55
WESM 101
WESM 101
The Philippine Power MarketThe EPIRA reform agenda promote competition and choice
1970 1980 1990 2000
Institutional 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
transmission
Power Supply Crisis
Private sector participation in power
generation with oligopsony by NPC and
Meralco
Electric Power Industry
Reform Act
The Philippine Power Market:Value Chain has evolved under EPIRA*
3
Generation•Open & competitive
•ERC requires that it approves the PSA for a DU’s captive customers
•Operates under WESM
•No cross-ownership in Transmission
•No company can own, operate and control 30% of installed capacity of any grid, or 25% of the national capacity
Transmission•Franchised & Regulated common carrier business
•Subject to rate-setting powers of the ERC
•National Grid Corporation of the Philippines (private consortium)
•Open access transmission system
•No cross ownership in generation and /or distribution
Distribution•Franchised & Regulated common carrier business
•Subject to rate-setting powers of the ERC
•Non-discriminatory distribution open access
•No cross-ownership in Transmission
Local RES•DU business segment; can sell to Contestable Customers in franchise area only
Retail Electricity Supplier (RES)
•ERC licensed
Contestable Market•End-users with demand >=1 MW
•Contestability threshold reduces to 750 kW by Jul 2016 and to 500 kW by Jul 2018
Captive Market•End-users with demand <1MW
•(See contestability thresholds below)
WiresGeneration Retail Supply
•Distribution Retail Price to Captive Market subject to ERC regulation (including wires charges to RES)
•Retail Supply Contract does not require ERC approval
End User Market
DU Regulated Retail Distribution Services
•DU/EC business segment for sales to Captive Market
•No DU may source more than 50% of its demand from an associated firm
• Contestability threshold goes down from 1 MW to 750kW after 2 years
• ERC may further reduce contestability threshold until it reaches household level (7-year goal)
EPIRA – Electric Power Industry Reform Act of 2001, Republic .Act # 9136
The Philippine Power MarketComparative Policy & Regulatory Regimes
Pre – EPIRA EPIRA
Generation Mix
• State monopoly in generation and transmission (NAPOCOR)
• Government plans for fuel diversity and energy autarky• Government has dirigiste oversight on what gets built
and how plants are run• “least cost” development planning• dispatch based on economic merit order
• Generation sector is open and competitive• Generation mix and what gets built are driven by the
power market:• Bidding Merit order in the WESM• PSAs by DUs and Contestable Customers
• Renewable Energy Act imposes RE quota (RPS), subsidies (FIT) and priority dispatch of VREs
Power Rates
• Bundled generation and transmission (NAPOCOR tariff)• Regulated by ERB using RoRB regulation (recovery of
actual costs; subject to efficiency standards)
• Unbundled: generation, transmission, distribution, gov’t charges (taxes, UCME, FITALL)
• DU End-user generation rate is composite of PSA charges approved by ERC and WESM
• Only the generation rates for captive customers and rates for wires services are regulated:• ERC requires DUs to conduct CSP for PSA for captive
market• PSAs of contestable customers do not require ERC
approval to be implemented• Regulation is based on full recovery of prudent and
reasonable economic costs
EPIRA promotes cost efficiency through competition and choice
RETAIL MARKET(Distribution System)
RETAIL
BUYERS
WHOLESALE MARKET(Luzon – Visayas Grid)
RETAIL
SELLERS
WESM SELLERS
The Philippine Power MarketEPIRA aims to bring supply competition and choice at the household level
5
GeneratorWholesale
Aggregator
IPP
Administrator
NPC IPP
WESM BUYERS
RESDirect
ConnectDistribution
Utility
Local RES
Captive Customers
ContestableCustomer
ContestableCustomer
• Market Operator
PEMC
• System Operator
