Singapore Energy Market-September 2012

Singapore energy market

September 2012

Further informationIf you would like further information on any aspect of this clientnote, please contact a person mentioned below.

Contact

Alex WongPartnerT +65 6302 [email protected]

Amy LeeCEOT +65 6302 [email protected]

Ming Hui ChockSenior AssociateT +65 6302 [email protected]

Adrian WongSenior AssociateT +65 6302 [email protected]

This note is written as a general guide only. It should not berelied upon as a substitute for specific legal advice

Contents

Introduction Recent developments in the Singapore energy industry 1

Schedule 1 Summary of Singapore electricity market deregulation and wholesale market operations 4

Schedule 2 Summary of Singapore gas market deregulation and the Gas Network Code 15

1 Singapore energy market

Introduction – Recent developments in the Singapore energy industry

With the merchant power market celebrating its first decade ofoperations and the gas market liberalisation recentlycompleted, Singapore is now looking to finalise its long termenergy market strategy. This note serves as an update onsome of the recent developments in the Singapore EnergyIndustry as it enters a crucial phase of development. Theattached schedules also present a summary of the functionsof the liberalised Singapore Electricity and Gas Markets.

POWER MARKET UPDATE

The Singapore power market has witnessed, over the last fewyears, both expansion and consolidation as it looks forward tothe coming years of energy market development. From aconsolidation perspective, almost all of the large incumbentpower generators have undergone repowering exercises andmoved almost exclusively towards CCGT plants for powergeneration as they reposition themselves in a morecompetitive wholesale market for power generation. Today,more than 80% of Singapore’s electricity is fuelled by pipednatural gas.

Expansion of the power generation sector has mainly comefrom new market entrants GMR Energy who will bring 800MWof gas fired units online over the next two years. After analmost decade long fight for access to gas, the long awaitedproject achieved financial close in 2011. GMR Energy is notalone though in the contest for space in the generationsegment of the market. Onsite and captive power generationremain permitted activities subject to certain restrictions

1and

the decision to allow Hyflux (through Tuaspring Pte Ltd) to joinin the market for power generation as part of the second TuasDesalination project also caught market watchers by surprise.

1 Policy on Self-Supply of Electricity – Information Paper, Energy MarketAuthority of Singapore (“EMA”), 21 April 2008

Singapore also continues to encourage energy efficiency as itmoves towards a greener future. The most directmanifestations of this include the continued steady growth ofthe National Environment Agency’s waste to energy plantsand the likely increase in the number of buildings takingadvantage of rooftop solar to reduce their carbon footprints.This is supported by the recently passed Energy ConservationAct 2012 which aims to mandate good energy managementpractices for large energy users and the support provided bythe Economic Development Board (“EDB”) for theestablishment of an energy efficiency fund in Singapore togrow businesses that focus on energy efficiency. All thismeans that there will continue to be overcapacity in thegeneration market for the foreseeable future and, at least intheory, the consumers should benefit from this competition

2.

2Full retail contestability has still not been achieved so household and smallconsumers retain the Market Support Services Licensee as their defaultpower retailer.


Introduction – Recent developments in the Singapore energy industry(cont’d)

Increased competition in the generation industry howeveralmost immediately translates into a battle for the cheapestfuel source for power generation. For a large part of theforeseeable past, this has been piped natural gas fromIndonesia and Malaysia. This dominance (which not onlyfuels power generation but also major industries in thepetrochemicals, electronics and biomedical sectors) has beendeliberately challenged in Singapore in the recent past by theimportance the Singapore government places indiversification of fuel sources and by the global fall in LNGprices (particularly long-term prices). It is Singapore’s long-term strategy for fuel mix diversification for power generationand industry that will dominate this discussion in the comingmonths.

LNG AND ITS IMPACT ON THE SINGAPORE GASMARKET

Singapore’s current gas import consists almost exclusively ofpiped natural gas imported through four pipelines from SouthSumatra and West Natuna gas fields in Indonesia and the gasimports from Malaysia.

Significant focus has been placed by the Singaporegovernment in reducing the reliance on these piped naturalgas imports and increasing gas imports from other sources.This led to the Singapore government moving ahead with thedevelopment of its first LNG import and regasification terminaland the appointment of BG Asia Pacific Pte Limited (“BG”) asSingapore’s first LNG aggregator.

At the time this decision was made, piped natural gas intoSingapore was significantly less expensive than thecomparable LNG price but the decision to proceed wasnonetheless made on strategic grounds and ignoring theimmediate economics of the decision. Singapore had tocreate an ʻartificialʼ demand for LNG in order to wean the market off its reliance on piped natural gas. This ʻartificialʼ market was created by simultaneously requiring powergenerators to accept LNG as part of their fuel portfolio as wellas imposing a moratorium on future piped natural gas imports.

In hindsight, the strategy appears to have been prescient.With new sources of gas flooding the global market (bothtraditional gas fields in Australia (which is set to overtakeQatar as the largest LNG exporter by the end of the decade)

and East Africa and shale gas in North America), LNG pricesare set to fall in the medium to long term in spite of strongdemand from China and Japan. At the same time, the WestNatuna and South Sumatra gas fields in Indonesia appear tobe depleting at a higher rate than originally envisaged andthis, coupled with pressure on the Indonesia government toreserve more of its precious resources for domesticconsumption, would likely mean a far less reliable future forpiped natural gas imports.

This has led to BG’s 3 Mtpa franchise for aggregating LNG forSingapore having a strong uptake. With 2.65 Mtpa of LNGhaving been taken up by February 2012, the EMA expects theentire franchise to be fulfilled by 2013 at the latest. This begsthe immediate question of Singapore’s LNG import policybeyond BG’s franchise. The EMA has sought feedbackthrough a consultation exercise

3that will aim to determine

whether Singapore’s future LNG import framework will becarried out through a regulated sole importer framework(“BG+1”) or a multiple aggregator framework (“BG+3”).

Under the BG+1 framework, the EMA will appoint a RegulatedSole Importer (“RSI”) who will import all incremental LNGbeyond BG’s 3 Mtpa supply. The EMA will regulate the RSI’sreturns as well as its LNG procurement, gas sales prices andcontract terms. A variant of this framework is adopted byAsian importers like South Korea, Taiwan and Thailand. It isexpected that the appointment will be conducted through asimilar RFP exercise that resulted in BG’s appointment.

The BG+3 framework would see up to 4 large LNG importersserving up to 15 Mtpa of LNG capacity (which is the projectedLNG demand by 2024) in Singapore. Under the governmentmandated aggregation variant of this model, importers will beselected by EMA (either sequentially over time orconcurrently) and awarded LNG import licences through acompetitive RFP process. Each importer would be awarded afranchise to import a specific amount of LNG. Under themarket-driven aggregation model, competition betweenplayers in the LNG import sector would give rise to naturalaggregation of demand into a few dominant players (e.g. theformation of a few buyer groups). EMA would set entrycriteria that importers must fulfil to qualify for access to theLNG terminal.

With the LNG terminal able to support 7 LNG storage tanksand up to 15Mtpa of LNG demand, the Singapore governmentis also open to seeing the LNG terminal being used as atrans-shipment and trading hub. As of today, a number ofinternational LNG trading companies (such as Shell, GDFSuez, ConocoPhillips and BP) have set up LNG tradingoffices in Singapore and they will be looking to tap the strongregional growth of spot and short-term LNG contracts. Thereshould be no doubt though that the government sees the LNG

3 LNG Procurement Framework – Consultation Paper, EMA, 30 March 2012


Introduction – Recent developments in the Singapore energy industry(cont’d)

terminal’s first priority as that of helping to ensure security offuel supply for Singapore.

