# Presentation: 533410

## May 4, 2005

*Director, Market Monitoring *

*May 4, 2005*

**ISO New England  **
**State of the Market Report 2004**

## Overview of 2004

- The New England markets continued to be competitive in 2004, operating as designed with no evidence of significant exercise of market power
- Low summer loads
- Summer peak was 2.3% lower than 2003
- Annual total load was 1.3% higher than 2003
- Surplus of generation region-wide
- Regional surplus consistent with:
- Competitive market results
- Uneconomic environment for new investment

## 2004 Is 5th Full Year of Market Operations

- Over that time, some important improvements:
- 9,480 MW of new, clean, generation
- Average heat rate of oil and gas units has declined by 5.6%
- Unit availability has increased from 81% to 88%
- Fuel Adjusted spot prices have decreased 5.7%
- Improved regulation performance has decreased requirements by 29%
- Market enhancements led to efficiencies
- SMD in 2003
- Biggest change in 2004 was introduction of Forward Reserve Market
- Resource Adequacy solution (LICAP) still needed

## Biggest Test for Markets in 2004: January Cold Snap

- Stressed New England energy infrastructure
- Markets generally operated well
- Analysis of period led to numerous improvements
- Improved information exchange between the ISO, gas pipelines and electricity market participants
- Additional dual-fuel operating flexibility
- Revised market timing under extreme conditions
- On-going work
- LMPs need to consistently reflect marginal needed resources
- 2005 results much improved
- Need increased availability incentives

## Biggest Challenges Ahead: Out-of-Market Payments

- Daily out-of-merit operations due to voltage and 2nd contingency coverage
- Transmission upgrades needed
- Unit flexibility
- Mainly have units with high economic minimums/ long run times
- Need additional quick start units in constrained areas
- Large increase in Reliability Agreements
- 2,200 MW under agreements, 4,625 MW additional seeking treatment
- Approximately 20% of system capacity
- Need long-term resource adequacy solution
- Reliability Agreements do not send signals for most existing generators and do not provide incentives for new entry

## Fuel Prices and Energy Prices

- Fuel-Adjusted prices lower than previous years
- Electricity prices were driven by high fuel prices, the largest component of generators’ marginal costs
- Natural gas prices were 5% percent higher than 2003 on average, and 82% higher than 2002
- Nearly half of New England capacity is gas-fired or gas capable
- These units were marginal in approximately 86% of pricing intervals
- Electricity prices peaked in January as natural gas prices rose

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## Slide 8

## Slide 9

## Energy Prices in 2004

- Next slides show real-time price duration curves for 2001 to 2004
- Percentage of hours when load-weighted price for New England is greater than each given price level
- 2004 price levels generally similar to 2003
- More price spikes than in 2003, and fewer than in 2002 and 2001:
- Real-time prices exceeded $500 in 3 hours, compared to 1 hour in 2003, 4 hours in 2002 and 15 hours in 2001
- Infrequent price spikes primarily due to milder summer weather and relatively robust capacity margins
- Scarcity pricing provisions not triggered
- Day-Ahead Hub prices $1.59/MWh higher than Real-Time prices

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## 2004 Average Nodal Prices, $/MWh 

## All-in Energy Prices

- Following slides shows “all-in” prices
- Cost of energy, ancillary services, capacity, and uplift costs
- Energy is load-weighted average of locational real-time prices
- Ancillary services include reserves and regulation prior to SMD, regulation in 2003, and regulation and forward reserves in 2004
- All-in prices rose slightly in 2004
- Energy costs similar in 2003 and 2004
- Uplift and ancillary services costs higher in 2004
- Introduction of the Forward Reserve Market and an increase in VAR tariff reliability payments
- Capacity costs very small in 2004

## Slide 16

## New England All-In Price Metric ($/MWh)

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## Load Profile

- Next slides show annual load duration curves for New England
- Percentage of hours in which the load is greater than the level indicated on the vertical axis
- Mild summer weather in 2004
- Peak days had far less impact on average prices than year with normal weather due to absence of severe price spikes
- 2003 had a similar pattern
- Only 2 hours when actual loads exceeded 24,000 MW
- Compared to 19 hours in 2003 and 34 hours in 2002
- There were 177 hours when loads exceeded 21,000 MW
- Compared to 200 hours in 2003 and 263 hours in 2002

