Market Reform Proposals

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Market Reform Proposals
Pete Fuller NEPOOL Markets Committee October 8,
2013
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Todays Discussion

• Proposed tariff language for NRGs market reform
  proposals
• Improved energy market pricing
• FCM as a capacity market
• Hedging as a commercial activity
• Pricing the FCM margin based on long-run costs

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Qualifier

• As currently structured and administered, FCM is
  deeply flawed
• Mitigation policies should provide the marginal
  existing resource a reasonable opportunity to
  recover all of its annual fixed costs
• A demand curve that recognizes the incremental
  value of additional capacity is essential,
  especially in the absence of a supply curve based
  on long-run costs
• Reliability reviews of existing resource offers
  (delist bids) should be eliminated all
  constraints that are to be enforced through
  planning or operability criteria should be
  specified in the auction requirements

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An Alternative to ISO-NEs PI Proposal

• 1) Address energy market pricing problems in the
  energy market
• Pursue rule changes to
• Consider including the full cost of meeting
  loadreservesall other constraints, rather than
  the incremental cost of the next MWh
• Eliminate price suppression from out-of-merit
  dispatch and other unpriced actions
• Eliminate any inappropriate hedging between DA
  and RT provided by ISO reliability actions
• Ensure alignment between DA and RT models of
  constraints and objective functions
• Allow some (all?) resources to include start-up
  and no-load costs in energy price offers

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An Alternative, continued

• Increase RCPFs (Section III.2.7A(c))
• Value of RCPFs could equal ISOs proposed PPR
  (5,455/MWh)
• That level of volatility may be excessive

Requirement Requirement Sub-Category RCPF
Local TMOR 250/MWh
System TMOR minimum TMOR 5001,000/MWh
Replacement Reserve 250/MWh
System TMNSR 8501,500/MWh
System TMSR 50/MWh
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An Alternative, continued

• 2) Make the capacity product a capacity product
• Define EFORp Hours
• the hours ending 1400 through 1700, Monday
  through Friday on non-holidays during the months
  of June, July, and August and hours ending 1800
  through 1900, Monday through Friday on
  non-holidays during the months of December and
  January. (current definition of Demand Resource
  On-Peak Hours)
• Calculate EFORp Hour Availability in each EFORp
  Hour using current definition of availability
  (III.13.7.1.1.3)
• Compare current year EFORp Hour Availability to
  historical 5-year period used to establish ICR
  and pay/charge deviations at 150 of Clearing
  Price, subject to annual caps (III.13.7.2.7.1.2)

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An Alternative, continued

• Poorly Performing Resources limit the criterion
  to three annual scores of 40 or less over four
  years
• Reference to Shortage Events no longer meaningful
• Penalty Caps
• Annual cap equal to Annualized FCM Payment
• Force Majeure cap equal to 20 of Annualized
  FCM Payment, subject to i) timely and accurate
  communications to ISO and ii) diligence in
  pursuing repairs

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An Alternative, continued

• 3) Eliminate Peak Energy Rent deduction
• Delete Section III.13.7.2.7.1.1 and associated
  references

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An Alternative, continued

• 4) Enable all resources to compete on the basis
  of long-run costs
• Establish allowable offer prices for existing
  resources (delist bids) based on average net
  long-run costs rather than net risk-adjusted
  going-forward costs
• Enable resources with approved prices above the
  DDBT to participate in the descending clock
  auction
• Changes primarily in III.13.1.2.3, Qualification
  Process for Existing Generating Capacity
  Resources and III.13.1.2.4, Qualification
  Determination Notification for Existing Capacity,
  as well as III.13.2.3.2 and associated references
• Establish the dynamic delist bid threshold (DDBT)
  at 80 of the Offer Review Trigger Price of a
  combustion turbine
• Eliminate FERC review of dynamic delist bids
  rejected for reliability (III.13.2.5.2.5.1(a)(i))

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An Alternative, continued

• Section III.13.1.2.3.2.1.2
• Net Average Long-Run Costs
• To the extent possible, all costs and operational
  data used in this calculation shall be the
  cumulative actual data for the Existing
  Generating Capacity Resource from the most recent
  full Capacity Commitment Period available,
  adjusted for inflation and anticipated
  incremental capital and operating expenses
  associated with the relevant Capacity Commitment
  Period. These are costs that are associated with
  the cost of owning and operating the resource
  subject to the obligations of a listed capacity
  resource during the Capacity Commitment Period
  (i.e., maintaining a constant condition of being
  ready to respond to commitment and dispatch
  orders). Costs should be net of anticipated
  energy and ancillary service revenues. Service of
  debt, depreciation and amortization, equity
  return, staffing, maintenance, capital expenses,
  taxes, insurance and other normal expenses that
  would be incurred in support of meeting the
  obligations of a Capacity Supply Obligation may
  be included.
• Replaces language and formula describing Net
  Risk-Adjusted Going-Forward Costs

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Additional Clean-up

• Additional clean-up proposals
• Table of FCM dates for FCAs 1-8 (III.13.1.10,
  III.13.2.1)
• Remove language associated with the floor price
  (III.13.2.7.3 and related references)
• Delete ARA dates that are in the past
  (III.13.4.5.1)

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• Comments and suggestions are welcome prior to the
  Committee votes.
• Thanks for your consideration.