With decisions on the LNG import strategy likely to be madein the coming months, the EMA will likely also have to resolvethe wider question on the long term fuel mix strategy and theon-going question of how LNG imports will affect the import ofpiped natural gas. Given the long term investments anddecisions required with respect to new piped natural gasimport contracts, the EMA is aware that it will not be able tomake sharp changes in direction once its long term policy andstrategy have been settled. Amongst other things, the EMAwill have to make challenging decisions on issues such asLNG imports into the nearby Malaysian LNG import terminals.Where regasified LNG is piped into Singapore from theseterminals, they will likely be considered to be piped naturalgas and thus subject to EMA’s current moratorium. Theextent to which the moratorium may be lifted for such futureimports (and thus a potential direct challenge to the businessof the Singapore LNG terminal) will be a difficult decision thatthe EMA will have to make in terms of striking a balancebetween market forces and price competitiveness andsecurity of supply.

SINGAPORE ENERGY MARKET INVESTMENTS IN THENEAR FUTURE

The business of the Singapore LNG terminal is, of course, ofsignificant interest to the EMA and the Singapore governmentas a whole. The initial intention was for the LNG terminal tobe a self-sustaining business model to be run independent ofgovernment subsidy (but albeit subject to regulation by theEMA). The decision for EMA to take over terminaldevelopment reflected the urgency and importance with whichthe government saw the terminal as a cornerstone of itsenergy strategy. That said, it remains the intention of thegovernment to, at an appropriate juncture, divest theownership of the LNG terminal to the private sector (perhapssimilar to the way in which the previous Temasek ownedgenerating companies were divested in 2008) – a decisionthat will no doubt attract significant market interest.

Whilst natural gas dominates the discussions on energy policyand strategy, there remain other elements of thegovernment’s overall energy diversification strategy thatdeserve a mention. The EDB has released an RFP for asynthetic gas facility (through coal gasification) to bedeveloped on Jurong Island to provide feedstock for industryand potentially also for power generation. The ability of theʻsyngasʼ facility to provide fuel for power generation is nonetheless subject to EMAʼs overall study and policy finalisation on gas import control. Electricity imports alsoremain on the horizon (with a possible 4-5 year timeline from2012). Subject to a restriction of 600MW per country (underthe ASEAN Grid masterplan) any such import will have to belicensed by the EMA and will likely involve a contracts-for-differences pricing structure. Similar to the aggregator

selection regime, any electricity import selection will likely besubject to a similar tender process.

In summary, the Singapore energy market is best describedas a ʻmanaged privatised’ market. Singapore is adamant not to fall into the cycle of underinvestment and high energyprices that befalls many other privatised energy marketsaround the world but yet wants to take full advantage ofderegulated market practices. The strategy appears to haveworked so far but its continued success will depend on theability of the EMA and the Singapore government as a wholeto balance the supply and demand pressures of the merchantmarket with the strategic priorities of the city state.


Schedule 1 – Summary of Singapore electricity market deregulation andwholesale market operations4

HISTORICAL BACKGROUND

The electricity and piped gas industries in Singapore havetraditionally been vertically integrated and government-owned.The Public Utilities Board (“PUB”) was formed in May 1963 toundertake the supply of water, electricity and piped gas to thepopulation of Singapore.

In 1995, the Government began to implement a number ofchanges to deregulate the electricity industry. On 1 October1995, the PUB transferred its electricity and gas activities toTemasek Holdings. Within Temasek Holdings, SingaporePower was created as the holding company for several othernew companies including the generation companies,PowerSenoko (now known as Senoko Power) andPowerSeraya; the transmission company, PowerGrid; and SPServices Ltd, the electricity supply and utilities supportservices company. A further generator, Tuas Power, was setup as an independent company directly under TemasekHoldings.

THE NATIONAL ELECTRICITY MARKET OF SINGAPORE(“NEMS”)

4

On 1 April 2001, the Government established a bodycorporate, the EMA, under the Ministry of Trade and Industry(“MTI”), to regulate, among others, the electricity industry. Inthat same year, PowerGrid transferred its system operatorfunction to the Power System Operator (“PSO”), and themarket operator function and pooling and settlementresponsibilities to the Energy Market Company Pte Ltd(“EMC”), which was formed as a subsidiary of the EMA tooperate the Singapore Electricity Pool (“SEP”) andsubsequently the wholesale electricity market in the NEMS.

The NEMS consists of a wholesale electricity market and aretail electricity market. The wholesale market consists of twomarkets: the “real-time” (or the “spot market”) for energy,reserve and regulation; and the “procurement market” forother ancillary services. The sale of energy, reserve andregulation are done through price/offer quantities submitted bygeneration companies every half hour.

In addition, as part of the government’s policy of separatingownership of electricity generation assets from ownership ofthe Transmission and Distribution Systems, Singapore Powerdivested its ownership interests in Senoko Power andPowerSeraya to Temasek Holdings. Temasek Holdingssubsequently divested Tuas Power, Senoko Power andPowerSeraya to private sector investors.

4 EMA – Introduction to the National Electricity Market of Singapore (version6) – October 2010.

REGULATORY FRAMEWORK

Electricity Act

The Electricity Act is the principal legislation governing theelectricity industry and the NEMS. The principal rights andobligations of the participants in the wholesale and retailelectricity markets are set out in the Singapore ElectricityMarket Rules (the “Market Rules”), the electricity licencesand in the codes of practice (the “Codes of Practice”) issuedby the EMA.

The Singapore Wholesale Market Rules

The Market Rules are effectively contracts between eachmarket participant and the EMC under section 49 of theElectricity Act. This ensures that market participants have theoption to take legal action against the EMC for damagessustained as a result of the non-observance of the MarketRules by the EMC and vice versa. The Market Rules alsocontain dispute resolution procedures.

The objectives of the Market Rules are:

to establish and govern efficient, competitive and reliablemarkets for the wholesale selling and buying of electricityand ancillary services in Singapore;

to provide market participants and the Market SupportServices Licensee (the “MSSL”)

5with non-discriminatory

access to the transmission system; and

to facilitate competition in the generation of electricity.

Electricity Licenses

Under the Electricity Act, an entity may not engage in certainelectricity-related activities unless it has been issued with anelectricity licence by the EMA (or it has been exempted fromholding one). The electricity-related activities that require anelectricity licence are:

operation of any wholesale electricity market;

generation of electricity;

transmission of electricity;

provision of market support services (such as meterreading and meter data management);

retail of electricity;

5 It should be noted that although the MSSL is obtaining supply from thewholesale market, it is not technically a market participant. However, theMarket Rules provide for MSSL to be treated, for the most part, similarly tothe manner in which market participants are treated. Thus, a MSSL issubject to most of the same obligations as market participants are underthe Market Rules.


Schedule 1 – Summary of Singapore electricity market deregulation andwholesale market operations (cont’d)

trading in the wholesale electricity market; and

importing or exporting electricity.

Codes of Practice

The electricity licences require that licensees comply withrelevant Codes of Practice and other standards ofperformance that govern their activities. The Codes ofPractice contain detailed rules that govern the electricitylicensees in conducting their activities. The Codes of Practicedeveloped to date include:

The Transmission Code

The Transmission Code is binding on the TransmissionLicensee, which is SP PowerAssets. It sets out the minimumconditions that SP PowerAssets must meet in carrying out itsobligations as owner of the Transmission System and tofacilitate non-discriminatory access to the TransmissionSystem.

Regulated Supply Service Code

The Regulated Supply Service Code is binding on MSSLs,which is currently SP Services only. It sets out the minimumconditions that a MSSL must meet in carrying out itsobligations to procure the supply of electricity and providemarket support services to non-contestable consumers undersection 21 of the Electricity Act.

