standard market design technical presentation april 18, 2001
DESCRIPTION
Standard Market Design Technical Presentation April 18, 2001. Presented to the NEPOOL Participants by ISO New England And PJM Office of the Interconnection. Benefits of the Standard Market Design Market Design Overview Congestion Management Locational Marginal Pricing - PowerPoint PPT PresentationTRANSCRIPT
Standard Market DesignStandard Market Design
Technical PresentationTechnical Presentation April 18, 2001April 18, 2001
Standard Market DesignStandard Market Design
Technical PresentationTechnical Presentation April 18, 2001April 18, 2001
Presented to the NEPOOL Participants by ISO New England And PJM Office of the Interconnection
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Discussion TopicsDiscussion Topics
Benefits of the Standard Market Design
Market Design Overview
Congestion Management Locational Marginal
Pricing Financial Transmission
Rights
Energy Market Day-Ahead Market Real-time Market
Capacity Market
Real-Time Market
Ancillary Services Regulation Operating Reserves Spinning Reserves
Market Settlements
Next Steps
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Standard Market Design Standard Market Design Drivers for ISO-NEDrivers for ISO-NE
Implement Working Markets that have Congestion Management and Multi-Settlement, as quickly as possible Take advantage of software and lessons learned in
New England and elsewhere
Maintain allocation agreements negotiated by NEPOOL Participants
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Benefits of the Standard Benefits of the Standard Market DesignMarket Design
Increase ability of Market Participants to make decisions affecting their load and resources Self-Scheduling External Transactions
Assure that the price reflects the resources actually dispatched Use “Ex-Poste” price calculations
Only units following instructions set price price based on actual, not predicted dispatch
Achieve a better balance between decisions made by software and operators
Operators need to assure that decisions made by software are reasonable
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Increased Ability of Market Increased Ability of Market Participants to Make DecisionsParticipants to Make Decisions
Previous design required that Market Participants turn all choices into prices and software would make decisions
SMD enables Market Participants to: Self-Schedule Generators Self-Schedule External Transactions Self-Supply Regulation Self-Supply Spinning Reserve Hedge Financially in Day Ahead Market and
bi-laterally
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Self-Scheduling of GeneratorsSelf-Scheduling of Generators
In Day-Ahead Market, units can be self-scheduled up to their maximum output
Units can adjust output in real-time (either higher or lower)
This is done by specific request, not by submitting a price
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Scheduling of External Scheduling of External TransactionsTransactions
External contracts can be self-scheduled in both Day-Ahead and Real-Time
Contracts willing to pay congestion will continue to flow Unless self-curtailed Physical curtailment needed
Unlikely as transmission costs increase, self-curtailment will occur
Dispatch should result in Economic Self-Curtailment
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Achieving better balance between Achieving better balance between software and operator decision-software and operator decision-makingmaking
Operator will review all constraints operative on the system and select those that affect dispatch
Pricing will be ex-poste, reflecting actual dispatch and operator entered constraints.
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What the Standard Market What the Standard Market Design Doesn’t DoDesign Doesn’t Do
Change allocation in negotiated settlements in New England All financial congestion rights will be
auctioned Proceeds from auction will be allocated per
auction revenue rights in NEPOOL Agreement
Zonal pricing for load is retained
Market Design Market Design OverviewOverview
Market Design Market Design OverviewOverview
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Market ObjectivesMarket Objectives
Maintain System Reliability
Support an Efficient Market
Maximize ability of Participants to make market decisions
Provide value to all Participants
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Requirements for Efficient Requirements for Efficient MarketsMarkets
LMP pricing based on actual system operating conditions
State estimator updated continuously Same network model for day-ahead market,
system scheduling, dispatch, and settlements
Cost causation for pricing to market Participants. Locational Consistent with Day Ahead Market
Consistency results in market confidence in prices
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Standard Market Design Standard Market Design
Maintains fundamental structure of New England market Spot Market w/ Regional physical dispatch
Major Elements include: Capacity Market Energy Market Financial Transmission Entitlements Markets Ancillary Services Markets
Regulation Spinning
Congestion Congestion ManagementManagementCongestion Congestion
ManagementManagement
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Transmission CongestionTransmission Congestion
ISO-NE energy market will use Locational Marginal Pricing (Nodal and Zonal Pricing) to manage transmission congestion
Energy market includes overlying trading hubs and zones to provide standard energy products for commercial markets
Energy market includes FTRs (Financial Transmission Rights) to allow Participants to manage congestion risk
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What is LMP?What is LMP?
