THE RISE OF CHINA - Rice University's Baker Institute...The Rise of China and Its Energy Implications is a major research initiative to investigate the implications of China’s oil

THE RISE OF CHINA AND ITS ENERGY IMPLICATIONS

ENERGYforumJames A. Baker III Institute for Public Policy • Rice University

Quantitative Analysis of Scenarios for Chinese Domestic Unconventional Natural Gas Resources and

Their Role in Global LNG MarketsKenneth B. Medlock III, Ph.D.

Peter R. Hartley, Ph.D.

JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY RICE UNIVERSITY

Quantitative Analysis of Scenarios for Chinese Domestic Unconventional

Natural Gas Resources and Their Role in Global LNG Markets

By

Kenneth B. Medlock III, Ph.D.

JAMES A. BAKER, III, AND SUSAN G. BAKER FELLOW IN ENERGY AND RESOURCE ECONOMICS, JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY, RICE UNIVERSITY

AND

Peter R. Hartley, Ph.D.

RICE SCHOLAR, JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY, AND GEORGE AND CYNTHIA MITCHELL CHAIR OF ECONOMICS, RICE UNIVERSITY

PREPARED BY THE ENERGY FORUM OF THE JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY

AS PART OF THE STUDY THE RISE OF CHINA AND ITS ENERGY IMPLICATIONS

DECEMBER 2, 2011

Scenarios for Chinese Domestic Unconventional Natural Gas Resources

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THIS PAPER WAS WRITTEN BY A RESEARCHER (OR RESEARCHERS) WHO PARTICIPATED IN THE

JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY STUDY. THE RESEARCH AND THE VIEWS

EXPRESSED WITHIN ARE THOSE OF THE INDIVIDUAL RESEARCHER(S) AND DO NOT

NECESSARILY REPRESENT THE VIEWS OF THE JAMES A. BAKER III INSTITUTE FOR PUBLIC

POLICY OR THE STUDY SPONSORS.

© 2011 BY THE JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY OF RICE UNIVERSITY

THIS MATERIAL MAY BE QUOTED OR REPRODUCED WITHOUT PRIOR PERMISSION, PROVIDED APPROPRIATE CREDIT IS GIVEN TO THE AUTHOR AND

THE JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY.


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ACKNOWLEDGMENTS

The Energy Forum of the James A. Baker III Institute for Public Policy would like to thank The Institute of Energy Economics, Japan, and the sponsors of the Baker Institute Energy Forum for their generous support of this program. The James A. Baker III Institute for Public Policy would also like to thank Deloitte MarketPoint LLC for its continued support of the Energy Forum’s natural gas modeling efforts. The Energy Forum further acknowledges contributions by study researchers and writers.

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ABOUT THE STUDY

The Rise of China and Its Energy Implications is a major research initiative to investigate the implications of China’s oil and natural gas policies and domestic energy market development on global energy markets. This study focuses on the influence of China’s energy development on U.S. and Japanese energy security and global geopolitics. Utilizing geopolitical and economic modeling and scenario analysis, the study analyzes various possible outcomes for China’s domestic energy production and its future import levels. The study considers how trends in China’s energy use will influence U.S.-China relations and the level of involvement of the U.S. oil industry in China’s domestic energy sector.

STUDY AUTHORS

JOE BARNES JAMES D. COAN

JAREER ELASS MAHMOUD A. EL–GAMAL

PETER R. HARTLEY AMY MYERS JAFFE STEVEN W. LEWIS DAVID R. MARES

KENNETH B. MEDLOCK III RONALD SOLIGO RICHARD J. STOLL

ALAN TRONER


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ABOUT THE ENERGY FORUM AT THE JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY

The Baker Institute Energy Forum is a multifaceted center that promotes original, forward-looking discussion and research on the energy-related challenges facing our society in the 21st century. The mission of the Energy Forum is to promote the development of informed and realistic public policy choices in the energy area by educating policymakers and the public about important trends—both regional and global—that shape the nature of global energy markets and influence the quantity and security of vital supplies needed to fuel world economic growth and prosperity. The forum is one of several major foreign policy programs at the James A. Baker III Institute for Public Policy of Rice University. The mission of the Baker Institute is to help bridge the gap between the theory and practice of public policy by drawing together experts from academia, government, the media, business, and nongovernmental organizations. By involving both policymakers and scholars, the institute seeks to improve the debate on selected public policy issues and make a difference in the formulation, implementation, and evaluation of public policy.

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ABOUT THE INSTITUTE OF ENERGY ECONOMICS, JAPAN

The Institute of Energy Economics, Japan (IEEJ), was established in June 1966 and specializes in research activities in the area of energy from the viewpoint of Japan’s national economy in a bid to contribute to sound development of Japanese energy supply and consumption industries and to the improvement of domestic welfare by objectively analyzing energy problems and providing basic data, information and the reports necessary for policy formulation. With the diversification of social needs during the three and a half decades of its operation, IEEJ has expanded its scope of research activities to include such topics as environmental problems and international cooperation closely related to energy. The Energy Data and Modeling Center (EDMC), which merged with the IEEJ in July 1999, was established in October 1984 as an IEEJ-affiliated organization to carry out such tasks as the development of energy data bases, the building of various energy models, and the econometric analyses of energy.

