Robert G. Ethier, Ph.D.

Director, Market Monitoring

May 5, 2004

ISO New England State of the Market Report 2003

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

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

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ECP & Hub LMP Natural Gas

New England Electricity & Natural Gas Prices: 2001 - 2003

SMD Implementation

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.

6

ISO-NE System Price Duration Curves, Prices < $2002001-2003

$0

$25

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$200

0% 5% 10%

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45%

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55%

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Percent of Hours

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erg

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rice

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h)

2001

2002

2003

System Price is single Energy Clearing Price for Interim Market Period ending Feb 28, 2003 and load-weighted Real Time Market LMPs for Mar-Dec 2003.-

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.

8

ISO-NE Hourly Load Duration Curves2001, 2002, 2003

8,000

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2003

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

All-In Price Metric 2001 - 2003 ($/MWh)Total per MWh Energy, Uplift, Capacity, and Ancillary Costs

Includes Energy and Fuel Adjusted Energy

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

2001 2002 2003

Total Energy Fuel Adjusted Total Energy Uplift Capacity Ancillary Services

Note: Energy Interim Market Period = ECP * System Load ; SMD Period = RT Load Obligation * RT LMP

Energy Costs

Fuel Adjusted Energy Costs

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

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

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

Net Revenue Metric 2003

All Values in $/MWh Combustion Turbine Unit Combined 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 $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

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.

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Percent of Installed Capacity Out of Service, Weekdays

0.0%

2.0%

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16.0%

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1999 2000 2001 2002 2003

% o

f A

vg. A

nn

. In

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Cap

acit

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Planned Unplanned Total

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.

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($8)

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Mar Apr May Jun Jul Aug Sept Oct Nov Dec

Hub ME CT NEMA

On-Peak Average Day-Ahead Congestion:

March - December 2003

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($6)

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Mar Apr May Jun Jul Aug Sept Oct Nov Dec

Hub ME CT NEMA

On-Peak Average Real-Time Congestion:

March - December 2003

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

Competitive Benchmark Results: 2003 vs. 2002

2002 Price Measure 2002 Price ($/MWh)

2002 Quantity-weighted Lerner index

Competitive Benchmark Price 32.38 Energy Clearing Price (ECP) 35.55 11% Aggregate Bid-Intersection Price

34.24 6%

2003 Price Measure 2003 Price ($/MWh)

2003 Quantity-weighted Lerner index

Competitive Benchmark Price 48.10 Energy Clearing Price 52.91 9% Aggregate Bid-Intersection Price

46.03 -4%

Note: Energy Clearing Price is the ECP prior to March 1, 2003; the Real-Time Hub Price as of March 1, 2003

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

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

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.