# Presentation: 533409

## 
May 5, 2004

*Director, Market Monitoring *

*May 5, 2004*

**ISO New England  **
**State of the Market Report 2003**

## 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.

## 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.

## New England Electricity & Natural Gas Prices:

**New England Electricity & Natural Gas Prices:**
** ****2001 - 2003**

**SMD Implementation**

## 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.

## Slide 6

## 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.

## Slide 8

## 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.

## 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

- 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**

## 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) .

## 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.

## 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.

## 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 |

- 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.
- 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.
- Capacity revenues for year ending 12/31/2003 are the UCAP revenues derated by the 5% forced outage rate.
- Ancillary service revenues are calculated only for Regulation.

## 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.

## Slide 16

## 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.

## On-Peak Average Day-Ahead Congestion: 

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

## On-Peak Average Real-Time Congestion: 

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

## 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.

## 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

## 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.

## 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.

## 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.