NGCP
• Meter Service Provider
NGCP
DU IPPs
Department of Energy (DOE)• Policy making• Planning• Market Establishment
Energy Regulatory Commission (ERC) • EPIRA enforcement• Rate setting (NGCP, DUs) • Quasi-judicial power on Competition• CPCs, COCs, Certificate of
Contestability
Initial contestability threshold is 1000 kW or more; after 2 years, next phase sets threshold 750 kW
• Meter Service Provider(s)
DUs
The Philippine Power MarketThe Luzon Grid centers in supplying the requirements of Meralco
The Philippine Power MarketThe Wholesale Electricity Spot Market (WESM): Luzon & Visayas grids
Visayas GridLuzon Grid
North West(3,532 MW)
~ ~ ~
MasinlocGNPower Sual
~ ~ ~
Subic Limay Bauang
North(1,820 MW)
~ ~ ~
AmbuklaoMagat Binga
~ ~ ~
CasecnanPantabangan
San Roque
Central(1,197MW)
~
Angat
~
Malaya
~
TMO
South West(2,326 MW)
~ ~
CalacaSLTEC
~ ~
Sta. RitaSn Lorenzo
South East(2,906 MW)
~ ~
QuezonKalayaan
~ ~ ~
Mak-Ban Tiwi Bac-Man
South(1,278 MW)
~
Iijan
Meralco
~
Pagbilao
Leyte(710 MW)
~
Unified Leyte
Bohol(25 MW)
~Bohol Diesel
Cebu(862 MW)
~Cebu EDC
~Toledo
~KEPCO
~
Naga Coal
~
SPC
~
CPPC
Negros(285 MW)
~
Negros Geo
~
Sacasol
Panay(521 MW)
~
PEDC
~
Trans Asia
~
SPC Island
The Philippine Power MarketThe Wholesale Electricity Spot Market (WESM): Luzon & Visayas grids
Capacity Distribution by Fuel Type Capacity Distribution by Control
The Philippine Power MarketThe Buyers: Captive and Contestable Market
The Captive Market• The Captive Market are the end-user customers of DUs
whose average demand is less than 1,000kW (the current “Contestability Threshold”)
• Relevant EPIRA Provisions: • Sec 23: The DUs have the obligation to supply
electricity in the least cost manner to its captive market subject to the collection of retail rate duly approved by the ERC.
• Sec 25: Retail rates shall be subject to ERC regulation based on principle of full recovery of prudent and reasonable economic costs incurred, or such other principles that will promote efficiency as may be determined by the ERC
• DUs secure PSAs effectively on behalf of their customers
• ERC requires CSP for DU PSAs
• PSAs require approval by the ERC before these can be implemented
• PSA contract prices are on full pass-through(no-gain-no-loss basis) except any portion disallowed by ERC
• DUs are allowed to recover from their end-users their approved PSA charges and WESM purchases
The Contestable Market• The Contestable Market are end-user customers (or
those directly connected to the grid) whose average demand is at least 1,000kW (the current “Contestability Threshold”)
• The Contestability Threshold reduces to 750 kW by July 2016 and to 500 kW by July 2018
• Contestable Customers may secure PSAs from licensed Retail Electricity Suppliers (RES) or from the DUs Local RES; The DUs will continue to provide Distribution Wheeling Services
• Contestable Customers are solely responsible for securing their supply; in the absence of a RES, a Contestable Customer may be supplied by ERC designated Supplier of Last Resort (SOLR)
• Any WESM requirement of a Contestable Customer is secured through its RES
• RES PSAs do not require ERC approval to be implemented
• The Contestable Market size is expected to grow as the Contestability Threshold is reduced (~ 35% when threshold reaches 500 kW)
The Philippine Power MarketCaptive Customer Generation Cost
Power RateY * S + X * B
PSAX% @ B
WESMY% @ S
Y%, X%DUs Contracting Strategy
SSpot Price Volatility
Price CapMust Offer Rule
Primary Price Cap
SecondaryPrice Cap
Supply-SideDetermination
Demand-SideDetermination
Rationale
Method/Application
Anti - AbuseOf Market Power
“Perfect Storm” Events
Notes:
S – spot price
B – Bilateral Contract Rate
Y – percent share bought in WESM
X – percent share under contract
OLIGOPOLY• High Market Concentration (HHI)• Pivotal Plant• Price Setting Plant
Abuse of Market Power
Triggers Level