Pricing method ISO-NE will use to … Price energy purchases and sales in ISO-NE Market Price transmission congestion costs to move energy
within ISO-NE Control Area
Physical, flow-based pricing system
Prices are based on How energy actually flows, NOT contract paths
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GenerationMarginal
Cost
GenerationMarginal
Cost
TransmissionCongestion
Cost
Cost ofMarginalLosses
Cost to serve the next MW of load at a specific location, using the lowest production cost of all available generation,
while observing all transmission limits
Locational Marginal Price Locational Marginal Price
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LMP ModelLMP Model
Price of energy is based on actual operating conditions, as described by state estimator
Price of energy at each location will be calculated and posted on the ISO-NE website at five-minute intervals
Five-minute LMP values will be integrated at end of each hour; hourly value will be posted on website
Accounting settlements will be performed based on hourly integrated LMPs (after LMP verification procedure)
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LMP CharacteristicsLMP Characteristics
Based on … actual flow of energy actual system operating conditions
LMPs … are equal (except for losses) when transmission
system is unconstrained vary by location when transmission system is
constrained
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Locational Marginal Pricing ModelLocational Marginal Pricing Model (LPA = Locational Pricing Algorithm)(LPA = Locational Pricing Algorithm)
Real-timeData
StateEstimator
LPAPreprocessor
LPA
LPAContingency
Processor
LMP’s forall locations
Generator Offers
System EconomicDispatch Rates
DispatcherInput Binding Transmission
Constraints
Flexible GeneratingUnits & Offers
Energy DemandGenerator MWSystem Topology
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How will ISO-NE use LMP?How will ISO-NE use LMP?
Generators get paid at generation bus LMP
Loads pay a zonal price, which is derived from the load bus LMPs
Transactions pay congestion charges equal to difference between source and sink LMPs
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LMP Verification ProcedureLMP Verification Procedure
Purpose - Ensure that LMP values are accurately and completely calculated for each of the 288 five-minute intervals of the previous operating day.
Procedure: Market Engineers review dispatcher logs, program error logs, input data timestamps and
LMP results for each interval. Recalculate or Replace LMP values as required Notify Settlements Department that the LMP results are verified and ready to use in
accounting. Post daily LMP file on web by noon next day
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What are Financial What are Financial Transmission Rights?Transmission Rights?
Financial Transmission Rights are …
a financial contract that entitles holder to a stream of revenues (or charges) based on the hourly energy congestion cost difference between the source and sink
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Allocation of FTRS in Allocation of FTRS in NEPOOLNEPOOL
In its June, 2000 order, FERC approved an auction of all Financial Transmission Rights, with the proceeds of the auction being allocated to the holders of Auction Revenue Rights
This proposal and allocation will remain as part of Standard Market Design
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Auction Revenue Rights Auction Revenue Rights AllocationAllocation
FTR Auction Revenue allocated to: Those paying for new transmission
upgrades to the extent additional FTRs are created
Those paying Congestion Costs Transmission Customers Congestion Paying Entities NEMA Load Serving Entities
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Why Do We Need FTRs?Why Do We Need FTRs?
Challenge: LMP exposes Market Participants to price uncertainty
for congestion cost charges During constrained conditions, ISO-NE Market
collects more from loads than it pays generators
Solution: Provides ability to have price certainty FTRs provide hedging mechanism that can be traded
separately from transmission service
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Characteristics of FTRsCharacteristics of FTRs
Defined from source to sink
Financially binding
Financial entitlement, not physical right
Independent of energy delivery
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What are FTRs Worth?What are FTRs Worth?
