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NARUC COMMITTEE ON ELECTRICITY:. CAPACITY MARKETS. NARUC COMMITTEE ON ELECTRICITY:. CAPACITY MARKETS Julie Simon.
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NARUC COMMITTEE ON ELECTRICITY: CAPACITY MARKETS
NARUC COMMITTEE ON ELECTRICITY: CAPACITY MARKETS Julie Simon
Capacity Marketsand Other Means of AssuringAdequate Generating Capacity:How do alternative proposals for ensuring adequate generation supply stack up? NARUC Winter Committee MeetingsWashington, D.C.February 14, 2006
Overview: Constellation Energy • FORTUNE 200 competitive energy company headquartered in Baltimore • North America’s No. 1 supplier of energy to wholesale and to retail commercial and industrial customers in competitive markets • A major generator of electricity with a diversified fleet of power plants located throughout the U.S. • A regulated distributor of electricity and natural gas in Central Maryland Vision: To be the first-choice provider for customers seeking energy solutions in the complex and changing marketplace
We Know Energy We serve customers across the energy value chain
Benefits of Competition • GED/EPSA study: customers saw $15.1 billion in value from wholesale electric competition in Eastern Interconnection (1999-2003) • CERA study: US residential customers paid $34 billion less for electricity over the last seven years than they would have under a traditional regulatory model • ISO/RTO Council: ISOs/RTOs improve grid reliability, improve operating efficiencies, promote regional planning, and lower consumer energy costs by providing transparency, liquidity, facilitating risk management and providing market monitoring • Competition better allocates risks, disciplines prices, and enhances efficiencies
Need to assure adequate generation, without creating stranded costs Need to value capacity “A nickel ain’t worth a dime anymore.”
“It is very difficult to make predictions, especially about the future.” Most regions of the country have adequate generation for the near term 2006 Forecasted Reserve Margins* WECC 32 percent SPP 31 percent MAIN 28 percent New England 28 percent ECAR 27 percent SERC 27 percent New York 25 percent MRO 22 percent MAAC 20 percent * CERA North American Electric Power Watch, Winter 2005/06
“Baseball is 90% mental. The other half is physical.” Well-designed competitive markets: • Value reliability • Capacity is part of the “energy commodity” • Markets make the dollar value more transparent • Send accurate price signals • Forward price signals incent forward contracting • Differentiate scarcity pricing from market power • Impose mitigation narrowly to address market power • Mitigation creates a “free” regulatory hedge • Have clear and consistent rules
“When you come to a fork in the road, take it.” • Energy-only is an end-state vision • If we are serious about providing better price signals, capacity market constructs should continually transition to energy-only • Modifying mitigation measures to better reflect scarcity pricing and incent demand response • Reduce capacity payment over time as mitigation is modified and energy prices provide an adequate revenue stream for investment
“You don’t want to make the wrong mistake…” • Price signals are interrupted by excess mitigation • $1000 bid cap • Must run contracts • Conduct and impact test • Local market power mitigation • Imports and reserves that do not set price • Mitigated energy market price signals are insufficient to incent: • Development of new generation when and where needed • Economically efficient retirement decisions • Forward contracting by load and generation • Demand response • Transmission expansion
“In theory, there is no difference between theory and practice. In practice, there is.” Well-designed capacity markets: • Replace the “missing money” caused by mitigation • Encourage load and generators to sign forward contracts • Value location • Adequate generation in the market-wide footprint does not necessarily mean adequate capacity in specific locations • Balance transmission, generation and demand response • Value desired planning reserve levels (Demand Curve) • Cannot require a 15% reserve margin and not pay for it • Smooth boom and bust cycle • Include an adequate planning horizon • It takes years to build a power plant • Timing drives fuel source
“You can observe a lot just by watching.” • All markets have demand curves: • If the demand curve is sloped, not vertical: • Value reliability beyond the required reserve margin • Help manage boom and bust cycle • Accurate price signals are the best “guarantee” of needed investment
Questions? Julie Simon Managing Director National Energy Policy & Regulatory Affairs Constellation Energy 750 E. Pratt Street, 14th Floor Baltimore, MD 21202 410-783-5214 julie.simon@constellation.com
NARUC COMMITTEE ON ELECTRICITY: CAPACITY MARKETS Hoff Stauffer
Market Stability and The Cost of Capital NARUC Winter Meetings Committee on Electricity Presented by Hoff Stauffer February 14, 2006 Washington, DC
An Important Concept Has Apparently Been Missing • This is the clear link between market stability (meaning low capacity price volatility) and the cost of capital. • Market stability is clearly good for consumers because it reduces the cost of capital and the capacity price. • Proper design of the capacity markets can achieve market stability.
