Transcript Document

OPSI 10th Annual Meeting
Improving Generation
Performance
October 14, 2014
Marji Rosenbluth Philips
Director, Federal and RTO Services
7/20/2015
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DIRECT ENERGY
• One of the largest Gas and Electric Marketer/Manager in
the U.S.
• Natural gas and electricity sales to small, medium and large
sized businesses, public institutions and government
– Load Serving Entity; Demand Response Provider; Agent for
Generators; Toll Gas for Generators
• Sales in 2013
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85 TWh Retail Power sold (Rank #2)
12 TWh Wholesale Power sold
550 Bcf Retail Gas sold (Rank #1)
250 Bcf Wholesale Gas sold
Peak load in PJM January 2014 was around 9,000 MWs
• DE Would be sixth largest zone based on MWs served
Basic Principles of Capacity “Market”
• Must provide opportunity for recovery of and on
capital investment
– PJM must ensure pool of money available to
resources; meet just and reasonable standard
• Payment should be based on attributes that
contribute to reliability
• Risk/reward/performance penalties must provide
appropriate incentives
– Capacity suppliers manage ALL risk of meeting
obligations
Key PJM Objectives
• More MWs (esp. for Winter 2015)
• “Better” MWs
– Greater operational flexibility
• Market Stability
• Bottom Line:
• PJM’s Proposal looks more like a GUARANTEE
OF REVENUES
• No market stability for load
What were we paying for?
• PJM assured consumers that RPM was working
– Have seen significant new build under existing price
– RPM has forced the exit of more expensive units as
intended
• NERC Report on the Polar Vortex confirms that
PJM meets reliability standards
• Bottom line:
• Consumers have been over paying some
generation and underpaying others if RPM is not
meeting reliability needs
What are Consumers Now Being Asked to Pay
for During Transition?
• Winter testing
• Incremental Auction Purchase by PJM of up to 10,000 MWs for winter
PLUS DR MWs that “go away” because the CSP obligation is not matched
with specific LSE load provider customers
• Higher costs
• Generator assurance that it can meet its performance obligations
– Firm fuel, storage, dual fuel capability
• Bottom Line:
• Some units will “requalify” as “firmer” capacity without having to invest
any money to change their operations
• Generators unlikely to be able to develop storage, dual fuel capability or
enter into firm fuel contracts during the Delivery year of 2015-16
– Difficult to build storage or dual fuel in one year
– Most “firm” gas contracts have already been executed; suppliers will have to
pay a premium to acquire “firm” transportation for 2015-16
Demand Response
• The “EPSA” Order addressed jurisdiction, not
DR’s contributions to reliability
• DR does not go away in terms of its contribution
to the system simply because a new form of
compensation must be identified
• Bottom Line:
• By requiring CSP obligations to be matched with
specific LSE load or the DR capacity goes “poof”
leads to inefficient outcomes: the DR product is
still there and does NOT need to be replaced or
consumers paying more than they should
Flaws in the Transition
• BOTTOM LINE:
• Consumers are double paying (if not more) for
reliability; generators are shifting market risk to
consumers in exchange for guaranteed capacity
revenue stream
• LSEs are undermined in their attempts to contract
forward while guaranteeing generator revenues
• PJM taking other initiatives that will be far more
effective (and less costly) and should wait to see
how these changes impact markets before moving
to draconian change in RPM construct
Overkill? Responding to 1 in 10 Year Incident
• The MWs are there; DR performed well; no final decision on “EPSA”
• Winter testing ensures MWs are there
– And if it is not serving that purpose than why should load pay for it and it not be up to
the generator to manage its [availability/capacity] risk?
• Enhancements to the energy market and generation bidding (to reflect
true gas costs) will improve market revenues substantially
• Does nothing to change operational limitations on units that cannot run in
extremely cold temperatures
• Does nothing to change gas generator ability to procure gas if dispatched
through reliability run or if unit is located behind the city gate
• Procuring and paying for additional MWs for 12 months to cover 2 months
exposure (post 2015-16 IA)
Transition Issues
• Load will be double paying for additional MWs PJM
intends to procure
– Winter testing; 10,000 MWs and DR MWs
• Ironically units, such as nuclear, may rebid as higher
performing capacity and get paid more without
changing any operational practice
• PJM likely wind up clearing “bad” MWs that were not
able to clear the initial BRA
• Premature to eliminate DR as a capacity product
We Support Changes That Can Achieve the Same
Results:
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Eliminate Force Majeure and Out of Management Control Performance Excuse
– Allow risk premium in bids to reflect insurance costs, cost of operational
changes
(Do not need to raise compensation to all units)
Get Energy market pricing right:
– Increase energy cap to reflect true cost when generator fails to perform and
must buy out of its DA commitment
• Can Eliminate penalties if energy cap raised
– Ensure scarcity prices function effectively
– Ensure appropriate market oversight
– Reduce uplift costs and capture them through LMP
Distribute non-performance penalties to load that paid for performance
Changes We Support:
• Allow hourly Day Ahead offer bids to reflect gas costs
– For each electric day, there are two “gas” days – generators
should be able to reflect different pricing in their bids
– Note that moving the gas day to 4am does not address this
issue
• Allow Real Time bid offers to reflect the cost of gas
– May mean raising LMP cap as noted in previous slide
• Shorten bidding and dispatch solution program timing
to fall within the hours that gas is actively traded
– NAESB has recommended extending the closing of timely
gas nominations, which will facilitate this
Changes We Support
• PJM’s preparing for the role of DR in future
auctions
– Support PJM being prepared in the event that the
EPSA Order becomes final
– PJM does not need to act pre-emptively in
auctions that have already cleared
• Long standing FERC policy to not mandate retroactive
adjustments
Other Solutions to Explore
• ISO-NE model single base clearing price with greater
performance incentive in real time
– Underperforming generators compensate over
performing generators; customers net neutral
• Bifurcate procurement to monthly or seasonal quantities
so do not overpay for product needed only for 2 months
• Continue to enhance regulation market in ways that
reward flexibility and will lead to liquidity
• Work with states to develop demand response programs
that appropriately compensate demand resources for
reliability they provide during winter and summer
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Other Solutions to Explore
• Consider going back to original RPM proposal
that allowed PJM to create constraints in the
clearing model to acquire desired generator
attributes
– Example: Can add constraint to LDA to clear x
amount of dual fueled generation; that way there
is transparent benefit to consumers of why the
generator is getting enhanced payments