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ABOUT THE AUTHORS

KENNETH B. MEDLOCK III, PH.D. James A. Baker, III, and Susan G. Baker Fellow in Energy and Resource Economics James A. Baker III Institute for Public Policy, Rice University Kenneth B. Medlock III, Ph.D., is the James A. Baker, III, and Susan G. Baker Fellow in Energy and Resource Economics at the Baker Institute and an adjunct professor and lecturer in the Department of Economics at Rice University. Currently, Medlock heads the Baker Institute Energy Forum’s natural gas program and is a principal in the development of the Rice World Natural Gas Trade Model, which assesses the future of international natural gas trade. He also teaches energy economics courses and supervises students in the energy field. Medlock studies natural gas markets, gasoline markets, energy commodity price relationships, transportation, modeling national oil company behavior, economic development and energy demand, forecasting energy demand, and energy use and the environment. Medlock is a council member of the International Association for Energy Economics (IAEE), and a member of United States Association for Energy Economics (USAEE), The American Economic Association and the Association of Environmental and Resource Economists. In 2001, he won (with Ron Soligo) the IAEE Award for Best Paper of the Year in the Energy Journal. In 2011, he was given the USAEE’s Senior Fellow Award. Medlock also served as an adviser to the U.S. Department of Energy and the California Energy Commission in their respective energy modeling efforts. He was the lead modeler of the Modeling Subgroup of the 2003 National Petroleum Council (NPC) study of long-term natural gas markets in North America, and is involved in the ongoing NPC study North American Resource Development. Medlock received his Ph.D. in economics from Rice and held the MD Anderson Fellowship at the Baker Institute from 2000 to 2001. PETER R. HARTLEY, PH.D. Rice Scholar, James A. Baker Institute for Public Policy George and Cynthia Mitchell Chair of Economics, Rice University Peter R. Hartley, Ph.D., is the George and Cynthia Mitchell Chair and a professor of economics at Rice University. He is also a Rice scholar of energy economics for the James A. Baker III Institute for Public Policy. Hartley has worked for more than 25 years on energy economics issues, focusing originally on electricity, but also including work on natural gas, oil, coal, nuclear, and renewable energy. He wrote on reform of the electricity supply industry in Australia throughout the 1980s and early 1990s and advised the government of Victoria when it completed the acclaimed privatization and reform of the electricity industry in that state in 1989. Apart from energy and environmental economics, Hartley has published research on theoretical and applied issues in money and banking,


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business cycles, and international finance. He worked for the Priorities Review Staff, and later the Economic Division, of the Prime Minister’s Department in the Australian government. He came to Rice as an associate professor of economics in 1986 after serving as an assistant professor of economics at Princeton University from 1980 to 1986. Hartley completed an honors degree in mathematics and a master’s degree in economics at The Australian National University. He obtained a Ph.D. in economics at The University of Chicago.


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I. Introduction1

The past decade has yielded dramatic change in the natural gas industry. Specifically, there has

been rapid development of technology allowing the recovery of natural gas from shale

formations. This technology has been applied with much success in North America, and there is

much interest in seeing similar developments in other countries around the world. Since 2000,

production of natural gas from shale formations in North America has dramatically altered the

global natural gas market landscape. In fact, the emergence of shale gas is perhaps the most

significant development in global energy markets in the last decade.

Knowledge of the shale gas resource is not new as geologists have long known about the

existence of shale formations, and accessing those resources was long held in the geology

community to be an issue of technology and cost. In the past decade, innovations involving the

use of horizontal drilling with hydraulic fracturing have yielded substantial cost reductions,

making shale gas production a commercial reality. In fact, shale gas production in the United

States has increased from virtually nothing in 2000 to over 10 billion cubic feet per day (bcfd) in

2010, and it is expected to more than quadruple by 2040, reaching over 50 percent of total U.S.

natural gas production by the 2030s (see Figure 1).

Figure 1. U.S. Natural Gas Production through 2040 (Reference Case)


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To be sure, shale gas developments in North America have had a ripple effect across the globe

by displacement of supply in global trade and by fostering a growing interest in shale resource

potential in other parts of the world. Thus, North American shale gas developments are having

effects far beyond the North American market, and these impacts are likely to expand over time.

The state of knowledge regarding the portion of shale gas that is economically recoverable has

changed rapidly over the last 10 years. A simple chronology of assessments for North America,

where most development activity has occurred to date, is as follows:

• As recently as 2003, the National Petroleum Council2 estimated that about 38 tcf of

technically recoverable resource was spread across multiple basins in the North America.

• In 2005, the Energy Information Administration (EIA) was using an estimate of 140 tcf

in its Annual Energy Outlook as a mean for North American technically recoverable shale

gas resource.

• In 2008, Navigant Consulting, Inc.3 estimated a mean of 280 tcf of technically

recoverable resources from reviewable geologic literature, but a survey of producers

indicated up to 840 tcf.

• In 2009, the Potential Gas Committee4 put its mean estimate at just over 680 tcf.

• In 2011, Advanced Resources International (ARI) reported an estimate of about 1,930 tcf

of technically recoverable resource for North America, with over 860 tcf in U.S. gas

shales alone.5

Importantly, although each assessment is from an independent source, the estimates are

increasing over time as more drilling occurs and technological advances are made. Moreover, the

shift in the generally accepted assessment of recoverable shale resource has left producers,

consumers, and governments all grappling with the implications for markets as well as the

geopolitical repercussions.

Shale gas developments stand to exert enormous influence on the structure of the global gas

market. Throughout the 1990s, natural gas producers in the Middle East and Africa, anticipating

rising demand for LNG from the United States in particular, began investing heavily in

expanding LNG export capability, concomitant with investments in regasification being made in


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the United States. But the rapid growth in shale gas production has turned such expectations

upside down and rendered many of those investments obsolete. Import terminals for liquefied

natural gas (LNG) are now scarcely utilized, and the prospects that the United States will become

highly dependent on foreign imports in the coming years are receding.

Rising shale gas production in the United States is also having an impact on markets in Europe

and Asia. In particular, LNG supplies whose development was anchored on the belief that the

United States would be a premium market are now being diverted to European and Asian buyers.

Not only has this immediately presented consumers in Europe with an alternative to Russian

pipeline supplies, it is also exerting pressure on the status quo of indexing gas sales in both

Europe and Asia to a premium marker determined by the price of petroleum products. In recent

rounds of renegotiations, Russia has had to accept far lower prices from many of its traditional

long-term customers and has accepted a partial link to gas on gas pricing.

