electricity market
TRANSCRIPT
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PJM Organization and Markets
Saudi DelegationColumbus Ohio
May 22, 2012
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Agenda
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Introduction & GovernanceEnergy Markets
LMP
FTRs/ARRs
Two Settlement
Virtual Bids
Ancillary
Capacity - Reliability Pricing Model
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What is an RTO?
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A Regional Transmission Organization (RTO) is:
– Independent from all market participants
– Responsible for grid operations and reliability – Responsible for transmission service within region
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PJM Demographics
Complexity
1365 Generation Resources with Diverse FuelOver 56,250 Miles of Transmission LinesOver 60 Million People Served
UniquenessSingle Control Area in NERC Region Area Served: 13 States + DC
Members/CustomersMember Companies ~ 760 +Transmission Svc. Customers ~ 100 +158,450 MW Peak Load (July 21, 2011)
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PJM Service Territory
PJM©2010 6 5/30/2012
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Transmission Owner Zones
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Nine Major North American RTOs / ISOs
PJM©2010 8 5/30/2012
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PJM Functions
3 – Plan for transmissionexpansion on a regional basis
Grid Operat ions
- 24/7 Monitor in g ofTransmiss ion Lines
- 24/7 Generation &Load B alance
Market Operation
- Energy-Capaci ty
- An ci l lary Services
RegionalP lanning
15 Year look- ahead toensure transmission
capability
1a & 1 b
2
3
1a – Monitor the high-voltagetransmission grid for reliability
1b – Balance generation and load onan instantaneous basis
2 – Operatecompetitive,
non-discriminatory
markets
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Function 1a - Monitoring the Bulk Power System for Reliability
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Operations Goal – Keeping the RTO in Balance at All Timeswhile Respecting Transmission LimitationsFunction 1b
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Electricity Markets - Match Buyers and Sellers
Sellers - Supply ResourcesFossil, Hydro, Nuclear, RenewableFERC Approved Power Marketers
B uyers - Wholesales EntitiesLoad Serving Entities
FERC Approved Power Marketers
Function 2
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Planning an Adequate and Reliable Transmission System
The Regional Transmission Expansion Planning Processidentifies upgrades to meet customers’ requirements:
• operational
• economic
• reliability requirements
Merchant Generation Base Line Upgrades
Function 3
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How is PJM different from the local utility?
PJM does:• Direct operation of the transmission system• Remain profit neutral
• Maintain independence from PJM members• Coordinate maintenance of grid facilities
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How is PJM different from the local utility?
PJM does not:• Own any transmission or generation assets.• Function as a publicly traded company.
• Take ownership of the energy on the system.• Perform the actual maintenance on generators or
transmission systems.• Serve, directly, any end use (retail) customers.
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Governance
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Two Tier Governance Structure
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Independent Board (10)
Members Committee (Sectors)
GenerationOwners Transmission
Owners
OtherSuppliers
ElectricDistributors
End-UseCustomers
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Members Committee Voting Protocol
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Transmission Owners
Generation Owners
Other Supplier
End Use Customers
Electric Distributors
5/7 0.71
2/8 0.25
21/23 0.91
5/5 1.00
Required to pass = 0.667Number of Sectors = 5
Required Affirmative = 5 x 0.667 = 3.335
3.47
3/5 0.60
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PJM Committee Structure
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Dispatch Function
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5/30/2012
Valley Forge Control Room
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5/30/2012
Milford Control Room
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Dispatch Functions
• Ensure sufficient generation is available orrunning to satisfy the demand at any hour ofthe day including maintaining adequatereserves. This is called Generation Control .
• Monitor, operate and control the high voltagetransmission system in a reliable manner.This is called Transmission Control .