Market Support Services Code

The Market Support Services Code (“the MSS Code”) isbinding on MSSLs. It sets out the minimum conditions that aMSSL must meet in carrying out its obligations to providemarket support services to Retail Electricity Licensees(“RELs”) and contestable consumers, and facilitate theiraccess to the wholesale electricity market.

Metering Code

The Metering Code is binding on the Transmission Licensee,generation licensees and MSSLs, and sets out the minimumconditions that a metering equipment service provider mustmeet in carrying out its obligations to install and maintainmeters. It also sets out the roles and obligations of the meterreader and meter data manager.

Codes of Practice for RELs

The Codes of Practice for RELs sets out the minimumstandards of behaviour that a REL must observe in retailing toconsumers.

Market Agreements and Contracts

Most market participants in the NEMS are required to enterinto a number of agreements and contracts. These aregenerally a consequence of their respective licence

conditions, the Market Rules and Codes of Practice. Thetable in page 6 sets out the various market agreements andcontracts in the NEMS.



Agreements and Contract Parties Purpose

Operating Agreement PSO and SP Power Assets The Operating Agreement gives the PSO the authority to directthe operations of the Transmission System subject to certainlimitations on the manner and extent of those operations.

MSSL – EMC Agreement EMC and MSSLs This agreement establishes a contractual relationship betweenthe EMC and the MSSL and provides that the Market Rules willhave the effect of contract as between the EMC and the MSSLin so far as it applies to them.

MSSL – Market ParticipantAgreement

MSSL, generation licenseesand direct market participants(“DMP”)

This agreement provides for meter reading services forwholesale settlement. The generation licensees pay directly forthe services with fees set by the MSSL.

PSO – Market ParticipantAgreement

PSO, generation licensees,RELs and DMP

This agreement establishes a contractual relationship betweenthe PSO and the market participant and provides that theMarket Rules will have the effect of contract as between thePSO and the market participant in so far as it applies to them.

MSSL Agreement MSSL and RELs This agreement is a services agreement between the MSSL asprovider and the RELs as procurers in relation to the variouscustomer support services as defined in the MSS Code.

Connection Agreement SP PowerAssets, generationlicensees, party wanting DMPand electricity consumers

This agreement gives effect to the obligations that must existbetween SP PowerAssets and the party wanting connectionservice.

Retailer Use of SystemAgreement

SP PowerAssets and RELs This agreement is for the collection of Use of System charges(“UoS Charges”), that is, the transmission and distributiontariffs, when a REL opts for consolidated billing, that is, when aREL assumes the payment responsibility of its customers forthe transmission charges.

Agency Agreement MSSL and SP PowerAssets This agreement is an agency agreement for the provision ofUoS Charges collection services for SP PowerAssets.

Ancillary Services Agreement EMC on behalf of the PSOand the generation licensees

This agreement is a contract between the EMC and a marketparticipant (usually a generation licensee) supplying ancillaryservices.

Source: EMA



ELECTRICITY INDUSTRY STRUCTURE

The EMA

The EMA was established in April 2001 pursuant to the EMAAct as an independent regulator overseeing the electricity andgas industries in Singapore. Under section 3 of the EMA Act,the EMA is charged with the general administration of theEMA Act, and its functions and duties include:

to perform the interests of consumers with regard toprices, reliability and quality of services;

to perform the functions of economic and technicalregulator;

to ensure that electricity licensees provide an efficientservice;

to ensure security of supply of electricity to consumersand to arrange for the secure operation of thetransmission system;

to protect the public from dangers arising from electricity-related activities;

to create an economic and regulatory framework for theelectricity sector that promotes competitive, fair andefficient market conduct and prevents the misuse ofmonopoly or market power;

to advise the Government on matters relating to theelectricity system; and

In fulfilling these functions, the EMA has at its disposal anumber of regulatory tools and powers. These include theauthority to issue, suspend, revoke or modify anelectricity licence; the power to issue and modify codes ofpractice and other standards of performance; the powerto issue directions to electricity licensees; the power tofine electricity licensees; and the authority to investigateand sanction anti-competitive conduct.

The EMC

The EMC is licensed to operate the wholesale electricitymarket in the NEMS. The EMC’s functions are to:

operate and administer the wholesale electricity market inthe NEMS;

prepare schedules for generation facilities, loads (that is,the withdrawal of electricity from the TransmissionSystem) and the Transmission System;

settle accounts of market participants;

facilitate the planning and augmentation of theTransmission System;

provide information and other services to facilitatedecisions for investment and the use of resources in theelectricity industry; and

exercise and perform the functions, powers and dutiesassigned to the EMC under the EMA Act, its electricitylicence, the Market Rules and applicable Codes ofPractice.

The EMC is a 51:49 joint venture between the EMA and M-Co(The Marketplace Company) Pte Limited (“M-Co Singapore”).M-Co Singapore is a related company of The MarketplaceCompany Limited, which developed, implemented andcurrently operates the wholesale electricity market in NewZealand.

PSO

The role of the PSO (a division of EMA) is to ensure thesecurity of supply of electricity to consumers and to arrangefor the secure operation of the electricity system.

The functions of the PSO include:

maintaining the reliability of the electricity system;

forecasting and reporting on conditions on theTransmission System;

coordinating the outages of generation facilities;

providing Transmission System status and loadforecasting to the EMC for the purposes of marketclearing;

coordinating the actions of the EMC and marketparticipants during emergencies; and

dispatching generation facilities.

Market Participant

A Market Participant in the NEMS is defined as a person (thatis, an entity or organisation, as well as people) that:

has an electricity licence issued by the EMA; and

has been registered with the EMC as a marketparticipant.

The wholesale electricity market is a mandatory market in thesense that any person who wishes to convey electricity overthe Transmission System must be registered as a marketparticipant with the EMC. Market participants may be:



the Transmission Licensee;

generation licensees;

RELs;

persons, other than the generation licensees and RELs,who have been licensed to trade in the wholesaleelectricity market; and

any department of the Government that generateselectricity before 1 April 2001.

A MSSL is not a market participant.

In the NEMS, it is mandatory for all generation facilities aboveto be licensed by the EMA. It is also mandatory forgeneration facilities above 10MW to be registered for dispatchby the PSO. Mandatory registration ensures that allgeneration facilities of any significant size are subject to theMarket Rules.

Transmission Licensee

SP PowerAssets is currently the sole Transmission Licenseein Singapore.

The responsibilities of SP PowerAssets and of the personswhose facilities are connected to the Transmission Systemare set out in the Transmission Code and the connectionagreements. The Market Rules also contain specificprovisions for SP PowerAssets and the PSO’s obligations inrespect of the reliability and security of the TransmissionSystem.

The transmission network transports electricity at high voltagefrom generators to the low voltage distribution network (or, ina small number of cases, directly to large industrialconsumers).

SP PowerAssets, being the monopoly provider oftransmission services, is not permitted to compete in theenergy market, whether as a generator, retailer or trader(either directly or indirectly by ownership of companiesengaged in such activities), because opportunities exist for itto afford a preference to its competitive activities or itscompetitive affiliates.

Market Support Services Licensee

SP Services is currently the sole MSSL and provides marketsupport services to the majority of electricity consumers inSingapore. SP Services charges regulated fees, as approvedby the EMA, for market support services provided.

RELs

The retail electricity market does not come under thejurisdiction of the Market Rules and the EMC. It is createdand regulated under the EMA Act, the electricity licenses andthe Codes of Practice issued by the EMA.

