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Andrew L. OttGeneral Manager, Market CoordinationPJM Interconnection, L. L. C.
PJM Energy Market Model
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Section 1 - Agenda
Overview of PJM Overview Locational Marginal Pricing Overview Financial Transmission Rights Overview Day-ahead Market Overview of Ancillary Services Overview Installed Capacity
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ElectricDistributors
Members Committee Sector VotingMembers Committee Sector Voting
GenerationOwners
TransmissionOwners
Other Suppliers
End-UseCustomers
PJM Independent Board - (Elected by Members)PJM Independent Board - (Elected by Members)
Governance
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PJM and PJM West Control Areas
Generating Units 594Generation Capacity 66,100 MWPeak Load 62,443 MWAnnual Energy 298,011
MWTransmission Miles 13,000Area (Square Miles) 79,000
Customers 11 MillionPopulation Served 25.1 MillionStates (+ D.C.) 8
Generating Units 594Generation Capacity 66,100 MWPeak Load 62,443 MWAnnual Energy 298,011
MWTransmission Miles 13,000Area (Square Miles) 79,000
Customers 11 MillionPopulation Served 25.1 MillionStates (+ D.C.) 8
PJM RTO with PJM West PJM RTO with PJM West
PJM - Full Service RTO• Control Area Operator• Transmission Provider • Market Administrator• Regional Transmission Planner • NERC Security Coordinator
PJM West
PJM RTO
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What is LMP?
Pricing method PJM uses to … price energy purchases and sales in PJM Market prices transmission congestion costs to move energy
within PJM Control Area Physical, flow-based pricing system
how energy actually flows, NOT contract paths
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Definition:Locational Marginal Pricing
Transmission Congestion
Cost
Transmission Congestion
Cost=
Generation Marginal
Cost
Generation Marginal
CostLMPLMP + +
Cost of Marginal
Losses
Cost of Marginal
Losses
Cost of Marginal Losses = Not currently implemented
Cost of supplying next MW of load at a specific location , considering generation marginal cost, cost of
transmission congestion, and losses.
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Said Another Way...
The marginal cost to provide energy at a specific location depends on: marginal cost to operate generation total load (demand) cost of delivery on transmission system
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Transmission System Congestion
Transmission system congestion occurs when available, low cost supply cannot be delivered to the demand location due to transmission limitations
As Market Participants compete to utilize the scarce transmission resource, the RTO needs an efficient, non-discriminatory mechanism to deal the congestion problem
Thermal LimitsVoltage LimitsStability Limits
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Control Actions
E DBrighton Sundance240 MW
A
B C
Thermal Limit
SolitudeAlta Park City
System Reconfiguration
Transaction Curtailments
Re-dispatch Generation
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When Transmission Constraints Occur
Delivery limitations prevent use of “next least-cost generator” Higher cost generator closer to load must be used to meet
demand Cost to operate more expensive generation are translated into
transmission congestion costs in LMP calculation LMP results in cost causation for congestion pricing to
market participants
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Managing Congestion on the Power Grid
LMP is not a new concept to power system operators, For many years, system operators have managed congestion using least-cost security constrained dispatch which is the same program that calculates LMP values
The PJM LMP-based market provides an open, transparent and non-discriminatory mechanism to manage transmission congestion under open transmission access.
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Transmission System Congestion
The PJM Market uses Locational Marginal Pricing to manage transmission congestion
The PJM Market also includes overlying trading hubs and zones to provide standard energy products for the commercial markets (i.e. it can reduce the number of pricing points that participants need to use)
The PJM Market includes Financial Transmission Rights to allow participants to manage congestion risk
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How Are LMP Values Calculated ?
The following examples demonstrate how LMP values are determined at all locations
The LMP values are a result of security-constrained economic dispatch actions
LMP values are calculated based on generation offer data and the power flow characteristics of the Transmission system.
