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Robert G. Ethier, Ph.D. Director, Market Monitoring May 5, 2004 ISO New England State of the Market Report 2003.

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Presentation on theme: "Robert G. Ethier, Ph.D. Director, Market Monitoring May 5, 2004 ISO New England State of the Market Report 2003."— Presentation transcript:

1 Robert G. Ethier, Ph.D. Director, Market Monitoring May 5, 2004 ISO New England State of the Market Report 2003

2 2 Fuel Prices and Energy Prices Electricity prices were driven to high levels by fuel prices, which are the largest component of generators’ marginal costs, and to a lesser extent by load levels. The next figure shows that monthly energy prices for 2002 and 2003 have been driven by fuel price trends. –Natural gas prices were 74% percent higher than 2002 on average. –Nearly half of New England capacity is gas-fired or gas capable. Electricity prices peaked in February and March as natural gas prices rose to unprecedented levels. –The July Peak Summer Load was much lower.

3 3 Fuel Prices and Energy Prices (Continued) Electricity prices increased less than gas prices because economic dispatch substituted other, cheaper fuels. –Gas-only units were on the margin 52% of the time in 2003 versus 55% in 2002, despite approximately 6,000 MW of new gas capacity added over the two years. –Gas-capable units were on the margin 67% of the time in 2003.

4 4 New England Electricity & Natural Gas Prices: 2001 - 2003 SMD Implementation

5 5 Energy Prices in 2003 The next figure shows real-time price duration curves for 2001 to 2003. –These curves show the percentage of hours when the load-weighted price for New England is greater than each given price level. Price levels were generally higher in 2003 than in the previous two years due to higher fuel prices. In 2003, there were fewer price spikes than the two previous years: –In 2003, real-time prices exceeded $500 for 1 hour, compared to 4 hours in 2002 and 15 hours in 2001. –The lower quantity of price spikes was primarily due to milder weather in New England combined with relatively robust capacity margins. Scarcity pricing provisions were implemented, but were not triggered in 2003.

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7 7 Load Profile The next figure shows annual load duration curves for New England. –These curves show the percentage of hours in which the load is greater than the level indicated on the vertical axis. In 2003, peak days had far less impact on average prices than in 2002. The absence of severe price spikes was due to mild summer loads. –There were only 19 hours in 2003 when actual loads exceeded 24,000 MW, compared to 34 hours in 2002. –In 2003 there were 200 hours when load exceeded 21,000 MW compared to 263 hours in 2002.

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9 9 All-in Energy Prices The following figure calculates an “all-in” price that includes the cost of energy, ancillary services, capacity, and other costs. –The all-in energy price is a weighted average of various locations within New England, since energy prices vary by location. –Ancillary services includes reserves and regulation prior to SMD, and regulation after SMD implementation. This figure shows that all-in prices rose in 2003. –The all-in price rise is primarily caused by increased energy prices in 2003, which rose 41% in 2003 due to higher fuel prices. (from $41.65/MWh to $55.36/MWh) –The capacity component fell in 2003 due primarily to increases in installed capacity. While the energy component increased in 2003, the fuel adjusted energy price fell relative to 2002.

10 10 All-In Price Metric 2001 - 2003 ($/MWh) Total per MWh Energy, Uplift, Capacity, and Ancillary Costs Includes Energy and Fuel Adjusted Energy Total Energy Fuel Adjusted Total Energy UpliftCapacity Ancillary Services Note: Energy Interim Market Period = ECP * System Load ; SMD Period = RT Load Obligation * RT LMP Energy Costs Fuel Adjusted Energy Costs

11 11 Economic Incentives for New Investment In long-run equilibrium, the market should support the entry of new generation by providing sufficient net revenues (revenue in excess of production costs) to finance new entry. We calculated the net revenue the markets would have provided to different types of units in 2003. –A gas-fired combined-cycle (heat rate= 7,000). –A gas-fired combustion turbine (heat rate=10,500).

12 12 Economic Incentives for New Investment (Continued) Even though energy and all-in prices were higher in 2003, the net revenue for gas-fired units was lower in 2003 than 2002 due to gas price increases. –New capacity added in 2002 and 2003 also reduced net revenues. These results indicate that the market in 2003 did not produce sufficient net revenue to support investment in a new gas turbine (GT) or a new combined-cycle (CC) unit. –A new GT would only recover 16% - 21% of its estimated annual fixed costs for 2003. –A new CC would only recover 64% -73% of its estimated annual fixed costs for 2003.