RELs may be market participants who purchase electricitydirectly from the wholesale electricity market or purchasethrough the MSSL. Since the RELs are permitted to trade inelectricity and are not subject to the same degree ofregulation as the MSSL, they may offer contestableconsumers contracts different from those available from theMSSL. RELs can bundle energy and other charges into asingle invoice, charge a price other than the UniformSingapore Energy Price (the “USEP”)

6for energy, and offer

additional services to consumers.

Consumers

Consumers are classified as either contestable or non-contestable, depending on their electricity usage.Contestable consumers are entitled to purchase electricityfrom a REL, or directly from the wholesale electricity market,or indirectly through MSSLs. Non-contestable consumers aresupplied by MSSLs.

Currently, consumers with a monthly usage of 10,000kWhand above are contestable. The EMA continues to studywhen full contestability of all retail consumers will be allowed.

Relationships between the Market Participants

The figure on page 9 shows the financial flows between theMarket Participants in the NEMS.

6 Please refer to page 13 for further discussions on the USEP.



Financial Flows between the Market Participants in the NEMS

Competition

An important role for the EMA is the monitoring of marketbehaviour to guard against the concentration of market power,abuse of dominance and exercise of anticompetitivebehaviours such as collusion and capacity withdrawal to driveup prices. The EMA is also empowered to prohibit anti-competitive practices including restrictions on mergers andacquisitions (that is, there will be cross ownership limitations).

Significantly, the anti-competition provisions in the ElectricityAct have retrospective effect. Where the EMA finds that aperson has acted in an anti-competitive manner, the EMA cangive a direction for the cessation of such conduct and imposea financial penalty on the person.

The electricity industry is excluded from the Competition Act2004 as the EMA will continue to regulate anti-competitivepractices and other competition issues in the electricityindustry.

OVERVIEW OF WHOLESALE MARKET OPERATIONS7

In the NEMS, the real-time dispatch of electricity (schedulinggenerators to supply energy, reserve and regulation) isdetermined by the operation of a wholesale spot market runevery half-hour. Generators offer their capacity (specifyingprice/quantity pairs) to the market and the PSO provides aprediction of the expected load along with any systemconstraints for that half-hour. The market then determines theleast-cost dispatch quantities and the corresponding marketclearing prices based on the offers made by generators.

The wholesale electricity market consists of two markets:

the spot market for energy, reserve and regulation; and

the procurement market for other ancillary services.

Every half-hour, the Market Clearing Engine (“MCE”), a linearprogramming computer model, determines the spot marketoutcomes for:

7 EMA – Introduction to the National Electricity Market of Singapore (version6) – October 2010.



the dispatch quantity produced by each generationfacility;

the reserve and regulation capacity required to bemaintained by each generation facility; and

the corresponding wholesale spot market prices forenergy, reserve and regulation.

Quantities and prices are based on price/quantity offers madeby the generators and load forecasts prepared by the EMCbased on demand forecast information received from thePSO.

RESERVE AND REGULATION

Reserve is unused capacity that has to be made available tothe electricity system quickly to correct any imbalance andmaintain reliable supply in case of an unexpected outage of ascheduled generation facility. This capacity must be able tobe in production within a short timeframe, depending on thearrangement. There are three reserve classes: primaryreserve (eight seconds’ response), secondary reserve (30seconds’ response) and contingency reserve (10 minutes’response).

Regulation, or “load-following”, is a normal operationalrequirement to cover second-to-second variations in loadaway from estimated load.

DISPATCH SCHEDULING

Dispatch scheduling is the process of matching the generationcapacity needed to meet forecast demand. It is at the heart ofrunning an electricity system. To enable the MCE to generatethe dispatch schedule, the PSO and the generation facilities’dispatch coordinators need to know in advance when eachgeneration facility will be operating and how much output isexpected from each. The dispatch schedule comes from theMCE.

The PSO instructs the generation facilities to conform to thedispatch schedule. Any deviations from the estimated loadand corresponding schedule are handled by the PSO usingancillary services.

THE MARKET CLEARING ENGINE

Every half-hour, the MCE is run to determine the dispatchschedule and the associated energy market prices for theupcoming dispatch period. The MCE also determines whichgeneration facility is on reserve and regulation duty along withthe market prices for reserve and regulation.

The objective of the MCE is to find a set of dispatchinstructions that minimises the cost of supplying load at allnodes (injection or exit points) of the Transmission System, aswell as meeting the reserve and regulation requirements for

electricity. There is no overall cheaper dispatch available, interms of the offers that have been made to the market, byproviding energy, reserve and regulation from differentsources, or in different quantities from the same sources.This is the minimum cost market dispatch.

The supply of energy, reserve and regulation is specified bymeans of offers that contain price/quantity tranches indicatingthe quantity of energy, reserve or regulation that eachdispatchable generation facility is willing to supply at thecorresponding energy, reserve or regulation prices.

With the dispatch based on estimates of the demand for thecoming dispatch period, the market prices are similarly theprices set according to those estimates. This form of pricesetting, called ex ante pricing (pricing before the event), givesthe market participants certainty about market prices even ifdispatch quantities differ from those scheduled

8.

The MCE does not produce a single market energy pricebecause of the effects of losses and congestion on thetransmission system. Different energy prices apply todifferent nodes on the transmission system.

THE OFFER PROCESS

Energy, Reserve and Regulation Offers

Generators make offers to supply energy, reserve, andregulation for each of their units in each half-hourly dispatchperiod in which they want to operate. They are similarlypermitted to offer interruptible load to supply reserve. Offerscan vary for each half-hour, and are assumed to stand, unlessmodified, from the time they are made through to dispatch.The market does not distinguish between offers used for themarket outlook, pre-dispatch and real-time processes. Itsimply uses the most recent offer made for each half-hour.

Key features of the generator offer process are:

standing offers are required. Generators are required tomake standing offers into the market. The standingoffers form a pattern for a week. The use of standingoffers is particularly valuable for smaller generators, sinceit eases the administrative burden of participating in themarket;

continuous adjustment of offers. Market participants areallowed to continually adjust their offers up to gateclosure

9;

8 For all but plants providing regulation, energy actually injected should notdiffer greatly from scheduled energy, under normal circumstances.

9 Although offers modified within the last hour may be subject to scrutinyfrom the market surveillance panel.



up to 10 price/energy quantity bands. Generators maymake energy offers consisting of up to 10 price/quantitybands (tranches) for each facility for each half-hour;

up to five price/reserve and regulation quantity bands.Generators and interruptible load may make reserveoffers (of different classes) and generators may makeregulation offers if they are registered to do so;

combined offers. Energy, reserve and regulation are alloffered simultaneously, and are co-optimised by themarket clearing model. The model respects the trade-

offs between the commodities so that a facility will not bescheduled to produce more energy, reserve andregulation than it can simultaneously manage; and

offers at a node. Energy offers for each generationfacility are made at the node where that facility is located.

Market Clearing Process in the Spot Market

Prices in S$ per megawatt hour (“MWh”)



MARKET CLEARING PROCESS

The figure on page 11 shows a simplified example of themarket clearing process in the spot market.

In this example, there are three generators (A, B and C)whose offers consist of four price/quantity tranches each. Thetranches are arranged in ascending price order. The market-clearing price is found at the point where total demand fromconsumers is met by the offer tranches. In this example, thethird tranche from Company C sets the market-clearing pricewith its offer price of S$85/MWh. The total demand is aforecast of the load for that period.

Offers below the Market Clearing Price are accepted andthose generation facilities are dispatched, in full, to the offers.Offers above the Market Clearing Price are not accepted, andso the generation capacity represented by those offers is nottaken at all. At the margin, the offer that sets the price isusually only partially dispatched. The generation facility at themargin is called the marginal unit (the “Marginal Unit”).

