WESM 101

WESM 101

The Philippine Power MarketThe EPIRA reform agenda promote competition and choice1970198019902000Institutional reforms: ERC, PSALM, Transco, etc (2001)Separation of generation from transmission (2003)Creation of WESM (2006)Privatization of NPC generation (2006)Competition in generation (2006)Transmission privatizationthru NGCP (2008)Retail Competition and Open Access (2013)State monopoly in generation and transmissionPower Supply CrisisPrivate sector participation in power generation with oligopsony by NPC and MeralcoElectric Power Industry Reform Act

The Philippine Power Market:Value Chain has evolved under EPIRA*3GenerationOpen & competitiveERC requires that it approves the PSA for a DUs captive customersOperates under WESM No cross-ownership in TransmissionNo company can own, operate and control 30% of installed capacity of any grid, or 25% of the national capacityTransmissionFranchised & Regulated common carrier businessSubject to rate-setting powers of the ERCNational Grid Corporation of the Philippines (private consortium)Open access transmission systemNo cross ownership in generation and /or distribution

DistributionFranchised & Regulated common carrier businessSubject to rate-setting powers of the ERCNon-discriminatory distribution open accessNo cross-ownership in Transmission

Local RESDU business segment; can sell to Contestable Customers in franchise area only

Retail Electricity Supplier (RES)ERC licensedContestable MarketEnd-users with demand >=1 MWContestability threshold reduces to 750 kW by Jul 2016 and to 500 kW by Jul 2018

Captive MarketEnd-users with demand Price G10 MWh

The WESMNodal Pricing: Line Rental from CongestionG1200 MWLoadG2100 MWSending NodeReceivingNodeWhen transmission limitations occur, the SO may be constrained to re-dispatch a more expensive GeneratorLine rental also compensates for the additional cost from a higher priced Generator to maintain load supply

24 MWhTransmission Capacity = 200 MW but subsequently restricted to 80 MWTransmission loss = 5%80 MWhTransmission Loss = 4 MWh100 MWhPrice G2 > Price G1

The WESMNodal Pricing: Line Rental Trading AmountLine Rental Trading Amount (LRTA) = difference between the customer ex-ante nodal price and the generator ex-ante nodal price multiplied by the Bilateral Contract Quantity (BCQ) G1LoadSending NodeReceivingNodeBCQ Line Rental = BCQ x (LMPReceiving - LMPSending)

Line Rental = BCQ x (EAPL EAPG)

The WESMNodal Pricing: Line Rental from Transmission LossesG1200 MWLoadG2100 MWSending NodeReceivingNodeTransmission Capacity = 200 MWTransmission loss = 5%100 MWh+ 5 MWhOffer:P 4000/MWhTransmission Loss = 5 MWh100 MWh0 MWhOffer: P 5000/MWhLMPG = P 4000/MWhLMPL = P 4200/MWh(= 4000 * 105/100)Load does not have PSATrading Amount: Load= TA + LR= 100 MWh x P 4200/MWh + 0 MW x P 200/MWh= P420,000

Settlement outside WESM= P 0.00Trading Amount: Generator= 105 MW x P 4000/MWh= P420,000

Settlement outside WESM= P 0.00Load has 100 MW PSATrading Amount: Load= TA + LR= 0 MWh x P 4200/MWh + 100 MW x P 200/MWh= P 20,000

Settlement outside WESM= 100 MWh x PSA PriceTrading Amount: Generator= (105-100)MWh x P 4000/MWh= P 20,000

Settlement outside WESM= 100 MWh x PSA Price

The WESMActual Operations: The spot market is volatile

* Hydrology assumed at 30% capacity factor** YTD peak demand for 2014 is 8,717 (5.2% growth vs 2013)

Avg. peak demand2014 Peak Demand (8,717 MW)Pmin, Price Taker (Zero Bids) and MRUAvg. Off-peak demand$/MWhThe WESMActual Operations: Lack of mid-merit plants in supply stack gestates volatility48

Range of daily dispatch

The volatility of the spot prices may be explained by this chart. It shows the stack of bid quantities and prices, About 5400 MW of capacity are offered at price of zero because these capacity are the Pmins (which is the minimum stable loading for a plant), the price-takers (which are generators with take-or-pay fuel or on physical PSAs such as the natural gas plants), and Must-Run-Units (those dispatched by the System Operator for security or power quality requirements).The average off-peak demand ranges from 5400 to 6400 MW which requirement is supplied from coal plantsThe average peak demand ranges from 6400 to about 8700 MW and supplied from three distinct fuel groups: coal up to 7700 MW, then a short stack of natural gas of about 200 MW, and thence the balance from oil based plants starting at 7900 MW.Volatility arises from the lack of a mid-merit cost plant because the Natural Gas plants are price takers consequent to their take-or-pay fuel contracts and physical PSAs. Thus, an outage of a base-load plant makes the market clear immediately from coal price to oil price.Moreover, a disruption of the Malampaya NG facility which supplies the 2700 MW natural gas plants always causes price spikes because oil plants set the clearing prices.

