NEMS Market Report 2014

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MARKET REPORT 2014

MARKET REPORT 2014


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CONTENTS

ENERGY MARKET COMPANY

Letter from the Chairman 1

MARKET OVERVIEW

Market History 3 Industry Structure 4

Market Features 6

MARKET GOVERNANCE

Overview 8

Letter from the Chair, Rules Change Panel 9

Market Evolution 10

Letter from the Dispute Resolution Counsellor 12

MARKET PERFORMANCE

Overview of the Year 15

Energy Demand 19

Energy Supply 20

Energy Prices 25 Ancillary Markets 29

Competition in the Generation and Retail Markets 35

Settlement and Prudential Management 37

Contracted Ancillary Services 38

Market Fees 39

ADDITIONAL INFORMATION

Glossary 41

Market Entities’ Contact Details 43


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ENERGY MARKET COMPANY : Letter from the Chairman

As Singapore strives to maintain a balanceof the three energy policy objectives ofeconomic competitiveness, energy securityand environmental sustainability, the

NEMS will have to continue to evolve tomeet new challenges and opportunities.With the support of all our stakeholders,I am confident that the NEMS will remainrelevant and continue to contributetowards the competitiveness of Singapore’seconomy.

Wong Meng Meng

ChairmanEnergy Market Company

After more than ten years of operation, I amhappy to note that the National ElectricityMarket of Singapore (NEMS) continuedto attract new investments in 2014. We

are also reaping other benefits of marketliberalisation as competition in Singapore’selectricity sector continues to keepwholesale prices competitive and driveeconomic efficiency.

We welcomed three new marketparticipants and five new generatingfacilities in 2014. The majority of thenew facilities were combined-cycle gasturbine (CCGT) units. Collectively, with thenew facilities, total generation registeredcapacity in the NEMS rose to a record levelof 12,884MW, marking an increase of3.7 percent compared to the previous year.

With the new facilities coming on board,the total amount of electricity offered in theNEMS – known as total generation supply– saw a 9.3 percent year-on-year (YOY)increase in 2014. This is the biggest YOYgrowth since the market started and it drovetotal annual supply in the NEMS close tothe 8,000MW mark, the highest levelsince 2003.

Electricity consumption also rose in 2014at a rate of 3.2 percent, to 46.7 terawatthours.

With the growth in supply outpacing thegrowth in consumption, coupled with loweroil prices in 2014, the Uniform SingaporeEnergy Price (USEP) fell for the secondconsecutive year to an average figure of$137 per megawatt hour (MWh). This isa 20.8 percent drop from the previous

year. With the exception of 2009, whenthe NEMS was impacted by the globalfinancial crisis, we have not seen the annualaverage USEP fall below $150/MWhsince 2007.

The USEP’s movements continue to bedriven by prevailing demand and supplyconditions and are signs of a well-functioning, efficient and competitivemarket. Aside from prices, the NEMS’effectiveness is evident in the ongoing movetowards more efficient generation, with themarket share of the more efficient CCGTunits hitting a new high of 97.5 percentin 2014.

We also saw a further reduction in marketconcentration as a result of the keencompetition in Singapore’s electricitymarket. The market share of the three

largest generation companies declinedfrom 69.7 percent in 2013 to 61.5 percentin 2014. In the retail market, the marketshare of the top three retailers, excluding SPServices which supplies all non-contestableconsumers, dropped 5.6 percentage pointscompared to the previous year.

At this point, I would like to thank thegovernance panels of the NEMS fortheir continuous efforts in developing themarket, monitoring the market’s activitiesand supporting the dispute resolutionneeds of the market. Together, the RulesChange Panel, Market Surveillance andCompliance Panel and Dispute Resolutionand Compensation Panel have contributedto the stability and efficiency of the NEMS,and made it into the world-class electricitymarket that it is today.

Dear Industry Members

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MARKETOVERVIEW


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MARKET OVERVIEW : Market History

Corporatisation 1995 Electricity functions of the Public Utilities Board corporatised

Singapore Power formed as a holding company

1996 Singapore Electricity Pool (SEP) design process began

Singapore Electricity Pool (SEP) 1998 SEP commenced

PowerGrid is SEP Administrator and Power System Operator (PSO)

1999 Review of electricity industry

National Electricity Market ofSingapore (NEMS)

2000 Decision for further reform to obtain full benefits of competition

New market design process began

2001 Electricity industry legislation enacted

Energy Market Authority (EMA) established as industry regulator and PSO

Energy Market Company (EMC) established as the NEMS wholesale market operator

First phase of retail contestability

2002 Testing and trialling of wholesale market system began2003 NEMS wholesale market trading began

2004 Vesting contract regime introduced

Interruptible loads (IL) began to participate in the reserves market

2006 First wholesale market trader joined the market and commenced trading as IL provider

First commercial generator since 2003 joined the market and started trading

Retail contestability expanded to 75 percent of total electricity demand

2007 Removal of the Market Registration Application Fee

2008 Sale of Tuas Power to China Huaneng Group in March, Senoko Power toLion Consortium in September, and PowerSeraya to YTL Power in December

Embedded generators (EG) joined the market

2009 Revised regulation price cap of $300/MWh was implemented

New EGs, small generators and incineration plants joined and started trading

2010 Vesting tender was introduced to tender out a percentage of non-contestable electricitydemand to generation companies for bidding

2012 NEMS completed ten successful years of trading

2013 Singapore’s Liquefied Natural Gas (LNG) terminal started commercial operations

LNG vesting contract introduced

Market Reform MilestonesThe opening of the National ElectricityMarket of Singapore (NEMS) in January2003 was the culmination of a number ofstructural reforms to Singapore’s electricityindustry.

Singapore’s journey to liberalisationstarted in October 1995, when industryassets were corporatised and put on acommercial footing. In 1998, the SingaporeElectricity Pool, a day-ahead market, beganoperations. On 1 April 2001, a new legaland regulatory framework was introducedthat formed the basis for a new electricitymarket.

The NEMS is an integral part ofSingapore’s overall energy policyframework which seeks to maintain a

balance of the three policy objectives ofeconomic competitiveness, energy securityand environmental sustainability. TheNEMS places Singapore alongside aninternational movement to introduce marketmechanisms into the electricity industry asa way to:• increase economic efficiency through

competition;• attract private investment;• send accurate price signals to guide

production and consumption decisions;

• encourage innovation; and• provide consumer choice.

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MARKET OVERVIEW: Industry Structure

Generators ExxonMobil Asia PacificKeppel Merlimau CogenKeppel Seghers Tuas Waste-To-Energy Plant (Tuas DBOO Trust)National Environment AgencyPacificLight PowerSembcorp CogenSenoko EnergySenoko Waste-to-EnergyShell Eastern PetroleumTP UtilitiesTuas Power GenerationTuaspringYTL PowerSeraya

Wholesale Market Traders Air ProductsBanyan UtilitiesCGNPC Solar-Biofuel Power (Singapore)CPvT Energy Asia

Diamond EnergyECO Special Waste ManagementGlaxo Wellcome Manufacturing – GlaxoSmithKline BiologicalsGreen Power AsiaMSD International GmbH (Singapore Branch)Pfizer Asia PacificSingapore LNG CorporationSingapore Oxygen Air LiquideSunseap Leasing

Retailers CPvT Energy AsiaDiamond Energy SupplyHyflux EnergyKeppel Electric

PacificLight EnergySembcorp PowerSenoko Energy SupplySeraya EnergyTuas Power Supply

Market Support Services Licensee (MSSL) SP Services

Market Operator Energy Market Company

Power System Operator (PSO) Power System Operator

Transmission Licensee SP PowerAssets

Singapore’s electricity industry is structuredto facilitate competitive wholesale and retailmarkets. Competitiveness is achieved byseparating the ownership of the contestableparts of the industry from those with naturalmonopoly characteristics.

Three New Market Participants Joined the Market

In 2014, three new market participants(MPs) registered in the NEMS as wholesalemarket traders. One of the three MPs furtherobtained a retailer license later in the year.

CGNPC Solar-Biofuel Power (Singapore)joined the NEMS in April and its 9.9MWbiomass facility started commissioning inthe last quarter of the year. CPvT EnergyAsia registered as a NEMS wholesaletrader for interruptible load service inFebruary, and as a retailer in October.Finally, Sunseap Leasing joined the NEMSin September. It is the first MP dedicated tosolar leasing since the market started.

With these additions, there are now 13wholesale market traders and nine retailersin the NEMS. The number of generationcompanies remains at 13.

Participants and Service Providers in the NEMS

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MARKET OVERVIEW: Industry Structure

Generation LicenseesAll generators with facilities of 1MW ormore that are connected to the transmissionsystem must participate in the NEMSand be registered with EMC. Generationlicensees are companies with generating

facilities that are 10MW or more thatare connected to the transmission systemand licensed by the EMA to trade in thewholesale electricity market. Wholesale Market TradersWholesale market traders are generatorswith facilities of 1MW or more but lessthan 10MW that are connected to t hetransmission system and licensed by theEMA to trade in the wholesale electricitymarket. This category includes consumersthat offer their own load to be interrupted,as well as companies that provide servicesto other consumers interested in offeringtheir load to be interrupted.

Retail Electricity LicenseesRetailers that sell electricity to contestableconsumers are licensed by the EMA.Retailers that are registered as marketparticipants purchase electricity directlyfrom the wholesale market.