UNIT COMMITMENT

The NEMS is a self-commitment market. This means that unitcommitment is the responsibility of each generation company,and no start-up or shutdown payments are made (generationcompanies are expected to factor these payments in to theiroffering strategy). This fact is important because somegeneration units require a significant period of time to warmup before they can produce electricity and hence need to becommitted some time in advance. The PSO needs to knowand account for the ability of the generation unit to ramp up ordown. This information is part of the standing capability datarequired from each generation unit.

PRICES AND CHARGES

Energy Price

In common with many modern electricity markets, the NEMSuses a form of energy pricing referred to as nodal pricing,meaning that prices at each node in the network will beinfluenced by the physical properties and constraints of thetransmission system. This results in the price of energydiffering at different physical locations on the network.

The MCE automatically produces a different price at eachnode on the network. Dispatchable generators are paid thenodal price at their point of injection.

Reserve and Regulation Price

Reserve is generation capacity that is required in case of anunexpected outage of scheduled plant. Because generatingunits may fail without warning, some reserve capacity has tobe made available to the system to correct any imbalancequickly and maintain reliable supply. Reserve is a significantfactor in the Singapore system since some generating units

(600MW thermal units, for example) are large relative to thetotal load.

A generator would wish to receive payment for the reserveand regulation it provides because it forgoes the opportunityof being dispatched fully, by being partially available for PSOto call on it for reserve and regulation, as and when required.

Reserve in Singapore can be provided by generation facilitiesand load

10. For a facility to provide reserve as quickly as in

eight seconds or even in 30 seconds, it needs to be alreadyspinning and synchronised. In most instances, that requiresthe unit also to be supplying energy, with reserve capabilitycoming from its ability to ramp up its scheduled output veryquickly. Since not all plants have this technical capability, aplant has to be certified as meeting the requirements forregistration to provide reserve before it can be offered in thereserve market.

There are also different reserve provider groups for eachclass of reserve. These groups represent the reliability ofdifferent reserve sources in providing reserve, and theireffectiveness in curtailing falls in system frequency.

Since a facility’s capacity may be available for both energyand reserve/regulation, the MCE must consider the optimaltrade-off between the offers for reserve, regulation andenergy. In solving the markets for each class of reserve andregulation, the MCE simultaneously finds the lowest costsolution (in terms of the offers made) that trades off betweenthese products for the various facilities. Within the MCE,optimisation of the supply of energy must account for theminimum running level of facilities that provide reserve. Theoverall optimal solution may result in a unit being run “out ofmerit” for energy so that the unit is available for reserve

11.

Offers for reserve from a generator can only be made inassociation with a corresponding offer for energy. Part of thestanding capability date for the plant is a function relating itsreserve capability to its energy capability. This relationship isentered into the MCE.

The cost of regulation is recovered from consumers andgeneration facilities. The cost is allocated on a S$ per MWbasis across all MW of consumption in a dispatch period plusthe first 10MW of electricity dispatched by each generationfacility in that dispatch period.

10 An Interruptible Load scheme was introduced into the Singapore market in2004.

11 Since often a facility must be running in order to be available for reserve, itmay be dispatched for energy even though its energy offer is higher thanthat of the marginal plant for energy. This is acceptable because there isno cheaper energy and reserve solution for the system as a whole. Thereserve price received by such a plant will compensate it for the shortfallbetween its energy offer price and the energy spot price.



USEP

While the generation facilities are paid their nodal price,buyers from the wholesale electricity market pay a uniformoverall average price so that no customers are disadvantagedby location. The USEP is calculated from the weightedaverage of the nodal prices at all of the exit nodes on theTransmission System. The nodal energy price at each nodeis weighted by the energy withdrawn from that node.

VESTING CONTRACTS

In the transition to the NEMS, the EMA had concerns with thedegree of market power that will exist in the wholesaleelectricity market. The EMA has addressed these concernsusing Vesting Contracts without interfering with the structureof the wholesale electricity market. Vesting Contracts arecontracts for differences (“CfDs”) vested on the largeincumbent electricity generation companies, for a transitionalperiod.

In Singapore, the Vesting Contracts take the following form:

generators will be required to enter into Vesting Contractswith the MSSL, who is the counterparty to all of theVesting Contracts. The MSSL will then distribute debitsand credits associated with the contracts to consumers,both contestable and non-contestable;

Vesting Contracts have a contract price (or strike price)set at about the economic or long-run marginal cost(LRMC) of a new entry generator (i.e. the electricity pricethat a new investor in base-load capacity would require inorder to cover its fixed and variable costs at a reasonablereturn to shareholders over the life of the plant). Thesame strike price applies to all generators;

the contract quantity will be set to keep the market powerof large generators at an acceptable level. During peakload times, the contract quantity will be a largerproportion of total load, while in off-peak times it will be asmaller proportion. The average contract quantity willreduce over time as new capacity is built to mitigate themarket power of incumbents; and

the contract quantities for each generator are based onthe generation capacity for each company.

Vesting Contracts are settled by the EMC in the wholesaleelectricity market and by the MSSL in the retail electricitymarket. The figure on page 14 illustrates the settlementprocess for Vesting Contracts.



BILATERAL CONTRACTS

The wholesale market in Singapore is not designed toeliminate or be immune to price volatility; rather, it is importantto the market that prices move freely. As a result, the designalso recognises the need to allow participants to manageprice risk.

The generation and electricity retail companies can enter intobilateral contracts, at their discretion, to reduce pricefluctuations. These contracts are purely financialarrangements, the most common of which are CfDs.

Under such an arrangement, the contracting parties agree toa strike price for a given volume of energy. They continue tobuy and sell on the spot market but settle betweenthemselves any financial difference between the spot and CfDstrike price. When the strike price is higher than the spotprice, the electricity retail companies make a payment to theelectricity generation companies for the difference, and viceversa.

Bilateral contracts create price certainty for the parties andlimit their exposure to potential volatility in the spot market.Bilateral contracts are outside the wholesale electricity marketand are not taken into account in the physical dispatchprocess, and are not in any way regulated by the MarketRules. However, the facility exists for the parties to thebilateral contracts to settle their contracts through the EMC’ssettlement system.


Schedule 2 – Summary of Singapore gas market deregulation and the GasNetwork Code

HISTORICAL BACKGROUND

The Singapore Government first announced its intention toliberalise the gas market in March 2000. The key concernsdriving the Government’s liberalisation plans related toopening up competition and establishing greater security ofsupply. In turn, gas market reform would support the parallelliberalisation of Singapore’s electricity market. Since theinitial announcement in 2000 and the implementation of anappropriate regulatory framework, the gas market inSingapore has evolved to a great degree, with new sources ofnatural gas coming on stream and new entrants emerging inthe market.

The Gas Act (Cap, 116A, 2002 rev.ed. as amended) (the“Gas Act”) was passed in 2001 and most of its provisionshave come into force. Modelled on legislation from otherliberalised gas markets, the Gas Act seeks to establish,among other things:

a separate and independent gas transporter inSingapore;

a single integrated Gas Network Code to govern therelationship between the transporter and other marketparticipants;

regulated open access to the integrated network, withcontractually defined and tradable capacity rights withinthe transmission network; and

a licensing regime for the gas transporter, importers,shippers, retailers and LNG terminal operators.

CURRENT KEY GAS MARKET PLAYERS

The EMA

Formed on 1 April 2001, the EMA is a statutory board underthe MTI that regulates the electricity and gas industries andmarkets in Singapore.