Security PlantSelling Rate
VoLL =GDP/kWh
RegulatoryIntervention
DOE Policy/ERC RuleContracting Level
Scarcity
1
2
34
• Malampaya S/D
• El Nino
• Elections
“too high too long”
Generation CostUS EIA April 2013 Report
Technology FuelNominal
Capacity, kW
Nominal Heat
rate, BTU/kWh
Capital Cost
$/kW
Fixed O&M Cost
$/kW-year
Variable O&M,
$/MWh
Adavance Pulverized Coal (APC) Coal 650,000 8,800 3,246 37.80 4.47
Adavance Pulverized Coal Coal 1,300,000 8,800 2,934 31.18 4.47
APC with Carbon Capture & Sequestration Coal 650,000 12,000 5,227 80.53 9.51
APC with Carbon Capture & Sequestration Coal 1,300,000 12,000 4,724 66.43 9.51
Natural Gas Combined Cycle (NGCC) Gas 620,000 7,050 917 13.17 3.60
Advance Generation NGCC Gas 400,000 6,430 1,023 15.37 3.27
Adavanced NGCC with CCS Gas 340,000 7,525 2,095 31.79 6.78
Conventional Combustion Turbine Gas 85,000 10,850 973 7.34 15.45
Advanced CT Gas 210,000 9,750 676 7.04 10.37
Integrated Gasification Combined Cycle Coal 600,000 8,700 4,400 62.25 7.22
Integrated Gasification Combined Cycle Coal 1,200,000 8,700 3,784 51.39 7.22
Advanced Nuclear Uranium 2,234,000 N/A 5,530 93.28 2.14
Biomass Combined Cycle Biomass 20,000 12,350 8,180 356.07 17.49
Biomass Bubbling Fluidized Bed Biomass 50,000 13,500 4,114 105.63 5.26
Fuel Cells Gas 10,000 9,500 7,108 43.00
Geothermal - Dual Flash Geothermal 50,000 N/A 6,243 132.00 -
Geothermal - Binary Geothermal 50,000 N/A 4,362 100.00 -
Municipal Solid Waste MSW 50,000 18,000 8,312 392.82 8.75
Hydroelectric Hydro 500,000 N/A 2,936 14.13 -
Pumped Storage Hydro 250,000 N/A 5,288 18.00 -
Onshore Wind Wind 100,000 N/A 2,213 39.55 -
Offshore Wind Wind 400,000 N/A 6,230 74.00 -
Solar Thermal Solar 100,000 N/A 5,067 67.26
Photovoltaic (PV) Solar 20,000 N/A 4,183 27.75 -
PV - Tracking Solar 150,000 N/A 3,873 24.69
PV - Tracking with 10% storage Solar 150,000 N/A 4,054
PV - Tracking with 20% storage Solar 150,000 N/A 4,236
Notes:• Capacity net of auxiliary load• Capital cost excludes financing costs (e.g., interest during constructions, bank fees)• Fixed O&M excludes owner’s costs (e.g., insurance, property taxes, asset management fees)• Variable O&M includes major maintenance
Generation CostUS EIA April 2013 Report
Notes:• Capacity net of auxiliary load• Capital cost excludes financing costs (e.g., interest during constructions, bank fees)• Fixed O&M excludes owner’s costs (e.g., insurance, property taxes, asset management fees)• Variable O&M includes major maintenance
Generation CostBase-load, Mid-Merit & Peaking Plant Cost
Technology Advance CT NG CCGT Advance PC
Capacity MW 210. 620. 650.
Capital Cost US$/kW 676. 917. 3,246.
Fixed O&M Cost
US$/kW-year 7.04 13.17 37.80
Variable O&M
US$/kWh 0.0104 0.0036 0.0045
Heat Rate BTU/kWh 9,750 7,050 8,800
Fuel Cost $/MMBTU 14.51 14.51 3.04
Project Life Years 20 30 30
Cost of Capital % 15% 15% 15%
1,158
6,788
FixedCost
VariableCost
hours of use
•High fixed cost• Low variable cost
• Low Fixed cost•High variable cot
Generation CostLuzon Demand Profile (2013)
Generation CostMatching Demand with Base-load, Mid-Merit & Peaking Generation
Base-load (5,350 MW)
Mid-Merit (1,844 MW)
Peaking (1,043 MW)
The Market FrameworkUniform Price Auction
SUPPLIERThose willing to sell at a lower price get to sell first
BUYERThose willing to buy at a higher price get to buy first
Price
Quantity
Clearing Price
Supply
Demand
No more buyers willing to pay a higher price
No more sellers willing to sell at a lower price
All Suppliers are paid at the same rate (i.e., a “Uniform Price” which is the Clearing Price), notwithstanding their bid may be lower
The market framework seeks short-run efficiency:• Output is produced by
least-cost suppliers• Output is consumed by
those most willing to pay
• The right quantity is produced
The overall objective of power systems operation is to produce power at the lowest total cost.
