Competitive Wholesale Power Market: Capacity Market By Raj Addepalli, Ph.D., CFA Presented at USEA-USAID Executive Business Meeting Bogota, Colombia July, 2006

New York Action Regulatory Restructuring – Flexibility Divesture of utility generation assets to eliminate vertical market power concerns Creation of the New York ISO Mid 1999 Wholesale and Retail Competition in the State Presently over 40% of customer load is supplied by competitive suppliers; remaining load is still supplied by host utilities as default service providers Utilities use a supply portfolio approach - includes certain long-term legacy contracts with divested generators, short-term purchases from generators and wholesale suppliers through bilateral contracts, purchases from the NYISO spot market, and financial derivatives to mitigate risk

The NYISO Control Area New York State: 19,157,532 people Peak Load Forecast of 33,295 MW 38, 340 MW Native Generation Over 335 generating units modeled Required Installed Capacity 39,288 MW 1700 MW in Demand Response 10,775 miles of High Voltage Transmission

2006 Capacity (MW) by Fuel Type

New York Market 91% Merchant Generation Regulated and Merchant Transmission Regulated Monopoly Distribution Competitive Retail Sales

New York Wholesale Markets Energy - Day-Ahead and Real Time Markets Installed Capacity Market Ancillary Services Markets Market based: Reserves (10 min spinning, 10 min non-spin and 30 minute reserves) Regulation Cost based: Voltage Support Blackstart Scheduling Demand Response Virtual Markets Transmission Congestion Contracts

New York Wholesale Markets- Energy Central Dispatch System Bilateral (forward) Contracts 50% NYISO Day-Ahead Market 45 – 50% Real Time <5% Bilateral Contracts outside the NYISO 50% NYISO Day-Ahead Market 45 - 50% NYISO Real-Time Market <5% 100%

Why Capacity Market? There is a continuing debate regarding whether there is a need for a separate capacity market or competitive markets should rely solely on energy markets to provide sufficient inducement for new entry. If reliability is not a criterion that needs to be satisfied, or if there is sufficient demand price elasticity, or if there is sufficient tolerance for very high energy prices, then perhaps one could consider reliance solely on energy markets - BUT we are not there yet.

ICAP Market Purpose Capacity markets were created to insure that a sufficient supply reserve margin would exist to assure the reliability of the electric system. A combination of bid/price cap energy market mitigation measures and the desired capacity reserve margin result in energy revenues that are insufficient, by themselves, to support new entry. Capacity market revenues provide the additional revenue stream that is needed to facilitate new entry.

Installed Capacity Market Reliability criterion of a one day in ten years loss of load expectation is established by the NERC’s Northeast Power Coordinating Council (NPCC). To meet the reliability rules, utilities and other load serving entities in New York are required to purchase capacity to meet forecast peak load plus 18% reserve margin Three Capacity Markets in NY New York City Long Island Rest Of State Six month strip auctions (summer and winter), monthly auctions and spot auctions are conducted by the NYISO The six-month and monthly auctions are voluntary Spot auction (deficiency auction) is mandatory If loads do not have sufficient bilateral capacity contracts, they are assigned the capacity cost based on the spot auction results

Original ICAP Market Design Demand Curve was vertical in nature Loads were required to purchase Minimum Requirement- bilateral or through NYISO market Deficiencies charged a high penalty Market proved dysfunctional Erratic ICAP prices When capacity is tight, ICAP prices spike When capacity levels exceed the minimum requirement, however, ICAP prices plunge Loads had no incentive to purchase ICAP above minimum Excess capacity beyond minimum not valued although it may help reliability Susceptible to market power abuse Suppliers had incentive to withhold to create deficiency

ICAP Demand Curve Original design used “vertical” demand curve Fixed minimum requirement Fixed deficiency charge New design uses “sloped” demand curve Price decreases gradually as supply increases Loads buy excess supply cleared in the auction Market function improved Prices less erratic Prices vary predictably with ICAP supply

Demand Curve Original ICAP Market Design vs. Sloped Demand Curve 5 10 5 10 15 20 25 96 98 100 102 104 106 108 110 112 % of Minimum Requirement $ per kW-month Original market design Sloped Demand Curve