Gas Transporter

As described below, in liberalised gas markets, the GasTransporter is the monopoly owner of the on-shoretransportation network consisting of the pipelines between theonshore receiving facility and the relevant offtake valve.PowerGas Limited (“PowerGas”) is the licensed gastransporter in Singapore.

Gas Importer

Importers own off-shore pipelines and procure natural gasfrom sources offshore on behalf of end-users by entering intoGas Supply Agreements (“GSAs”) with gas suppliersupstream.

Singapore’s Gas Importers include Gas Supply Pte Ltd(“GSPL”), SembCorp Gas Pte Ltd (“SembGas”), and KeppelGas Pte Ltd (“Keppel”).

LNG Aggregator

The LNG Aggregator’s role is to:

aggregate gas demand from all potential users, excludingthose end users which are procuring PNG under long-term EUAs;

procure LNG from suppliers on behalf of the end-users;and

enable and facilitate appropriate trading mechanisms forLNG to be arbitraged against PNG and vice versa.

The LNG Aggregator will likely require an importation licenceunder the Gas Act.

BG was selected as Singapore’s first LNG Aggregator.

Shippers

Shippers, consisting of either Importers or end-users such asgenerating companies, enter into on-shore transportationagreements with the gas transporter to ship gas from areceiving facility to an end-user or retailer at a point on thetransportation network. Under the Gas Network Code,Shippers include Direct Access Customers (“DACs”) asdefined under the Gas Act.

Retailers

Retailers purchase gas from Shippers and sell it on to endusers. Retailers will hold a Gas Retailer’s licence that willallow them to retail gas to Retail Customers and arrange thetransport of gas with the Transporter. They are prohibitedfrom being in the business of gas transportation and will bebound by the Gas Network Code.

Gencos and other End Users

The Singapore Gencos, powered largely by combined cyclegas turbines, are the primary end-users for imported naturalgas. End users enter into End User Agreements (“EUAs”)with Shippers or Retailers to purchase and consume thenatural gas in the system. For example, Senoko Powerassumes the role as Shipper under the Gas Network Codewhile also constituting end users themselves. GSPL andSembGas, assume the role of Shippers for the purposes ofthe EUAs between the parties. End users can also be DACswho contract directly with the Transporter for Capacity Rights.DACs are bound by the Gas Network Code.


Schedule 2 – Summary of Singapore gas market deregulation and the GasNetwork Code (cont’d)

THE EXISTING REGULATORY FRAMEWORK: THE GASACT

The Gas Act was passed in 2001 to create the competitivemarket framework for the gas industry as well as to makeprovision for the safety, technical and economic regulation ofthe transportation and retail of gas. The figure above is anillustration of the structure of the gas market.

Licensing of Gas Market Players

The EMA’s regulation of the gas market players describedabove shall rely on the licensing provisions of the Gas Act.The impending Section 6(1) provides for the following specificlicences.

Transporter Licence

In addition to granting the right to PowerGas to own andoperate its gas transportation business, the TransporterLicence (issued under Section 6(1)(a) of the Gas Act), shallset out, inter alia:

the methodology by which the Transporter is entitled tolevy charges;

the basis for economic regulation;

the standards/codes to which the Transporter is requiredto follow and comply; and

the parameters for safety and security.

The rights and obligations set out in the Transporter Licencewill be supplemented by the provisions of the Gas Network

Code, which will govern the commercial and legal relationshipbetween PowerGas and the Shippers.

Shipper Licence

The Gas Act originally only identified gas transportation andretail as licensable activities, It was subsequently determinedthat Shippers under the Gas Network Code should also belicensed (Shipper licenses are issued pursuant to Section6(i)(c) of the Gas Act). It was felt that relying solely upon thecontractual rights of the Transporter under the Gas NetworkCode vis-à-vis Shippers did not provide sufficient controls inthe event a Shipper was behaving unscrupulously. By makingthe shipping of gas a licensable activity overseen by the EMA,greater comfort would be given to the industry as a whole thatdominant shippers could not unfairly influence the market.Therefore, as well as being contractually bound to the termsof the Gas Network Code, it will be a licensing requirementthat Shippers comply with the Gas Network Code.

Retailer Licence

Retailers (under Section 6(1)(d) of the Gas Act) are licensedfor the purposes of protecting consumers. In this regard thelicence:

addresses the basis upon which Retailers may levycharges upon their customers;

includes price control provisions until retail competitionevolves;

identifies standards of performance to which Retailers aresubject;



specifies the duties to be followed by Retailers uponreceiving requests from consumers for gas supply; and

sets out parameters for safety and security regardingsupply of gas to consumers’ premises.

Onshore-Receiving Facility Operator’s (“ORF”) Licence

Following the 29 June 2004 ʻblack-out’ in Singapore, the Energy System Review Committee (“ESRC”) produced areport (the “ESRC Report”), which identified problemsassociated with the operation of the ORF as causing theblack-out, it was recognised that, given the critical role playedby ORFs in the Singapore energy supply chain, facilities ofthis nature should be regulated. The ESRC specificallyrecommended “a reliability, outcome-based licensing systemfor ORF operators in Singapore”. The objective being thatpoor reliability should be penalised while good reliabilityshould be rewarded. Licensing of ORFs (which incidentallyare the same as Upstream Facility Operators under the GasNetwork Code) is now covered under Section 6(i)(e) of theGas Act. The ORF licence addresses operational and safetyissues.

LNG Terminal Operator Licence

As stated above, Section 6 of the Gas Act as originally draftedhas been amended to specifically identify the role ofmanaging or operating the LNG Terminal as a licensableactivity (under Section 6(1)(f) of the Gas Act), and its rightsand obligations in that capacity are set out therein.

Gas Importation Licence

As part of the fuel policy promoting the use of LNG beingimplemented, importers of natural gas need to be licensed soas to enable the EMA to manage any future importation ofPNG. BG as the LNG Aggregator will need an importationlicence under Section 6(1)(h) of the Gas Act.

Accompanying Codes/Regulations

Metering Code

The Metering Code addresses the obligations of MeterOwners to maintain, calibrate and install their meters, theprocedures for the provision of meter readings, thespecifications to be met for different types of meter and alsoaddresses issues associated with the production, storage,collection, transmission and verification of metering data.

Retailer Code of Conduct

The Retailer Code of Conduct supplements the RetailerLicence and sets forth in detail the minimum standards ofperformance in accordance with which a Retailer is requiredto conduct its retail activities. More specifically the codefocuses on:

the manner in which a Retailer may market/advertise itsbusiness;

the manner in which the Retailer must present itsinvoices to a customer;

the procedures to be followed to address customercomplaints;

the terms and conditions to be included in a consumercontract; and

the basis upon which a Retailer may discontinue supplyof gas to a customer.

Gas Supply Code

The Gas Supply Code addresses issues of safety in thesupply of gas with regard to connections to the system, turn-on, discontinuance, disconnection and alteration of thephysical apparatus downstream of the gas meter or gasservice isolation valve. More specifically the Code focuseson:

the obligations of the gas transporter to maintainminimum gas pressure at the premises of retailcustomers the basis upon, and manner in which anapplication may be made for the connection of a gasinstallation to a gas main;

the basis upon, and manner in which gas may beadmitted into the gas appliance;

the procedures and processes to be put in place by thetransporter to respond and attend to gas escapes; and

the procedures and processes to be followed by thetransporter prior to the interruption of the gas supply to aconsumer’s premises public safety issues in constructing,maintaining, monitoring, inspecting and testing gaspipelines.

Gas Regulations

The Gas Regulations are passed pursuant to the Gas Act andprovide the legislative basis upon which relevant persons(other than licensees) are required to comply with applicablecodes of practice. The Gas Regulations address the relevantpersons responsibility for maintenance and connection alongthe gas supply chain from a gas main to a gas service pipe,gas meter and gas installation.