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Load Curve – Summer Profile
26 5/30/2012
RTO Load (MW)
70000
80000
90000
100000
110000
120000
130000
140000
150000
T i m e
( E P T )
0 : 3
9
1 : 1
9
1 : 5
9
2 : 3
9
3 : 1
9
3 : 5
9
4 : 3
9
5 : 1
9
5 : 5
9
6 : 3
9
7 : 1
9
7 : 5
9
8 : 3
9
9 : 1
9
9 : 5
9
1 0 : 3
9
1 1 : 1
9
1 1 : 5
9
1 2 : 3
9
1 3 : 1
9
1 3 : 5
9
1 4 : 3
9
1 5 : 1
9
1 5 : 5
9
1 6 : 3
9
1 7 : 1
9
1 7 : 5
9
1 8 : 3
9
1 9 : 1
9
1 9 : 5
9
2 0 : 3
9
2 1 : 1
9
2 1 : 5
9
2 2 : 3
9
2 3 : 1
9
Long, gradual rise
Significantpersistence
2+ hour drop offAt 9,000 MW/Hr
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Load Curve – Winter Profile
27
RTO Load (MW)
70000
75000
80000
85000
90000
95000
100000
T i m e
( E P T )
0 : 3
9
1 : 1
9
1 : 5
9
2 : 3
9
3 : 1
9
3 : 5
9
4 : 3
9
5 : 1
9
5 : 5
9
6 : 3
9
7 : 1
9
7 : 5
9
8 : 3
9
9 : 1
9
9 : 5
9
1 0 : 3
9
1 1 : 1
9
1 1 : 5
9
1 2 : 3
9
1 3 : 1
9
1 3 : 5
9
1 4 : 3
9
1 5 : 1
9
1 5 : 5
9
1 6 : 3
9
1 7 : 1
9
1 7 : 5
9
1 8 : 3
9
1 9 : 1
9
1 9 : 5
9
2 0 : 3
9
2 1 : 1
9
2 1 : 5
9
2 2 : 3
9
2 3 : 1
9
4-hour pickupAt 4,000 MW/Hr
3-hour eveningpeak period
4-hour drop offAt 4,500 MW/Hr
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Locational Marginal Price
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What is Locational Marginal Price?
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Pricing method PJM uses to:price energy purchases and sales inPJM Marketprice transmission congestion costs to
move energy within PJM RTOprice losses on the bulk power system
Physical, flow-based pricing system:how energy actually flows, NOTcontract paths
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How does PJM Use LMP?
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Generators get paid at generation bus LMPLoads or Customer Demand pay at load bus LMPBilateral Transactions pay differential in source andsink LMPPJM LMPs are the result of the physical flow ofenergy, not a contract path
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Locational Marginal Price
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SystemEnergy
Price
TransmissionCongestion
Cost
Cost ofMarginal
Losses
LMP is made up of 3 independent components
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LMP Components - System Energy Price
PJM©2009 33
SystemEnergy
Price
TransmissionCongestion
Cost
Cost ofMarginal
Losses
System Energy PriceRepresents optimal dispatch ignoring congestion andlosses
Same price for every bus in PJM
Calculated both in day ahead and real time
Intersection of the Supply and Demand Curve
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LMP Components - Congestion
PJM©2009 35
SystemEnergy
Price
TransmissionCongestion
Cost
Cost ofMarginal
Losses
Congestion PriceRepresents price of congestion for binding constraints
Calculated using cost of marginal units controlling constraints andsensitivity factors on each bus
Will be zero if no constraintsWill vary by location if system is constrained
Calculated both in day ahead and real time
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LMP Components - Congestion
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Limit = 1000 MW
Load = 1500MW$20 Power
$50 PowerSystem Energy Price = $20Congestion = $ 0
Losses =LMP = $20
System Energy Price = $20Congestion = $30Losses =LMP= $50
Dispatch 1000 MWFlow = 1000 MW
Dispatch 500 MW
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LMP Components – Marginal Losses
PJM©2009 37
SystemEnergy
Price
TransmissionCongestion
Cost
Cost ofMarginal
Losses
Loss PriceRepresents price of marginal losses
Calculated using penalty factorsWill vary by location
Calculated both in day-ahead and real-time
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Transmission Losses
Real Power (MW) LossesPower flow converted to heat in transmission equipmentHeat produced by current (I) flowing through resistance (R)
Losses equal to I2R
Heat loss sets the “thermal rating” of equipment
Losses increase with:Lower voltageLonger linesHigher current
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LMP Components Marginal Losses
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Limit = 1000 MW
Load = 1500MW$20 Power
$50 PowerSystem Energy Price = $20Congestion = $ 0
Losses = ($ 1)LMP = $19
System Energy Price = $20Congestion = $30Losses = $ 2LMP= $52
Dispatch 1000 MWFlow = 1000 MW
Dispatch 500 MW
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What are FTRs?