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The WESMActual Operations: The market is highly contracted.4949

Monthly 2011-2013 Luzon Energy and Peak Demand Luzon Energy offers, Actual demand, and System LWAP (average)

Market Transaction Mix - 100% stacked columnMarket Transaction Mix - stacked column

The WESMActual Operations: Market Concentration Index - Herfindahl-Hirschman Index50Herfindahl-Hirschman Index (2010-2013)

The WESMActual Operations: Market Concentration Index - Residual Supply Index51Hourly Market Residual Supply Index Based on Offered Capacity of Generators (2010-2013)

Monthly Market Residual Supply Index Based on Offered Capacity of Generators (2010-2013)A Market RSI less than 100% indicates the presence of pivotal generator(s) in a period. A generator that frequently sets the price may have greater opportunities to design bidding strategies to influence the pricesRSI < 100%Presence ofPivotal Generator(s)

RSI correlates with PSI, where lower RSI denotes a higher number of pivotal suppliers. The figure shows the hourly trend of the market RSI for the period in review. In general, the market demonstrated a robust environment during the said period as indicated by the high percentage of time that the Market RSI exceeded the 100% mark, indicating the absence of pivotal generators most of the time. The frequency by which the Market RSI exceeded 100% was highest in August 2012, which was attributed to improved supply conditions due to fewer plant outages and increased availability of hydro-electric plants. It also helped that demand for electricity during the month was relatively lower resulting in wider supply margin. It was observed that the percentage of time with RSI above 100% was higher during certain billing months when the market manifested better supply and demand conditions. On the other hand, the frequency by which the market RSI values exceeded the 100% markwas lower during tight demand and supply conditions such as those experienced during the billing months of July and December 2012 and April and May 2013. In particular, the July 2012 billing month had the lowest number of RSI values falling above the 100% mark indicating tight supply conditions due to the outages of coal plants and the nonavailability of the Ilijan plant brought about by the Malampaya gas facility maintenance. Further, the April and May 2013 billing periods likewise yielded lower RSI values as supply was insufficient to meet the higher demand for electricity, which was limited due to lower capacity offers from the generating plants

The RSI is a dynamic continuous index measured as ratio of the available generation without a generator to the total generation required to supply the demand. The RSIis measured for each generator. The greater the RSI of a generator, the less its potential ability will be to exercise market power and manipulate prices as there will be sufficient capacity from theother generators. In contrary, the lower the RSI, the greater the market power of a generator (and its potential benefit of exercising market power), as the market is strongly dependent on itsavailability to be able to fully supply the demand. In particular, an RSI greater than 100% for a generator means that the remaining generators can cover the demand, and in principle, thatgenerator cannot manipulate market price. On the other hand, an RSI less than 100% means that the generator is pivotal in supplying the demand. The RSI for the whole market (Market RSI) ismeasured as the lowest RSI among all the generators in the market. A Market RSI less than 100% indicates the presence of pivotal generator/s.ter in a period (i.e. monthly). A generator that frequently sets the price may have greater opportunities to design bidding strategies to influence the prices.

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The WESMActual Operations: Market Concentration Index -Price Setting Frequency Index52Price Setting Frequency Index (2013)

The price setting index identifies the generators that set the price or are near setting the spot price in a trading interval. A generator is considered a price setter if its last accepted offer is within 95% to 100% of the nodal price. The PSFI is calculated as the percentage of time that a generator qualifies as price set

The price setting index identifies the generators that set the price or are near setting the spot price in a trading interval. A generator is considered a price setter if its last accepted offer is within 95% to 100% of the nodal price. The PSFI is calculated as the percentage of time that a generator qualifies as price set

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The WESMActual Operations: LWAP Analysis

NORMAL STATESufficient Operating MarginWithin limits for frequency, voltage, transmission loadingYELLOW ALERT

Contingency Reserve is less than capacity of largest synchronized unitThe WESMThe Reserve MarketAvailable CapacitySystem Capacity