The most important of the accompanying codes andregulations for the gas market is the Gas Network Code itself,which will be described in detail below.



SUMMARY OF THE GAS NETWORK CODE

The following list identifies the main features of the GasNetwork Code.

Capacity Rights

What are Capacity Rights?

Shippers reserve capacity in the Transmission Networkbetween an injection point and an offtake point. CapacityRights are expressed in mmBtu/Balancing Period (that is onehour) and entitle the Shipper to convey that quantity of gasthrough the Transmission Network in a Balancing Period. TheTransmission Network is the high pressure pipeline systemwhere it is possible to identify Capacity Rights. This contrastsfrom the low pressure enmeshed systems which convey gasto small industrial and residential premises which are knownas the Distribution Networks.

How can a Shipper obtain a Capacity Right?

Shippers can apply for Capacity Rights directly to theTransporter or can obtain Capacity Rights by trading directlywith another Shipper.

A Shipper’s Registered Capacity Rights are those expressedin a Capacity Certificate granted by the Transporter to aShipper. A Shipper’s Available Capacity Rights are itsRegistered Capacity Rights plus or minus any TransferredCapacity Rights depending upon whether it is a Transferee orTransferor or Shipper.

How are Capacity Rights determined and made available toShippers?

The capacity within the Transmission Network is assessed bythe Transporter using assumption modelling based uponpressures/flows/offtake requirements. The system inSingapore is entirely dependent upon the pressure controlupstream. There is very limited linepack in Singapore and nogas storage.

If demand for capacity within a pipeline exceeds thatpipeline’s capability the Transporter is required to augment itssystem. This is known as the Open Season process andreflects a demand driven market for the development of thetransportation system.

What charges are payable for Capacity Rights?

Capacity Charges are levied to the Registered Shipper inrespect of its Capacity Rights on a monthly basis (irrespectiveof whether or not that Shipper may have traded some of itscapacity rights). The level of Capacity Charges can beelicited from a Capacity Statement which is published by theTransporter annually and reflect a distant related pricingmethodology. The transporter’s allowed rate of returns on itsassets in any year is regulated by the EMA pursuant to thegas transportation licence.

Penalty regimes/discipline

Shippers are entitled to convey more gas through theTransmission Network between the system points if theyapply for Authorised Capacity Overruns and their applicationis accepted by the Transporter. In those circumstances aShipper will pay an enhanced Capacity Charge equal to 1.25times of the normal charge. If a Shipper fails to apply for anAuthorised Capacity Overrun or its request is rejected, butnonetheless flows more gas through the TransmissionNetwork than it is entitled, it will be liable to pay anUnauthorised Overrun Charge set at two times the normalcharge.

In the event the Transporter fails to deliver gas to a Shipper atan offtake point in compliance with a nomination/scheduledquantity which accords to a Shipper’s Available CapacityRights the Transporter shall, subject to numerous exemptions,be liable to pay liquidated payments to the affected Shipper.

Gas quantities

Nominations

For every Balancing Period a Shipper wishing to convey gasthrough the Transmission Network is required to nominate thequantity of gas it wishes to inject, and offtake, at each pointwithin the Transmission Network. Nominations are made on aseven day rolling basis and can be changed in respect of asingle Balancing Period at any point in time up to one hourprior to Gate Closure. Gate Closure is one hour prior to thecommencement of a Balancing Period.

A Shipper’s Nomination has to be balanced (that is theamount nominated for injection has to equal the aggregateamount nominated for offtake at all the Eligible Offtake Points.In the event a nomination is in acceptable form and is within aShipper’s Available Capacity Rights plus its AuthorisedOverrun Amount, it will be scheduled by the Transporterwithin its Initial Operating Schedule. Within 30 minutes ofGate Closure, the Transporter will issue a Final OperatingSchedule. The Scheduled Quantities specified in the FinalOperating Schedule are used for various purposes within theGas Network Code:

establishing the parameters for the Transporter’s liabilityregime in the event it fails to deliver gas;

establishing the parameters for Failure to Notify Chargesand Nomination Divergence Charges; and

in assessing a Shipper’s Injection and Offtake Quantitypursuant to the default allocation formula.

Metering

In accordance with the metering obligations under theMetering Code, it is possible to assess the metered quantities



of gas injected into, and offtaken from, the TransmissionNetwork for every Balancing Period.

The metered quantities/profiled quantities are then utilised inthe Gas Network Code for the purposes of Initial Settlement toassess each Shipper’s Injection and Offtake Quantities for aBalancing Period.

Once meter readings which have been based on profiledreadings are obtained for the Transmission Network OfftakePoints and meter readings have been provided in respect ofthe Distribution Network Offtake Points (which enables theTransporter to re-calculate a Shipper’s AggregateTransmission/Distribution Quantity) each Shipper’s Injectionand Offtake Quantities for a Balancing Period in a particularmonth will be recalculated for the Final Settlement process.

Usage Charges and other charges

A Shipper’s Offtake Quantity is used to calculate its UsageCharges on the Transmission Network and any UnauthorisedOverrun Charges. In addition, in the event a Shipper’sOfftake Quantity at an Eligible Offtake Point differs from itsscheduled quantity by a pre-determined percentage theShipper will be liable for Nomination Divergence Charges andFailure to Notify Charges.

Commodity Variances

Where a Shipper’s Injection Quantity does not equal itsaggregate Shipper Offtake Quantity (subject to theTransmission Network Shrinkage Factor) in a BalancingPeriod a Shipper will be imbalanced. Commodity Variancescan be caused by pressure fluctuations or by one Shipper“taking” gas which is deemed to have been injected into theTransmission Network at a different point by another Shipper.

Where a Shipper’s Injection Quantity is greater than it’sShipper Offtake Quantity (that is it has injected more gas intothe system than it has offtaken) that Shipper will have apositive Commodity Variances. By contrast where aShipper’s Injection Quantity is less than its Shipper OfftakeQuantity (that is it has offtaken more gas into the system thanit has injected) that Shipper will have a negative CommodityVariances.

A Shipper with a positive imbalance in any Balancing Periodcan bi-laterally trade its Commodity Variances with anotherShipper who has a negative Commodity Variances in thesame Balancing Period.

Allocation

In order to allow for open competition and as more Shippersenter the gas market, it is likely that more than one Shipperwill inject gas at a single Transmission Network InjectionPoint. The Metered Injection Quantity at a TransmissionNetwork Injection Point needs to be allocated amongst each

of those Shippers to determine each Shipper’s InjectionQuantity.

The Shippers may enter into an allocation agreementwhereby an appointed allocation agent will, upon beingprovided with the Metered Injection Quantity for a particularBalancing Period, allocate that quantity amongst the injectingshippers pursuant to the terms of the allocation agreementand inform the Transporter accordingly.

Alternatively, if there is no allocation agreement in effect at aTransmission Network Injection Point where there is morethan one injecting shipper or if, during a Balancing Period, theallocated amounts provided by the allocation agent do notaccord with the Metered Injection Quantity, the Transportershall, itself, determine each Shipper’s Injection Quantityutilising a default allocation mechanism. The terms of thedefault allocation mechanism are reflected in the Gas NetworkCode and are based upon a combination of factors includingthe attribution of a shipper’s offtake quantity to each injectionpoint and the amount of a shipper’s nomination (for thepurposes of assessing whether a shipper is deemed to have“contributed” to an “excess” or “shortfall” position).

Similarly, where there is more than one Shipper at aTransmission Network Offtake Point, the Shipper OfftakeQuantity is determined either by an appointed allocation agentor in accordance with a default allocation formula basedentirely on pro-rating the Metered Offtake Quantity amongstthe Shippers in accordance with their nominations.