Constrained Case
E
A
B C
D240 MW Thermal Limit
SolitudeAlta
Park City
Brighton
600 MW$10/MWh
110 MW$14/MWh
100 MW$15/MWh
520 MW$30/MWh
200 MW$30/MWh
300 MW 300 MW
300 MW
Dispatched Dispatched at 600 MWat 600 MW
Dispatched Dispatched 100 MW100 MW
Dispatched Dispatched at 110 MWat 110 MW
Dispatch Solution Ignoring Thermal LimitDispatch Solution Ignoring Thermal LimitDispatched Dispatched
90 MW90 MW
Total Dispatched900 MW
253 253
174174
216
216
384384 8484
348
348
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Sundance
E
A
B C
D240 MW Thermal Limit
SolitudeAlta
Park City
Brighton
600 MW$10/MWh
110 MW$14/MWh
100 MW$15/MWh
520 MW$30/MWh
200 MW$30/MWh
Sundance
300 MW 300 MW
300 MW
Constrained Case
600 MW11
0 M
W
240 240
159 159
223
223
377377 7777
360
360
124 MW
LMPsLMPs$10.44$10.44
$23.51$23.51$21.14$21.14
$15$15
$30$30
Marginal Generators 15
66 M
W
Park City and Sundance supply the next increment of load on the system
Attempt to serve an additional increment of load (1 MW)
Resulting Sensitivity Factors determine LMP
Bus Location
Sensitivity Factors for 1 MWhof Load Supplied from:
Calculation Details
Park City@$15/MWh
Sundance@$30/MWh
A 1.00 MWh 0.00 MWh 1.00($15) + 0.00($30) = $15
B 0.59 MWh 0.41 MWh 0.59($15) + 0.41($30) = $21.14
LMPs and Flow Sensitivity Factors
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LMPs and Flow Sensitivity Factors
Bus Location
Sensitivity Factors for 1 MWhof Load Supplied from:
Calculation Details
Park City@$15/MWh
Sundance@$30/MWh
C 0.43 MWh 0.57 MWh 0.43($15) + 0.57($30) = $23.51
D 0. 00 MWh 1.00 MWh 0.00($15) + 1.00($30) = $30.00
E 1.30 MWh -0.30 MWh 1.30($15) + -0.30($30) = $10.44
Least Cost Security Constrained Dispatch Algorithm
Calculates least expensive way to serve load while respecting transmission limit
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What Are FTRs?
Financial Transmission Rights are …
a financial contract that entitles holder to a stream of revenues (or charges) based on the hourly energy price differences across the path
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Purpose of FTRs
To protect firm transmission customers from increased cost due to transmission congestion, when energy deliveries are consistent firm reservations*
To allow energy traders to purchase protection from transmission congestion charges on a specified path
To facilitate a forward energy market by providing a mechanism to manage basis risk caused by LMP differences during periods of transmission congestion
* Note: Risk-averse customers can enter into long-term supply contracts and purchase FTRs to become indifferent to the hourly LMP values
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Characteristics of FTRs
Defined from source to sink (point to point*) MW level based on transmission reservation Financially binding - an Obligation Financial entitlement, not physical right Independent of energy delivery
* Note: FTR Sources and Sinks can be single nodes or aggregated points such as Trading Hubs, Zones or Aggregates
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Obtaining FTRs
Network service based on annual peak load designated from resources to aggregate loads
Firm point-to-point service may be requested with transmission reservation designated from source to sink
Secondary market -- bilateral trading FTRs that exist are bought or sold
FTR Auction -- centralized market purchase “left over” capability
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Energy Delivery Consistent with FTR
Thermal Limit
FTR = 100 MW
Congestion Charge = 100 MWh * ($30-$15) = $1500
FTR Credit = 100 MW * ($30-$15) = $1500
LMP = $30
LMP = $15
Source (Sending End)
Sink (Receiving End)
Bus B
Bus A Energy Delivery = 100
MWh
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Energy Delivery Not Consistent with FTR
FTR Credit = 100 MW * ($30-$10) = $2000
Congestion Charge = 100 MWh * ($30-$15) = $1500
Bus A
LMP = $10
Bus C
LMP = $15
LMP = $30
Bus B
Energy Delivery = 100 MWh
FTR = 100 MW
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FTR Revenue Adequacy
In the PJM market, if congestion charges collected are less than the target value of the FTRs then the FTR credits are reduced proportionately
Reasons for FTR credit deficiency have been: Unexpected transmission outages Conservative operations due to unexpected Solar Magnetic Storms Lower than expected voltage performance Increased loop flows from neighboring control areas
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What is the Day-ahead Market?