Market Support Services Licensee –SP ServicesA Market Support Services Licensee (MSSL)is authorised to provide market supportservices. Such services include facilitatingcustomer transfers between retailers, meterreading and meter data management. SPServices is the only MSSL. In addition toits market support services function, SPServices also facilitates access to the NEMSfor contestable consumers who have notappointed a retailer, and supplies electricityto non-contestable consumers.

Market Operator – EMCEMC operates and administers thewholesale market. This role includescalculating prices, scheduling generation,clearing and settling market transactions,and procuring ancillary services. EMC

also administers the rule change processand provides resources that support marketsurveillance and the compliance anddispute resolution processes.

Transmission Licensee –SP PowerAssetsSP PowerAssets owns and is responsible formaintaining the transmission system.

Power System Operator The Power System Operator (PSO), a

division of the EMA, is responsible forensuring the security of supply of electricityto consumers. The PSO controls the dispatchof generation facilities, co-ordinatesscheduled outages and power systememergency planning and directsthe operation of the high-voltagetransmission system.

Regulator – EMAThe EMA is the regulator of the electricityindustry and has the ultimate responsibilityfor the market framework and for ensuringthat the interests of consumers areprotected.

ConsumersConsumers are classified as being eithercontestable or non-contestable, dependingon their level of electricity usage.Contestable consumers may choose topurchase electricity from a retailer, directlyfrom the wholesale market or indirectly fromthe wholesale market through the MSSL, SPServices. Non-contestable consumers aresupplied by SP Services.

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MARKET OVERVIEW: Market Features

Description Purchaser Seller

Energy Generated electricity Retailers Generators

Reserve Stand-by generation capacity or IL that canbe drawn upon when there is an unforeseen

shortage of supply. Three classes of reserveare traded:

1) primary reserve (8-second response)2) secondary reserve (30-second response) and3) contingency reserve (10-minute response)

Generators Generators,Retailers

andWholesalers

Regulation Generation that is available to fine-tune thematch between generation and load

Generatorsand Retailers

Generators

The NEMS has a number of features thatdrive efficiency and make its design trulyworld class. These include:• co-optimisation of energy, reserve and

regulation products;• security-constrained dispatch and

nodal pricing; and• near real-time dispatch.

Co-optimisation of Energy, Reserveand Regulation Products

A sophisticated process involving about50,000 different mathematical equationsis used to determine the price and quantityof the energy, regulation and reserveproducts traded. Integral to this process isthe concept of co-optimisation, wherein themarket clearing engine (MCE) considers

the overall costs and requirements of allproducts, and then selects the optimal mixof generation and interruptible loads (IL) tosupply the market.

Security-Constrained Dispatch andNodal Pricing

To determine the prices for products tradedon the wholesale market, offers made bygenerators and ILs are matched with thesystem demand forecast and system securityrequirements. The MCE produces a security-

constrained economic dispatch by takinginto account the:• available generation capacity;• ability of generation capacity to

respond (ramping);• relationship between the provision of

energy, reserve and regulation (co-optimisation);

• power flows in the system;• physical limitations on the flows that

can occur in the transmission system;

• losses that are incurred as power istransported; and

• constraints in relation to systemsecurity.

This process is run every half-hour todetermine the:• dispatch quantity that each generation

unit is to produce;• reserve and regulation capacity that

each generation unit is required tomaintain;

• level of IL that is required; and• corresponding prices for energy,

reserve and regulation in the wholesalemarket.

Energy prices – referred to as nodal prices– vary at different points on the network.The differences in nodal prices reflectboth transmission losses and the physicalconstraints of the transmission system. Thismeans that the true costs to the market ofdelivering electricity to each point on theelectricity network are revealed.

The MCE models the transmission networkand uses linear and mixed integerprogramming to establish demand andsupply conditions at multiple locations(nodes) on the network. Modelling ensuresthat market transactions are structured in

a way that is physically feasible given thecapacity and security requirements of thetransmission system. For each half-hourtrading period, the MCE calculates theprices to be received by generators at the56 injection nodes, and the prices at upto 766 withdrawal or off-take nodes1 thatare used as the basis for the price to bepaid by customers. This method of pricedetermination encourages the economically-efficient scheduling of generation facilities

in the short term and provides incentives toguide new investment into the power systeminfrastructure in the long term.

EMC uses metered demand and generationfrom the MSSL and market prices to settlemarket transactions on a daily basis.Generators receive the market price forenergy that is determined at their pointof connection to the transmission network(injection node). Retailers pay the UniformSingapore Energy Price (USEP) for energy,which is the weighted-average of the nodalprices at all off-take nodes.

Generators pay for reserve accordingto how much risk they contribute to thesystem. Regulation is paid for by retailers inproportion to their energy purchase and bydispatched generators up to a ceiling of5 megawatt hours for each trading period.

Near Real-Time Dispatch

Market prices and dispatch quantitiesfor energy, reserve and regulation arecalculated five minutes before the startof each half-hour trading period. Thisensures that the market outcomes reflectthe prevailing power system conditions andthe most recent offers made by generators.The result of near real-time calculation ofdispatched generation quantities ensures aslittle real-time intervention as possible, andhence minimal deviation from a competitivemarket solution.

To support near real-time dispatch, EMCproduces market forecast schedules upto a week ahead of the relevant tradingperiod. These forecast schedules increase infrequency as the trading period approachesto ensure that MPs have the informationthey need to adjust their trading positionsprior to physical dispatch.

1 Numbers of injection and withdrawal nodes are as of31 December 2014.

Energy, Reserve and Regulation Products

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MARKETGOVERNANCE


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MARKET GOVERNANCE: Overview

Governing Documents andInstitutions

The Energy Market Authority (EMA) wasestablished under the Energy MarketAuthority of Singapore Act 2001. The EMA

is the electricity market regulator under theElectricity Act 2001 and is responsible for,among other mandates:• creating the market framework for

electricity and gas supply;• promoting development of the

electricity and gas industries;• protecting the interests of consumers

and the public;• issuing licences; and• advising the Government on energy

policies.

Rule Change Process

The day-to-day functioning of the NationalElectricity Market of Singapore (NEMS)wholesale market is governed by theSingapore Electricity Market Rules.

The rule change process is the responsibilityof the Rules Change Panel (RCP). Appointedby the Energy Market Company (EMC)Board, RCP members represent generators,retailers, wholesale market traders, thefinancial community, the Power SystemOperator (PSO), the Market SupportServices Licensee (MSSL), the transmissionlicensee, electricity consumers and EMC,ensuring representation by all the keysectors of the industry.

The rule change process is designed tomaximise transparency and opportunitiesfor public involvement. Rule modificationsrecommended by the RCP require thesupport of the EMC Board and the EMA.When approving changes to the MarketRules, the EMA is required to considerwhether the proposed rule modifications(i) unjustly discriminate in favour of oragainst a market participant (MP) or aclass of MPs; or (ii) are consistent with thefunctions and duties of the EMA under

subsection 3(3) of the Electricity Act. Each year, the RCP establishes and publishesits work plan to ensure that stakeholdersremain informed about the likely evolutionof the market. The work plan can be foundat www.emcsg.com.

Market Surveillance and Compliance

The Market Surveillance and CompliancePanel (MSCP), comprising professionalsindependent of the market, is responsiblefor monitoring, investigating and reporting

the behaviour of MPs and the structuralefficiency of the market. The panel identifiesmarket rule breaches and assesses marketoperations for efficiency and fairness.In circumstances in which the MSCPdetermines that an MP is not compliant withthe Market Rules, it may take enforcementaction, which may include levying apenalty. The MSCP also recommendsremedial actions to mitigate any rulebreaches or inefficiencies identified. Thepanel produces the MSCP Annual Report,which has been published together with theNEMS Market Report since 2007.

Dispute Resolution

The Market Rules contain a process thatfacilitates the resolution of disputes betweenMPs and service providers. The disputeresolution process is designed to be a

cost-effective way of resolving disputes andpreserving market relationships by avoidingcourt proceedings. This process is managedby the Dispute Resolution Counsellor (DRC).

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MARKET GOVERNANCE: Letter from the Chair, Rules Change Panel

Beyond the Panel, I would like to expressmy gratitude to others who have contributedto making 2014 a fruitful year, includingthe EMA, the EMC Board, EMC’s Market

Administration team and all other marketparticipants whose valuable inputs havecontributed to the success of the rulechange process.

Paul PohChairRules Change Panel

The industry has entrusted the Rules ChangePanel (RCP) the challenging task of guidingthe evolution of the Market Rules thatgovern the wholesale electricity market

of Singapore. Against the backdrop ofan increasingly competitive and dynamicindustry, the Panel ensures that the MarketRules remain relevant and balanced inachieving diverse objectives.

The Market Clearing Engine (MCE) isoften examined by the Panel for areas offine-tuning in order to unlock efficienciesin the scheduling process. This year, thePanel introduced the option for generationfacilities to have their minimum stable load(MSL) levels modelled by the MCE, whichwould improve the stability of the facilities’operation and enhance system security.In addition, the Panel enhanced the MCEto model line flows, based on the exactconstituent units of a multi-unit generationfacility, that are connected to the grid. Amore precise modelling of line flows wouldresult in more accurate price signals.

The Panel also strived tirelessly to improvethe status quo through the review of existingprocesses. For the dispute resolutionprocedures, existing time limits were

adjusted to fast-track the resolution ofdisputes. In addition, the Panel studieda rule change proposal on the existingcompensation guidelines, to provide greaterclarity to generators when they are directedby the Power System Operator (PSO) todeviate from their dispatch schedules.While it was important to maintain thetrust and confidence of investors throughcompensation, the rule change wasproposed so that generators did nothave the scope to manipulate the marketby restricting their ability to submit offerchanges while under such direction bythe PSO.