Revelations about the potential for increased shale gas production are also occurring in other

regions around the world, with shale gas discoveries being discussed in Europe, China, India,

Australia, and elsewhere. To be sure, the enormity of global shale gas potential will have

significant geopolitical ramifications and exert a powerful influence on U.S. energy and

foreign policy.

In this study, we utilize scenario analysis to examine the role that China plays in the future of

global gas market developments. In doing so, we consider two cases, which we compare to a

reference case, where:

1. China’s technically recoverable shale resource base is dramatically larger; and

2. China’s economic growth falters, thus lowering natural gas demand growth.

We also expand on the effect of shale gas developments more generally by highlighting a recent

paper by Medlock and Jaffe (2011)6 in which no shale is developed anywhere in the world. This

highlights the overall importance of the shale gas resource to international gas markets.


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Among the geopolitical repercussions of expanding shale gas production are:

• It virtually eliminates U.S. requirements for imported LNG for at least two decades,

reducing U.S. and Chinese dependence on Middle East natural gas supplies, lowering the

incentives for geopolitical and commercial competition between the two largest

consuming countries, and providing both countries with new opportunities to diversify

their energy supply.

• It substantially reduces Russia’s market share in both Europe and Asia, depending on the

amount of shale resource that is ultimately available in both regions.

• It lowers prices and stimulates greater use of natural gas, thereby having significant

implications for global environmental objectives to the extent it displaces coal.

• It reduces overall dependence on Iranian natural gas, which limits Iran’s ability to tap energy

diplomacy as a means to strengthen its regional power or to buttress its nuclear aspirations.

It should be pointed out that the sustained rapid development of shale gas is not a certainty. In

particular, environmental concerns regarding the use and potential contamination of water

resources are major issues that will need to be addressed before governments will allow full

realization of shale’s growth potential.7 In China, in particular, water availability for hydraulic

fracturing may considerably diminish the potential for domestic shale development.

According to a report by Gleick et al. (2008),8 China faces some of the most severe water

challenges in the world due to overallocation, inefficient usage, and widespread pollution, as

well as a fairly weak regulatory body. Moreover, the response to issues of scarcity from Beijing

and central water agencies has typically been one involving proposals for massive new

infrastructure to divert water from one region to another rather than new approaches to

management. One such massive project is the South-to-North Water Transfer Project, which

will funnel 45 billion cubic meters (bcm) of water to the northern part of the country through

the Yangtze River basin but will not be completed for several decades at the earliest. There are

also plans for investment in water distribution systems and the construction of more than 1,000

water and wastewater treatment facilities. Plans for coastal water desalination are also in their

early stages.


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Regional conflicts over water allocation have emerged from a national water policy that seems

centered around moving water from region to region via large infrastructure projects. This

national policy stance is not new. The intensity of the problem in some regions can be witnessed

by the fact that periodic clashes have occurred since the 1970s over water from the Zhang

River. The North China Plains also face fierce competition over water, as Beijing’s growing

population has led to the city’s exploitation of nearly all major rivers flowing through

surrounding provinces.

Figure 2 highlights the potential water availability issues and their intersection with potential

shale gas developments. Notice, with the exception of only a couple of basins, the coincidence of

shale gas resources and water stress is very high. Due to potential water constraints, we have

substantially reduced the technically recoverable shale gas resource base in China in our

Reference Case. However, we do compare this outcome to one in which any potential water

issues can be largely overcome, which results in a technically recoverable shale resource base

that is substantially larger. We describe all scenarios in more detail below.

Figure 2. China Shale Resource and Water Stress Map9


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II. Study Approach

In this study, we utilize the Rice World Gas Trade Model (RWGTM)10 to examine the market

implications and geopolitical consequences of potentially important supply and demand side

developments in China, namely rising supplies of natural gas from shale and changes in its

economic outlook. The RWGTM is a dynamic spatial general equilibrium model where supply

and demand is balanced at each location in each time period such that all spatial and temporal

arbitrage opportunities are eliminated. The model, therefore, proves and develops reserves,

constructs transportation routes and associated infrastructure, and calculates prices to equate

demands and supplies while maximizing the present value of producer rents within a competitive

framework. Thus, new infrastructures must earn a minimum return to capital in order for its

development to occur.11 By developing pipeline transportation routes and LNG delivery

infrastructure, the RWGTM provides a framework for examining the effects of critical economic

and political influences on the global natural gas market within a framework grounded in

geologic data and economic theory. Moreover, it provides insight as to the location and

conditions under which resources are competitive in a global market.

The RWGTM allows the examination of potential futures for U.S. and global natural gas in a

manner that allows quantification of geopolitical influences on resource development and export

flows. The RWGTM predicts regional prices, regional supplies and demands, and interregional

flows. Since geopolitical influences can alter market outcomes in many different ways, the non-

stochastic nature of the RWGTM allows an analysis of many different scenarios and allows the

model to characterize the impact of later economic outcomes on earlier investment decisions. In

this way, the inter-temporal nature of the RWGTM allows a complete analysis of the impact on

investment decision pathways of specific scenarios. This follows from the fact that capacity and

reserve expansions are determined by current and future prices along with capital costs of

expansion, operating and maintenance costs of new and existing capacity, and revenues resulting

from future outputs and prices. The RWGTM is a unique tool because it allows simultaneous

analysis of many different outcomes and is not sequence dependent.


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The RWGTM is a highly disaggregated representation of existing and potential resources,

demand sinks, and distribution networks. The extent of regional detail in the RWGTM varies

based primarily on data availability and the potential influence of particular countries on the

global natural gas market. For example, large consuming and producing countries, such as

China, the United States, India, Russia, and Japan, to name a few, have extensive sub-regional

detail in order to understand the effect that existing or developing intra-country capacity

constraints could have on current or likely future patterns of natural gas trade. In general,

regions are defined at the country and sub-country level, with extensive representation of

transportation infrastructure connecting over 290 regions with more than 135 supply regions.