Economic value determined by hourly LMPs in the Day Ahead Market
Benefit (Credit) Same direction as congested flow
Liability (Charge) Opposite direction as congested flow
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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
Energy Delivery Consistent Energy Delivery Consistent with FTR with FTR
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Congestion Charge = 100 MWh * ($30-$15) = $1500
FTR Credit = 100 MW * ($30-$10) = $2000
Bus A
LMP = $10
Bus C
LMP = $15
LMP = $30
Bus B
Energy Delivery = 100
MWh
FTR = 100 MW
Energy Delivery Not Energy Delivery Not Consistent with FTR Consistent with FTR
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Obtaining FTRs Obtaining FTRs
FTR Auction -- Centralized Market for Obtaining Financial Rights to Transmission Annual and Monthly Auctions for all available FTRs Startup - 2 periods of 6 month and Monthly Auctions
Secondary Market -- Bilateral trading FTRs that exist are bought or sold
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What is the FTR Auction?What is the FTR Auction?
Provides method of auctioning FTR capability that exists on transmission system
Allows market Participants to bid for FTRs and offer to sell existing entitlements
Energy MarketEnergy MarketEnergy MarketEnergy Market
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Spot MarketSpot Market
Voluntary offer-based market Unit Specific (start-up, no-load, and energy offers) Slice of external system (energy only) Offers “locked in” by noon day Ahead Daily energy offers for generators
Energy pricing based on Locational Marginal Pricing with overlying zones and trading hubs
Central unit commitment (voluntary) and security constrained dispatch (voluntary)
Day-Ahead forward market
Real-time spot market
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Market MechanismsMarket Mechanisms
Market supports financial contracts separate from physical spot market Will settle based on data submitted after the fact, giving
Participants ability to arrange sophisticated bi-laterals that ISO-NE will settle
Forward energy market Trading hubs Day-Ahead market (Two-Settlement system)
Transmission congestion - hedging mechanisms External Transactions may specify not willing to pay
congestion (ISO-NE curtails) or transactions may self-curtail (with notification)
Financial Transmission Rights
Financial energy contracts
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Energy Market OptionsEnergy Market Options
CUSTOMERSIndustrial Commercial Residential
BilateralTransactions with Generators
Spot Market
Load ServingEntities obtain
energy to serve
customers
Self-scheduleresources
External Bilaterals
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Energy Market Operations Energy Market Operations
Day-Ahead Market - create a set of financial schedules that are physically feasible
Re-bid period (4 p.m. to 6 p.m.) for units not accepted in day ahead market
Reliability Scheduling - performed after re-bid period Reserve adequacy Transmission security
Regulation Market - evaluate regulation adequacy and set regulation floor price
Real-time Operations - near-term scheduling and real-time, security-constrained economic dispatch
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Energy MarketsEnergy Markets
Day-Ahead Market Develop day-ahead schedule using least-cost
security constrained unit commitment and security constrained economic dispatch programs
Calculate hourly LMPs for next Operating Day using generation offers, increment bids, demand bids, decrement bids and external bilateral transaction schedules
Real-time Energy Market Calculate hourly LMPs from LMPs calculated every
five minutes, based on actual operating conditions
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Energy SettlementsEnergy Settlements
Day-Ahead Market Settlement Based on scheduled hourly quantities and day-ahead
hourly prices Includes both Energy and FTR Settlement
Real-time Market Settlement Based on actual hourly quantity deviations from day-
ahead schedule using real-time prices
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Day-Ahead Market Participation Day-Ahead Market Participation
Generation Resources Submit market-based offers Submit Self-schedule
Demand Submit fixed quantity & location Submit bids for price responsive load
External Transactions Submit schedules into the day-ahead market May specify maximum amount of congestion they are