Plants in Merit Order Table dispatched for energySystem DemandRegulating Reserve

Energy 4% of Demand

Contingency ReserveDispatchable Reserve

Capacity Largest unitNext largest unit

Excess Capacity

Capacity in OutageRED ALERT

Contingency Reserve is zeroGeneration deficiency existsThere is Critical LoadingImminent overloading of Trans. Line or equipment

Widen competition and supply base for Energy and ReservesLower overall cost from Co-optimization of Energy and ReservesTransparency in pricing and dispatch schedulingIncentive for new generation investment and customers with dispatchable (interruptible) loadsThe WESMThe Reserve MarketRationale for the Reserve MarketSchedulingGross Pool Concept

WESM Rules3.5.5Gross Pool Concept

WESM Rules3.5.7PricingLocational Marginal Price

WESM Rules3.5Zonal Reserve Price

WESM Rules3.10.10SettlementEx Ante & Ex Post Settlement

WESM Rules3.10.1Ex Ante Pricing Settlement

WESM Rules3.10.10ENERGYMARKETRESERVEMARKET

Energy and Reserve Co-optimization (WESM Rules 3.6.1.1 )Simultaneous determination of schedules and prices

Other Markets with Energy and Reserve Co-OptimizationSingaporeNew ZealandAustralia (AEMO)US (PJM, CAISO, NYISO, MISO)Canada (IESO)

The WESMPrice & Cost Recovery Mechanism for the Reserves MarketThe application for the approval of the PCRM was filed with the ERC on Jan 8, 2007;

Approved by the ERC on Jul 7, 2008:Gross Pool conceptZonal reserve pricingEx-ante settlementCo-optimization of energy and reservesAdministered reserve prices

Re-filed with the ERC on Feb 26, 2013; hearing by ERC on Jan 28, 2014. PEMC recommends 2-stage implementation:Interim Phase (Mar 26, 2014): Operate Reserve Market based on current designCompletion Stage (24 Months after Interim Phase): Full compliance to all ERC directives

On Jul 7, 2008, the ERC also directed compliance to directives:Implement an Ex-Ante Reserve Effectiveness FactorRealign Specifications of Reserve Services to create a Fast Contingency ServiceSet up new Lower Reserve ServiceIntroduce Interruptible Load Dropping (ILD) as a fully functioning reserve serviceSet up interim arrangement for ILDSet up appropriate changes in the Philippine Grid CodeSubmit plans for future enhancement and develop Interim PlansEstablish appropriate mitigating measures in the Energy and Reserve Market to curb misuse of market power or occurrence of anti-competitive behavior

56It must be emphasized that that the Reserve PCRM formulated by PEMC is patterned after these two (ASPP and OATS), to ensure that there is no inconsistency between the trading of reserves in the WESM and the overall rules, systems and procedures presently implemented by the System Operator in the procurement of ancillary services.

The WESMMarket Dispatch Optimization Model (Co-optimization)Total Cost800 MW x 12 K = 9,600 K200 MW x 4 K = 800 KTotal10,400 KTotal Cost800 MW x 5 K = 4,000 K200 MW x 7 K = 1,400 KTotal5,400 K

3000300050005000400010007000Reserve(200 MW)Energy(800 MW)ABCDEnergy onlyMaximized forreservesRemaining scheduled for energyBacked off for reservesSo that more can be provided for energyBalance of reserve requirement

3000300040005000

100070000Reserve(200 MW)Energy(800 MW)ABCDEnergy onlyMaximized forreservesRemaining scheduled for energyMaximizedfor reservesBalance for energyBalance of Energy requirementResults in more expensive marginal price of P 12,000/MWh for energyCo-optimized solution dispatches a more expensive resource for reserve (P 7000/MWh)

Overall cost is lower as a result of cheaper marginal energy price of P 5000/MWhRequirement:Energy = 800 MWReserve = 200 MW

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The WESMEnergy and Reserve Market Co-optimization

A reserve region shall have only one market price per type of reserve per trading intervalRegulating, Contingency, Dispatchable, and Interruptible load).

The market price shall be the zonal reserve price

Zonal Reserve Price = Reserve Clearing Price + Opportunity Cost

Clearing Price is the reserve offer price of the last resource to satisfy the reserve requirement plus the concept of opportunity cost.Opportunity Cost is defined as the economic loss suffered by generating resource from losing an opportunity to sell in the energy market as a result of being scheduled in the reserve marketReserve Price in the WESM