Conceptual Framework • The structure of the markets determines cash flow volatility. • Cash flow volatility determines the financial structure used to finance capacity additions. • The financial structure determines the cost of capital. • The cost of capital determines capacity prices. • Capacity prices determine customer costs.
Financing Structure Determines Cost of Capital(illustrative example) WACC = % Debt * Cost of Debt * (1 – tax rate) + % Equity * Cost of Equity
Capacity Prices Are Lower in a More Stable Market Market Structure StableUnstable WACC 5.9% 17.2% Real Capital Charge Rate 6.1% 20.1% Initial Capital Costs ($/kw) $400 $400 Annual Capital Charges ($/kw-year) $24 $80 FOM $10 $10 Energy Margin ($2) ($2) Capacity Price ($/kw-year) $32 $88
Capacity Prices Determine Consumer Costs CONSUMER COSTS $/kwh Market Structure StableUnstable Energy Costs $45 $45 Other Costs $15 $15 Capacity Price* $ 9 $25 Total Costs $69 $85 * at 40% load factor
Effect of Contract Term on Capital Charge Rate CCR Contract Term in years
Design Options for Market Stability • Extend effective date of auction far enough in the future to permit new entry • Extend the term of the contract (the longer the better) • Give RTO authority to “manage” new capacity • Demand curves (but hard to get right)
Contact Information Hoff Stauffer Managing Director Wingaersheek Research Group 9 Dune Lane Gloucester, MA 01930 Office 978-281-1674 Cell 617-407-2632 Email hoff@hoffstauffer.com
NARUC COMMITTEE ON ELECTRICITY: CAPACITY MARKETS Ronald McNamara
Capacity “markets” - substitutes for a good price? NARUC February 14, 2006 Ron McNamara
Study of Prices in Constrained Areas • Two markets were studied • PJM • ISO-NE • Prices from both Day-Ahead and Real-Time Markets were analyzed for both peak and off-peak hours of the day. • Prices were analyzed three different ways: • Nominal • Real Term • Fuel Adjusted
PJM Market • Delmarva Peninsula is an area in PJM that often suffers import limits • Delmarva Power (DPL) was used as a surrogate for analyzing the Delmarva Peninsula constrained market. • Prices in Delmarva were compared with PJM system wide prices. • In addition Delmarva prices were compared to prices at the Western Hub. • Western Hub was used since much of the transmission congestion that affect DPL prices would not affect Western Hub prices.
PJM Market • In nominal terms, DPL prices are somewhat higher than the PJM system or Western Hub of PJM prices given the congestion into DPL. • The relative price analysis shows the same effects. • Both the Day-Ahead and Real-Time market display the same price dispersion between the constrained and unconstrained regions of PJM for most of the hours of the day. • While the DPL prices spike higher than PJM and Western Hub prices, the average effect of these spikes may not be large enough to drive needed investment in Delmarva infrastructure.
RealPrice(PPI Base = 2000) • DPL Western Hub and PJM System wide prices were adjusted for inflation (PPI). • In real terms, the price spread between the constrained market price of DPL and PJM price is very narrow at best. • Western Hub real price series is the lowest since 1999, except around July 2005 when it started to rise above PJM price. • Price divergence between constrained and unconstrained markets is not clearly discernable most of the period.