willing to pay
Financial Submit increment offer Submit decrement bid
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Day-Ahead Market MechanismsDay-Ahead Market Mechanisms
Provides Market Participants with the option to ‘lock in’ day-ahead scheduled quantities at day-ahead prices
Provides additional price certainty to Market Participants by allowing them to ... Commit & obtain commitments to energy prices &
transmission congestion charges in advance of real-time dispatch (forward energy prices)
Submit price sensitive demand bids Inform ISO-NE of maximum congestion charges it is willing
to pay Submit increment offers & decrement bids (virtual demand
and supply positions)
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Day Ahead Energy MarketDay Ahead Energy Market
Day-Ahead energy market is day-ahead hourly forward market
Objective is to develop financially binding schedules that are physically feasible Full transmission system model Unit commitment constraints Reserve requirements model
Day-Ahead market results based on Participant demand bids and supply offers (both physical and financial)
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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
Day Ahead Market ObjectivesDay Ahead Market Objectives
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Day-Ahead Market Time LineDay-Ahead Market Time Line
6:00 pm6:00 pm
12:00 noon12:00 noon
12:00 - 4:00 pmDay-Ahead market
is closed for evaluation by ISO-
NE
4:00 - 6:00 pmRe-bidding period
Throughout Operating DayISO-NE continually re-evaluates
and sends out individual generation scheduleupdates, as required
Up to 12:00 noonISO-NE receives bids and offers for energy next Operating Day
midnightmidnight
4:00 pm4:00 pm
4:00 pmISO-NE posts day-
ahead LMPs & hourly
schedules
4:00 pmISO-NE posts day-
ahead LMPs & hourly
schedules
Day-Ahead Market closes
Day-Ahead Results Posted & Balancing Market Offer period
opens
Balancing Market Offer period closes
Day-Ahead Market determines commitment
profile that satisfies fixed demand, price sensitive demand bids, virtual bids, and Operating Reserve Objectives
minimizes total production cost
Reserve Adequacy Assessment focus is reliability updated unit offers and
availability based on 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 load forecast
Unit Commitment AnalysesUnit Commitment Analyses
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Day-Ahead MarketDay-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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Reserve Adequacy Reserve Adequacy AssessmentAssessment
Based on load forecast, physical generation assets, actual transaction schedules and full operating reserve requirements
Virtual bids and offers not included
To preserve economic incentives, any additional unit commitment needed for reliability objectives only minimizes cost to come on line (minimize startup and cost to operate at minimum output) and are settled at Real Time Prices
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Transmission Security Transmission Security AssessmentAssessment
Based on ISO-NE load forecast of actual system operating conditions
Performed starting 36 hours in advance of operating day and continuing up to real-time dispatch hour
Objective is to ensure reliability and to augment the transmission analysis that is performed in day-ahead market
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Day-Ahead Market Day-Ahead Market SubsystemsSubsystems
MarketsDatabase
EMS
RSC(Unit
Commitment)
Market UserInterface
SPD(EconomicDispatch &
Day-Ahead LMP)
STCA(SecurityAnalysis)
OtherSystems
DMT
SettlementsDatabase
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Market User InterfaceMarket User Interface
Logging in
Viewing market messages
Submitting generation offers
Submitting demand bids
Submitting increment offers and decrement bids
Submitting redeclarations
Viewing public & private day-ahead results
Managing portfolios
Responding to error messages
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Resource Scheduling & Resource Scheduling & Commitment (RSC)Commitment (RSC)
Performs security-constrained unit commitment based on generation offers, demand bids, and transaction schedules submitted by Participants
Enforces constraints – physical unit specific and generic transmission
Utilizes linear programming solver to create an initial unit dispatch