13 13 Economic Incentives for New Investment (Continued) This was done pool-wide because LMPs existed for only a portion of the year –A unit in Connecticut, for example, would have earned additional revenue.

14 14 Net Revenue Metric 2003 All Values in $/MWhCombustion Turbine UnitCombined Cycle Unit Energy revenues 1 $58,773$315,239 Energy marginal costs 2 $47,907$241,792 Net Revenue: Energy$10,867$73,447 Revenue: Capacity 3 $1,972 Revenue: Ancillary Services 4 -$1,492 Total Net Revenue$12,839$76,912 Estimated Annual Fixed Costs$60,000-80,000$105,000-$120,000 1 Energy revenues are calculated as the revenue per MW of a hypothetical unit assumed to be dispatched during each hour when the market clearing price equals or exceeds the unit's marginal cost, adjusted for a 5% forced outage rate. Revenues are calculated based on the system wide energy clearing price prior to SMD (March 1, 2003), and based on the real-time Hub LMP from March 1, 2003 onward. 2 Energy marginal costs are calculated as the average Massachusetts natural gas daily spot price multiplied by the unit's respective heat rate + the unit's respective variable O&M. These marginal costs are then adjusted for a 5% forced outage rate. 3 Capacity revenues for year ending 12/31/2003 are the UCAP revenues derated by the 5% forced outage rate. 4 Ancillary service revenues are calculated only for Regulation.

15 15 Forced Outages The next figure presents the trend in the forced outage rates from the beginning of the operation of the New England Markets. –The forced outage rate is the percentage of time capacity is unavailable due to full or partial forced outages. Total outage rates have declined substantially following the implementation of markets in New England. –This is consistent with the incentives the deregulated markets provide to maximize availability, particularly during high load (on-peak) conditions. –Previous analysis suggests that new combined-cycle units initially have high outage rates. New England has many new combined-cycle units. Improvements in outage rates may be expected as these units mature.

16 16 Percent of Installed Capacity Out of Service, Weekdays 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% 20.0% 19992000200120022003 % of Avg. Ann. Installed Capacity PlannedUnplannedTotal

17 17 Congestion Costs The following figure shows the monthly average congestion components of LMPs in the day-ahead and real-time markets for March through December 2003. Maine had significant negative congestion as generation was periodically constrained down due to export constraints. Connecticut had significant positive congestion as it was periodically import constrained. Northeastern Massachusetts/Boston experienced less congestion than expected based on historical data due to significant generation additions and transmission upgrades. Note that these numbers understate congestion costs, as they exclude significant out-of-merit local operating reserve costs, which don’t affect LMPs.

18 18 On-Peak Average Day-Ahead Congestion: March - December 2003

19 19 On-Peak Average Real-Time Congestion: March - December 2003

20 20 Competitive Benchmark Analysis Evaluated actual energy clearing price and actual cumulative bid-in capacity sorted by ascending price (“aggregate bid-intercept”) versus marginal cost-based simulated dispatch. Simulated dispatch designed to produce an estimate of the perfectly competitive market outcome. –Caution that the estimate is subject to an unknown error. Metric is % increase over “perfect” market outcome (“Quantity-weighted Lerner Index”). Results in 2003 show market continues to function well, with modest differences from competitive baseline.

21 21 Competitive Benchmark Results: 2003 vs. 2002 Note: Energy Clearing Price is the ECP prior to March 1, 2003; the Real-Time Hub Price as of March 1, 2003

22 22 Other Conclusions The New England markets continued to perform competitively in 2003 with no evidence of significant economic or physical withholding. Day-ahead and real-time energy prices exhibit good convergence. –Average day-ahead/real-time spread was $1.10 MWh during first year of SMD Virtual trading volumes were reasonable in 2003, contributing to the convergence between the day-ahead and real-time prices.

23 23 Other Conclusions (Continued) Real-time prices in adjacent regions continue to be inefficiently arbitraged. The ISO-NE Demand Response Program provides a modest real-time reduction when necessary. –Mild conditions in 2003 limited the implementation of such reductions. Regulation was only ancillary service market in 2003. –A market flaw was identified in 2003 and corrected in early 2004.

24 24 Other Conclusions (Continued) Out-of-merit operation an on-going issue. –Primarily in import-constrained areas. –Would be helped by increase in quick-start capacity. –Continuing to investigate unit commitment and software resolutions. –New Forward Reserve Market should help incent this capacity. Resource Adequacy in constrained areas in an on-going issue. –Clear market deficiency when large numbers of units required for reliability do not cover going-forward costs.

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