Transparency is an important trait forwell-functioning markets as it allows keystakeholders to make informed decisionsin both the short and long term. The Panelhas always advocated market transparencyand this year, it supported proposals forEnergy Market Company (EMC) to analysehourly energy uplift charge values in themonthly trading report, and for the PSO to

publish actual and forecast load data forcomparison.

As always, the Panel is careful to ensurethat market enhancements justify theassociated costs that will be incurred. Inthe Panel’s deliberation on the proposed

regulation effectiveness factor toredistribute payments based on providers’performances, the Panel recognised thebenefits of incentivising better performance.However, given that most p roviders arealready operating at a high performancelevel, further differentiation did not justifythe high implementation costs. As such,the Panel decided not to proceed with theproposal.

The close of 2014 marked the end of t hecurrent Panel’s term. I would like to take thisopportunity to thank the outgoing Panelmembers for their dedicated contributionsover the years: Kng Meng Hwee, ChanHung Kwan, Koe Pak-Juan, Michael WongHo Ming and Loh Chin Seng. At the sametime, I would like to welcome Soh YapChoon, Lim Han Kwang, Grace ChiamI-Ling, Priscilla Chua Peizhen and MarcusTan Yam Ngee to the new Panel. This ispart of the Panel’s rejuvenation process,and I look forward to the fresh perspectivesthat these new members will bring to our

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MARKET GOVERNANCE: Market Evolution

Rule Changes Supported bythe RCP

The following rule changes were discussedand approved, as part of the RCP’scontinual efforts to guide the evolution of

the wholesale electricity market.

Modelling of Minimum Stable Load

Generators have a technical limitation inthat they need to operate at their minimumoutput level (known as the minimum stableload or MSL) in order to maintain stableoperation. The market clearing engine(MCE), however, could schedule generatorsfor energy at any output level without takinginto consideration their MSLs.

A rule change was thus proposed to giveMPs the choice to limit the MCE to scheduletheir generators at either above their MSLlevels, or at zero. With the proposedconstraint, there could be times when agenerator is scheduled at its MSL but theclearing prices are below the generator’soffers. To address this, a compensationframework for generators which arescheduled out-of-merit order at their MSLswas also introduced as part of this rulechange.

Increasing the Transparency of Energy UpliftCharges

The monthly and hourly energy upliftcharges (MEUC and HEUC) are chargesimposed on loads based on their actualconsumption in each settlement interval.It was proposed that EMC increasethe transparency of these charges byconducting qualitative and quantitativeanalyses on a monthly basis.

EMC’s review concluded that there issufficient transparency on the MEUC, sincethe breakdown of the MEUC is publishedin the monthly MEUC statements andalso verifiable using other information onEMC’s website. There is, however, scope toenhance the transparency of the HEUC, as

its final values are published without anyexplanation.

EMC thus recommended a framework toidentify and analyse settlement intervalswith outlier HEUC values arising frommetering errors, transmission constraintsand metering adjustments, and proposedthat this analysis be provided in the existingmonthly trading reports.

The RCP, by majority vote, supported the

proposal to increase the transparencyof the HEUC and its correspondingimplementation cost. The proposal will beimplemented from February 2015 and EMCwill start providing the analysis of the outlierHEUC values in the January monthly tradingreport.

Reconciliation of the Demand Forecast

An MP proposed that EMC publish acomparison between the PSO’s loadforecasts used in the preparation of forecastand dispatch schedules, and the actualmetered load. This comparison should showthe load values for each dispatch periodand provide reasons for variance whereapplicable. This will enhance the industry’sunderstanding of the accuracy of the loadforecasts and factors that influence them.

After some deliberation, the RCPunanimously agreed that both the VeryShort Term Load Forecast (VSTLF) andSCADA (supervisory control and dataacquisition) data of actual gross generationshould be made available by the PSO

to the MPs for the latter’s analyses of thedemand forecasts. The PSO has startedpublishing both data on the EMA’s websiteon a weekly basis.

Review of Dispute Resolution Procedures

As part of its three-yearly review ofthe dispute resolution procedures, theRCP received two proposals to improvethe current compensation applicationprocedures, which delineate the processes

through which a claimant can seekcompensation under the Market Rules.

Proposal 1: Extension of time limit formaking a determination

After receiving a compensation request,the current rules require EMC or the PSOto notify the claimant of its eligibility forcompensation within 20 business days.However, as EMC or the PSO may needto seek further information to support theclaimant’s application, it was suggested thatthe 20 business days commence from thelater of the two dates – the date of receiptof the compensation request or date ofreceipt of further information requested.

The RCP supported the rule change toextend this time limit, so as to allow EMC orthe PSO to have sufficient time to assess thecompensation request.

Proposal 2: Stipulate time limit foracceptance of compensation andsubmission of matter for arbitration

After EMC or the PSO has made adetermination on the claimant’s eligibilityand compensation amount, claimants caneither accept the determination or disagreeand submit the matter for arbitration.However, the rules at present do not set atime limit for them to do so. A rule change

was thus made to require that claimantseither accept the compensation amountor submit the matter for arbitration within20 business days of EMC or the PSO’sdetermination.

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MARKET GOVERNANCE: Market Evolution

Remodelling of Multi-Unit Facilities

A proposal was received to refinethe modelling of Multi-Unit Facilities(MUFs) in the MCE, to better account forsituations when any of the ConstituentGenerating Units (CGUs) comprising eithersteam turbines or gas turbine units aredisconnected from the dispatch network.

When a CGU is disconnected, the MCEwill notionally connect it back to cater forthe possibility that it could be re-connectedto the grid in future periods. The MCEcurrently apportions the line flows froman MUF’s energy schedule across all ofits individual CGUs (even those that areonly notionally connected), and sets its gasturbine CGUs’ output as a proportion of its

steam turbine CGUs’ output. This leads topotential problems whereby the whole MUFmay not be scheduled if its steam turbineCGU is not connected. This poses systemrisk by reducing supply, and impedesmarket efficiency.

To overcome this, a rule change was madeto implement a conditional check to decidewhether to connect each non-synchronisedCGU back to the dispatch network. Inaddition, two constraints used to allocate

line flows proportionally to the CGUswere revised to more accurately reflect thereduced capacity of a steam turbine whenone of the two gas turbines that drive it isdisconnected.

Review of Compensation Guidelines

This year, the Panel reviewed thecompensation guidelines in the MarketRules intended to provide guidance on thecompensation due to generators, when theywere directed by the PSO to deviate fromtheir schedule.

The dispatch schedule generated by theMCE is the most economically efficientoutcome and should generally be adheredto for dispatch purposes. However, in real-time, the PSO may need to intervene anddirect certain generators to deviate from theMCE’s schedule. Such generators shouldthen be compensated if PSO’s directionslead them to incur costs not recoverablefrom market revenue.

The Panel agreed that upon PSO’s direction,generators should not be allowed to changetheir offers so as not to affect the clearingprice or take advantage of their “must-run”status. To ameliorate the potential that theiroffers were not reflective of their costs,that there were no offers for the instructedquantities, or that the market clearing pricewas lower than their offers, generatorswould be given the ex-post choice ofeither using an offer-based or cost-based

methodology to calculate the compensablequantum.

A rule change was thus proposed suchthat when the PSO has issued a directionrelating to the provision of energy to agenerator, the generator would not beallowed to change its offers for thosedispatch periods.

Rule Changes Not Supported by theRCP

The RCP also discussed the followingproposal but decided not to support itbecause the potential benefits did not justify

the costs.

Introduction of Regulation EffectivenessFactor

The proposal involved introducing theRegulation Effectiveness Factor (REF),which measures the responsiveness ofa given regulation provider and in turn,translates into share of regulation payments.This ensures that these providers areappropriately incentivised to be responsiveto regulation signals.

In a 2010 RCP paper, EMC found that whilethere was no evidence of excess regulationprovision on a system-wide level, someGeneration Registered Facilities (GRFs)were more responsive and correspondinglyprovided regulation in excess of theirschedules. However, given the challengesinvolved with a comprehensive regulationresponsiveness assessment, the RCPunanimously agreed not to pursue it.

At the RCP Work Plan Prioritisation Exercise2014, a proposal was received to re-evaluate the REF proposal. It was alsoobserved that markets such as PJM andNYISO already have mechanisms in placewhereby regulation resources with thehighest value to system control were giventhe highest payments.

This review focused on coming up withan assessment scheme that minimisedimplementation costs. However, basedon simulation results, most regulationproviders were already operating at ahigh performance level. The Panel agreedthat further differentiation among differentproviders would be minimal and did notjustify the high implementation costs. It thusdecided not to proceed with the proposal.

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MARKET GOVERNANCE: Letter from the Dispute Resolution Counsellor


Dispute Resolution andCompensation Panel

The Dispute Resolution and CompensationPanel (DRCP) was established under theMarket Rules to provide dedicated disputeresolution services to the NEMS whenrequired.

DMS Contacts

Pursuant to the Market Rules, each marketentity has nominated at least one DisputeManagement System (DMS) contact to be

the first point of engagement in the event ofa dispute.