Financial Transmission Rights are …
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financial instruments awardedto bidders in the FTR
Auctions that entitle the
holder to a stream ofrevenues (or charges) basedon the hourly Day Aheadcongestion price differences
across the path+
LMP =SystemEnergyPrice
CongestionPrice
MarginalLossPrice
+
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Why do we need FTRs?
Challenge:Protect Load Servers from price uncertainty for congestionchargesRedistribute excess congestion charges
Solution:FTR credits equal congestion charges on same path
FTRs provide hedging mechanism that can be tradedseparately from transmission service
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• Economic value based on Day AheadCongestion Component of LMP
• Defined from source to sink• Financial entitlement, not physical right• Independent of energy delivery
Characteristics of FTRs
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Energy Delivery Consistent with FTR
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Source(Sending End)
Thermal Limit
FTR = 100 MW
Congestion Charge = 100 MW * ($30-$15) = $1500
Congestion= $30Congestion = $15
Sink(Receiving End)
Bus BBus A Energy Delivery = 100 MWh
FTR Credit = 100 MW * ($30-$15) = $1500
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PJM©2009 46
100 MW FTR
SourceLMP =$18
System Energy = $20Congestion = ($3)Marginal Loss = $1
SinkLMP =$29System Energy = $20Congestion = $7Marginal Loss = $2
FTR Value = 100 MW * (7 - (-3)) = $1,000 Credit
“Prevailing Flow” FTRs point in the same direction as the congestion”
FTRs as a Benefit
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PJM©2009 47
100 MW FTR
SinkLMP =$18
System Energy = $20Congestion = ($3)Marginal Loss = $1
SourceLMP =$29
System Energy = $20Congestion = $7Marginal Loss = $2
FTR Value = 100 MW * ((-3) - 7) = $1,000 Liability
“Counterflow ” FTRs point in the opposite direction of the congestion”
FTRs as a Liability
Ob i i
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Obtaining FTRs
Annual AuctionMulti-roundMulti-periodMulti-productEntire System Capability
Secondary market -- bilateral tradingFTRs that exist are bought or sold
Monthly & Balance of Planning Period FTR Auction --centralized market
purchase “left over” capability
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Wh FTR W h?
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What are FTRs Worth?
Economic value determined by
Day ahead hourly LMPs
Benefit (Credit)Prevailing Flow
Liability (Charge)Counterflow
FTR Options availableNever negatively valued
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Wh ARR ?
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What are ARRs?
Auction Revenue Rights …
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are entitlements allocated
annually to Firm TransmissionService Customers that entitle theholder to receive an allocation of
the revenues from the AnnualFTR Auction
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Wh t th h ld d ith th FTR?
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What can the holder do with the FTR?
“Self -Scheduling” FTR into Annual Auction on exactsame path as ARRReconfigure ARR by bidding into Annual Auction to
acquire FTR on alternative path or for alternativeproductMay retain allocated ARR and receive associatedallocation of revenues from the auction
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Two Settlement
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Wh t i T –S ttl t?
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What is Two –Settlement?
