelimits of either incomplete liberalisation or ofgeography.

Open Access This chapter is licensed under the terms ofthe Creative Commons Attribution 4.0 InternationalLicense (http://creativecommons.org/licenses/by/4.0/),which permits use, sharing, adaptation, distribution andreproduction in any medium or format, as long as yougive appropriate credit to the original author(s) and thesource, provide a link to the Creative Commons licenseand indicate if changes were made.

The images or other third party material in this chapter areincluded in the chapter’s Creative Commons license,unless indicated otherwise in a credit line to the material. Ifmaterial is not included in the chapter’s Creative Commonslicense and your intended use is not permitted by statutoryregulation or exceeds the permitted use, you will need toobtain permission directly from the copyright holder.

19.4 The Downstream Segment: Natural Gas Trading Hubs and the Liberalisation … 471

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Open Access This book is licensed under the terms of theCreative Commons Attribution 4.0 International License(http://creativecommons.org/licenses/by/4.0/), which per-mits use, sharing, adaptation, distribution and reproduc-tion in any medium or format, as long as you giveappropriate credit to the original author(s) and the source,provide a link to the Creative Commons license andindicate if changes were made.

The images or other third party material in this book areincluded in the book’s Creative Commons license, unlessindicated otherwise in a credit line to the material. Ifmaterial is not included in the book’s Creative Commonslicense and your intended use is not permitted by statutoryregulation or exceeds the permitted use, you will need toobtain permission directly from the copyright holder.

Further Reading 477