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Scheduling, Pricing, & Scheduling, Pricing, & Dispatch (SPD)Dispatch (SPD)
Performs security-constrained economic dispatch using commitment produced by RSC
Calculates hourly unit generation MW levels and LMPs for all load and generation buses
Considers additional generic constraints that affect dispatch, such as reactive interface limits
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Study Network Analysis Study Network Analysis (STCA)(STCA)
Creates model for each hourof scheduling day based on Network topology Generation MW profile produced by SPD Transmission outages
Performs AC contingency analysis using contingency list from EMS
Represents violations as constraints and passes them back to RSC and/or SPD for resolution
Real Time Market Real Time Market and Dispatch and Dispatch
Real Time Market Real Time Market and Dispatch and Dispatch
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Real-Time DispatchReal-Time Dispatch
Single control area
Central unit commitment and security constrained dispatch Unit specific (start-up, no load, and energy) Slice of external system (energy only)
Dispatches units committed in Day Ahead Market and Reliability Assessment
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Real-Time DispatchReal-Time Dispatch
Central constrained dispatch is basis for spot market
ISO-NE dispatches generation to meet “residual” load (not covered by self-scheduled or external bi-laterals )
Generation dispatch based on economics of generator offers, plus transmission constraints
Results of dispatch used to set Locational Marginal Prices and deviations from Day Ahead Market
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Unconstrained OperationsUnconstrained Operations
If no transmission constraints exist Generation is dispatched in merit order (respecting
operating limits) Highest cost generator requested to operate sets
clearing price (LMP) All LMPs are same across system except for
transmission losses
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Constrained OperationsConstrained Operations
Transmission constraints can prevent use of “next least-priced generator”
Higher priced generators closer to load (on constrained side of limit) must be used to meet load
Cost expressed as “security constrained re-dispatch cost”
Locational prices set based on generation used to control constraint
Capacity MarketCapacity MarketCapacity MarketCapacity Market
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Capacity MarketCapacity Market
PJM has a Capacity Market Current market similar to New York and New England
markets PJM West will have an available capacity market (6%
reserves/day)
A Capacity Market is needed to: Assure sufficient capacity exists within the region to
meet reliability standards Compensate 10 and 30 minute Non-Spin Capacity
until a Non-Spin Market or Markets are developed
New England can develop its own Capacity Market that meets these objectives
Ancillary Ancillary Services MarketsServices Markets
Ancillary Ancillary Services MarketsServices Markets
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Ancillary ServicesAncillary Services
Regulation Service
Operating Reserves (Net Commitment Period Compensation)
Spinning Reserves (planned)
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Ancillary Market ObjectivesAncillary Market Objectives
Support well functioning Energy Market
Market Flexibility Support bilateral transactions Self scheduling of supply Spot Market access
Market Information Internet posting system
Market Incentives
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SMD Regulation MarketSMD Regulation Market
Regulation requirement set by ISO-NE at X% of 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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SMD Regulation MarketSMD Regulation Market
SMD replaces current Automatic Generation Control market with a regulation market
Market will be in MWs, not Regs
Service and mileage payments will be incorporated into bids
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Description of Regulation Description of Regulation MarketMarket
Regulation Optimizer (REGO) is run after energy schedules and LMPs in Day Ahead Market
Objective is to meet regulation requirements at least cost
Selection of DA regulation resources based on merit order ranking of Regulation Offers plus opportunity costs from hourly schedules and LMPs.