U.S. demand is characterized at the state and sub-state level for the residential, commercial,

industrial, and power generation sectors. Demand in all other countries is less detailed at the end-

use level, as it is estimated for the power generation sector and all other sectors—a limitation

directly related to data availability.

Supply costs are present for each region in three primary categories—(i) proved reserves, (ii)

growth in existing fields, and (iii) undiscovered resources—and are present for both

conventional and unconventional resources. The resource data derives from sources including

the Oil and Gas Journal (OGJ), United States Geological Survey (USGS), National Petroleum

Council (NPC), Australian Bureau of Agriculture and Resource Economics (ABARE), and

Baker Institute research on unconventional resources in North America and globally. North

America finding and development (F&D) costs are based on estimates developed by the NPC

and have been adjusted using data from the Bureau of Economic Analysis KLEMS data to

account for changes in upstream costs since the early 2000s. These costs have been

econometrically related to play-level geological characteristics and applied globally to generate

costs for all regions of the world. In general, long-run F&D costs increase with depletion, and

short-run adjustment costs limit the “rush to drill” phenomenon. Technological change is

allowed to reduce F&D costs over the long run.

In a global natural gas market as develops in the RWGTM, events in one region of the world

influence all other regions to the extent trade can occur between regions. Thus, political factors

affecting relations between Russia and China, for example, will affect flows and prices


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throughout the world, not just in Northeast Asia. This follows because transportation links

connecting markets transmit price signals as well as volumes of physical commodity. It is in this

manner that markets become increasingly connected over time, specifically as profitable spatial

arbitrage opportunities are exploited until they are eliminated. The costs of constructing new

pipelines and LNG facilities in the RWGTM are estimated using data on previous and potential

projects available from the EIA, International Energy Agency (IEA), and various industry

reports. Within the United States, Federal Energy Regulatory Commission (FERC)-filed tariff

rates are used to determine the cost of transporting natural gas via pipeline. For regions outside

the United States, a rate-of-return calculation is generally used to construct the tariffs on

pipelines, such that the present value of the tariff revenue at 50 percent capacity utilization just

recovers the upfront capital cost in 20 years. For LNG, facility throughput tariffs and shipping

rates are based on information obtained from various industry reports.

We compare results in an analysis based on the following three scenarios.

• Reference Case: This case posits a scenario in which all known global shale gas

resources can be developed given prevailing commercial technologies and open tendering

practices. This scenario includes all global shale resources that have been identified as

commercially viable in Europe and Asia and thereby present a full picture of the current

expectations for changing geopolitical and market implications of a full scale

development of known shale gas resources.

• High China Shale Case: This case assumes the quantity of commercially viable shale

resource available for development in China is substantially larger than in the Reference

Case. In fact, the estimated technically recoverable shale resource distributed across four

basins is 600 tcf, an increase by an order of magnitude over the Reference Case. The

dramatically larger resource assessment is still smaller than the resource identified in the

recent ARI/EIA study, but other issues related to development, which are outlined herein,

make this a reasonable upper bound assessment for this case.

• Low China Demand Case: This case posits a much slower growth rate of the Chinese

economy than the Reference Case. The average annual growth rate of real GDP in China

from 2010-2030 is 2.5 percent in this case, which is a reduction from 5.1 percent in the

Reference Case. This occurs due to an assortment of potential problems that might affect


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the Chinese economy in the coming years (high inflation, problems related to

infrastructure constraints, etc.).12

III. Defining the Resource

Shale gas resources became prominent for its potential to provide large amounts of marketable

natural gas in only the last several years, centered primarily on developments in the United

States. Beginning with the Barnett shale in northeast Texas, the application of innovative new

techniques involving the use of horizontal drilling with hydraulic fracturing has resulted in the

rapid growth in production of natural gas from shale. Moreover, the production potential that has

been identified since the emergence of the Barnett shale—which until very recently was the

largest single producing natural gas play in North America, having just been surpassed by

production from the Haynesville shale in neighboring Louisiana—has dramatically altered

expectations for global LNG trade. Less than 10 years ago, most predictions were for a dramatic

increase in LNG imports to the United States, but shale production has turned this thinking

upside down. Today, growth opportunities for LNG developers are seen in primarily in Asia,

which could be threatened by a similar emergence of shale in those regions.

Knowledge of shale gas resource is not new as geologists have long known about the existence

of shale formations. However, the ability to access shale resources in a commercial manner is

new. In a study published in 1997, Rogner estimated over 16,000 trillion cubic feet (tcf) of shale

gas resource in-place globally with just under 4,000 tcf of that total estimated to be in North

America.13 At that time, only a very small fraction (<10 percent) of this was deemed to be

technically recoverable and even less so economically. But recent innovations have rendered this

resource accessible both by providing the technological capability and by reducing costs, thereby

providing economic feasibility. In fact, the IEA recently estimated about 40 percent of the

estimated resource in-place by Rogner (1997) will ultimately be technically recoverable.

Despite very large assessments of resource in-place, the commercial viability of shale is

determined as a subset of resource in-place. In particular, technically recoverable resources define

the boundary of those resources that can be recovered with existing technology, but economically


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recoverable resource defines the boundary of what is commercially accessible. Thus, large

resource in-place estimates do not necessarily imply large-scale production is forthcoming

because technical innovations and cost reductions are critical to commercial viability.

As noted above, the application of horizontal drilling with hydraulic fracturing to create a

reservoir in virtually impermeable shale formations propelled the Barnett shale to becoming the

largest single producing natural gas play in North America. This subsequently altered producers'

expectations about the viability of shale resources in other locations, and triggered a virtual rush

to the shale resource. Innovations aimed at lowering costs continue, with longer laterals,

increased frac stages, and better proppants. For example, Schlumberger recently reported very

promising results in test wells from the use of its innovative new “HiWAY” fracing technique,

yielding up to double the daily production and greater expected ultimate recovery when

compared to standard slickwater fracs. Currently in North America, break-even prices for some

of the more prolific shales are estimated to be as low as $3 per thousand cubic feet (mcf), with a

large majority of the resource accessible at below $6/mcf. Ten years ago, costs were significantly

higher. As firms continue to make cost reducing innovations, greater quantities of the shale

resource will become both technically and economically viable.