## Slide 21

## Slide 22

## Demand Response 

- New England offers range of price and reliability-based response programs
- Total enrollment around 350 MW at end of 2004
- Total hours of curtailment increased in 2004 due to increased number of events
- Many in winter months due to high gas prices
- 4,223 MWh in 2003
- 13,475 MWh in 2004
- Program enrollment roughly constant from 2003 to 2004
- Need much greater levels of demand response in the long run

## Demand Response Participation

## Major Market Changes: Forward Reserve Market

- What is the Forward Reserve Market?
- Advanced purchase of fast-start capacity
- 10-minute non-spin and 30-minute non-spin
- Units must offer above a strike price based on natural gas costs
- Liquidated damages incent delivery
- Market experienced adequate participation and reasonable outcomes

## Forward Reserve Market: Results and Observations

- Purchased approximately 1,900 MW each auction
- Clearing prices of $4.08 to $4.50/KW-Mo.
- Auction worked
- Unit availability good
- “Right” resources won
- Participants responded to incentives by adding dual-fuel capability, buying firm gas, and offering a less efficient combined-cycle as 2 peaking units

## Economic Incentives for New Investment

- In long-run equilibrium, market should support the entry of new generation
- Need 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 2004
- A gas-fired combined-cycle “CC” (heat rate= 7,000)
- A gas-fired combustion turbine “GT” (heat rate=10,500)
- Combustion-turbines units that participated in the Forward Reserve Market had increased revenues over 2003

## Economic Incentives for New Investment (Continued)

- Net revenue for gas-fired combined-cycle units lower than 2003 and 2002, despite higher Energy and All-In prices in 2004
- Due to gas price increases
- Also due to new capacity added in 2002 and 2003
- Indicates insufficient net revenue from market to support investment in new GT or CC units
- GT would only recover 66% - 88% of estimated 2004 annual fixed costs
- CC would only recover 50% -64% of estimated 2003 annual fixed costs
- Existing units also financially stressed
- Consistent with surge in Reliability Agreements

## Net Revenue Metric 2004

- 	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 real-time Hub LMP.
- 	Capacity sales revenue is based on ISO ICAP Supply Auction clearing prices.
- 	Ancillary services revenue is Regulation for combined-cycle, and Regulation and Forward Reserves for combustion-turbine. Forward Reserve revenues equal auction revenues minus average penalties.

- Combined Cycle

- Combustion Turbine

## Slide 30

## Forced Outages

- Next slide presents trends in forced outage rates from the beginning of the New England Markets
- Forced outage rate is percentage of time capacity is unavailable due to full or partial forced outages
- The decrease in availability 1996-1998 was due to the extended outages of several nuclear units
- Total outage rates have declined substantially following implementation of markets in New England
- Consistent with deregulated market incentives to maximize availability
- Previous analysis suggests initial high outage rates in new combined-cycle units
- New England has many new combined-cycle units
- Improvements in outage rates may be expected as these units mature

## Slide 32

## Congestion and Marginal Loss Costs

- Following slide shows average hourly differences between  LMPs at Hub vs. each load zone
- Differences reflect impact of congestion and marginal losses on LMPs
- Maine had negative congestion
- Due to export constraints and negative marginal losses
- Connecticut had significant positive congestion
- Periodically import constrained
- Note that these numbers understate congestion costs
- Exclude significant out-of-merit local operating reserve costs

## Slide 34

## Competitive Benchmark Analysis

- Evaluated actual energy clearing price and cumulative bid-in capacity
- Ascending price (“aggregate bid-intercept”) vs marginal cost-based simulated dispatch
- Simulated dispatch designed to produce estimate of perfectly competitive market outcome
- Estimate is subject to an unknown error
- Metric is % increase over “perfect” market outcome
- “Quantity-weighted Lerner Index”
- Market continues to function well
- Modest differences from competitive baseline

## Competitive Benchmark Results: 2003 vs. 2004

## Conclusions

- 2004 characterized by low summer loads and ample generation
- The New England markets continued to perform competitively
- No evidence of significant economic or physical withholding
- Cold Snap experience led to important market improvements
- Little incentive to add capacity, even in constrained areas
- Participants responded to Forward Reserve Market signals
- Out-of-market payments require on-going attention
- LICAP solution needed
- Additional Demand Response needed