Transcript No Slide Title

Capacity Adequacy
Jeff Bladen
Manager, Retail Markets
7/20/2015
©2005 PJM
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Reliability Assurance Agreement
Purpose
• Ensure capacity resource adequacy
• Provide coordinated planning of capacity resources
• Support development of robust, competitive marketplace
Membership
• All Load Serving Entities within PJM
• 70+ signatories
Filed with FERC
• Initial filing - June 2, 1997
• Available on the internet at:
http://www.pjm.com/documents/agreements/raa.pdf
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Capacity Obligations
• Objective: Predict the amount of
generation capacity the control area needs
to meet our reliability criteria (load will not
exceed the available generation, on
average, more than 1 day in 10 years).
• Plan: Estimate the margin required to
ensure reserves to handle:
– the expected peak load,
– with a factor to account for failure rate of
generation units.
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Capacity Obligations
Capacity Obligations are established under
the provisions of the Reliability Assurance
Agreement.
Installed Reserve Margin (IRM)
 Establishes the capacity required, above peak load, to ensure the
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reliability of the control area.
Estimated out three years in advance
Fixed one year prior to the start of the planning period (June-May)
Developed by Load and Capacity Subcommittee using
probabilistic methodologies and best available data.
Approved by the Planning Committee and Reliability Assurance
Agreement - Reliability Committee
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Forecast Pool Requirement
Calculation of
Forecast Pool Requirement
(1 + IRM) * (1 - PJM Average Forced Outage Rate)
or
(1 + .15) * (1 - .0653)
=
1.0749
* Factors displayed will be effective through May 31, 2006
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Zone Forecasts
PPL
PEPCo 7,111 MW
RECO
6,566
PSEG
418 MW
MW
PE
10,231 MW AE
8,086 MW
2,588 MW
FE
11,277 MW
DPL
3,869 MW
AEP
22,823 MW
DOM
17,434 MW
APS
8,420 MW
DQE
2,663 MW
DAY
3,601 MW
ComEd
22,211 MW
BGE
6,900 MW
Sum of Entity Forecasts : 134,198 MW
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Sub-zone Obligation Example
EDC = 7,023 MW
PECO
8,086 MW
LSE #1 = 537 MW
LSE #2 = 526 MW
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LSE #1 Obligation
Peak Load Contribution
500 MW
Forecast Pool Requirement
X
Unforced Obligation*
=
1.0749
537.45
MW
* Simplified example. Assumes a zonal scaling
Factor of 1.0, and ignores the ALM factor.
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• Current Installed Capacity Markets:
How Well Have They Worked? What
Changes Were Needed? What Changes
Are Proposed ?
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Current Capacity Market Issues
• One price fits all
– Not coupled to Locational Value
– Not coupled to operational
reliability
– Not coupled to value provided
• Insufficient information to drive
behavior
• Limited forward certainty
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Drivers for Capacity Market Reform
• Generation Net Revenue Shortfall
• Inconsistency between capacity pricing
and reliability requirements
• Result has been
• Generation Retirement
• Lack of New Capacity
• Need for short-term corrective action
• Upcoming Reliability Violations in 2008
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Figure 2-9 PJM energy market net revenue by unit
marginal cost: Calendar years 1999 to 2004
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PJM Daily and Monthly Capacity Credit Market (CCM)
performance: Calendar years 2000 to 2004
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New Jersey Capacity Summary
• Generation Retirements
• 1,973 MW (2003-2004)
• 2,439 MW proposed (2005-2007)
• 680 MW possible (2009 – Oyster Creek Nuclear)
• Load Growth
• 2,200 MW (2004 – 2009)
• Declining Generation Additions
• 111 MW (2003-2004)
• 920 MW under construction
• 4 MW under study in interconnection process
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Analysis results highlighting problems delivering capacity
to Eastern PJM starting in 2008
Legend
Pass
Fail
Violation
Resolved
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Alternatives
• Do nothing
• Risk of blackouts
• Retain retiring generators
• Will not be enough
• Add new generation
• Need over 4,000 MW of new generation, current capacity
construct will not support investment
• Build transmission
• Need $600-700 million in transmission upgrades
• Cannot be built fast enough
• Some rights-of-way may be unattainable
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Integrating Capacity with Regional Transmission
Planning
• Must have an integrated solution – need
generation and transmission
• Cannot build enough transmission fast
enough to resolve problems
• Need locational price signals
• Need to build generation in proper location
based on deliverability shortfall
• Need price signals and sufficient lead time
• Generators must have sufficient incentives
and time to respond in order to compete with
transmission
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What is the RPM?
• Reliability Pricing Model (RPM) is PJM staff’s
proposal for a new resource adequacy
construct
• RPM is part of an integrated approach to
ensuring long term resource adequacy and
competitively priced delivered energy
• RPM aligns the price paid for generation
capacity with overall system reliability
requirements
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Reliability Pricing Approach
• Forward auctions
– residual procurement after specification of selfsupply and bilaterals
– cleared based on generation offers, demand
obligation and reliability metrics
• Reliability metrics
– locational constraints
– generator operating characteristics that enhance
reliable operations
• cycling units, dispatchable units
• units capable of supplying supplemental reserve
– fuel diversity
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Proposed Timing of RPM Auctions
4 Years
23 months
13 months
4 months
June
Self- Supply
& Bilateral
Designation
EFORd
Fixed
May
Planning
Year
ILR
Base
Residual
Auction
Incremental
Auction
Incremental
Auction
Incremental
Auction
Ongoing Bilateral Market – (shorter-term reconfiguration)
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RPM Simulation results
May 2007 – June 2008
Value of Capacity ($/MWday)
May 2008 – June 2009
May 2009 – June 2010
The increase Capacity Import
Capability into Southern NJ is due to
Transmission upgrades effective May
2009
$20 - $39 =
$40 - $59 =
$60 - $79 =
$80 - $99 =
$100 - $119
=
$120 - $139
=
$140 - $159
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Key Benefits of RPM
• Provides integrated Demand Response
participation
• Incents new resources to offer into Forward
Auction
• Allows merchant Transmission solutions to
offer incremental import capability into
constrained areas to compete with generation
solutions
• Provides stable capacity price signal to incent
sustained investment where needed
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