The current DMS contacts are:

1. Air Products - Shawn Zhang

2. Air Products - Tang Siew Wai

3. CGNPC Solar-Biofuel Power- Nelson Ong

4. CGNPC Solar-Biofuel Power- Zhang Hua

5. Diamond Energy - Muhammed Iqbal

6. ECO Special Waste Management- Ethiraj Thirumalai

7. ECO Special Waste Management- Vincent Tang

8. Energy Market Company- Ambrose Chia

9. Energy Market Company- Tan Phaik Kim

10. ExxonMobil - Elaine Lee

11. ExxonMobil - Teddy Yong

12. GlaxoSmithKline Biologicals- Chew Siou Ping

13. GlaxoSmithKline Biologicals -Wong Joon Jee

14. Green Power Asia - Daniel Ma15. Hyflux Energy - Calvin Quek

16. Hyflux Energy - Chin Si En

17. Keppel Electric - Janice Bong

18. Keppel Electric - Joelyn Wong

19. Keppel Merlimau Cogen - Sean Chan

20. Keppel Merlimau Cogen- Tini Mulyawati

21. National Environment Agency

- Siew Weng Soon22. National Environment Agency

- Teresa Tan

23. PacificLight Power - Calvin Tan

24. PacificLight Power - Linda Wen

25. Pfizer Asia Pacific - Lee Chin Hoo

26. Pfizer Asia Pacific - Tan Meng Tong

27. Power System Operator - Agnes Tan

28. Power System Operator - Loh Poh Soon

29. Sembcorp Cogen - Chua Gwen Heng30. Sembcorp Cogen - Loh Chin Seng

31. Sembcorp Cogen - Ramesh Tiwari

32. Sembcorp Power - H C Chew

33. Senoko Energy - Eveline How

34. Senoko Energy - Loo Hui Hua

35. Senoko Energy Supply - Eu Pui Sun

36. Senoko Energy Supply - Michelle Lim

37. Seraya Energy - Daniel Lee

38. Seraya Energy - Elaine Syn

39. Singapore LNG Corporation- Lam Zheng Xin

40. Singapore LNG Corporation- Vincent Lam

41. Singapore Oxygen Air Liquide- Lim Yong Yi

42. SP PowerAssets - Chan Hung Kwan43. SP PowerAssets - Ong Sheau Chin

44. SP Services - Budiman Roesli

45. SP Services - Lawrence Lee

46. Tuas Power Generation - Priscilla Chua

47. Tuas Power Supply - Jazz Feng

48. Tuas Power Supply - Zhang Ai Jia

49. YTL PowerSeraya - Daniel Lee

50. YTL PowerSeraya - Elaine Syn

51. YTL PowerSeraya - Jonathan Chew

52. YTL PowerSeraya - Mark New

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MARKET GOVERNANCE: Letter from the Dispute Resolution Counsellor

DRCP Members

The DRCP members are:

Mediation Panel

1. Chandra Mohan

2. Daniel John

3. Danny McFadden

4. Geoff Sharp

5. Associate Professor Joel Lee

6. Associate Professor Lim Lei Theng

7. Dr Peter Adler

8. Robert Yu

9. Shirli Kirschner

Arbitration Panel

1. Ang Cheng Hock, Senior Counsel

2. Chelva Rajah, Senior Counsel

3. Giam Chin Toon, Senior Counsel

4. Gregory Thorpe

5. Harry Elias, Senior Counsel

6. Kenneth Tan, Senior Counsel

7. Professor Lawrence Boo

8. N Sreenivasan, Senior Counsel

9. Naresh Mahtani

10. Philip Jeyaretnam, Senior Counsel

11. Phillip Harris

12. Raymond Chan13. Dr Robert Gaitskell, Queen’s Counsel

14. Tan Chee Meng, Senior Counsel

15. Professor Tan Cheng Han,Senior Counsel

Conclusion

I thank the DRCP members and DMScontacts for their contributions, and lookforward to continuing to support the dispute

resolution needs of all NEMS market entitiesin the coming year.

George LimSenior CounselDispute Resolution Counsellor

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MARKETPERFORMANCE


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15

MARKET PERFORMANCE: Overview of the Year

Q1 Q2 Q3 Q4 YOY Growth

TWh YOY Growth (%)

Q4

Q1

Q2

Q3

Annual Electricity Consumption 2010 – 2014

Electricity consumption continues to increase in 2014

Electricity purchased by market participants(MPs) is settled using electricity consumptiondata provided by the Market Support

Services Licensee (MSSL).

Electricity consumption rose at a higher rateof 3.2 percent in 2014 to 46.7 terawatthours (TWh), compared to the 2.4 percentincrease in 2013. This was despite a slowergrowth in Singapore’s economy in 2014 at2.9 percent2 compared to 4.4 percentin 2013.

On a quarterly basis, all four quartersin 2014 saw higher year-on-year (YOY)electricity consumption compared to the

same periods in 2013. Similar to 2013,the third quarter of 2014 had the highestelectricity consumption at 12.1TWh. Thiswas the first time since the market startedthat electricity consumption for a quarterhad surpassed the 12TWh mark.

2 Based on the Singapore Ministry of Trade and Industrypress release on 17 February 2015: MTI Maintains 2015GDP Growth Forecast at 2.0 to 4.0 Per Cent.

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Generation Capacity as of 31 December 2014:Registered Versus Licensed

Annual Generation Supply by Plant Type 2010 – 2014

CCGT/Cogen/Trigen ST GT Licensed Capacity

MW MW

Forecasted DemandST GTCCGT/Cogen/Trigen

PacificLightPower

KeppelMerlimau

Cogen

YTLPowerSeraya

SembcorpCogen

SenokoEnergy

Tuas PowerGeneration

TP Utilities Tuaspring IncinerationPlants

EmbeddedGenerators*

≥10MW

Generators


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17


Annual USEP and Ancillary Prices 2010 – 2014

$/MWh

2010 2011 2012 2013 2014

1.67 4.70 6.20

33

As the growth in supply outpaced that offorecasted demand, the Uniform SingaporeEnergy Price (USEP) fell from $173 permegawatt hour (MWh) in 2013 to$137/MWh in 2014. This was the lowestlevel since 2007 when it registered

$125/MWh. The USEP t raded at a discountof more than 18 percent below the BalanceVesting Price4 in all months in 2014.

Primary and secondary reserve pricesincreased by $0.16/MWh and $1.60/MWhto $1.67/MWh and $4.70/MWhrespectively. The average supply forprimary reserve dropped 5.0 percentwhile that for secondary reserve dropped

5.8 percent. Requirements were higher at4.6 percent for primary reserve and 1.3percent for secondary reserve.

Contingency prices on the other hand fellfrom $9.12/MWh in 2013 to $6.20/MWhin 2014. Contingency requirement waslower by 1.4 percent in 2014, whilecontingency supply was higher by10.5 percent.

Regulation price saw the largest changeamong the ancillary services, falling 58.5percent from 2013 to $33/MWh in 2014.The new regulation requirement which tookeffect on 1 February 2014 was markedlylower, at 19.4 percent below the volume

required in 2013. Regulation supply whichwas 4.0 percent higher in 2014 furtherweighed the price down to its lowest since2008 when it was $31/MWh.

USEP falls for the second straight year, dragging two ancillary prices down

4 The Balance Vesting Price (BVP) replaced the VestingContract Hedge Price (VCHP) from the third quarter of2013.

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$ Billion

HSFOUSEP

Index

Annual Value of Products Traded 2010 – 2014

Total value of products traded sinks to new five-year low

2014 saw the total annual value of productstraded decline again to $7.01 billion,reprising the drop seen in 2013. This wasa new five-year low since 2010 when thetotal value of products traded was around$8 billion.

The supply surge has brought about keenercompetition in the market, resulting in theUSEP ending about 20.8 percent lower than2013. Forecasted demand’s 3.6 percentgrowth was insufficient to counterbalancethe large supply growth, resulting in thelower USEP.

Adding further downward pressure on theannual value of products traded was thecontraction in the regulation market, whichfell more than $0.5 billion as a result oflower regulation price and quantity.

Overall, the annual value of productstraded in 2014 fell by 19.4 percent. Out ofthis, 18.7 percent can be attributed to t heenergy market, 0.1 percent to the reservesmarket and 0.6 percent to the regulationmarket.

USEP deviates from fuel price5 as electricity market competition intensifies

2014 saw another 462MW of registeredcapacity coming on board. All five of thenew facilities were in the form of the moreefficient CCGT/cogen/trigen generatingplants. In comparison, five new facilitiestotalling 1,618MW were registered in the

NEMS in 2013.

The greater competition in the last two years manifested as deviations betweenthe USEP and fuel oil indices. In 2014, theUSEP fell 20.8 percent whereas fuel pricescame down by 8.1 percent.

Annual USEP and Fuel Price (HSFO) Movements 2010 – 2014

5 The HSFO 180 CST price is used as a proxy for fuel price.

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MARKET PERFORMANCE: Energy Demand

MW

Forecasted demand YOY growth increases in all months

Forecasted demand is the projectedelectricity consumption in the NEMS. Theforecast is provided in real-time by the

Power System Operator (PSO) and is akey component in determining the USEP.

Comparing YOY, forecasted demandwas stronger across all months in 2014.Excluding February due to the ChineseNew Year festival effect, September sawthe highest monthly YOY growth rate of5.6 percent. In 2013, the highest monthlyYOY growth rate of 4.0 percent occurred inOctober (again, January was excluded dueto Chinese New Year).

Monthly Forecasted Demand 2010 – 2014

Annually, forecasted demand was 3.6 percenthigher in 2014, up from 2.8 percent in 2013.