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Description of Regulation Description of Regulation MarketMarket
Opportunity cost is estimated as: |LMP-ED|*GENOFF, where LMP = forecasted hourly LMP at generator bus, ED = price associated with generator setpoint to
maintain full regulation, and GENOFF = MW deviation between economic and
regulation setpoints
RMCP = highest merit order price of designated resources, and sets a floor price for the R/T market
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Description of Regulation Description of Regulation MarketMarket
Real Time regulation evaluation performed in same manner prior to start of hour utilizing real time LMPs
Real time opportunity costs plus Offers determine merit order selection of resources
Resources selected are compensated at higher of RMCP or real time opportunity plus Offers
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Real-time Operations (DMT)Real-time Operations (DMT)
Regulating Capability
Regulation
Assignments
LMPs, MWDispatch
Instructions
Dispatcher maintains regulating capability within a defined amount around Regulation Requirement
DMT runs periodically, alerting dispatchers when the actualprice of regulating units exceeds the day-ahead RMCP
EMSLPA Regulation
Signal
Markets Database
GenerationOwner
State Estimator Solution
DMT
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Operating ReserveOperating Reserve(Net Commitment Period Compensation)(Net Commitment Period Compensation)
Based on Principle that if generators are following ISO instructions, they receive their full offer costs Cleared offers for pool-scheduled generation
in day-ahead market are guaranteed to be made whole for the day
Accepted offers for pool-scheduled generation operating in the real-time market as requested are also made whole
Additional payments provided for generator cancellations, and generation reduced for reliability
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Spinning Reserves Spinning Reserves
Induce response by on-line, marginal resources through compensation
Introduce competition for spinning capacity
Compensate providers of spinning capacity on the basis of clearing price rather than actual cost
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Spinning ReservesSpinning Reserves
Market Under Development at PJM Assure Generators indifferent to providing
reserves or providing energy Compensate spinning resources that supply
reserves in a contingency Compensate resources backed down or
condensing to provide reserves in a contingency
ISO will seek NEPOOL approval and input as part of implementation of the market
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Ten Minute Non-Spin and Thirty Ten Minute Non-Spin and Thirty Minute Operating ReserveMinute Operating Reserve
The current Standard Market Design does not include a TMNSR or a TMOR Market
The capacity market design will be adjusted to address the removal of these markets
Market Market SettlementsSettlements
Market Market SettlementsSettlements
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Market SettlementsMarket Settlements
Customers receive monthly charges/credits for: Transmission Service (Network and Point-to-Point) Energy Markets (Day-Ahead and Real-time)
Day-Ahead and Balancing Spot Market Energy Day-Ahead and Balancing Transmission Congestion Point-to-Point Transmission Losses
Ancillary Services Regulation Market Operating Reserves (NCPC) Capacity Credit Markets (and excess/deficiency payments) Spinning Reserves
76
Comparison of PJM and SMDComparison of PJM and SMDSettlements Settlements
Two Settlement System
Operating Reserve (replaces NCPC)
FTR hourly settlement, Transmission Congestion charges and credits
Mwh based financial bi-laterals with ability to submit data noon the following day
Congestion Calculations done explicitly at each location
Marginal Losses done explicitly at each location
Zonal settlement for load
Totally Separate Transmission Tariff Settlements and Market Settlements.
Use current MIS system, with additional reports and columns, to deliver reports
Same as PJM Different from PJM
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Energy MarketsEnergy Markets
Day-Ahead Energy Market Settlement Hourly net energy market position priced at DA LMPs Net position based on cleared increment and generation
offers, decrement and demand bids, imports, exports, and bilateral energy transactions in the day-ahead market
Zone weighting based on historical weighting (previous week/month
Balancing Settlement of Real-time Energy Market Hourly deviation between real-time and day-ahead net spot
market energy positions priced at real-time LMPs Real-time net energy position based on real-time generation,
load, imports, exports, and bilateral energy transactions Zone weighting based on State Estimator loads at each node
78
Energy Markets Energy Markets (cont.)(cont.)
Transmission Congestion Day-Ahead and balancing charges based on LMP
differences between transaction source/sinks and between generation/ imports/bilateral purchases and load/exports/bilateral sales
Congestion credits (including any unscheduled transmission service by ISO-NE) allocated to FTR holders, with the value of FTRs based on day-ahead LMPs
79
Internal Bi-lateral Internal Bi-lateral ArrangementsArrangements
Current system for internal financial bi-laterals is complex and unwieldy Supports a limited number of possible financial
arrangements Requires significant software development to support
any additional types of contracts Reporting and administering in LMP would be difficult
Propose to increase Participant flexibility by adopting PJM approach to internal bilateral arrangements
80
SMD Internal ArrangementsSMD Internal Arrangements
Buyer, Seller or Agent submits MWH of contract to ISO by noon the day after the operating day
Contract confirmed by buyer and seller
Allows for greater flexibility and creative contracts outside ISO contract types.