A Day-ahead hourly forward market for electric energy. It provides the option to ‘lock in’: scheduled quantities at day-ahead prices scheduled energy deliveries at day-ahead
congestion price Fully financial, allows virtual demand and
supply bids
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Two Settlements
Day-ahead Market Settlement based on scheduled hourly quantities and day-ahead
hourly prices Real-time Market Settlement
based on actual hourly quantity deviations from day-ahead schedule hourly quantities and on real-time prices
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Example 1:LSE with Day-ahead Demand
less than Actual Demand
Day Ahead Market
Real-time Market
100 MW100 MW
Scheduled Demand Actual
Demand
105 MW105 MW
= (105 - 100)* 23.00 = $115.00
Real-time LMP = $23.00Day Ahead LMP = $20.00
= 100 * 20.00 = $2000.00
if Day-ahead Demand is 105MW = $2100.00
as bid = $2115.00
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Day Ahead Market
Real-time Market
200 MW200 MW
Scheduled MW
Actual MW
100 MW100 MW
Day Ahead LMP = $20.00
= 200 * 20.00 = $4000.00
Real-time LMP = $22.00
= (100 - 200) * 22.00 = $2200.00 payment
Example 4:Generator with Day-ahead MW greater than Actual MW
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Implications of Day-ahead Market
Day-ahead schedules are financially binding Demand scheduled day-ahead
pays day-ahead LMP for day-ahead MW scheduled pays real-time LMP for actual MW above scheduled paid real-time LMP for actual MW below scheduled
Generation scheduled day-ahead paid day-ahead LMP for day-ahead MW scheduled paid real-time LMP for actual MW above scheduled pays real-time LMP for actual MW below scheduled
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Ancillary Service Markets
Energy and energy transportation (transmission service) are the commodities that RTO customers need in the RTO market.
Ancillary Services (regulation, reserves, etc.) are services that the RTO needs to ensure reliable system under RTO market operations
Since Energy is the desired commodity, Ancillary Services should not dominate or distort the market
The market design should provide an efficient mechanism to acquire Ancillary Services without distorting the energy market
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PJM Regulation and Reserve Market Philosophy
Separate Real-time markets for Regulation and Spinning Reserve are co-optimized with the Energy market are the most efficient mechanism to acquire these services.
Day-ahead Energy market includes regulation and reserve constraints but does not have separate financial settlements for regulation and reserves.
Product substitution problem (substitution of regulation or reserves for forward energy) is handled by including lost opportunity cost component in regulation and reserve pricing
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Day-ahead Ancillary Service Model In theory, Day-ahead Ancillary Service markets with
separate availability bids are more efficient. In practice, the added complexity of separate Day-ahead
Markets for regulation and reserve does not result in efficiency gains.
With separate Day-ahead markets for these products, the complex interaction and product substitution issues make real-time dispatch less efficient
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Installed Capacity (ICAP) Requirement
Needed to ensure long term generation adequacy and short-term generation availability
In theory ICAP is not needed but in practice it is required for a variety of reasons
Generation receives revenue for selling ICAP service which is essentially a call on energy during periods of generation shortage
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Installed Capacity (ICAP) Requirement
ICAP resources in PJM have additional obligations: Must submit offers into Day-ahead Market Must be available to PJM in-day if not sold outside
PJM or on forced outage Energy can be sold outside PJM but is subject to recall
under capacity emergency conditions
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Section 2 - Agenda
Day-ahead Market Details Real-time Market Details Transmission Service and Transactions Ancillary Markets Demand Response Mitigation Measures
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Spot & Ancillary Markets
Market Flexibility Support bilateral transactions Self scheduling of supply Spot Market access
Market Information Internet posting system
Market Incentives Market Adaptation
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PJM Market Mechanisms
The PJM Market supports a variety of financial contracts that are separate from the physical spot market.