The Market FrameworkThe current market framework: demand is “Price-Taker”
SUPPLIERThose willing to sell at a lower price get to sell first
BUYERBuyers do not submit “demand bids”; they’re Price-Takers
Price
Quantity
Clearing Price
Demand is Price Taker
The Market FrameworkMarket Power & Price Cap
SUPPLIER MARKET POWER• Physical (Capacity) Withholding• Economic Withholding
Price
Quantity
Clearing Price
Market Price Cap
Demand is Price Taker
Clearing PriceWith Market Powerby Suppliers
Market Power
Physical Withholding
EconomicWithholding
The Market FrameworkMarket Power, Price Cap & Demand Bid
SUPPLIER MARKET POWER• Physical (Capacity) Withholding• Economic Withholding
Price
Quantity
Clearing Price
Market Price Cap
Demand is Price Taker
Demand with response
Clearing PriceWith Demand response
Clearing PriceWith Market Powerby Suppliers
Market PowerDemand Response
The Market FrameworkMarket Power, Price Cap & Demand Bid
SUPPLIER MARKET POWER• Physical (Capacity) Withholding• Economic Withholding
Price
Quantity
Clearing Price
Market Power
Clearing PriceWith Market Powerby Suppliers
Market Price Cap
Demand is Price Taker
Demand with limited response
Clearing PriceWith limited Demand response
Demand Response
The Market Framework
• The overall objective of power systems operation is to produce power at the lowest total cost
• Uniform Price Auction promotes economic dispatch because of the financial incentives for the suppliers to bid their short-run marginal cost
• The market framework seeks short-run efficiency:• Output is produced by least-cost suppliers
• Output is consumed by those most willing to pay
• The right quantity is produced
• Generators win market share by offering low prices (Generators are more likely to bid at their marginal cost)
• Demand is currently a “Price-Taker”
• There are rules to thwart and prevent generators from exercising market power:• “Must Offer Rule” → physical withholding
• “Price Cap” → economic withholding
• “Secondary Price Cap” → “too-high-too-long”
• The spot market operates under WESM Rules (approved by ERC)
• Default market position: • A Generator sells all its production in the WESM and a Customer (DU) buys all its requirements in the WESM, unless,
they have a bilateral contract and their transaction is settled outside the WESM
• RCOA effectively places Contestable Customers in the WESM (whose connection is conveyed through its DWSA)
• WESM prices are volatile• Month to month, hour to hour changes• More volatile than commodity prices (coal, oil, Fx)The business of entities selling and buying in the WESM are exposed to volatility risk (Not a way to run business!)
• A bilateral contract is basically a hedge benefitting both buyers and sellers with business stability. WESM Rules on net settlement allow the parties to settle their bilateral contract transaction outside of the market
• In a WESM regime, the merit of a particular bilateral contract lies in:• the “trade off” between: (a) the generation rate volatility indexed on commodity prices and escalation indices, versus
(b) the WESM price volatility from market forces and chance events;• Its competitiveness in relation to other offers (such as plants of other fuel types)
The Market FrameworkWESM is the default market for sellers and buyers
The Market FrameworkEnd-User Protection
Dominant Firm(s)
Pivotal Plant(s)
Price Setting Plant(s)
Clearing Plant(s)
EPIRA Sec 45 (a) - Grid Caps:• 30% of grid• 25% of national
Spot Market
Must Offer Rule
Price Cap
BilateralContract Supply
EPIRA Sec 45 (b) - DU contract limit:50% supply limit from associated firm
Transmission
Distribution
PEMCMarket
Surveillance
ERC Tariff Regulation:Performance-Based Rate-Setting
ERC Approval of DU PSARegulation of Retail Rate
Market Suspension by ERC• Natural Calamities• National or international
security emergency
End-User
EPIRA Sec28 – De-Monopolization and Shareholding Dispersal
Generating Plant(s) EPIRA Sec 43 (t) – Public Offering:Public offering of 15% of stock
WESM Rules
The WESMWESM System has marked its 8th year
24
Mindanao
Luzon
Visayas
Mindanao
Metro Manila
Masinloc ►
Legend:
WESM Connected
Non WESM
HVDC line & submarine cable
Highlights• The WESM is a real time, bid-based and hourly market for energy.
• Similar designs: New Zealand, Australia and Norway.
• Luzon and Visayas grids run as a single market (88% of total demand) but with limited trade from weak interconnections (Leyte –Luzon HVDC 346 MW)
• Metro Manila account for 59% of the consumption.
• Annual peak demand occurs between May and June (Dry Season)
• Three peaks occurring at 11:00AM, 2:00PM and 7:00PM.
