Locational Capacity Market Background and Overview

1. Locational Capacity Market Background and Overview Mark Karl ISO New England NEPOOL Markets Committee Westborough, MA 18 November, 03

2. Purpose of this Presentation • Report on work to date by the Power Supply Resource Adequacy Work Group (PSRAWG). • Group discussion has focused on developing a response to the FERC ICAP compliance order. • Although agreement has not been reached, the choices have been narrowed. • To meet the March compliance date, work must start with the full Markets Committee. • This presentation is intended to provide necessary background to MC members who have not participated in PSRAWG.

3. Presentation Outline • LICAP/ Reliability Background • Alternative Market Approaches Considered • Capacity Deliverability Concept • Locational ICAP Market • Next Steps

4. Reliability Background • Reliability rules regarding resource adequacy have not changed to reflect changes in generation interconnection requirements since NEPOOL markets opened. • Bucksport Decision overturned previous full interconnection standard in favor of a minimum standard. • Current ICAP rules still assume all generation is deliverable to all loads in New England. This is no longer true. • Because Interconnection Rules (or other rules) do not address deliverability, ISO-NE needs to create market mechanisms to address it.

5. Background - Markets • Many new resources have been built where it was convenient to locate and independent of regional deliverability issues • Many older resources are finding it difficult to remain viable. • Competition from newer units results in lower capacity factors (lower revenue from energy) • Competition from newer units results in lower energy revenues

6. Resulting Problem • Certain generators in specific locations are needed to maintain reliability. • Current Markets do not recognize the locational value of this capacity. • Given current levels of compensation, many of these generators may desire to retire or may go bankrupt. • FERC has recognized this problem and issued a compliance order requiring a market solution be filed no later than March 2004 for implementation by June 2004.

7. Alternative Approaches to the Reliability Problem • Direct or semi-direct payments to selected units • Reliability Must Run (RMR) Contracts, • Designated Congested Areas (DCAs), • Peaking Unit SafeHarbor Bids (PUSH Units). • Energy-Only Market Design • Develop a Regional Deliverability Criteria. • Improvements to the current ICAP Market: • Locational ICAP

8. Alternative Solutions – Semi-Direct Payments • Reliability Must-Run Contracts: • Interfere with the market and do not send a price signal. • Difficult to negotiate • In some states, State Regulation and Law do not clearly assign the responsibility to serve load • ISO cannot sign a contract – Can only send a request to FERC • FERC feels RMR contracts are a last resort

9. Alternative Solutions – Semi-Direct Payments (Continued) • Peaking Unit SafeHarbor Bids (PUSH Units). • FERC Ordered implementation pending March 2004 filing. • Minimal effectiveness at meeting revenue needs of generators in load pockets. • Locked in generation targeted by PUSH bids not running because of new capacity additions. • Designated Congestion Area Approach (DCAs) • Part of initial SMD filing but not accepted by FERC.

10. Alternative Reliability Solution – Energy-Only Market • Allows price to play its role to attract new capital through compensation of existing resources and incite others to enter the generation market. • Energy Price should also ration consumption by charging the actual cost of reliability (or resource scarcity) to the consumer - encourages demand response. • Competitive energy market could work without capacity payments. • Energy-Only Market requires a greater tolerance for price volatility and very high prices during scarcity.

11. Energy- Only Market - How it could Work • Hourly energy market clears at P1($/MWh), i.e the intersection of hourly demand and hourly supply curves. • Generators will remain in service if their market revenues cover their variable and avoidable fixed operating costs. D P1 S P1 Hourly Gross Operating Margin Q (MW)

12. Energy Only Market - How High could Prices be? • No specific study in place for NE. • General studies [e.g., Dynegy, C. 02] indicate that the $/MWh energy clearing price may be as high as $25,000 to satisfy the 1 in 10 reliability criteria. • Other Studies [e.g., Stoft, 01] indicate that the energy clearing price—under particular generation and load assumptions—could be in the range of $12,000 to satisfy the 1 in 10 reliability criteria.