Day-ahead Energy Market Virtual supply offers Virtual Demand Bids Price-sensitive Demand bids “Up to” congestion bids for external transactions External transactions may submit separate Day-ahead financial energy profile
Financial Transmission Rights Financial Energy Contracts
PJM eSchedules
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Day-ahead Market Data Flow
Generation Offers Demand Bids Increment Offers & Decrement
Bids (virtual supply & demand) Load Forecast and Reserve
Requirements Hydro Unit Schedules Scheduled Transmission
Outages Bilateral Transactions Facility Ratings Net Tie Schedules PJM Network Model
TechnicalSoftware
Schedules for Next Day (generation & demand)
Transaction Schedules Day-ahead LMPs Day-ahead Binding Constraints Day-ahead Net Tie Schedules Day-ahead Reactive Interface
Limits Day-ahead Summary
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Day Ahead Energy Market
The PJM Day-ahead energy market is a day-ahead hourly forward market
Objective is to develop a set of financial schedules that are physically feasible Full transmission system model Unit commitment constraints Reserve requirements model
Day-ahead market results based participant demand bids and supply offers
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Develop day-ahead financial schedules
Coordinate financial schedules with
reliability requirements
Provide incentive for
resources & demand to submit
day-ahead schedules
Provide incentive for generation to follow real-time
dispatch
Fundamental Requirements
Day-Ahead Market closes
Day-ahead Results Posted & Balancing Market Bid period
opens
Balancing Market Bid period closes
Day-ahead Market determines commitment
profile that satisfies fixed demand, price sensitive demand bids, virtual bids and PJM Operating Reserve Objectives
minimizes total production cost
Reserve Adequacy Assessment focus is reliability updated unit offers and
availability Based on PJM load forecast minimizes startup and cost to
run units at minimum Transmission Security Assessment focus is reliability performed as necessary starting two
days prior to the operating day Based on PJM Load Forecast
Unit Commitment Analyses
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Day-Ahead Market
Financial model - degree of similarity to physical dispatch is determined by participant bids and offers
Full transmission model assures revenue adequacy for day-ahead schedules
Economic incentives drive convergence of day-ahead market and real-time market
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PJM Energy
MarketOptions for energy supply
CUSTOMERSIndustrial Commercial Residential
BilateralTransactions
PJMSpot MarketLoad Serving
Entities obtainenergy to
servecustomers
Self-scheduletheir own resources
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PJM Spot Market
Voluntary Bid Based Market Unit Specific (start-up, no-load and energy bids) External Transactions: Unit specific or Slice of System (energy only) generation may offer or self-schedule Bids “locked in” by noon day before with rebid period for generation not
selected day-ahead Generation Offer curves are for entire 24 hour period (no hourly changes in offer
prices are permitted) Generation status and self-scheduled quantities can change in-day with 20 minute
notice
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PJM Spot Market
Voluntary nature of spot market is a critical design feature to provide maximum number of options for participant
Transparent spot price and open, flexible spot markets are necessary to provide the maximum ability for participants to react to price signals. This allows the market to compliment reliable operations rather then hinder it.
PJM design provides both spot and bilateral options Risk-averse participants can lock in forward bilateral energy contracts and acquire Financial
Transmission Rights to become indifferent to the spot market prices. Municipalities with on-site generation can self supply and be indifferent to spot market price or can
react to market signals. Spot and bilateral and self-supply options are critical in all markets (i.e. energy, regulation, spinning
reserve, etc.)
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Real-time Economic Dispatch
Least-cost security-constrained dispatch optimizes energy and reserves and calculates unit specific dispatch instructions for the next five-minute period. (ex-ante dispatch)
LMP values calculated every five minutes based on actual generation response to dispatch instructions that were sent in the previous five minute period (ex-post pricing)
Real-time performance monitoring software determines if generator is following dispatch instructions.
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Real-time Market Incentives
Generation is incented to follow real-time dispatch instructions: If generation is following real-time dispatch instructions then it is
eligible to set LMP, otherwise it become a price taker. If generation is scheduled by PJM and is following real-time
dispatch instructions then it receives a revenue guarantee of at least its specified offer data, otherwise there is not revenue guarantee.
No penalties are imposed for over or under generation
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Efficient Real-time Markets
LMP pricing, pricing based on actual system operating conditions State estimator updated continuously (every minute) Same model for day-ahead market, system scheduling, dispatch, and
settlements High degree of consistency between generator LMP values and dispatch
instructions Consistency results in market confidence A large amount of real-time operational data is posted quickly, this also
gives market participants confidence
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Efficient Real-time Markets
The price of energy at each location is calculated and posted on the PJM website at five minute intervals.