• Hourly trading intervals (shorter durations in the future)
PARTICIPANTSLuzon Visayas
Direct Indirect Direct Indirect
Generators 34 18
Electric Cooperatives 26 17 26 2
Private DUs 7 3 3
Bulk Users 6 49 7 13
Suppliers 4
The WESMOperational Features
Mandatory Market: No one is allowed to inject to or withdraw
from the grid unless such entity is a WESM member
Generators must offer all its capacity (“Must Offer Rule”)
Generators must run at Pmin (bid price zero)
Gross Pool & Central Dispatch: Generators must bid to win a market share
regardless of their supply contracts; Taking into account system status, Market
Operator (MO) schedules all available generation offers which are “stacked” from lowest to highest price until demand is met
Locational Market Pricing: The WESM price is the offer of the last
“block” to be “stacked” to meet the demand A price is computed at each node reflecting
the cost of transmission loss or congestion.
Net Settlement: Parties with bilateral contracts settle their
transactions outside the WESM (paying their counter-parties directly based on contract prices)
Any off-take of a DU from the grid not matched with a generator’s BCQ declaration is deemed supplied from the market (the “spot quantity” for which DU pays the WESM)
Settlements are essentially based on BCQ declarations
The WESMSequence of Transactions
BUYER SELLER MARKET OPERATOR SYSTEM OPERATOR
Nominates day-ahead (or period-ahead)requirements to itsPSAcounter-party
Submits its offers before bid closing based on its customer nominations and its market strategy.
Determines the settlement prices and Merit Order Table of how plants will be dispatched using the Market Dispatch Optimization Model (MDOM); sends to SO
Complies with SO instructions (tolerance of +/- 3%)
Draws its real time requirements from the grid
Declares to the MO the BCQs for its customers
SO provides actual metering data for previous day trading intervals
Determines settlement information (counter-party quantities for BCQ, spot sales,); bills users and pays generators
Implements the dispatch schedule MOT and monitors actual system conditions and plant compliance with dispatch orders; makes real time adjustments for frequency, voltage and contingencies
Period ahead
1 hour before
Trading interval(one hour)
Day after andPeriod after
The WESMGross Pool & Central Dispatch
Generator Offer Rules
• Must offer all capacity (Pmax) all the time
• Must offer Pmin at price of zero
• Must make 10 offer blocks every interval for each unit (including Pmin as first offer block);
• Minimum of 1 MW per block
• Block offers in ascending order of prices
• Price cap at PhP 32,000/MWh
Types of Offers/Bids
Standing Offers/Bids are default offers/bids that are submitted to ensure relevant data are used if the Trading Participant fail to submit Regular Offers/Bids
Regular Offers/Bids
are offers/bids the Trading Participants submit hourly, daily, or any interval (maximum of 7 days) depending on the Trading Participants’ choice or strategy.
Also called Daily Offers/Bids as these are usually submitted on a daily basis.
A daily bid can only be submitted during an ‘Open Market Window’
The WESMMarket Clearing Price
100Gen A
75Gne B
125Gen C
100Gen D
200Gen E
100Gen F
P 500/MWh
P 900/MWh
P 1,350/MWh
P 1,850/MWh
P 3,100/MWh
P 2,150/MWh
Demand = 500 MW
Generators arranged from lowest to highest bid
CLEARING PRICE• Generators submit a bid for
the energy they wish to supply• Offers are arranged from
lowest to highest price (“stacked”)
• Offer of last plant needed to meet demand sets the “Clearing Price”
• All Buyers pay at the Clearing Price
• All Generators are paid at the Clearing Price (whatever the offer)
The WESMGross Pool & Central Dispatch
Plant Fuel Bid Pmax Pmin Net of Pmin
Bauang Oil 8,500 190 - 190
Limay Oil 12,000 540 540
Subic Oil 9,000 120 120
Mariveles Coal 1,800 600 300 300