13. Energy-Only Market Issues • Price spikes are not acceptable to certain customer classes. • Price volatility and large price swings are likely to be a handicap to finance investment in new generation. • Earnings Volatility puts upward pressure on project interest rates. • Unwillingness to trust the regulatory process to permit very high prices even when warranted. • A significant departure from current practice that will take long time to influence investment, during which time reliability and resource adequacy will suffer.

14. Alternative Reliability Solution –Deliverability • Deliverability is an aggregate concept – There are sufficient capacity resources on the system so that aggregate resources are deliverable to aggregate load. • PJM Approach - to receive capacity credit, a resource must be deliverable to load. • May Choose full or limited interconnection. • PJM Application • Load Deliverability • Generation Deliverability

15. Load Deliverability in PJM Load Deliverability - the ability to deliver energy from the aggregate of capacity resources to an electrical area experiencing a capacity deficiency.

16. Generator Deliverability Generator Deliverability - the ability of an electrical area to export capacity resources to the remainder of PJM to ensure that bottled capacity conditions will not exist at peak load.

17. Application of Deliverability to ISO-NE • First step would be to assess current state of generators and transmission system to determine how much capacity is deliverable • Second step would be to quantify additional transmission and generation neededto ensure capacity is deliverable to meet reliability requirements.

18. Deliverability in ISO-NE (Continued) • Issues: • Cost is unknown – required transmission reinforcement could be expensive. • Improvements to the system may need 5 to 10 years lead time. • Does not comply with FERC June 2004 requirement. • Does not address near-term generator revenue issues. • Allocation of transmission costs to the different stakeholders and allocation of deliverability rights to existing generators will be difficult to resolve. • Even PJM seems to be drifting away from deliverability.

19. Reliability Solution Under Development - LICAP • Recognizes locational value of capacity in load pockets (import constrained areas), and generation pockets (export constrained areas). • Help ensure that capacity resources located in import constrained areas receive locational value of capacity and remain operational. • Needed to address reliability concerns in certain locations within the New England control area within a very short time frame. • Planned for Implementation by June 2004 consistent with FERC Order.

20. Locational Capacity Market Goals • Assure that Regional Need for Capacity is Met (1 day in 10 year standard) • Assure that any incremental local needs for capacity are met • Local requirements imposed as a result of insufficient transmission and/or generation. • Address Reliability Must Run/PUSH Unit issues to permit elimination of these approaches.

21. Locational Capacity Market Design Objectives • Purchase sufficient capacity to assure that reliability standards are met • Recognize that, up to a point additional capacity above the minimum requirement provides additional reliability • Complement the energy market to provide a complete set of markets • Analysis of market results to date shows that price signals are insufficient to incent new investment. • Results hold true for both base-load and peaking units • Energy market net revenues are about $4.50 to $7.00/kw month lower than of full costs of new peaking unit or base-load combined cycle

22. Frequency of Energy Prices Under SMD (Fuel Adjusted - Day-Ahead Market, 3/1/03 – 9/30/03, at Trading Hub)

23. Contribution of Energy Market Toward Levelized Cost of New Capacity (Day-Ahead Market, 3/1/03 – 9/31/03, NEMA/Boston)

24. Contribution of Energy Market Toward Levelized Cost of New Capacity(Day-Ahead Market, 3/1/03 – 9/31/03, Connecticut)

25. Locational Capacity - Proposed Approach • Set pool and zonal capacity requirements, determine zonal transfer capability, and determine transfer rights ownership. • Assign zonal capacity responsibility using existing meter reader “tag” data. (Zonal responsibility equal to proportionate share of coincident peak times zonal requirement) • First Bilateral Trade Period • Monthly Supply Auction • Final Bilateral Trade Period • Conduct Spot Auction (Deficiency Auction) and settle Capacity Transfer Rights (CTR’s). • Track Load Shifting and conduct load shift accounting

26. LICAP - Proposed Market Design Concepts • Financial Rights Model (a.k.a., “LMP” or “Single Market” approach) • Least cost solution calculated for each zone based on bidding within each resource’s own zone and established transfer limits • Congestion rents allocated based on financial “Capacity Transfer Rights” allowing owner to collect payment stream equal to price difference between zones • Separate Price Calculated for Each Zone • Price clearing auction designed to minimize as-bid cost • Bids due for all zones/results announced for all zones at same time • Utilize both a supply and a deficiency (spot) auction • Spot (Deficiency) auction requires that prices in “downstream” zones be at least as high as prices “upstream” (e.g., import constrained zonal price >= rest of pool zonal price)