It provides PJM Market Participants with theoption to participate in a forward market forelectric energy in PJM
Consists of two marketsSeparate settlements performed for each market
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Two Settlement Markets
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Two-Settlement Markets
• Day-ahead Market
– Financial market using Bid-In Load – Prices calculated hourly / Hourly settlements – Includes virtual bids and price sensitive demand
• Real-time Market – Physical Market based on actual system conditions – Prices calculated every 5 minutes – Hourly Settlements based on deviations from Day-Ahead position
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Day Ahead Market Timeline
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Day-Ahead Market Timeline
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6:00 pm
12:00 noon
12:00 - 4:00 pmDay-ahead market isclosed for evaluation
by PJM
4:00 - 6:00 pm
Re-bidding period
Throughout Operating DayPJM continually re-evaluates and sends
out individual generation schedule
updates, as required
Up to 12:00 noon PJM receives bids andoffers for energy next
Operating Day
midnight
4:00 pm
4:00 pm
PJM posts day-aheadLMPs & hourlyschedules
Day Ahead vs Real Time LMP 2009
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Day-Ahead vs. Real-Time LMP - 2009
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Virtual Bids
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INCS vs DECS
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INCS vs. DECS
• Look like a generator(injects MW)
• Specifies a price andquantity
• Turns on when the pricegets high enough
64
INCS DECS
• Look like a load(withdrawals MW)
• Specifies a price andquantity
• Turns on when the pricegets low enough
How do virtual bids make money?
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How do virtual bids make money?
• Sells MW into Day AheadMarket at High Price
• Buys replacement MW
from Real-Time Market atLower Price• Hopes that Day-Ahead
Prices are Higher thanReal-Time Prices
PJM©2009 65
INCs DECs
• Buys MW from DayAhead Market at LowPrice
• Sells those MW in Real-Time Market at HigherPrice
• Hopes that Day-AheadPrices are Lower thanReal-Time Prices
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Ancillary Services
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Ancillary Services
• Regulation Market• Synchronized Reserve Market• Black Start Service• Reactive Services• Scheduling, System Control & Dispatch
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Regulation Market
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Regulation Market
Purpose: To provide for the continuous balancing of generation
and load
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• Generation and Demand Response resources
• Transmission customer must provide or purchase• RMCP = Regulation Market Clearing Price• Regulation Price = Higher of RMCP or offer price plus
opportunity cost
Synchronized Reserves Market
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• LSE’s have obligation to purchase based on Load Ratio
Share – Bilateral – Scheduling owned resources – Purchase from Synchronized Reserve Market
• Co-optimized with Regulation Market• Allows for participation by Demand Side Response
resources
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Purpose: To bring generation and load back in balance after the
loss of generation
Synchronized Reserves Market
Blackstart Service
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• Transmission Owners, with PJM identify critical
Blackstart units• Generator annual revenue requirements - Cost-
based service• Charges go to Transmission Customers
• Annual Blackstart testing requirements
Purpose: To provide for the continuous balancing of generation
and load
Blackstart Service
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Scheduling, System Control & Dispatch
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Scheduling, System Control & Dispatch
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• Schedule 9 of PJM Tariff
- Control Area Administrative Service- FTR Administrative Service- Market Support Service- Regulation Administrative Service
- Capacity Resource and Obligation Service
Purpose: To provide transmission service and operate the energy
market.
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Capacity vs. Energy
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p y gy
Capacity
• A commitment of a resourceto provide energy duringPJM emergency under thecapped energy price.
• Capacity revenues paid tocommitted resourcewhether or not energy isproduced by resource.
• Daily product
Energy
• Generation of electricalpower over a period of time
• Energy revenues paid toresource based on
participation in PJM’s Day -Ahead & Real-Time EnergyMarkets
• Hourly product
Capacity, energy & ancillary services revenues are expected, in the long term, to meet thefixed and variable costs of generation resources to ensure that adequate generation is
maintained for reliability of the electric grid.