Masinloc Coal 1,300 600 160 440
Sual Coal 1,400 1,200 450 750
Pagbilao Coal 1,450 760 240 520
Quezon Coal 1,375 456 180 276
MakBan Geothermal 1,800 120 50 70
BacMan Geothermal 2,000 130 55 75
Tiwi Geothermal 1,500 100 40 60
Pantabangan Hydro 1,200 130 130
Magat Hydro 2,000 360 360
Kalayaan Hydro 2,100 740 740
Ilijan Nat Gas 4,500 1,200 800 400
Santa Rita Nat Gas 5,000 1,060 600 460
San Lorenzo Nat Gas 5,000 530 400 130
8,836 3,275 5,561
System Demand 7200
For a System Demand of 7200 MW, determine the following:
1. Market Clearing Price2. Marginal Plant
Given: No Non-Scheduled Generator No Must Run Unit (MRU)
The WESMGross Pool & Central Dispatch
Bids are sorted from lowest to highest1
The “Pmin” is taken into account 3
Plant Fuel Bid Pmax Pmin Net of Pmin "Stack"
Limay Oil 12,000 540 540 8,836
Subic Oil 9,000 120 120 8,296
Bauang Oil 8,500 190 - 190 8,176
Santa Rita Nat Gas 5,000 1,060 600 460 7,986
San Lorenzo Nat Gas 5,000 530 400 130 7,526
Ilijan Nat Gas 4,500 1,200 800 400 7,396 Clearing Plant
Kalayaan Hydro 2,100 740 740 6,996
BacMan Geothermal 2,000 130 55 75 6,256
Magat Hydro 2,000 360 360 6,181
Mariveles Coal 1,800 600 300 300 5,821
MakBan Geothermal 1,800 120 50 70 5,521
Tiwi Geothermal 1,500 100 40 60 5,451
Pagbilao Coal 1,450 760 240 520 5,391
Sual Coal 1,400 1,200 450 750 4,871
Quezon Coal 1,375 456 180 276 4,121
Masinloc Coal 1,300 600 160 440 3,845
Pantabangan Hydro 1,200 130 130 3,405
8,836 3,275 3,275
-
System Demand 7200 -
Non-Scheduled Generation
Must-Run Units
2
• The “Pmin” is stacked at the bottom (priced at zero)
• The net of Pmin capacities are stacked on top
4• The last plant to be stacked to fully
cover demand is the “Clearing Plant”; its bid sets the Market Clearing Price
The WESMGross Pool & Central Dispatch
Pmin = 3,275 MW
System Demand = 7,200 MW
System Capacity = 8,836 MW
Market Clearing Price= P 4,500/MWhBid
s in
P/M
Wh
The WESMGross Pool & Central Dispatch
32
Offers Dispatched
Offers Not Dispatched
The WESMPlant Dispatch Protocol: Planned Dispatch (Ex Ante)
33
0600H 0700H
Interval 7
MO
MMS – Market Management SystemMO – Market OperatorEAQ – Ex-Ante Quantity
WESM Trading Interval
RTD Schedule(what should happen)
Initial Quantity Target Quantity
The WESMPlant Dispatch Protocol: Intra-hour Redispatch
34
0600H 0700H
Interval 7
SO
MMS – Market Management SystemMO – Market OperatorEAQ – Ex-Ante Quantity
WESM Trading Interval
Redispatch(SO Instructions)
The WESMPlant Dispatch Protocol: Actual(Ex Post)
35
0600H 0700H
Interval 7
MO
MMS – Market Management SystemMO – Market OperatorEAQ – Ex-Ante Quantity
WESM Trading Interval
RTX Schedule(What actually happened)
Initial Quantity Target Quantity
Amount Settled Outside WESM Amount Settled in WESM
39
The WESMSettlement: WESM Transaction Amounts
BCQ
EAQMQ
EPP
EAP
Amount Settled In WESM
Ex Ante Transaction Amount
“Imbalance”
EATA = EAP x (EAQ – BCQ)
Ex Post Transaction Amount
“Forecast Error”
EPTA = EPP x (MQ – EAQ)
Amount Settled Outside of WESM
(paid directly to generator)
Amount paid under PSA
= BCQ x Contract Rate
The WESMDetermining the Ex Ante Price
40
Pricing ConditionsPrice for Ex Ante
RTD RTX
OK OK RTD
PEN OK RTX
OK PEN RTD
PEN PEN MRR
PSM OK PSMRTD
OK PSM RTD
PSM PSM PSMRTD
• PSM – with congestion resulting in price separation by a factor of 1.2 or more (ratio of highest nodal price to lowest nodal price)
• PEN – with CVCs; with congestion (no large price separation)• MRR – Market Re-Run, If the Ex-Post price is believed to be in error or reflect CVC
prices
The WESMDetermining the Ex Ante Price
41
Line Rental – “The economic rental arising from the use of a transmission line, calculated as the difference in value between flows out of the receiving node of that line and flows into the sending node…”
Line rental charges pay for system loss and congestion costs incurred for quantities supplied through power supply contracts.
