Market Reform Proposals

1. Market Reform Proposals Pete Fuller NEPOOL Markets Committee October 8, 2013

2. Today’s Discussion • Proposed tariff language for NRG’s 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

3. 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

4. An Alternative to ISO-NE’s PI Proposal 1) Address energy market pricing problems in the energy market • Pursue rule changes to: • Consider including the full cost of meeting load+reserves+all 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

5. An Alternative, continued • Increase RCPFs (Section III.2.7A(c)) • Value of RCPFs could equal ISO’s proposed PPR ($5,455/MWh) • That level of volatility may be excessive

6. 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)

7. 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

8. An Alternative, continued 3) Eliminate Peak Energy Rent deduction • Delete Section III.13.7.2.7.1.1 and associated references

9. 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))

10. 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’

11. 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)

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