Given the magnitudes of the assessments of shale resources reported in just the past couple of

years, modeling done at the James A. Baker III Institute for Public Policy (BIPP) at Rice

University indicates a relatively conservative estimate of North American technically

recoverable shale resource of 686 tcf. A detailed account is provided in Table 1. The “break-even

price” indicated in Table 1 is the average price needed for development of the average “type”

well for the associated technically recoverable resource.

Shale gas resources are not limited to only North America. In-depth studies are currently

underway to fully assess shale resource potential in Europe, Asia, and Australia, but a dearth of

commercial activity renders the current assessments in those regions highly uncertain. In Europe,

while some estimates exist, there is active research into assessing shale potential in Austria,

Sweden, Poland, Romania, Germany, Croatia, Denmark, France, Hungary, Netherlands, Ukraine,

and the United Kingdom, to name a few locations.


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Table 1. North American Shale Gas Assessments in the RWGTM

Currently, our work at BIPP indicates a technically recoverable assessment in Europe of roughly

220 tcf split between Sweden, Poland, Austria, and Germany, with the largest proportion (about

55 percent) in Poland, and entry costs in the $6-8/mcf range. Data for Asia and the Pacific is

generally even more preliminary, but potential has been identified in China (75 tcf of recoverable

resource) and Australia (50 tcf of recoverable resource), to name two. These estimates are very

Mean Technically Recoverable Resource (tcf) Breakeven Price

Antrim 13.2 5.50$

Devonian/Ohio 170.8

Utica 5.4 6.25$

Marcellus 135.4

Marcellus Tier 1 47.4 4.00$



NW Ohio 2.7 6.75$

Devonian Siltstone and Shale 1.3 6.75$

Catskill Sandstones 11.7 6.75$

Berea Sandstones 6.8 6.75$

Big Sandy 6.3 6.00$

Nora/Haysi 1.2 6.25$

New Albany 3.8 7.00$

Floyd/Chattanooga 4.3 6.00$

Haynesville 105.0

Haynesville Tier 1 42.0 4.00$



Fayetteville 36.0 4.25$

Woodford Arkoma 8.0 4.50$

Woodford Ardmore 4.2 5.75$

Barnett 54.0

Barnett Tier 1 32.2 4.25$

Barnett Tier 2 21.8 5.75$

Barnett and Woodford 35.4 6.50$

Eagle Ford 35.0 4.00$

Palo Duro 4.7 6.25$

Lewis 10.2 6.25$

Bakken 1.8 4.00$

Niobrara 1.3 6.50$

Hilliard/Baxter/Mancos 11.8 6.50$

Paradox/Uinta 13.5 6.50$ Mowry 8.5 6.50$

Horn River 90.0

Horn River T1 50.0 4.50$

Horn River T2 40.0 5.25$

Montney 65.0

Montney T1 25.0 4.75$

Montney T2 40.0 5.50$ Utica 10.0 6.25$

Total US Shale 521.5

Total Canadian Shale 165.0

Total North America 686.5


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preliminary and are thus full of uncertainty, but it is possible that estimates of commercially

accessible resources in these regions will grow over time, particularly as technologies are

developed to increase production rates and lower costs.

In fact, the shale resource is by most accounts very large. The previously mentioned studies by

Rogner (1997) and ARI (2011) are summarized in Table 2, where technically recoverable

resources from Rogner’s study have been inferred using the IEA’s recent assessment of a

reasonable recovery factor. Notice that the resources are quite substantial, especially when

compared to the assessments in the Reference Case, which are also included in Table 2.

Ongoing research will likely result in an increased assessment to be used in our own modeling,

but that is preliminary at the time this research was completed. Nevertheless, in order to

understand the implications of larger recoverable resources, we have constructed the High

China Shale Case for comparison.

Table 2. A Summary of Global Shale Gas Assessments**

Notable differences in the assessments in Table 2 center largely on the level of detail. For

example, the RWGTM has no shale gas assessment in Latin America, FSU, India, Middle East,

North Africa, and Other. This accounts for a difference in the total technically recoverable

Rogner (1997)* ARI (2011) RWGTMNorth America 1537 1931 686Latin America 847 1225 ---

Europe 220 639 220FSU 251 --- ---China 1275 75India 63 ---

Australasia 925 396 50Middle East --- ---North Africa 558 ---

Other 235 538 ---Total 6445 6625 1031

*- applies a 40% recovery factor to the estimated gas in place.

1411

1019

**- The assessments in the RWGTM incorporate an assessment of economic viability as well as a discount factor applied to reflect other constraints.


21

assessment relative to the ARI assessment of over 2,300 tcf. It is important to point out, however,

that the economic viability of much of the resource identified in the Rogner and ARI studies can

be called into question due to the rock properties and other factors related to the geophysical

properties of the shale. Work is currently ongoing to assess the extent to which this is the case. In

addition, factors such as market structure and mineral property rights also will play a role in the

economic viability of shale around the world, a point that cannot be understated. Arguably, if the

current market structure in the United States did not exist, the shale gas boom would not have

occurred. This is due to the fact that the small producers who initiated the proof of concept had

little to no risk of accessing markets from very small production projects. A market in which

capacity rights are not unbundled from facility ownership does not foster entry by small

producers.

IV. Scenario Analysis—Reference Case

The repercussions of expanding shale gas production potential are profound. In the Reference

Case scenario, LNG exports originate from a wide diversity of sources instead of being

concentrated in any one geographical region, and no single supplier gains significant market

leverage (see Figure 3). Qatar remains the largest LNG exporter while Australia emerges as a

close second. Nigeria, Iran, and Venezuela eventually each grow to positions of prominence, and

they collectively account for about 35 percent of global LNG exports by 2040.