Parties to a bilateral contract settle their transactions outside the market
A Generator will supply not only the energy for the BCQ of its customer but also to cover line losses
“Line rental” is a mechanism that allows a Generator’s recovery of its cost for suppling energy for line losses
The WESMNODAL PRICING: Understanding Line Rental
G1 Load
Sending Node
ReceivingNode
BCQ →
Line Rental = BCQ x (LMPReceiving - LMPSending)
The WESMNodal Pricing: Line Rental from Transmission Losses
G1200 MW
Load
G2100 MW
Sending Node
ReceivingNode
Because of “Transmission Losses”, a Generator’s delivery to the grid would be higher than the energy received by the Customer
Line rental compensates Generator for having to deliver more for transmission losses
Transmission Capacity = 200 MWTransmission loss = 5%
100 MWh+ 5 MWh
Transmission Loss = 5 MWh 100 MWh
Price G2 > Price G1
0 MWh
The WESMNodal Pricing: Line Rental from Congestion
G1200 MW
Load
G2100 MW
Sending Node
ReceivingNode
When transmission limitations occur, the SO may be constrained to re-dispatch a more expensive Generator
Line rental also compensates for the additional cost from a higher priced Generator to maintain load supply
24 MWh
Transmission Capacity = 200 MW but subsequently restricted to 80 MWTransmission loss = 5%
80 MWh Transmission Loss = 4 MWh 100 MWh
Price G2 > Price G1
The WESMNodal Pricing: Line Rental from Transmission Losses
G1200 MW
Load
G2100 MW
Sending Node
ReceivingNode
Transmission Capacity = 200 MWTransmission loss = 5%
100 MWh+ 5 MWhOffer:P 4000/MWh
Transmission Loss = 5 MWh100 MWh
0 MWhOffer: P 5000/MWh
LMPG = P 4000/MWh LMPL = P 4200/MWh(= 4000 * 105/100)
Load does not have PSA
Trading Amount: Load= TA + LR= 100 MWh x P 4200/MWh + 0 MW x P 200/MWh= P420,000
Settlement outside WESM= P 0.00
Trading Amount: Generator= 105 MW x P 4000/MWh= P420,000
Settlement outside WESM= P 0.00
Load has 100 MW PSA
Trading 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 Price
Trading 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
0
50
100
150
200
250
300
350
400
450
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000
$/MWh
Capacity Stack based on Bidding
Stack Heirarchy Peak Demand Ave. Off-Peak Demand
* 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 MRU
Avg. Off-peak demand
$/MWh
The WESMActual Operations: Lack of mid-merit plants in supply stack gestates volatility
48
Range of daily dispatch
The WESMActual Operations: The market is highly contracted.
4949
Market Transaction Mix - 100% stacked column
Market Transaction Mix - stacked column
The WESMActual Operations: Market Concentration Index - Herfindahl-Hirschman Index
50
Herfindahl-Hirschman Index (2010-2013)
The WESMActual Operations: Market Concentration Index - Residual Supply Index
51
Hourly Market Residual Supply Index Based on Offered Capacity of Generators (2010-2013)
0
50
100
150
200
250
1/1/2010 5/31/2010 10/28/2010 3/27/2011 8/24/2011 1/21/2012 6/19/2012 11/16/2012 4/15/2013 9/12/2013
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 prices
RSI < 100%Presence of
Pivotal Generator(s)
The WESMActual Operations: Market Concentration Index -Price Setting Frequency Index
52
Price Setting Frequency Index (2013)
Below 5,000 5,000 to 10,000 Above 10,000
AMBUKLAO HEP 6.2% 12.1% 4.1%
ANGAT HEP 2.2% 0.0% 0.1%
APEC 6.1% 0.0% 0.0%
BAKUN HEP 0.2% 0.0% 0.0%
BATANGAS CFTPP 0.0% 0.0% 0.0%
BAUANG DPP 0.0% 27.5% 50.3%
BINGA HEP 1.9% 2.3% 2.2%
CASECNAN 1.8% 0.0% 0.0%
CBK (KPSPP) 2.2% 1.6% 1.3%
HEDCOR 2.2% 0.0% 0.0%
KEPCO ILIJAN 12.9% 0.0% 0.1%
LIMAY CCGT 1.0% 0.3% 14.0%
MAGAT HEP 2.3% 5.9% 2.3%
MAKBAN GPP 4.4% 0.0% 0.2%
MALAYA TPP 0.4% 0.0% 5.1%
MASINLOC CFTPP 26.8% 0.1% 0.0%
GN POWER 12.6% 0.1% 0.1%
MASIWAY HEP 1.2% 0.0% 0.0%
PAGBILAO CFTPP 42.1% 0.5% 0.2%
PANTABANGAN HEP 0.5% 0.0% 0.0%
QUEZON POWER 4.5% 0.0% 0.0%
SAN ROQUE POWER 1.8% 0.0% 0.1%
STA RITA FGPP 2.7% 0.1% 0.0%
SUAL CFTPP 40.5% 0.1% 0.0%
SUBIC POWER CORP 0.1% 25.9% 3.0%
TIWI GPP 3.1% 0.0% 1.9%
TRANS ASIA 0.1% 22.0% 3.4%
LUZON
Plants / Resource IDCategory