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MARKET PERFORMANCE: Energy Supply

Market Participant Generation Type Registered Capacity

Sembcorp Cogen 1 CCGT unit 403.8MW

TP Utilities 1 CCGT unit 32.5MW

CGNPC Solar Biofuel Power 1 CCGT unit 9.9MW

Singapore LNG Corporation 2 CCGT units 15.6MW

Generation Facilities Registered and De-registered in 2014

A total of five generating facilities were introduced in 2014. All were CCGT generatingfacilities with a total capacity of 461.8MW. The new generators brought the totalregistered capacity to 12,884MW at the end of 2014.

The two GT generating facilities that werede-registered in June were already de-rated to 0MW the year before. Thus theyhad no impact on registered capacity

in 2014.

Of the registered capacity in 2014,9,892MW or 76.8 percent belonged tothe CCGT/cogen/trigen category.

More CCGT generating units commissioned in 2014

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Supply YOY (%) MW YOY Change (%)Supply Cushion (%)

Supply YOY Supply Cushion Total Supply YOY ChangeSTCCGT/Cogen/Trigen GT

16.0

12.0

8.0

4.0

0.0

Supply and Supply Cushion Increases Accelerate in 2014

Supply cushion measures the percentageof total generation supply that is availableafter matching off forecasted demand.It is calculated by subtracting forecasteddemand from total supply, over total supply.If both supply and forecasted demand rise

in tandem, the supply cushion would thenremain constant.

Monthly Supply by Plant Type 2014

Steep rise in supply lifts supply cushion

Given that the growth in supply hassurpassed that of forecasted demand overthe years, the supply cushion has also risensteadily, averaging a 0.9 percent increaseper year from 2011 to 2013. In 2014,however, the increase was dramatically

larger than the preceding years – thesupply cushion rose 3.8 percent, from 26.2percent in 2013 to 30.0 percent in 2014.This was the highest level of supply cushionsince the market started, and it was the firsttime that the supply cushion reached the30-percent mark.

Total supply was significantly higher in2014, registering a 9.3 percent growthcompared to 2013. There was positive YOYsupply growth for all months, ranging from5.8 percent to 12.8 percent.

The shift to a CCGT-dominated marketcontinued to be reflected in the proportionof CCGT supply to total supply – in allmonths, CCGT supply made up at least95.0 percent of total supply, with YOYgrowth ranging from 9.0 percent to21.9 percent.

Supply stays above 7,500MW in all months in 2014

ST supply shrank further, with negative YOYgrowth for all months ranging from as lowas -75.2 percent to -47.9 percent. On anannual average, it made up only about1.7 percent of total supply.

In the months of September and October,total supply registered above the 8,000MWlevel, a new record in the history ofthe NEMS.

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2013 2014 Average for 2013 Average for 2014

MW

Monthly Generation Maintenance 2013 Versus 2014

Volatility in monthly generation maintenance increases

Although the annual average generationmaintenance levels in 2013 and 2014 weresimilar, the monthly maintenance profileswere disparate. Whilst 2013 had higherlevels of maintenance in the earlier andlater parts of the year, 2014 saw highermaintenance levels in the second and thirdquarters of the year.

The standard deviation of monthlygeneration maintenance in 2014 was248MW compared to 179MW in 2013.And while 2013’s monthly generationmaintenance levels ranged from 619MWto 1,203MW, 2014 saw a wider range ofbetween 475MW and 1,317MW.

The average ratio of generationmaintenance to registered capacitydecreased to 7.0 percent from 7.5 percent

in 2013. This was due to the higherregistered capacity while maintenancelevels were similar.

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Utilisation Rate (%)

60

50

40

30

20

10

0

Monthly CCGT/Cogen/Trigen Utilisation Rate 2014 Annual ST Utilisation Rate 2013 Annual CCGT/Cogen/Trigen Utilisation Rate 2013

Monthly ST Utilisation Rate 2014 Annual CCGT/Cogen/Trigen Utilisation Rate 2014 Annual ST Utilisation Rate 2014

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Monthly Utilisation Rate by Plant Type 2014

Flatter and lower utilisation rates for CCGT/cogen/trigen and ST plant types in line with strong supply conditions

The utilisation rate measures the scheduledenergy as a percentage of registeredcapacity.

For the third consecutive year, the annualCCGT/cogen/trigen utilisation rate fell

and averaged 56.2 percent, down from58.4 percent in 2013. Compared to 2013,the monthly utilisation rate in 2014 wasmore constant, with a narrower range ofbetween 54.3 percent and 57.9 percent(2013’s range was between 53.6 and 63.9percent). Additionally, while there werethree months in 2013 when the CCGT/cogen/trigen utilisation rate went above

60.0 percent, the highest CCGT/cogen/trigen utilisation rate in 2014 was only57.9 percent, occurring in June.

The annual ST utilisation rate was halvedagain in 2014. It fell from 20.1 percent in

2012 to 10.2 percent in 2013, and droppedfurther to 4.5 percent in the current year.This was not unexpected with the entranceof more efficient CCGT/cogen/trigengenerating facilities. ST generating facilitiesare generally more costly to operate, thusless likely to be dispatched.

The drop in utilisation rates underscoresthe situation of a well-supplied electricitymarket.

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MARKET PERFORMANCE: Energy Prices

USEPSupply Cushion BVP LVP

$/MWh Supply Cushion (%)

Monthly USEP, BVP, LVP and Supply Cushion 2014

USEP trades well below BVP and LVP benchmarks throughout the year

Starting from the third quarter of 2013,the LNG Vesting Price (LVP) and BalanceVesting Price (BVP) replaced the VestingContract Hedge Price (VCHP) as abenchmark against the USEP.

A certain percentage of the total allocatedvesting quantity is pegged to LNG, i.e.,Total Allocated Vesting Quantity = LNGVesting Quantity (pegged to LNG) +Balance Vesting Quantity (pegged to pipednatural gas). Correspondingly, the LVP isthe price for the LNG Vesting Quantityallocated, while BVP is the price for theBalance Vesting Quantity allocated.

Against the backdrop of a well-suppliedmarket, the monthly average USEP tradedbetween $93/MWh and $156/MWh in2014. This was significantly lower than2013, when the range was between$147/MWh and $201/MWh.

The BVP7 maintained a large buffer thataveraged 28.0 percent above the USEP forthe year. The closest that the USEP came toreaching the BVP was in July, but even then,it was still a considerable $34.49/MWh or18.1 percent below the BVP.

The highest monthly average USEP in2014 was $156/MWh in July, alongsideforecasted demand which also peakedat 5,700MW. Correspondingly, thesupply cushion was at its lowest point at27.7 percent. The USEP then started itsdownward trend in August when itdropped 9.8 percent to $140.46/MWh,before sliding further for another four

consecutive months to reach its lowestpoint of $92.59/MWh in December.The proportions of offers priced below$100/MWh were notably higher inNovember and December at 65.9 percentand 71.0 percent respectively.

7 Average of BVP in 2014 was $190.04/MWh; averageof LVP in 2014 was $196.02/MWh.

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$/MWh MW

Forecasted DemandGeneration Supply USEP

Daily USEP, Forecasted Demand and Generation Supply 2014

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Point F:On 4 and 5 November, the average dailyprices were at the highest and secondhighest levels of $358/MWh and$265/MWh respectively. GT wasscheduled for 11 periods on 4 November(Periods 24 to 34) and three periods on 5

November (Periods 22 to 24).

Over the two days, there were 21 periodswhen the USEP rose above $500/MWh,with 14 periods falling on 4 Novemberand seven periods falling on 5 November.The high prices corresponded with thefollowing observations: four CCGT facilitiesand one steam turbine of another CCGTwere on maintenance on both days (totalCCGT capacity on maintenance was765.5MW or 5.9 percent of total registeredcapacity); security constraint limits were

tightened due to the scheduled maintenancework on a constrained transmissionline from Period 18 on 1 November toPeriod 17 on 6 November; on the dayswhen the lower security constraints wereimposed, forecasted demand peakedcorrespondingly, on 4 and 5 November;and finally, offer changes in the affectedperiods also resulted in the MCE clearing athigher prices.

The key observations on some of the dailyspikes in the USEP in 2014 (higher than$210/MWh) are as follows:

Point A:On 2 January, the daily USEP averaged$220/MWh. A forced outage of a CCGT

facility that occurred in Period 21 loweredsupply in the next period by more than5.0 percent and caused the supply cushionto fall from 23.0 percent to 17.0 percent.The USEP spiked above $700/MWh inPeriods 22 and 23. Another forced outageof a generating unit occurred in Period 29,lifting the USEP to the day’s peak of$732/MWh with interruptible load (IL)activated for contingency reserve forPeriods 29 and 30. In total, there were14 periods that day when the USEP roseabove $300/MWh (Periods 22 to 35). GT

was scheduled for these 14 periods.

Point B:On 4 April, the daily USEP averaged$264/MWh. A CCGT outage in Period 1,along with two other CCGT facilities beingon maintenance (total CCGT capacity onmaintenance was 733MW or 5.7 percent oftotal registered capacity), dampened supplyavailability. Forecasted demand strengthenedfrom Period 16, when it increased by249MW from Period 15’s 5,405MW andclimbed at an average of about 80MWper period, until it reached the day’s peakof 6,523MW in Period 29. In the sametime frame, the supply cushion fell from25.8 percent in Period 15 to levels below20.0 percent. Only in Period 37 did thesupply cushion climb back above 20.0percent. There was no IL activation, but GTwas scheduled for 15 periods (Periods 19to 24, and Periods 27 to 35).