Settlements are performed based on hourly integrated LMPs
Self-scheduled generation and transactions are price-takers Generator and transaction status can change in real-time
with 20 minute notice
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Look-ahead Dispatch
Performs least-cost security-constrained dispatch looking forward over the next four hours
Provides capability to view solutions at 15 minute intervals over the four hour period
Performs calculations of 15 minute integrated load forecast Reserve models are consistent between Day-ahead market,
look-ahead dispatch and real-time dispatch
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Look-ahead Dispatch
Accounts for unit operating constraints and for transaction ramp limits
Optimizes energy, reserves and regulation with full transmission model (DC model linearized every five minutes from AC operating point)
Surrogate voltage constraints are recalculated at 15 minute intervals using on-line AC security analysis software
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Look-ahead Dispatch
The following program modules have the capability to improve look-ahead performance by automatically adjusting input data based on recent operational performance: Load Forecast - adjust Load Forecast for future intervals by
measuring forecast performance over the last 30 minutes of operation
Generation Performance Monitor - Adjusts generation status and ramp capability based on recent operational performance (i.e. last 30 minutes)
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Transmission Service
PJM sells long-term and shorter Transmission Service (Network, Firm Pt-to-Pt and Non-firm)
Transmission service reservations enable market participants to reserve physical capacity to import, export or wheel through energy
Transmission Service rates are license plate and the rates are known at the time of purchase
Participants have the option to specify a dispatch price for imports/exports or to be a price taker (self-schedule)
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Transmission Service for External Transactions
Transmission Service is required to schedule energy transactions through PJM or to export energy from PJM.
Transmission Service is not required for Imports Transmission service reservations reserve ramp room for
external transactions At Market boundaries, seams problems can occur if energy
transactions between markets are curtailed with short notice by the market operator without coordination with neighbors
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Transaction Management
LMP efficiently controls transmission congestion while allowing a large degree of flexibility in the Market. PJM sells unlimited non-firm transmission service LMP values encourage market behavior to be consistent with
efficient power system operations eSchedules system allows participants to enter internal
financial bilateral transactions up to noon day-after the operating day
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A
B C
D
Implicit
Net Congestion Result between D and ALMP (D-A)
LMP (B
- A) LMP (C - B) LM
P (D - C)
Calculated CongestionLMP [(D-C)+(C-B) +(B-A)] = LMP (D-A)
Calculated CongestionLMP [(D-C)+(C-B) +(B-A)] = LMP (D-A)
Implicit
Bilateral TransactionSource Sink
Load and generation implicitly pay congestion by paying (receiving) LMP Transactions explicitly pay congestion by paying (receiving) LMP difference
Anatomy of a PJM Bilateral Transaction
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PJM’s Regulation Market
Regulation requirement set by PJM ISO at 1.1% of PJM forecast peak or valley demand
Obligation can be satisfied by: Bilateral contract Self-scheduling Spot purchase
Generators submit regulation offer data by 1800 day before
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What is Regulation?
Definition A variable amount of generation
capability under automatic control which is operated independent of the economic dispatch signal and can respond within five minutes
Generating units that provide fine tuning that is necessary for effective system control
Governors respond to minute-to-minute changes in load Regulating units correct for small load changes that cause
the power system to operate above and below 60 Hz for sustained period of time
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PJM’s Regulation Market
PJM executes regulation adequacy assessment and sets Regulation Market Clearing Price (RMCP) for each hour of next day at 2200 day before
Actual assignment of regulation to generators is made in real-time operations
Payment for regulation is higher of RMCP OR Offer Price + Opportunity Cost
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PJM’s Regulation Market
This design provides an real-time efficient market for regulation while recognizing the practical realities of system operation.
The forward floor price mechanism (RMCP) tends to reduce oscillation (switching units on and off regulation frequently) that can sometimes occur from the optimization results
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Successful Regulation Market Implementation
Prior to implementation insufficient regulation available in some situations
Post implementation observations sufficient regulation available purchase price remained the same significant improvement in system control
Results Reduced transaction notification times Evaluating regulation requirements
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Opportunity CostPayments
Regulation Market
Clearing Price
(Average Price per MWh of Regulation Purchased)
Regulation Market Prices
$0
$10
$20
$30
$40
$50
$60
$70
1Q99
2Q99
3Q99
4Q99
1Q00
Apr
May
00
Jun-
00
3Q00
4Q00
1Q01
2Q01
3Q01
4Q01
Before Market ImplementedAfter Market Implemented
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Spinning Reserve Market
Scheduled for implementation in late 2002 Similar in concept to regulation market Two types of products
Tier 1: Marginal, unloaded steam Tier 2: Condensers (CTs and hydro), steam reduced to provide spinning, and load
Tier 1 response is paid by event Tier 2 is a capacity payment Tier 2 hourly clearing price (SRMCP) is calculated hour-ahead
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Spinning Reserve Market
Obligations will be calculated based on load ratio share of the spinning requirement
Those with obligations will be able to fulfill them by: self-scheduling spinning reserve on owned resources trading spinning capability bilaterally purchasing from the spinning market
Spinning Reserve clearing price can vary by location when 500 kV reactive interface limits are binding
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Operating Reserves
Operating Reserve requirements are modeled in both Day-ahead and Real-time Markets
Payments for Operating Reserve are included in uplift that results from all other uneconomic operation of generation that is requested by PJM
Uneconomic operation of generation can occur for a variety of reasons including: Unit commitment constraints, Reserve requirement, Minimum run times, dispatch uncertainty, etc.