Objectives of RPM
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j
• Resource commitments to meet system peakloads three years in the future
• Three year forward pricing which is aligned with
reliability requirements and which adequatelyvalues all capacity resources
• Provide transparent information to all
participants far enough in advance for actionableresponse
Purpose of RPM is to enable PJM to obtain sufficient resources to reliably meet the needsof electric consumers within PJM.
Resource Adequacy Requirement
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q y q
• Determines the amount of capacity resourcesrequired to serve the forecast peak load andsatisfy the reliability criterion.
• The reliability criterion is based on Loss of LoadExpectation (LOLE) not exceeding one event inten years.
An Installed Reserve Margin (IRM) = 15.3% satisfies the reliability criterion for the2013/14 Delivery Year.
Resource Adequacy ICAP Requirement = Forecast Peak Load * (1+ IRM)
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Locational Deliverability Areas
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y
• Regions – Western PJM (ComEd, AEP, Dayton, APS, Duquesne, ATSI, Duke) – Mid-Atlantic Area Council (MAAC) Region – Eastern MAAC (PSE&G, JCP&L, PECO, AE, DPL & RECO) – Southwestern MAAC (PEPCO & BG&E) – Western MAAC (Penelec, MetEd, PPL)
• Zones – AE, AEP, APS, ATSI, BGE, Comed, Dayton, DUQ, Dominion, DPL, Duke,
JCPL, MetEd, PECO, Penelec, PEPCO, PPL, PSEG
• Sub-Zones – PSEG Northern Region (north of Linden substation) – DPL Southern Region (south of Chesapeake and Delaware Channel)
* Includes ATSI effective with 13/14 DY and Duke effective with 14/15 DY.
PJM required to make a filing with FERC before adding a new LDA.
RTEPP has currently identified 25* sub-regions as Locational Deliverability Areas (LDAs) for evaluatingthe locational constraints.
RPM Structure3 Years
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Base ResidualAuction
DeliveryYear
SecondIncrementalAuction
ThirdIncrementalAuction
June May
3 months
10 months
FirstIncrementalAuction
20 months
EFORdFixed
Ongoing Bilateral Market
InterruptibleLoad forReliability (ILR)(Only effectiveprior to 12/13DY)
May
Feb.
July
Sept
ConditionalIncremental
Auction Effective12/13 DY)
May bescheduledat any timeprior to DY
Mar
RPM Auctions (Starting with 12/13 DY)
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( g )
Activity Purpose Cost of Procurement
Base Residual Auction Procurement of RTO Obligation less anamount reserved for short lead timeresources, less FRR Obligation
Allocated to LSEs through LocationalReliability Charge
1st Incremental Auction Allows for:(1) replacement resource procurement(2) increases and decreases in resource
commitments due to reliability
requirement adjustments; and(3) deferred short-term resource
procurement
Allocated to resource providers thatpurchased replacement resourcesand LSEs through LocationalReliability Charge2nd Incremental
Auction
3rd Incremental Auction
Conditional IncrementalAuction
Procurement of additional capacity in aLDA to address reliability problem that iscaused by a significant transmission linedelay
Allocated to LSEs through LocationalReliability Charge
Interruptible Load forReliability (ILR)
ILR Option eliminated starting with 12/13 DY
What is the VRR?
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• The price is higher when the resources are less thanthe reliability requirement and lower when theresources are in excess.
• VRR Curves are defined for the PJM RTO and for
each constrained Locational Deliverability Area(LDA) within the PJM region.
The Variable Resource Requirement (VRR) Curve is a downward slopingdemand curve that relates the maximum price for a given level ofcapacity resource commitment relative to reliability requirements.
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www.pjm.com
Source: PJM 2014/15 Base Residual Auction Report
Clearing 2012/2013 Base Residual Auction
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Clearing determined by the intersection of the supply and the demand curves.
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