75.4%
12.4%
12.3%
% of Time of Price Range (P) Occurance
P < 5,000
5,000 < P < 10,000
P > 10,000
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 WESMActual Operations: LWAP Analysis
NORMAL STATE• Sufficient Operating Margin• Within limits for frequency, voltage, transmission loading
YELLOW ALERT
• Contingency Reserve is less than capacity of largest synchronized unit
The WESMThe Reserve Market
Availab
le Cap
acity
System C
apacity
Plants in Merit Order Table dispatched for energy
System D
eman
d
Regulating Reserve
Energy
4% of Demand
Contingency Reserve
Dispatchable Reserve
Capacity Largest unit
Next largest unit
Excess Capacity
Capacity in Outage
RED ALERT
• Contingency Reserve is zero• Generation deficiency
exists• There is Critical Loading• Imminent overloading of
Trans. Line or equipment
• Widen competition and supply base for Energy and Reserves
• Lower overall cost from Co-optimization of Energy and Reserves
• Transparency in pricing and dispatch scheduling
• Incentive for new generation investment and customers with dispatchable (interruptible) loads
The WESMThe Reserve Market
Rationale for the Reserve Market
Scheduling
Gross Pool Concept
WESM Rules3.5.5
Gross Pool Concept
WESM Rules3.5.7
Pricing
Locational Marginal Price
WESM Rules3.5
Zonal Reserve Price
WESM Rules3.10.10
Settlement
Ex Ante & Ex Post
Settlement
WESM Rules3.10.1
Ex Ante Pricing Settlement
WESM Rules3.10.10
ENERGYMARKET
RESERVEMARKET
Energy and Reserve Co-optimization (WESM Rules 3.6.1.1 )
Simultaneous determination of schedules and prices
Other Markets with Energy and Reserve Co-Optimization
Singapore
New Zealand
Australia (AEMO)
US (PJM, CAISO, NYISO, MISO)
Canada (IESO)
The WESMPrice & Cost Recovery Mechanism for the Reserves Market
• The 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 concept
• Zonal reserve pricing
• Ex-ante settlement
• Co-optimization of energy and reserves
• Administered 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 design
• Completion 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 Factor
• Realign Specifications of Reserve Services to create a Fast Contingency Service
• Set up new Lower Reserve Service
• Introduce Interruptible Load Dropping (ILD) as a fully functioning reserve service
• Set up interim arrangement for ILD
• Set up appropriate changes in the Philippine Grid Code
• Submit plans for future enhancement and develop Interim Plans
• Establish appropriate mitigating measures in the Energy and Reserve Market to curb misuse of market power or occurrence of anti-competitive behavior
The WESMMarket Dispatch Optimization Model (Co-optimization)
Total Cost800 MW x 12 K = 9,600 K200 MW x 4 K = 800 KTotal 10,400 K
Total Cost800 MW x 5 K = 4,000 K200 MW x 7 K = 1,400 KTotal 5,400 K
Quantity,
MW
Price,
P/MWh
A 400 - - -
B 300 3,000.00 100 1,000.00
C 250 5,000.00 250 4,000.00
D 300 12,000.00 300 7,000.00
Reserve OfferEnergy
Offer,
P/MWh
Pmax, MWGENERATOR
Energy Reserve
A 400 -
B 200 100
C 150 100
D 50 -
Total 800 200
Schedules, MWGENERATOR
Sequential Clearing
Energy Reserve
A 400 -
B 200 100
C 200 50
D - 50
Total 800 200
Simultaneous Clearing
GENERATORSchedules, MW
3000 3000
5000 5000
40
00
1000
70
00
Reserve(200 MW)
Energy(800 MW)
A B C D
Energy only
Maximized forreserves
Remaining scheduled for energy
Backed off for reserves
So that more can be provided for energy
Balance of reserve requirement
3000 3000
4000
5000
1000
70
00
0
Reserve(200 MW)
Energy(800 MW)
A B C D
Energy only
Maximized forreserves
Remaining scheduled for energy
Maximizedfor reserves
Balance for energy
Balance of Energy requirement
Results in more expensive marginal price of P 12,000/MWh for energy
Co-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/MWh
Requirement:Energy = 800 MWReserve = 200 MW
The WESMEnergy and Reserve Market Co-optimization
A reserve region shall have only one market price per type of reserve per trading interval Regulating, 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 market
Reserve Price in the WESM