Importantly, it has been shown by Medlock and Jaffe (2011) that shale gas, by displacement, has

both spatial and temporal impacts on the global gas market. More specifically, they show that

shale gas delays for well over a decade the world’s reliance on regions that have historically been

volatile and greatly reduces the chances of decisive monopoly power being exercised by any

individual or grouping of producers. In the United States, in particular, growth in LNG imports is

put off by at least two decades.14 Nevertheless, global LNG trade grows, largely due to growth in

Asia. In fact, the Reference Case reveals very different reliance on LNG across regions, ranging

from very low in North America to very high in Asia (see Figure 4).


22

Figure 3. Reference Case LNG Exports (by country) to 2040

We can see that Asia accounts for a massive 59 percent of global LNG demand, with China

leading the way at 24 percent of all global LNG imports. This compares to a European import

share of 22 percent and a North American import share of 16 percent.15 In sum, growth in

supplies of natural gas from shale is a catalyst for deepening of the global natural gas market,

and strong demand growth in Asia triggers significant growth in global LNG trade.

The deepening of the global gas market has distinct benefits. In particular, as shown in Hartley

and Medlock,16 growth in LNG trade implies growth in physical liquidity, which increases

arbitrage allowing for shocks in one region to be transmitted to others. While this may seem

undesirable, it actually mitigates the impact of any single shock. For example, greater ability to

import LNG provides European consumers a means of dealing with future disruptions in Russian

supplies, or U.S. consumers a means of coping with unexpected hurricane damage. Thus, the

impact of the shock on any one region is reduced through arbitrage.


23

Figure 4. Reference Case LNG Imports (by country) to 2040

Brito and Hartley17 show that growth in physical liquidity also limits the ability of a single

supplier to price above marginal cost. The relative abundance of LNG, prompted by the dramatic

growth in shale, also puts downward pressure on demand for pipeline supplies, meaning Europe

and Asia see increased competition. Importantly, this has implications for the terms at which

existing and future supplies are negotiated. In fact, as the natural gas supply curve becomes more

elastic, as is the case with shale gas developments, it will become increasingly difficult to price

above marginal cost, meaning oil indexation is likely to lose some of its prominence.

Absent storage and physical liquidity, oil indexation provides an element of price certainty. But,

to be sure, oil indexation is a form of price discrimination. Figure 5 provides an illustration of

price discrimination. Note that oil indexation does not preclude the existence of spot

transactions, but market structures that do not easily allow resale can severely limit them. In

Figure 5, about 15 percent of the marketed volumes are sold on a spot basis, with the remaining

85 percent contracted above marginal cost.

In general, for a firm to be able to price discriminate (1) it must be able to distinguish consumers

and prevent resale, and (2) its consumers must have different elasticities of demand. Both of

these conditions are met in Europe and Asia. However, an increased ability to trade between


24

suppliers and consumers (i.e., increased physical liquidity) leads to a violation of condition (1).

This is more likely to happen as the supply curve in Figure 5 becomes more elastic (flatter).18

Even now, evidence of diminished ability to price discriminate is emerging in Europe as there

have been multiple announcements of changes in contractual terms, with a propensity to index at

least a portion of sales to spot prices. Thus, by displacement, the increase in shale production in

North America has begun to have impacts on traditional pricing mechanisms in other markets. If

shale resources are proven to be commercially viable in Europe and Asia, this will accelerate,

and the “new normal” could very well be characterized by more intense competition and

increased pressure for departure from the traditional oil-indexed pricing paradigm.

Figure 5. Oil Indexation and Price Discrimination

As demonstrated in Medlock and Jaffe (2011), if the increased competition from shale had not

emerged, two producing countries in particular would be left with a dominant position in the

global gas market: Russia and Iran. Before the shale discoveries, these nations were expected to

account for more than half of the world’s known conventional gas resources. Notably, both

Russia and Iran have been more than just casual observers in the Gas Exporting Countries Forum

(GECF). The emergence of shale limits the near term possibility of a successful natural gas cartel

being formed by those countries involved in the GECF by increasing the elasticity of supply of

S

D

P@ P=MC

POIL INDEX

Oil Indexed Contract Volume

“Spot” Volume

Total Volume

P

Q

Rent earned from pricing supply above marginal cost

Marginal price


25

natural gas in countries outside GECF, which reduces the potential for a small group of

producers to exercise monopoly power.

In fact, in the Reference Case, as can be seen in Figure 6, world dependence on Middle East

natural gas remains below 20 percent until the late 2030s as rising demand from Asia finally

makes its mark. But, as argued in Medlock and Jaffe (2011), reliance on Middle East natural gas

is significantly higher in a world without shale gas. Moreover, the Middle East country that is

disadvantaged the most as a result of rising shale gas production is Iran, whose exports are

effectively delayed by over a decade.

Figure 6. World Supply by Region, 1990-2040 (Reference Case)

In the Reference Case, China becomes a major importer of natural gas both via pipeline and

LNG. In fact, it is the largest driver of growth in LNG trade going forward. Figure 7 indicates

both the growth in demand for natural gas and the manner in which demand is met—via

domestic production (conventional and unconventional gas), LNG imports, and pipeline imports.

Among the domestic options, shale gas becomes an increasingly important source of supply, but

it largely acts to offset declines in conventional gas production. Almost all of the growth in

demand is balanced by imports of pipeline gas from Russia, Turkmenistan, and Myanmar (with

Russia being the largest supplier long term) and by LNG imports. In fact, LNG imports account

for over 50 percent of China’s gas supply longer term.