It should be noted that the quantity of gas taken off theTransmission Network from a Transmission/Distribution Point(that is a point where gas passes from the TransmissionNetwork to a Distribution Network at a pressure reductionstation) is not allocated amongst the Shippers pursuant to anallocation agreement or a default mechanism. Instead thequantity metered at such point is allocated, at InitialSettlement, amongst the Shippers based upon a Shipper’sprofile of customers obtaining gas from that point to determinea Shipper’s Transmission/Distribution Quantity. Followingreceipt of the actual meter readings from those customers, aShipper’s Transmission/Distribution Quantity in eachBalancing Period is re-calculated using a combination ofprofiling and attribution for the purposes of Final Settlement.

Risks and liabilities

In addition to addressing the mechanics and operatingprocedures by which gas is intended to be conveyed throughthe Transportation System, the Gas Network Code also dealsexpressly with the rights and obligations owed by theTransporter to Shippers and vice versa and theconsequences for failing to comply with the provisionsestablished within the Gas Network Code. The following listidentifies those provisions which are most critical to therisk/liability regime.



Gas specification

The Gas Network Code includes a list of gas specificationparameters for the quality of gas which may be injected intothe Transmission Network. This includes items such as theranges of calorific value and the Wobbe Index and themaximum permitted allowances for Carbon Dioxide,particulates and various elements (known as the “Gas EntryConditions”).

Penalty regime

The pre-defined penalties to which the Shippers are subject,as specified in the Gas Network Code and include theUnauthorised Overrun Charges, Failure to Notify Charges andNominations Divergence Charges.

The pre-defined penalties to which the Transporter is subject,as specified in the Gas Network Code and includecompensation for Transporter Injection Imbalances.

Scheduled Maintenance

The Transporter is entitled to carry out ScheduledMaintenance on the Transmission Network in accordance withits Annual Maintenance Programme. The programme isprepared and published annually and has to be approved bythe EMA. The only requirement imposed upon theTransporter is that it must use endeavours to secure that theestimated reduction in the availability of a Shipper’s CapacityRights as a result of Scheduled Maintenance is minimised.

During Scheduled Maintenance the Transporter is exemptfrom the liability regime to deliver gas to offtake points to theextent disrupted by the Scheduled Maintenance.

Scheduled Maintenance will not, however, effect the paymentof Capacity Charges by the Shippers to the Transporter.

System Stress

In circumstances where the operating state of theTransportation System is unsafe (most likely because of asignificant fall in pressure) the Transporter has the ability todeclare a System Stress. During the period of System Stressthe normal procedures and principles established in the GasNetwork Code for the conveyance of natural gas aresuspended. For instance, the Transporter can requireShippers to inject and offtake gas from the TransportationSystem in accordance with its instructions (albeit that thecompliance by the Shipper with the instructions is subject toits reasonable endeavours). The penalty regimes and theimbalance calculations are suspended during System Stress.

Upon the return of the Transportation System to its normaloperating state, the Transporter issues a notice to Shippersidentifying the Code Re-start Time. The Transporter is thenrequired to appoint an independent auditor to investigate thecause of the System Stress and to make, where possible,

recommendations for the avoidance of a similar situationarising in the future. The costs incurred during System Stressare allocated to the party causing the System Stress or aresmeared across all the Shippers in circumstances where noperson is deemed to have caused the System Stress.

Force majeure

As one would expect, force majeure relieves the affectedparty from performing its obligations under the Gas NetworkCode. In the context of the Gas Network Code it isacknowledged that essentially the Transporter is obliged toconvey gas and the Shippers are obliged to pay CapacityCharges. As such Shippers are only relieved from theirobligations to pay Capacity Charges to the extent a forcemajeure event impacts upon the Transporter’s ability toconvey gas in accordance with Shippers’ Capacity Rights.

The important point to note is that an event which impactsupon a Shipper’s ability to take gas (for example an explosionat a power station) will not be construed as a force majeureevent under the Gas Network Code. The event does notaffect such Shipper’s obligation to pay Capacity Charges.Capacity Charges will, therefore, continue to be payable bythat Shipper irrespective of the fact that it is not in a positionto receive gas and is making no nominations.

Where a force majeure event under the Gas Network Codelasts for more than 30 months either party may terminate itsTransportation Framework Contract.

Limitations/caps on liability

Aside from the specific remedies identified in the Gas NetworkCode such as Nomination Divergence Charges, Failure toNotify Charges etc., the Gas Network Code specificallyaddresses the manner in which other claims may be madeagainst the Transporter by a Shipper or against a Shipper(s)by the Transporter.

In this respect the parties are only liable to each other(whether as a result of a breach of contract, negligence orbreach of statutory duty) to the extent that the relevant eventhas resulted in physical damage to the property of the partybringing the claim or has resulted in that party being liable fora third party’s claim where that third party’s property has beendamaged.

The damage will not encompass claims for consequentiallosses. The liability of the Transporter to any one Shipper islimited to a maximum of S$500,000 per event. The liability ofthe Transport to all Shippers is limited to S$5 million.

These limits do not apply to a party’s liability for death orpersonal injury or where the liability arises as a result of thatparty’s wilful misconduct.



Credit Regime

Two distinct credit regimes apply to the Shippers under theGas Network Code. The first applies to their liability to theTransporter for the payment of Transportation Charges (thatis Capacity Charges, Usage Charges and DistributionCharges). The second applies to their liability to theTransporter for the payment of Balancing Charges (that isCommodity Variance Charges, Nomination DivergenceCharges, Metering Performance Charges).

The credit regime applicable to the Transportation Chargesrequires a Shipper to remit to the Transporter security (eitherin the form of cash deposits or banker’s guarantee) in anamount equal to three times its Average MonthlyTransportation Code Indebtedness.

The credit regime applicable to the Balancing Chargesrequires a Shipper to remit to the Transporter security (eitherin the form of cash deposits or banker’s guarantee) in anamount equal to its Balancing Credit Limit (which is currentlyset at a value equal to two months of a Shipper’s AvailableFirm Capacity Rights multiplied by the Administered NegativeImbalance Price). The credit regime applicable to theBalancing Charges is vitally important to each of the Shippersbecause, ultimately, through the Balancing Neutralitymechanism they each are taking credit risk on each other’sability to settle Balancing Charges. In other words, in theevent the Transporter is required to enforce the securitygranted in its favour as a result of a Shipper failing to pay itsinvoice for Commodity Variance Charges and the security isinsufficient, the Transporter will look to all the other Shippersfor its under-recovery through the Commodity Varianceneutrality mechanism.

Shipper Termination

The ultimate sanction (and clearly the last resort) available tothe Transporter is to terminate its transportation frameworkcontract with a Shipper in default. A Shipper Default isexpressly defined in the Gas Network Code and obviouslyincludes failure to make payment.

In a situation where a Shipper is terminated, all its RegisteredCapacity Rights (other than where a Transferee Shipper ofthose Capacity Rights has elected to become the RegisteredShipper thereof) revert to the Transporter. Under thosecircumstances the amount of spare capacity on the systemwill clearly increase. Another Shipper may “take-up” thatcapacity, but if that does not occur it is possible that, wherethe Transporter is permitted to obtain a regulated rate ofreturn on its assets on an annual basis, all other Shipper’scosts will be increased accordingly to enable the return to bemade on the same asset base with less Shippers.

Dispute resolution

The Gas Network Code establishes an expert resolutionforum for technical disputes and resolution by arbitration inaccordance with the SIAC Rules for all other disputes.


Notes

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Singapore Energy Market-September 2012