# Presentation: 296085

## Highlights of the 2003 New York ISOState of the Market Report 

- David B. Patton, Ph.D.
- Potomac Economics
- Independent Market Advisor
- April 14, 2004

## Introduction to the Annual Report

- This presentation provides highlights from the Annual Report on the New York electricity markets for 2003.
- The market assessment addresses the following areas:
- Energy market prices and outcomes
- Market performance
- Market participant bid and offer patterns
- External transactions scheduling
- Capacity market
- Ancillary services
- Demand response programs

## Fuel Prices and Energy Prices

- Electricity prices tend to be influenced primarily by fuel prices (the largest component of generators’ marginal costs) and load levels.
- The next figure shows that monthly energy prices for 2002 to 2003 have been driven by fuel price trends.
- Natural gas prices were 70 percent higher than 2002 on average.
- Distillate oil prices increased 24 percent on average.
- Electricity prices peaked in February and March as natural gas prices rose to unprecedented levels, and peaked again in August due to summer loads.
- The figure also shows that average prices in east NY exceed prices in west NY by 32 percent due to the Central-East constraint separating west and east NY and the constraints into and within NYC.

## Energy and Natural Gas Prices2001 - 2003

## Energy Prices in 2003

**Energy Prices in 2003**

- The next figure show real-time price duration curves for 2001 to 2003 in the highest-priced five percent of hours in each year.
- These curves show the number of hours when the load-weighted price for New York State is greater than each given price level.
- Price levels were generally higher across all hours 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 weighted prices exceeded $500 for 3 hours, compared to 6 hours in 2002, and 11 hours in 2001.
- The lower quantity of price spikes was primarily due to milder weather and increased imports from New England.
- Scarcity pricing provisions were implemented, but were not triggered in 2003.

## Price Duration Curves in Highest 5% of HoursNew York State Average Real-Time Price

## Load Profile

- The next figure shows annual and summer load duration curves for New York.
- These curves show the number 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 3 hours in 2003 when actual loads exceeded 30,000 MW, compared to 25 hours in 2002 and 17 hours in 2001.
- In 2003 there were 38 hours when loads exceeded 28,000 MW compared to 133 hours in 2002 and 66 in 2001.

## Load Duration Curves for New YorkSummer 2002 vs. Summer 2003

- *  Summer includes June to August each year.  The blackout hours in 2003 are not included.

## All-In Energy Prices

**All-In Energy Prices**

- The following figure calculates an “all-in” price that includes the costs of energy, ancillary services, capacity, and other costs.
- The all-in price is calculated for various locations within New York since both capacity and energy prices vary substantially by location.
- For the purposes of this metric, uplift and ancillary services costs are distributed evenly for all locations.
- This figure shows that the all-in price rose for all locations in 2003.
- This increase is primarily caused by higher energy prices in 2003, which rose 36 percent in 2003 due to higher fuel prices.
- The capacity component also rose in 2003 due primarily to:         a) rising forecasted peak load resulting in a higher obligations, and b) additional purchases under the demand curve.

## Average All-In Price in 2002 and 2003Costs per MWh of Load

## Economic Incentives for New Investment

**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 at various locations in 2003.
- The types of units are gas combined-cycle (heat rate = 7000), new gas turbine (heat rate = 10500), old gas turbine (heat rate = 12000).
- For the gas turbines, the figures show the effect on the suppliers’ net revenue of incurring higher costs to purchase natural gas intraday.

## Economic Incentives for New Investment

**Economic Incentives for New Investment**

- Even though prices were higher in 2003, the net revenue for gas-fired units were lower in 2003 due to gas price increases.
- These results indicate that the market in 2003 did not produce sufficient net revenue to support investment in a new gas turbine.
- A new gas turbine would have recovered only 30 to 75 percent of annual net revenue needed to support a new gas turbine in 2003.
- These results for a new combined-cycle unit are less clear.
- Net revenue for a new CC in NYC ranges from $250,000 to $300,000 per MW-year (the required net revenue is unknown).
- In upstate New York, a new gas turbine would recover 40 to 80 percent of the required annual net revenue for a new CC.

## Estimated Net Revenue in the New York CityDay-Ahead Market – 2002 to 2003

## Estimated Net Revenue in Upstate New YorkDay-Ahead Market – 2002 to 2003

## Forced Outages

- The next figure presents the trend in the equivalent forced outage rate from the beginning of the operation of the New York markets.
- The Equivalent Forced Outage Rate (EFOR) is the portion of time a unit is unavailable due to full or partial forced outages.
- EFOR declined substantially following the implementation of the NYISO markets.
- This is consistent with the incentives the deregulated markets provide to maximize availability, particularly during high load conditions.
- EFOR declined again after the change from ICAP to UCAP in the fall of 2001.  This increased the incentive to minimize outages since a unit’s UCAP amount reflects its forced outage rates.

## Equivalent Forced Outage Rates1998 to 2003

## Congestion Costs

**Congestion Costs**

- The following figure shows monthly congestion costs collected in the day-ahead and the real-time markets (i.e., balancing congestion costs).
- This figure shows congestion costs have increased from 2001 to 2003:
- $310 million in 2001
- $525 million in 2002
- $688 million in 2003
- The increase in congestion costs from 2001 to 2003 is partly due to the modeling of the load pockets within NYC, which began in June 2002.
- The significant balancing congestion costs are evidence of inconsistencies between the day-ahead and real-time models.
- This should be remedied when the new real-time system (“RTS”) is implemented in Fall 2004.

## Monthly Congestion Expenses  2001 - 2003

## Ancillary Services Costs

- Ancillary services expenses include expenses for regulation, voltage support, and various operating reserves.
- These costs tend to be smaller as a percent of total market expenses in the summer than in other seasons because of the relatively high energy prices during the summer.
- Ancillary services costs declined slightly as a percentage of total market expenses from 2002 to 2003.
- However, the amount spent on ancillary services increased by $20 million to almost $130 million.
- Increased expenditures for ancillary services was primarily due to the higher cost of regulation.

## Expenses for Ancillary Services2002 - 2003

## Other Conclusions and Recommendations

- The NYISO markets continued to perform competitively in 2003 with no evidence of significant economic or physical withholding.
- Day-ahead and real-time energy prices continued to exhibit good convergence.
- Virtual trading volumes increased in 2003, contributing to the good convergence between the day-ahead and real-time prices outside NYC.
- The capacity demand curve implemented in 2003 has been successful in stabilizing capacity prices and facilitating price convergence between the various UCAP auctions.

## Other Conclusions and Recommendations

- Real-time prices in adjacent regions continued to not be efficiently arbitraged.
- Implementation of the VRD provisions that are under development with New England will address this issue.
- Eliminating the export fees with adjacent regions would also help improve the efficiency of the interchange between markets.
- The NYISO’s demand response programs provide a substantial amount of real-time load reductions when necessary – however, mild conditions in 2003 limited the need for such reductions.

## Other Conclusions and Recommendations

- Apparent reductions in real-time transmission limits has caused substantial congestion costs in real-time.
- Introduction of RTS should address this concern because the RTS and SCUC software will operate on the same platform.
- Supplemental commitments for local reliability continue to be significant, which can distort energy prices.
- In the long-term, we recommend incorporating the local reliability requirements in the initial commitment.
- In the short-run, we recommend that the operators pre-commit units that they know will be required to meet local reliability requirements.