Point C:On 26 April, three CCGT facilities wereon maintenance (total CCGT capacity onmaintenance was 1,199MW or 9.3 percentof total registered capacity). A CCGTforced outage in Period 30 dragged supplylower. As the supply cushion retreated

below 20.0 percent, the USEP rose from$164/MWh in Period 30 to $809/MWh inPeriod 31. IL was ac tivated for contingencyreserve in Period 30 with GT scheduled for15 periods (Periods 23 and 24, and Periods31 to 43). There were 8 periods that daywhen the USEP rose above $300/MWh.The daily average USEP was $237/MWh.

Point D: On 4 July, two CCGT facilities were onscheduled maintenance, and another CCGTwas unable to return from maintenanceas scheduled (total CCGT capacity onmaintenance was 1,100MW or 8.5 percentof total registered capacity). Separately,the forced outage of another CCGT thatoccurred in Period 23 propelled the USEPto $556/MWh in Period 24, and theUSEP remained above $500/MWh forthe next two periods. The supply cushionalso fell from 20.6 percent in Period 23to 18.1 percent in the following period,and it stayed be low 20.0 percent untilPeriod 36. IL was activated for contingencyreserve in Periods 23 and 24 and GT wasscheduled for a total of 15 periods (Period24, Periods 26 to 36 and Periods 41 to43). Contingency reserve violation was alsorecorded in Periods 24 to 31. This violationwas due to a newly implemented StepwiseConstraint Violation Penalty (CVP), wherethe Market Clearing Engine (MCE) wouldchoose to “violate” reserve requirements ifthe cost of violating them is less than that

of scheduling more expensive offers in themarket, thereby lowering overall cost to themarket. The USEP for the day averaged$218/MWh.

A security constraint limit of 1,450MWapplied to four lines between Jurong Pier

and the Upper Jurong and Tuas areasreached its limit in Periods 41 to 43.

Point E:On 16 July, forecasted demand was oneof the drivers for the high USEP. Besideshitting the fifth highest daily level in the

year, volatility in the forecasted demand(there were 16 periods when forecasteddemand rose above 6,500MW – fromPeriod 20 to Period 35) also contributed tothe high prices. A CCGT tripping in Period16 triggered the higher prices, bringing

the supply cushion down to 19.6 percent inPeriod 18 from 24.8 percent in the previousperiod. IL was activated for contingencyreserve in Periods 16 and 17, and GT wasscheduled for four periods (Period 19 andPeriods 29 to 31). The USEP averaged$258/MWh for the day.

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Security Constraint 2 (MW)

Period with Security Constraint 2 Binding

Security Constraint 1 (MW)

Period with Security Constraint 1 Binding Max MNNMin MNN USEP

$/MWhSecurity Constraint Limit (MW)

Application of Security Constraints in 2014

In light of the commissioning activities since2013, the PSO continued to implementsecurity constraints in 2014. This is inline with the view expressed in the EMApolicy paper published in 2011 titledDevelopments in the Singapore ElectricityTransmission Network 8 – that newgeneration facilities could lead to excesssupply in the network, particularly duringthe early years of the new plantings. Thesecurity constraints were applied to theSouth-West Block of the transmission grid,which is where most of the new generatingfacilities in 2013 and 2014 are located.

Security constraints were applied fromPeriod 26 on 24 April to Period 48 on 31December, totalling 12,071 periods or 68.9percent of the year. This was higher thanin 2013 when a security constraint wasapplied for 55.6 percent of the year. Outof the 12,071 periods in 2014 when thesecurity constraints were in place, securityconstraint limits were reached (situationsknown as security constraint binding) for atotal of 55 periods, or 0.5 percent of thetotal periods with the security constraintsapplied. This was lower than in 2013, whensecurity constraint binding was observedin 131 periods or 1.3 percent of the totalperiods with the security constraint applied. 8 Sourced from EMA website, policy paper #2 published

on 5 April 2011.

The first security constraint which commencedon 24 April consisted of a 1,150MW limiton three lines in the Jurong Island area(Security Constraint 1). On 4 July, anothersecurity constraint limit of 1,450MW onfour different lines was implemented inthe Jurong Pier to Upper Jurong and Tuasareas (Security Constraint 2). Periodically,whenever any of the affected transmissionlines were on scheduled maintenance, thePSO modified these two security constraintsby tightening the limits or changing thenumber of lines subject to the constraint, orboth. The security constraint limits variedfrom 300MW on a single line to 1,450MWon four lines.

Typically, the difference betweenthe minimum and maximum MarketNetwork Nodal (MNN) prices is lessthan $10/MWh, but this widens when thesecurity constraint limit is reached. Thecharts above show the periods in 2014when security constraint binding took place,and the associated minimum and maximumMNN and USEP prices. There were severalperiods across five days (24 April, 16 July,27 August, 4 November and 15 November)when the differences between the maximumand minimum MNN prices exceeded$100/MWh.

Security Constraint Limit with Security Constraint Binding Security Constraint Binding Periods with Minimum and MaximumMNN Prices and USEP

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MARKET PERFORMANCE: Ancillary Markets

$ Million

Annual reserve payment drops to lowest level since 2008

Reserves serve as a backup in theelectricity market to unexpected outages

caused by generators tripping. The amountof reserves required is determined by theamount needed should the largest on-linegenerator trip. In the NEMS, three reserveproducts are traded: primary, secondaryand contingency reserves. Each reservehas its own price and response time, thelatter being 8 seconds for primary reserve,30 seconds for secondary reserve and10 minutes for contingency reserve. Thegenerators bear the cost of providing thereserves.

The reserve payment in 2014 wasabout 19.0 percent lower than 2013,at $51.4 million. This is the lowest levelseen since 2008 when the reserve paymenttotalled $31.6 million. The contingencyreserve price drop in the year wasgreater than the price increases seen inthe primary and secondary reserves. In2014, contingency reserve price fell by$2.93/MWh compared to the year before,while the price increments for primary andsecondary reserves were only $0.16/MWhand $1.60/MWh respectively.

The two largest monthly reserve paymentstook place in January and August at

$6.8 million and $6.1 million respec tively.These corresponded with the contingencyreserve’s highest monthly prices whichwere $10.93/MWh in January and$10.60/MWh in August.

Annual Reserve Payment 2010 – 2014

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Monthly Secondary Reserve Price, Requirement and Supply 2014

MW $/MWh

Offer capacity at and above $5/MWhOffer capacity below $5/MWhRequirement

Price

MW $/MWh


Price

10

8

6

4

2

0

Monthly Primary Reserve Price, Requirement and Supply 2014

Primary reserve price rises as reserve requirements increase and offeravailability shrinks

In 2014, the monthly primary reserve pricewas marginally higher and averaged$1.67/MWh, compared to $1.50/MWhin 2013. The main causes were a higherprimary reserve requirement and loweroffer availability. The primary reserverequirement was 4.6 percent higher in2014 than the previous year, while primaryreserve offers were 5.1 percent lower.Primary reserve offers in the price tranchebelow $5/MWh were about 3.1 percentlower in 2014 compared to 2013.

There were no changes to the RiskAdjustment Factor (RAF)9 in 2014. It wasset at 1.0 for all three classes of reserves.

9 There is a RAF for each class of reserve in the NEMS.The RAF is multiplied by the raw reserve requirement toarrive at the final reserve requirement that is cleared bythe market clearing engine (MCE). The PSO may amendthe RAF for any reserve class temporarily if it foreseespower system conditions that may warrant a higher reserverequirement than usual.

The highest monthly primary reserveprice observed was in February whenthe primary reserve requirement peakedat 208MW. From April onwards, priceswere below $2.00/MWh as reserverequirements slipped below 200MW.

2014’s increase in primary reserve pricewas much smaller compared to 2013’s riseto $1.50/MWh from $0.46/MWh in 2012.

Secondary reserve price mirrors primary reserve price movements

The monthly average secondary reserveprice in 2014 of $4.70/MWh was51.8 percent higher compared to the$3.10/MWh in 2013. Similar to primaryreserve, the secondary reserve requirementwas higher by 1.3 percent, with the highestrequirement seen in February at 285MW.Secondary reserve offers were lower by5.8 percent, while offers priced below$5/MWh were 4.7 percent lower thanin 2013.

The highest monthly secondary reserveprice of $9.44/MWh was seen in February,when the secondary reserve requirementwas almost at the same level as theamount of secondary reserve offers pricedbelow $5.00/MWh. In all other months,the amount of offers in the price tranchebelow $5.00/MWh exceeded the reserverequirement.

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MW $/MWh


Price Instances of IL activation No. of periods of IL activation

Count

Monthly Contingency Reserve Price, Requirement and Supply 2014

Contingency reserve price retreats on lower price volatility and lowerreserve requirement

The monthly average contingency reserverequirement was lower by 1.4 percentin 2014 compared to 2013. The monthlycontingency reserve requirement was alsomore stable, ranging between 573MWand 589MW compared to 2013 whenit fluctuated between 549MW and605MW. Although contingency reserveoffers in 2014 were 10.5 percent higheroverall, there was minimal change in theoffers priced below $5.00/MWh, whichwere 0.5 percent lower than in 2013.The monthly contingency reserve priceaveraged $6.20/MWh, lower than 2013’saverage of $9.12/MWh.

Both the highest and lowest monthlycontingency reserve prices in 2014were lower than 2013’s respective levels.The highest monthly average price in2014 was registered in January at$10.93/MWh, while the lowest monthlyaverage price was seen in April at$1.93/MWh.