27. LICAP - Proposed Market Design Concepts • Method of allocating transmission rights (CTR’s) • Load in import constrained zones required to purchase a minimum of a specified percentage of their capacity from sources within the zone • Resources in export constrained zones permitted to sell only a limited portion of their capacity outside of the zone • Accommodate alternative allocations of transmissions rights • Rights are fully allocated. No surplus collection of revenue • Demand Curves • Used to address binary pricing issue • Bilateral Transactions • Stipulated as transfer of obligation at a specified zone • Fully accommodated

28. LICAP - Proposed Market Design Concepts • Monthly Supply Auction • Optional participation by load and resources • Virtual bidding allowed • Auctions cleared at least cost with no transfer of capacity to “downstream” zones (e.g., from rest-of-pool zone to import constrained zone) • Clearing Rules Identical to current auctions • Monthly Spot Auction (Deficiency Auction) • All remaining load obligations are procured in the zone in which loads are located and assets are sold in the zone in which they are located. • Participants receive payment for “Capacity Transfer Rights” with a value equal to the price difference between zones. (Financially equivalent to allowing some capacity in one zone to meet requirements in another.)

29. LICAP - Proposed Market Design Concepts • Capacity Transfer Rights • Act as perfect hedge, allowing holder to buy/sell outside of own zone and achieve preferable price • Financial instrument, not a physical right • Will be paid regardless of whether they are “used” • Unlike FTR’s, transfer rights cannot have negative value because price inversion cannot occur • Assumed to be settled at Spot (Deficiency) Auction prices

30. Locational Capacity – Demand Curve • Implement an Installed Capacity Market Demand Curve • Replaces the deficiency charge in the current market. (Needed because of the short term nature of the current ICAP market --- No Chance for New Entry to set price) • Prevents prices from going from near zero to near the deficiency charge when capacity goes from slightly surplus to slightly deficient • Complements energy market and provides additional incentives needed to support investment, recognizing reliability value provided by all capacity

31. ICAP Demand Curve • Demand Curve should equal deficiency charge when available capacity is just equal to the requirement • Demand Curve should equal zero at some point, recognizing that at that point additional capacity provides no measurable increase in reliability • Demand curve should reach a maximum at some point reflecting the fact it is unlikely that capacity will ever fall significantly below the requirement • Demand Curves may vary with location.

32. Sample Demand Curve $15 $/kW-month S1 Deficiency charge S 120% 100% % of Requirement

33. LICAP Market Implementation Issues • NEPOOL capacity markets have not addressed locational value issues and reliability impact of transmission congestion. • Sudden imposition of LICAP market requirements has the potential to create significant cost impacts. • Although LICAP prices may be correct, State Regulators have expressed considerable concern. • A way to mitigate rate impact issues may be to phase-in the impact of LICAP on the market.

34. Characteristics of an Effective Phase-in Mechanism • Considers planned additions of new transmission • Transparent and predictable • Acceptable to the stakeholders • Recognizes RMR contract terms • Assures continued operation of low capacity factor units needed for reliability

35. Possible Phase-in Methods • Change local demand curve annually allowing higher payments in successive years • Create separate demand curves for low and high capacity factor units • Supplemental payment for low capacity factor units • Assume lower demand curve for all units during the phase-in • Payment for capacity in this area should be somewhat higher than in the rest of market • Supplemental payment could be based on the difference between the initial demand curve and the end-state demand curve • Exempts low capacity factor units from phase-in

36. Work Plan • December, 2003 – Proposal Development with PSRAWG • December, 2003 – Detailed market Discussion at Markets Committee • January, 2004 – Final Draft of Market Rule Manual • February, 2004 – Draft Market Rules Manual voted on at NEPOOL Markets Committee • March, 2004 – NEPOOL Participant Committee Vote.