26

Figure 7. China Natural Gas Balance, 2010-2040 (Reference Case)

Strong growth in LNG imports to China has implications for pricing in Asia, as might be

expected. In Figure 8, we see the prices for Asia, National Balancing Point (NBP), and Henry

Hub. Note that the Asian price remains strong relative to other global markers, being at parity

with NBP and well above the price at Henry Hub. Interestingly, demand growth in China

ultimately drives a strengthening of energy ties between Russia and China, a result that may, if it

eventuates, influence the balance of power in Northeast Asia.

Figure 8. Select Natural Gas Prices, 2010-2040 (Reference Case)19


27

V. Scenario Analysis—High China Shale Case

As noted above, the recent assessment by ARI (2011) places China’s technically recoverable

shale gas resource at over 1,200 tcf, which is a stark contrast to the resource assessment used in

the Reference Case (75 tcf). However, there is tremendous uncertainty around the economically

recoverable assessment of shale in China. Challenges related to water access and availability,

infrastructure, resource ownership and market incentive, and market structure are all very

relevant issues that must be considered when formulating the amount of shale resource that may

ultimately be recovered. Given the tremendous uncertainty associated with resolution of these

types of issues, we consider a case in which the resource assessment in China is raised to 600 tcf.

Table 3 indicates the distribution of the shale resources in both the Reference Case and the High

China Shale Case. Notably, the resource is spread across multiple basins, where the distribution

is informed by the ARI study and historical gas production. Note that the largest concentration of

shale is in western (Tarim) and north central China (Ordos), which coincide with the regions

with the largest technically recoverable assessments for conventional natural gas (85 and 19 tcf,

respectively) and, in the case of the Ordos basin, coal bed methane (100 tcf).

Table 3. Shale Assessment Across Cases (Units: tcf)

Figure 9 indicates demand and the manner in which demand is met in the High China Shale

Case. As in Figure 7 above, sinks (demand and exports) are represented as negative values and

sources of supply are represented as positive values. A few things are of substantial note. First,

Reference High China Shale

Tarim BasinJunggar Basin

Tuja Basin

Sichuan BasinJianghan Basin

North Central Ordos Basin 30 150

Songliao BasinBohai Bay Basin

Total 75 600

250

45

---West

Central 120

Northeast --- 80


28

even though shale gas production is substantially higher, resulting in lower import dependence,

China still imports natural gas via pipeline and as LNG. Second, China begins to export gas (to

South Korea) beginning in 2016, rising to almost a billion cubic feet per day. The overall impact

of lower import dependence and exports to South Korea substantially reduces demand for LNG

imports in Asia (see Figure 12).

Figure 9. China Natural Gas Balance, 2010-2040 (High China Shale Case)

Figure 10 indicates the changes relative to the Reference Case associated with the assumptions

regarding the technically recoverable shale resource base indicated in Table 3. The top panel in

Figure 10 indicates a very large increase in shale gas production, which results in a decline in

both LNG and pipeline imports. We also see that demand is higher due to lower prices (see

Figure 11), and that China begins to export gas (by pipeline to South Korea).

Higher shale gas production in China leaves it less exposed to potentially disruptive events in the

Middle East and Russia. This follows because in the Reference Case, China becomes

increasingly dependent on both the Middle East and Russia for both LNG and pipeline imports.

Thus, to the extent that natural gas supplies can instead be sourced from domestic production,

China is better off.


29

Figure 10. Changes in Supply Sources and Disposition Relative to Reference Case

Sources of Supply

Demand

Exports


30

The benefits extend beyond China’s borders as well. This is evidenced in Figure 11 through the

impact that greater Chinese shale production has on prices. Asian prices are reduced by the

greatest amount, but prices at both NBP and the Henry Hub are also reduced. This occurs as a

result of the large reduction in LNG demand in Asia, which reduces competition for LNG

imports. In fact, LNG imports to the U.S. and European nations increase (see Figure 13) in the

High China Shale Case.

Figure 11. Decadal Average Changes in Price Relative to Reference Case

Figure 12. Changes in LNG Exports by Country Relative to Reference Case

We also see that global LNG exports are generally lower as a result of greater shale production

in China, a result that reinforces the point that Asian demand is the driver of LNG growth in the

Reference Case. Figure 12 indicates that in 2040 about 85 percent of the reduction in LNG


31

exports falls on Iran, Qatar, Russia, and Venezuela. This is analogous to the point made in

Medlock and Jaffe (2011) that shale resources tend to reduce the long-run market influence of

Iran, Russia, and Venezuela.

Figure 13. Changes in LNG Imports by Country Relative to Reference Case

VI. Scenario Analysis—Low China Demand

The recent experience of the Chinese economy has led many to predict very robust long-term

average annual growth rates of the economy. This, in turn, yields very robust outlooks for

Chinese energy demand, and more specifically, natural gas demand. Given the impact that such

strong growth has on global natural gas flows in the Reference Case, we examine a scenario in

which demand growth in China is much less robust. We affect this change by assuming much

slower economic growth. In the Reference Case, the average annual growth rate in GDP from

2010 through 2030 is 5.6 percent, but in the Low China Demand Case the average annual growth

rate in GDP is 2.9 percent.


32

Figure 14. China Natural Gas Balance, 2010-2040 (Low China Demand Case)

Figure 14 indicates demand and the manner in which demand is met in the Low China Demand

Case. As above, sinks (demand and exports) are represented as negative values and sources of

supply are represented as positive values. Of note is the fact that the reduction in demand (see

Figure 15) results in lower import dependence, where the majority of the reduction occurs as a

result of lower LNG imports. The overall impact of lower import dependence and exports to

South Korea substantially reduces demand for LNG imports in China (see Figure 15). Lower

LNG demand in China, as in the analysis above, leads to higher LNG imports in the United

States and Europe (see Figure 18).

As in the High China Shale Case, China exports natural gas to South Korea in this case as well,

which reduces Korean demand for LNG in addition to the reduction in China (see Figure 18).

However, the source of supply for exports from China is different. In particular, Russian natural

gas is imported via pipeline and re-exported, meaning China is more likely to be a transit country

when demand growth is lower.


