1

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

3

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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The Energy Balance

58 6259 6160

DEMAND GENERATION

Losses InterchangePower

GeneratedLoad

Hertz

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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

62

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

73

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

74

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