Sloped Demand Curve The purposes of the sloped demand curve include (compared to a vertical one): stabilize revenue streams for generators reduce potential market power of generators provide for more predictable prices for sellers and buyers value capacity beyond the minimum level as having reliability value

Derivation of the Sloped Demand Curve The Sloped Demand Curve is specified in the tariff, and approved by FERC. The parameters are updated every three years. DC is a simple straight line defined by two points. The reference point is (X1,Y1) X1: The installed capacity requirement: 118% of peak load Y1: The cost of new entry for a peaker less anticipated energy and ancillary service market revenues X2: The capacity level where its value is zero: 132% of peak; Y2=0 The maximum price is capped at 1.5x the cost of new entry

Reference Point The analysis to help determine the reference point update last year was performed by a consultant, Levitan Associates, with the help of market participants. Key Assumptions include: Installed cost of a new peaker- Frame 7FA gas turbine for the ROS market Equipment (Power Island, Balance of Plant, Spare Parts Construction Owner’s costs (Development, Engineering during construction etc) Startup and Testing

Key Assumptions (contd) Size, Heat Rate Debt/Equity ratio: 50%/50% Cost of Money: 20 year debt @7.5% interest rate, equity (after tax) @12.5% Fixed O&M (property taxes, site lease, contract services, staffing, insurance, general and administrative costs) Depreciation life, Income Tax Rate etc From the above, compute annualized carrying cost of peaker

Key Assumptions (contd) Expected Energy Revenues Apriori Estimation Historic Based Expectations Deterministic Stochastic OR Post-fact hypothetical peaker based estimate Expected AS Revenues The annualized reference value is then adjusted for summer/winter periods

Items Debated Is there a need for introducing a sloped demand curve? Will the change induce new merchant entry - the ability to generate cash flows to cover cost of new entry over long-term Will it help keep needed existing economicgeneration from retirement? Should there be a forward market (beyond one year) component to the capacity market? What are the customer impacts - including quantity of ICAP to be purchased and the new market clearing price? Is there authority for NYISO or regulators to impose such a purchase obligation on the loads? How does regulatory uncertainty affect investor risk assessment?

Items Debated What should be the frequency for updating parameters? Derivation of each element in the reference price Y1 Levels of X1 and X2: should X1 be exactly at the minimum requirement or somewhat to the right of it? What should be the price to the left of X1? The slope of the demand curve stability vs volatility of prices customer impact impact on generator market power Monopsony power - the ability of large loads to enter into contracts ‘out of market’ with new suppliers to suppress market clearing prices

Resource Planning ISO Reliability Planning Process Pre restructuring, vertically integrated utilities built (or contracted for) needed resources to ensure reliability of the system In a restructured market, it is envisioned the market should address resource needs to ensure reliability Planning process is primarily designed to provide information to the market participants While market is expected to address resource needs, there could be instances of “market failure” and the market may not satisfy the resource needs In that case, there is a need for a back-stop solution to procure adequate resources to ensure reliability

Resource Planning Annual Comprehensive Reliability Plan NYISO does a 5-10 year Reliability Needs Assessment annually as a first step and identifies reliability based resource needs It seeks market based responses (transmission, generation, demand response) to meet the needs In addition, it seeks from the responsible utilities a “backstop regulated solution” in case market solutions do not materialize in a timely fashion; other entities can also offer an “alternate regulated solution” NYISO certifies projects that would technically meet the identified need without identifying a preferred solution Cost Allocation based on beneficiaries-pay methodology

Resource Planning “Economic” Planning process: Primarily intended to address congestion NYISO posts information on a historical basis on several quantitative metrics of congestion - to assist the market place Under what conditions should regulatory solutions be considered to alleviate congestion? Work in progress

Checklist Any time we consider changing the market design, we try to address the following: What is the affect on existing wholesale or retail competitive markets? Would it provide sufficient incentives for new generators to enter the market - lead to the entry of appropriate techonology and size generators? Would it provide sufficient incentives for existing generators to stay in the market, if economically appopriate? Will it lead to cost minimization to customers? Will it work as intended? Is it simple to implement? Is it a minor change or major change? What are the risks of implementing? Will it have unitended consequences? How are potential market power concerns addressed? Will it be transparent and clear to market participants and accepted by them? Is it easy to police and to ensure there is no abuse by market participants? Would it receive regulatory support?