Annual Interruptible Load (IL) Activations for Contingency ReserveMarket 2010 – 2014

Instances and number of periods of IL activation decline in 2014

Total IL registered capacity increasedin 2014. For primary and secondaryreserves, the total IL registered capacityincreased from 21MW in 2013 to23.2MW in 2014 as a result of increasedcapacity for an existing facility.

For contingency reserve, on top of theincreased capacity for the existingfacility, a new facility of 2.2MW wasalso introduced. This raised the totalIL registered capacity for contingencyreserve to 25.2MW, up from 21MWin 2013.

Like the previous year, IL was not activatedfor primary and secondary reserves in2014. The number of IL activations forcontingency reserve in 2014 was 15, whilethe total number of periods when IL wasactivated was 36. June had the highestconcentration of IL activations by numberof periods, with 12 of the total 36 periodsoccurring in the month.

Typically, each IL activation lasted onlytwo periods. The only exception wason 3 June, when IL was activated for 11periods.

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Statistics exclude IL providers.Note: The percentages in this chart may not add up to 100% due to rounding.

A B C D E

%

Tuas Power Genera tion Inc inera tion Plants Embedded Genera tors*

Keppel Merlimau Cogen Sembcorp Cogen YTL PowerSeraya Senoko Energy

TP UtilitiesGeneration units subject to failure probability PacificLight Power

Instances of Forced Outage No. of Generation Units

The number of generation units refers to the number of generation units registered in the NEMS which are subject to reser veresponsibility share.*Embedded generators exclude TP Utilities

100.0

80.0

60.0

40.0

20.0

0.0

Reserve providers in the NEMS are classifiedinto five groups, with Group A reflectingreserve providers with the highest level ofresponsiveness and Group E reflecting those

with the lowest level of responsiveness. Ahigher level of responsiveness attracts ahigher proportion of reserve price.

Ratings for primary and secondaryreserve providers fell for the secondtime since 2012, when the concentrationof these reserve providers in Group Awas the highest. In 2014, there were 12changes to the reserve provider group

effectiveness ratings, out of which onewas an improvement and the rest weredowngrades. Of the 11 downgrades, fourwere moved down by more than one grade

(for example, from Group A to GroupC). In addition, one reserve provider wascategorised in Group E compared to nonein 2013.

All contingency reserve providers wereclassified in Group A.

Reserve Provider Group Effectiveness for Primary and SecondaryReserve Classes (Aggregate) 2010 – 2014

Reserve provider group effectiveness declines for the second year

Annual Forced Outages by Generation Companies 2010 – 2014

Total forced outages drop in 2014

There were a total of 121 forced outagesin 2014. This was a decline from the 141outages in 2013 which was the secondhighest number of forced outages since the

market started.

Collectively, the number of forced outagesfrom Keppel Merlimau Cogen, SenokoEnergy and PacificLight Power in 2014dropped by 36 compared to the previous

year. This contributed to the overall declinein the number of forced outages in 2014.

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%

ST GTCCGT/Cogen/Trigen

GT failure probability for 2010 was 1.302 percent

Average Failure Probability by Year 2010 – 2014

Higher CCGT failure probability in Q1 2014 raises average for the year

The average failure probability for aGeneration Registered Facility (GRF) is the

probability that after being dispatched bythe PSO for a settlement interval, the GRFwill cease operating, disconnect from thetransmission system, or both during thatsettlement interval, even if no other GRFfails. A generation facility with a lowerfailure probability will be allocated lessreserve cost compared to one with a higherfailure probability.

In 2014, the average failure probabilityfor CCGT/cogen/trigen rose to 0.057percent10, up from 0.048 percent in 2013.

This was due to a high failure probabilityvalue in the first quarter (Q1) of 2014 at0.099 percent.

Failure probability values are calculatedbased on past values11, so some lag exists.

The failure probabilities for the quartersfollowing Q1 2014 were markedly lower asan increasing portion of the forced outagedata used in the calculations came from2014 which had a lower level of forcedoutages compared to 2013. The CCGT/cogen/trigen failure probability declined to0.056 percent in Q2 2014, 0.042 percentin Q3 2014, and 0.031 percent in Q42014.

The average failure probability for STdeclined from 0.189 percent in 2013 to

0.024 percent in 2014, while that of GTdropped from 0.250 percent in 2013 to0.001 percent (the lowest possible number)in 2014.

10 For an average of 10,000 half-hourly periods,CCGT/cogen/trigen incurred 5.7 t rips.

11Q1 2014 failure probability was calculated usingforced outage data between 1 December 2012 and30 November 2013; Q2 2014 failure probability wascalculated using forced outage data between 1 March2013 and 28 Febr uary 2014; Q3 2014 failure probabilitywas calculated using forced outage data between 1 June2013 and 31 May 2014; Q4 2014 failure probabilitywas calculated using forced outage data between

1 Septembe r 2013 and 31 August 2014.

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$ Million

Offer capacity at and above $30/MWhOffer capacity below $30/MWh

Price Requirement

MW $/MWh

Regulation payment in 2014 stood at$32.5 million, a stark contrast from the$87.6 million in 2013 when regulationpayment was at the second highest levelsince the market started (the highestregulation payment of $108.3 millionoccurred in 2007). This was the lowestregulation payment seen since 2008 whenthe amount was $27.5 million.

Regulation payment in January was$5.5 million. After the new regulationrequirement took effect from 1 February,the average regulation payment fromFebruary to December was only$2.5 million.

Regulation payment falls along with lower regulation price and requirement

Monthly Regulation Price, Requirement and Supply

Regulation price falls on smaller regulation requirement

Regulation price in 2014 plummeted 58.5percent to an average of $33/MWh, downfrom $80/MWh the year before. Month-to-month, prices moved within a tight rangewith the lowest regulation price seen inOctober at $11.78/MWh, and the highestseen in January at $57.59/MWh.

2014’s regulation requirement, which tookeffect from 1 February, was 19.4 percentlower than the year before. Regulationoffers in 2014 were also about 4.0 percenthigher than in 2013.

Annual Regulation Payment 2010 – 2014

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MARKET PERFORMANCE: Competition in the Generation and Retail Markets

%

2010 2011 2012 2013 2014

*Embedded generators exclude TP Utilities

Annual Market Share by Generation Company 2010 – 2014 (Based on Scheduled Generation)

2014 saw shifts in market share that were,to a large degree, an extension of themovements in 2013. The market share ofthe largest players continued to erode,and that of smaller market participantsincreased. PacificLight Power, which fielded

two generators in June and August 2013,saw its market share rise from 1.1 percentin 2013 to 8.5 percent in 2014. SembcorpCogen’s third generator, which came onlinein March 2014, lifted its market sharefrom 8.5 percent in 2013 to 9.7 percentin 2014, after two consecutive years ofdecline. TP Utilities, which commissionedits second generator in May 2014, saw itsmarket share rise modestly to 1.6 percentfrom 1.1 percent in 2013.

Of the three largest market participants,YTL PowerSeraya saw its market share slipfor the fourth consecutive year, to 18.4percent. Senoko Energy’s market sharedropped from 27.0 percent in 2013 to 22.9percent in 2014.

More market participants bring about greater competition

While Senoko Energy remained the largestgeneration company by market share, thedrop in its market share was significant asit was the first time since the market startedwhen no single generation company had ahold of at least a quarter of the total market

share.

Tuas Power Generation gained slightlyas its fifth CCGT facility which cameonline in May 2013 had a strongerpresence in 2014. Collectively, the threelargest generation companies (SenokoEnergy, Tuas Power Generation and YTL

PowerSeraya) held a 61.5 percent of themarket share, down f rom 69.7 percentin 2013.

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MARKET PERFORMANCE: Competition in the Generation and Retail Markets

2010 2011 2012 2013 2014

%

Annual Market Share of Market Support Services Licensee and Retailers 2010 – 2014 (Based on Withdrawal Energy Quantity)

In 2014, PacificLight Energy garnered3.7 percent of the retail market, whileSembcorp Power, Tuas Power Supply andSenoko Energy Supply also saw mildincreases. The largest drop was seen inKeppel Electric’s market share, which fell to

13.2 percent from 16.3 percent in 2013.

Also notable was the drop in the marketshare of SP Services, to 33.3 percent from36.1 percent in 2013. In line with the movetowards full retail contestability, the EnergyMarket Authority lowered the threshold toqualify for contestability in 2014 twice:

once in April when the threshold waslowered to 8,000kWh from 10,000kWh,and again in October when the thresholdwas further reduced to 4,000kWh.This would enable more commercialor industrial consumers to choose theirretailers.

Contestable consumers enjoy a bigger pool of retailers

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MARKET PERFORMANCE: Settlement and Prudential Management

Energy Market Company (EMC) isthe financial clearing house for thewholesale market and settles the followingtransactions:• energy;• ancillary market products – three

classes of reserve (primary, secondary

and contingency) and regulation;• bilateral and vesting contracts;• uplift charges;• financial adjustments;• fee recovery of EMC and the PSO

administration costs; and• contracted ancillary services not

provided through the ancillary market(black-start services).

The market is well-secured. To cover theexposure of a debtor and the time requiredto manage a default, all retailers must

provide on-going collateral to EMC. Thiscredit support protects EMC and other MPsfrom payment defaults. EMC reviews therisk exposure of MPs on a daily basis.