33

Figure 15. Changes in Supply Sources and Disposition Relative to Reference Case

Sources of Supply

Demand

Lower demand also results in lower prices in Asia as well as in Europe and the United States.

This result owes itself to the reduction in competition for LNG from Asia, which allows supplies

to be redistributed at lower cost to other regions.


34

Figure 16. Changes in Selected Prices Relative to Reference Case

Lower demand for LNG from China, and Asia more generally, results in lower global LNG

exports. From Figure 17, we see that the majority of the reduction in exports by 2040 falls to

Qatar, Iran, Russia, and Venezuela. In fact, about 85 percent of the reduction in LNG exports

falls to these four countries collectively.

Figure 17. Changes in LNG Exports by Country Relative to Reference Case


35

Figure 18. Changes in LNG Imports by Country Relative to Reference Case

VII. Conclusion

This Baker Institute study on the role of China in the future of global gas markets has examined

some of the consequences of rising supplies of natural gas from shale in China and lower than

expected demand for natural gas in China. The study finds that development of shale gas

resources in China will have multiple beneficial effects for energy security in China, and in Asia

more generally. In addition, a reduction in import dependence in China has a ripple effect that

results in lower prices in Europe and the United States as well as in Asia.

Natural gas stands to play a positive role in the global energy mix, making it easier to shift away

from more polluting, higher carbon intensity fuels and increasing the near term options to

improve energy security and handle the challenge of climate change. Greater shale gas

production will lower the cost of improving local air quality in China by encouraging a switch to

natural gas in place of coal. In fact, the increase in demand that results in the High China Shale

Case is indicative of this occurring when the relative abundance of natural gas is greater. The

ample geologic endowment of shale gas in North America and around the globe means that

natural gas prices will likely remain affordable even in the face of rising oil prices, and that the

high level of supply insecurity currently facing world oil supplies could be eased by a shift to


36

greater use of natural gas without fear of increasing the power of large natural gas resource

holders such as Russia, Iran, and Venezuela.

To tap this benefit, initiatives such as the U.S.-China Shale Gas Resource Initiative could serve

to ensure that Chinese development of its resources is done in a responsible and commercial

manner.20 But shale gas development, for reasons highlighted herein, are not certain. So it is

imperative that impediments to development be addressed in a timely manner in order for

Chinese shale gas production to grow in a robust manner.


37

Notes

1. We would like to thank Energy Forum research associate Keily Miller for her

invaluable help gathering information on water resources in China.

2. National Petroleum Council, “Balancing Natural Gas Policy: Fueling the Demands of a

Growing Economy,” September 2003.

3. Navigant Consulting, “North American Natural Gas Supply Assessment,” July 4, 2008.

4. The Potential Gas Committee, “Potential Gas Committee Biennial Assessment,” June

18, 2009.

5. “World Shale Gas Resources: An Initial Assessment of 14 Regions outside the United

States” (report prepared by Advanced Resources International for the Energy Information

Administration, April 2011).

6. Kenneth B. Medlock III and Amy Myers Jaffe, “Shale Gas and U.S. National Security”

(working paper, James A Baker III Institute for Public Policy, Rice University, May 2011).

7. See Time Magazine cover story, “The Gas Dilemma,” April 11, 2011.

8. See “China and Water” in Gleick, Cooley and Morikawa, The World’s Water

2008:2009: The Biennial Report on Freshwater Resources, Island Press, 2008. Available at

http://www.worldwater.org/data20082009/ch05.pdf.

9. Map replicated from “Natural Gas Weekly Kaliedoscope,” Barclay’s Capital

Commodities Research, November 16, 2010.

10. The RWGTM has been developed by Kenneth B. Medlock III and Peter Hartley at

Rice University using the Marketbuilder software provided through a research license with

Deloitte Marketpoint, Inc. More details regarding the model is available upon request.

11. Note, the debt-equity ratio is allowed to differ across different categories of

investment (proving resources, developing wellhead delivery capability, constructing

pipelines, and developing LNG infrastructure).

12. We do not address these issues at length in this paper. Rather, we simply assume a

lower growth rate to provide an outcome that yields substantially lower Chinese demand for

natural gas. Note that we could also assume China, for a policy reason, chooses not to

aggressively pursue natural gas. In either case, the result is lower demand.

http://www.worldwater.org/data20082009/ch05.pdf


38

13. H-H. Rogner, “An Assessment of World Hydrocarbon Resources,” Annual Review of

Energy and the Environment 22 (1997): 217-62.

14. Ultimately, LNG imports rise as declines in conventional resources continue and

domestic production growth begins to taper. More information on the model is available

upon request.

15. Note that North America includes Mexico.

16. “Political and Economic Influences on the Future World Market for Natural Gas”, in

Natural Gas and Geopolitics: 1970-2040, ed. D. Victor, A. Jaffe, and M. Hayes, Cambridge

University Press (2006).

17. Dagobert L. Brito and Peter R. Hartley, “Expectations and the Evolving World Gas

Market,” Energy Journal 28, no. 1 (2007).

18. This will also happen in a liberalized market where trading of capacity rights is

allowed, insomuch as the arbitrage allows price signals to clearly transmit. This promotes entry

and, to the extent that hubs develop, financial liquidity. Once that occurs, the means to use

capital markets to underwrite physical transactions increases and liquidity grows, thus making it

difficult to price discriminate.

19. Note the prices depicted in Figure 7 are spot prices, and do not reflect volumes sold

on a contractual basis at an oil-indexed premium.

20. “Statement on U.S.-China Shale Gas Resource Initiative,” The White House Office of

the Press Secretary, November 17, 2009, http://www.uspolicy.be/headline/statement-us-china-

shale-gas-resource-initiative.

http://www.uspolicy.be/headline/statement-us-china-shale-gas-resource-initiative

http://www.uspolicy.be/headline/statement-us-china-shale-gas-resource-initiative

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