81
Replaces Old Arrangements Replaces Old Arrangements
Load Asset Contracts (%)
Obligation Contracts (% of the buyers Obligation in the market)
Linked to Reserve Contracts (Either the MWHS flow at a specified rate in the Energy
Market or the MWHs are moved to the Reserve Markets)
Lack of Contract Confirmation
Summary Summary Summary Summary
83
Comparison of PJM and SMDComparison of PJM and SMD
Features the Same as PJM Two Settlement System Energy Market Operation Ex-Poste Pricing algorithm Regulation market Operating reserve replaces NCPC FTR auction methodology FTR concept Spinning reserve market (may be jointly
developed)
84
Comparison of PJM and SMDComparison of PJM and SMD
Features the Same as PJM A capacity market will exist
Transactions will be able to be self scheduled
Generators can change self schedules as desired
Virtual demand and supply bids in DEM
Limited financial bi-laterals with ability to submit data noon the following day
85
Comparison of PJM and SMD Comparison of PJM and SMD
Significant Differences between the SMD and PJM FTR allocation FTR Auction Revenue Allocation Inclusion of losses in day ahead market and
real-time losses Details of capacity market
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What was in ISO-NE and isn’t in What was in ISO-NE and isn’t in Standard market DesignStandard market Design
10 Minute Non-Spin
30 Minute Non-Spin
4 hour reserve
Ability to change bids in real-time
AGC Market with Regs
Support for exotic financial contracts
Capacity Market
Capacity Market
Reliability Scheduling
Ability to change Self-Schedules in real-time
Regulation Market
Ability to enter financial contracts day after
Functionality RemovedReplacement Functionality
Next StepsNext StepsNext StepsNext Steps
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Market Rule & Operating Procedures Market Rule & Operating Procedures Development ProcessDevelopment Process
PJM does not file“Market Rules” with FERC. They use Operating Agreement schedules.
Added detail is in PJM Manuals: Includes material in NEPOOL Market Rules and NEPOOL
Operating Procedures
Our objective is to: Conform NEPOOL Market Rules to PJM schedules in their
Operating Agreement Conform Operating Operating and administrative
Procedures to PJM Manual Format and content
No Change in NEPOOL Governance or Approval Authority
89
Market Rule & Operating Procedures Market Rule & Operating Procedures Development ProcessDevelopment Process
Market Rules - ISO-NE is creating Market Rule 1X from Schedule 1 of the PJM Operating Agreement
This will address the Core Markets and Settlements and will be filed with FERC
Additional detail needed from PJM is in PJM Manuals and will be incorporated into the NEPOOL Manuals
90
Market Rule & Operating Procedures Market Rule & Operating Procedures Development ProcessDevelopment Process
ISO-NE and NEPOOL will create NEPOOL Manuals which include detail from current Market Rules and our NEPOOL Operating Procedures consistent with Standard Market Design
NEPOOL Manuals will be approved by NEPOOL
Some details will go into ISO-NE Administrative Procedures
91
Next Steps in Market Next Steps in Market Development …Development …
ISO-New England is beginning process of creating NEPOOL Manuals
Reviewing the PJM Manuals and NEPOOL Operating Procedures and assembling a draft set of NEPOOL Manuals to maintain Standard Market Design and keep what is needed for New England
Draft will be circulated for NEPOOL review and approval
92
Market Rule 1X Market Rule 1X
Contains the Core Markets and Settlements
A Draft is being distributed today
This will be on the Markets Committee Agenda for April 25, 2001
It will be part of the resolution on May 9, 2001 at the Participants Committee
93
Next Steps: Approval ProcessNext Steps: Approval Process
April 23, 2001 presentation to NEPOOL Participants Committee
April 25, 2001 discussion of Market Rule 1X by NEPOOL Markets Committee
May 9, 2001 vote by NEPOOL Participants Committee
DiscussionDiscussionDiscussionDiscussion