All generation make-whole payments are covered in Operating Reserves accounting
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PJM Ancillary Service Rates for 2001
Product Q1 Q2 Q3 Q4
Energy $33.77 $32.43 $41.71 $21.65
Regulation $0.48 $0.51 $0.56 $0.33
Day-aheadOperating Reserve
$0.17 $0.41 $0.37 $0.15
Balancing OperatingReserve
$0.99 $1.31 $1.23 $0.76
Spinning Reserve $0.13 $0.12 $0.15 $0.15
Regulation, Spinning Reserve are in $ per MWh of load
Day-ahead Operating Reserve is in $ per MWh of cleared Day-ahead demand
Balancing Operating Reserve is in $ per MWh of Balancing Deviation
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Active Load Management (ALM) Participants required to be LSEs, although not necessarily the
LSE serving the customer’s load Participants receive ICAP credit for nominated load –
significant financial penalties exist for non-performance Activated by PJM or LSE a limited number of times per
summer period, for limited durations Emergency Load Response Pilot Program
Participants not required to be LSEs, but must be PJM members (special membership available)
Activated by PJM immediately prior to ALM Participants receive higher of $500/MWh or LMP Costs allocated to all entities short to the energy market during
the hour of the reduction
PJM Demand Response Programs
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Economic Load Response Pilot Program Participants not required to be LSEs, but must be full
PJM members (no special membership) Reductions initiated by end-use customers based on
LMP Participants receive LMP minus their retail rate for
actual reductions Costs allocated to the LSE that would have served the
customer’s load
PJM Demand Response Programs
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2001-2002 Economic Option
Customer’s LSE charged LMP for reductions LSE credited customer’s retail rate Difference credited to the party that signed the
load reduction up with PJM
time
$$
Flat retailenergy rate
10
100
30
500
1000
20
Fluctuatingwholesale rate
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Demand Response Issues
Jurisdictional issues regarding end-use customers participating in the wholesale market
Socialization of program costs How much, if any, should be socialized and to whom? Is a causal allocation correct?
Metering requirements Can any customer get an hourly meter (i.e. fixed load profiles) If no hourly meter exist, what are the options?
Demand Response Incentives Should these programs mimic response to real time prices or
provide additional compensation?
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PJM Mitigation Measures: Design
Energy market offer cap = $1,000/MWh Energy market offer cap includes operating reserve
payments Start up and no load costs can be modified only biannually Regulation market offer cap = $100 plus opportunity cost Only one market-based offer curve per day
Hourly price offer changes not permitted
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PJM Mitigation Measures
Local market power mitigation (units built < July 9, 1996) Must run units are cost capped for determining LMP Receive greater of cost plus 10% or LMP Alternative methods to determine payment cap
Required submission of cost data by unit (units built < July 1996) If maximum economic output specified in day ahead offer is less
than in real time, forced outage ticket If unit classified as Max Emergency in day ahead and not in real
time, forced outage ticket
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PJM Mitigation Measures
Generator interconnection process (RTEP) Flexible capacity markets
Multiple capacity markets: Daily, monthly, multi-monthly Bilateral capacity markets Owned or contracted generation
Capacity markets Recall option on energy output during emergencies Day ahead offer requirement Penalty for withholding energy (forced outage adjustment) Facilitate retail access
Capacity market effective offer cap = capacity deficiency rate $177.30/MW-day
Allocation of capacity deficiency payments Interval market
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PJM Mitigation Measures
Transmission outage notification requirements and FTR auction Required notification period for transmission outages Required coordination of transmission outages Required coordination of generator outages Increment offers/decrement bids cannot create day ahead
congestion > real time congestion Publication of bid and other data Demand elasticity initiatives