A margin call is issued when a retailer’sestimated exposure reaches a value equalto or greater than 70 percent of the level ofits credit support. In 2014, EMC issued 20margin calls, and all were met within therequired time frame of two business days.

In 2014, the value of total retail settlementpayments (net of bilateral offsets) was$3.47 billion and the value of creditsupport on 31 December 2014 was$416.6 million.

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MARKET PERFORMANCE: Contracted Ancillary Services

Contract Period Cost of Ancillary Services Total MW Contracted

01 April 2014 to 31 March 2015 $15,342,803.62 88.848

In addition to the co-optimised reserve andregulation markets, EMC negotiates andenters into ancillary services contracts on

behalf of the PSO, to ensure the reliableoperation of Singapore’s power system. Ifthese services are unable to be procuredcompetitively, for example, due to a limitednumber of available suppliers, their pricesare regulated.

From 1 April 2014 to 31 March 2015,the only contracted ancillary servicerequired was black-start capability. Black-start service ensures that there is initialgeneration to supply electric power forsystem restoration following a complete

blackout.

Based on the PSO’s operationalrequirements, EMC procured 88.848MWof black-start service at a cost of $15.34

million. The capability was sourced fromYTL PowerSeraya, Senoko Energy, TuasPower Generation and Keppel MerlimauCogen.

Contracted Ancillary Services 1 April 2014 to 31 March 2015

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MARKET PERFORMANCE: Market Fees

Total Fees$’000

Fees/MWh*$

EMC Net Fees 24,521 0.2757/0.2700

PSO Net Fees 20,421 0.2277

Total Fees 44,942 0.5034/0.4977

Supplier Service Method of Assessment

SP PowerAssets Transmission charges Levied based on actual usage

SP Services (MSSL) Meter reading and datamanagement

Levied on a per meter basis

The costs associated with the wholesalefunctions of the NEMS are recovereddirectly from the wholesale market or from

MPs and consumers.

EMC and PSO fees are recovered fromboth generator and retailer class MPs inproportion to the quantity of energy that

they trade.

EMC Net Fees and PSO Fees Recovered Directly from the NEMS– 1 April 2014 to 31 March 2015

*The full year volume at 89,678MWh is based on the budget for the year approved by the RCP and EMA. EMC’s adminfees were reduced f rom $0.2757/MWh to $0.2700/MWh from 1 Novemb er 2014.

Fees Recovered Directly from MPs and Consumers

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ADDITIONALINFORMATION

ADDITIONAL INFORMATION Gl


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ADDITIONAL INFORMATION: Glossary

ancillary servicesThe additional services necessary to ensurethe security and reliability of the powersystem. The ancillary services tradedcompetitively on the wholesale marketare regulation and the three classes ofreserve. The black-start ancillary service

is contracted by Energy Market Company(EMC) on behalf of the Power SystemOperator (PSO) on an annual basis.

balance vesting priceThis refers to the price for the balancevesting quantity allocated.

balance vesting quantity With the start of the Liquefied Natural Gas

(LNG) Vesting Scheme in the third quarterof 2013, a certain percentage of the totalallocated vesting quantity is pegged toLNG. The remaining percentage peggedto piped natural gas is known as balancevesting quantity.

black-start ancillary serviceA service to ensure that there is initialgeneration for system restoration followinga complete blackout.

contestable consumersConsumers that have the right to choose topurchase electricity from a retail supplier,directly from the wholesale market, orindirectly from the wholesale marketthrough the Market Support ServicesLicensee (MSSL), SP Services. Consumers

qualify to be contestable based on theirlevel of electricity consumption.

co-optimisationThe process used by the market clearingengine (MCE) to ensure that the mostinexpensive mix of energy, reserve andregulation is purchased from the market tomeet electricity demand in each dispatchperiod.

dispatch scheduleA schedule produced by the MCE everyhalf-hour that is the basis for the supplyof energy, reserve and regulation in themarket.

embedded generators (EG)Generation units that generate electricityto their onsite load principally for selfconsumption.

energy The flow of electricity.

gigawatt (GW)A measure of electrical power equivalent toone thousand megawatts. Gigawatt hour(GWh) represents the number of gigawattsproduced or consumed in an hour.

interruptible load (IL)A contestable consumer of electricitythat participates in the wholesale marketand allows its supply of electricity tobe interrupted in the event of a systemdisturbance in exchange for reservepayment.

lng vesting priceThis refers to the price for the LNG vestingquantity allocated.

lng vesting quantity With the start of the LNG Vesting Schemein the third quar ter of 2013, a certainpercentage of the total allocated vestingquantity is pegged to LNG. This is knownas the LNG vesting quantity.

loadThe consumption of electricity.

market clearing engine (MCE)The linear programme computer applicationused to calculate the spot market quantitiesand prices.

market participant (MP)A person who has an electricity licenceissued by the Energy Market Authority(EMA) and has been registered with EMCas a market participant.

megawatt (MW)A measure of electrical power equivalent toone million watts. Megawatt hour (MWh)represents the number of megawattsproduced or consumed in an hour.

metered demandMetered demand is the electricityconsumption which is proxied by thewithdrawal energy quantity (WEQ).

nodal pricingA market structure in which prices arecalculated at specific locations, or nodes,in the power system to reflect the demandand supply characteristics of each location.Nodal pricing is also commonly referred toas locational marginal pricing.

non-contestable consumersConsumers that are supplied by the MSSL,

SP Services, at a regulated tariff. Theseconsumers have not been given the right tochoose to purchase electricity from either aretail supplier, directly from the wholesalemarket or indirectly from the wholesalemarket through the MSSL, SP Services.

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ADDITIONAL INFORMATION: Glossary

regulationGeneration that is on standby to fine-tunethe match between generation and load.

reserveStand-by generation capacity or

interruptible load that can be drawn uponwhen there is an unforeseen disruption ofsupply.

retail market The transactions made between retailcompanies and end consumers.

supply cushionThe supply cushion measures the

percentage of total supply available aftermatching off demand.

terawatt (TW)A measure of electrical power equivalentto one million megawatts. Terawatt hour(TWh) represents the number of terawattsproduced or consumed in an hour.

uniform singapore energy price

(USEP)The USEP is the weighted-average of thenodal prices at all off-take nodes.

vesting contract A vesting contract is a regulatory instrumentimposed on some generators by the EMA,with the objective of mitigating the potentialexercise of market power when the supplyside of the industry is concentrated amonga small number of generators. A vesting

contract requires these generators toproduce a specified quantity of electricity(vesting contract level) at a specified price(vesting contract hedge price).

vesting contract hedge price (VCHP)The VCHP is calculated by the MSSLevery three months. It is determined usingthe long-run marginal cost (LRMC) of themost efficient generation technology inthe Singapore power system, i.e., the

combined-cycle gas turbine (CCGT). EMC’ssettlement system uses the VCHP to settlethe vesting quantity between the MSSLand the generation companies. With theintroduction of LNG into the generationmix, the VCHP has been replaced by ‘LNGvesting price’ and ‘balance vesting price’from July 2013.

withdrawal energy quantity (WEQ)Withdrawal energy quantity (in MWh)refers to the amount of electricity withdrawnby load facilities. It is provided by theMSSL.

wholesale market The transactions made between generationcompanies and retail companies.

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ADDITIONAL INFORMATION: Market Entities’ Contact Details

Generator Licensees ExxonMobil Asia PacificKeppel Merlimau CogenKeppel Seghers Tuas Waste-To-Energy Plant (in its capacity as Trustee ofTuas DBOO Trust)National Environment AgencyPacificLight PowerSembcorp CogenSenoko Energy

Senoko Waste-To-Energy (in its capacity as Trustee of Senoko Trust)Shell Eastern PetroleumTP UtilitiesTuas Power GenerationTuaspringYTL PowerSeraya

www.exxonmobil.com.sgwww.kepinfra.comwww.keppelseghers.com

www.nea.gov.sgwww.pacificlight.com.sgwww.sembcorp.comwww.senokoenergy.com.sg

www.kepinfra.comwww.shell.com.sgwww.tputilities.com.sgwww.tuaspower.com.sgwww.hyflux.comwww.ytlpowerseraya.com

Retailer Licensees CPvT Energy AsiaDiamond Energy SupplyHyflux EnergyKeppel ElectricPacificLight EnergySembcorp PowerSenoko Energy SupplySeraya EnergyTuas Power Supply

www.cpvtenergy.comwww.diamond-energy.com.sgwww.hyflux.comwww.keppelelectric.comwww.pacificlight.com.sgwww.sembcorp.comwww.senokoenergy.com.sgwww.serayaenergy.com.sgwww.tpsupply.com.sg

Wholesale Market Traders Air Products SingaporeBanyan UtilitiesCGNPC Solar-Biofuel Power (Singapore)CPvT Energy AsiaDiamond EnergyECO Special Waste ManagementGlaxo Wellcome Manufacturing – GlaxoSmithKline BiologicalsGreen Power AsiaMSD International GmbH (Singapore Branch)Pfizer Asia PacificSingapore LNG CorporationSingapore Oxygen Air LiquideSunseap Leasing

www.airproducts.com.sg

www.cgnsedc.com.cnwww.cpvtenergy.comwww.diamond-energy.com.sgwww.eco.com.sgwww.gsk.comwww.greenpowerasia.comwww.msd-singapore.comwww.pfizer.com.sgwww.slng.com.sgwww.soxal.comwww.sunseap-leasing.com

Market Operator Energy Market Company www.emcsg.

NEMS Market Report 2014

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