MARKET CLEARING PRICES
UNDER ALTERNATIVE RESOURCE SCENARIOS
2000 to 2010
California Energy Commission Staff Report
Publication Number: P200-00-004 (formerly P300-00-001)
Date Released: March 13, 2000
The Executive Summary of the report is available below. You can also download a copy of this report in Adobe Acrobat Portable Document Format. You will need the free Acrobat Reader software to read this PDF file. The software is available from Adobe Systems Incorporated's Website. If you would like to obtain a printed copy of this report, please contact the Commission's Publications Unit at 916-654-5200.
Download Entire Document in Adobe Acrobat PDF.
(79 pages, 323 kilobytes)
Data Files (Microsoft Excel) for Above Report.
March 13, 2000. In "ZIPPED" format and as separate files.
In this report, the California Energy Commission staff evaluates the impact of two alternative resource development scenarios on market clearing prices for electricity purchased in California's wholesale market for the years 2000 through 2010. One resource scenario reflects rapid development of many currently announced projects and the other a more cautious rate of resource development driven by energy prices. Staff found that if eleven large power plants are put into service between 2001 and 2003, there would be more generation available than load growth requires over most of the ensuing decade. With this excess generation competing in the market, energy prices would decline below what is estimated as necessary to fund new generation. Developers are unlikely to build generation when the prospects for making a profit are so bleak. To proceed on the rapid development scenario, they would need to have alternative income sources, a significantly cheaper facility (or financing), or a perspective that some aspect of the future market is likely to be different from what is assumed in the staff's analysis.
The staff's forecasts of market clearing prices for these two scenarios for all years in the forecast period are based on the results from a regional market model. The approach attempts to capture the independent nature of resource development decisions. It is based on specific assumptions about the timing and quantity of new resource additions and provides useful insight as to how electricity prices in the competitive market would respond to an influx of new supply.
In developing the scenarios, the staff first evaluated more than 40 proposed power plant projects for their likelihood of being built in California within the 2000 to 2010 time frame. This evaluation considered the potential for interzonal and intrazonal transmission congestion, natural gas availability, possible difficulty in mitigating environmental impact as well as the likelihood of local opposition. Based on these factors, the staff identified 19 plants, representing 9,186 megawatts (MW), to include in the scenarios. Another 157 MW of capacity from new renewable energy projects were assumed to be built in the forecast period for a total of 9,343 MW of new capacity. For scale, this is approximately 14 percent of today's California capacity.
The rapid development scenario has 2,840 MW of capacity being added in 2002 and another 6,398 MW in 2003. The remaining additions involve one replacement/repowering of capacity in 2006 and another in 2008 for net additions of 104 MW. This rapid development leads to electricity wholesale prices dropping from a 2001 high of $30.3 per megawatt-hour (MWh) to a low of 21.9 $/MWh by 2003 (constant dollars). Market clearing prices are low until 2009 when they recover to current levels.
The cautious development scenario spreads out, in time, the development of the same projects included in the rapid development scenario. The same capacity is added in 2002, but only 1,819 MW are built in 2003. Eight projects that were added under the rapid development scenario in 2003 are deferred. This cautious development leads to prices dropping only to $23.7/MWh in 2003 and hovering about $2/MWh higher than the rapid development prices through the middle of the decade.
As a general guideline for adding new capacity, the staff used a reserve margin of seven percent as an indicator of when to add plants that would be cost-effective to their owners. Planning reserve margins historically have been in the 15-20 percent range. The planning margin was intended to ensure that sufficient generation capacity existed at the time of the peak demand to cover supply and demand contingencies, and still meet minimum operating reserve requirements. If new load growth caused planning margins to drop to the seven percent level, staff believed that prices would rise sufficiently to attract new entry. Our market simulations showed that this assumption may not be valid.
Overall, the staff believes that reserves will be lower in a competitive market as compared to a regulated market because of economic pressure to use resources more efficiently. Factors contributing to this include the following:
- A greater reliance on load diversity among regions in the West and an increase in regional transfers of electricity,
- Improved plant availability during peak demand hours which in large part determine whether a generator will make a profit for the year, and
- Greater demand-side responsiveness to high prices during the peak.
Because the staff is using a regional market model that simulates the loads and resources of the entire region encompassed by the Western Systems Coordinating Council (WSCC), it was also necessary to make certain assumptions about new additions outside of California. Of the 26,309 MW of new generation proposed for the WSCC outside of California, 7,173 MW were judged to have a high probability of being built because they were already under construction or had received all necessary regulatory approval. This amount of new capacity, however, was not enough to maintain the reliability of certain subregions of the WSCC outside of California. Staff added capacity to a subregion outside of California if its planning reserves fell below 6 percent. The staff, however, let reserves in some subregions drop below 6 percent in recognition that these areas have historically met peak demand by relying heavily on purchases from other regions.
The resulting average annual MCPs from the staff's two scenarios were compared to the annual average revenue requirement of a new market entrant. This comparison provides a useful measure when, how much, and how consistently, new entry is likely to be attracted to the California market in the next decade. Based on a fixed cost revenue requirement of $97 per kilowatt-year (kW-year) for a combined cycle plant and $72/kW-year for a combustion turbine and variable costs of $19/MWh and $26/MWh respectively, the market simulations indicate that market prices are insufficient to fund new generation between 2003 and 2009 for both scenarios.
In developing the annual average revenue requirement for a new market entrant, the staff found that the cost of capital for financing these projects and the cost of fuel are the two variables that will weigh heavily in determining the plant's competitiveness and ultimately its profitability. The cost of capital for a new market entrant is especially sensitive to lenders' and investors' perceptions of market uncertainty and risk. Some of that risk is attributable to the immaturity of the competitive market itself and should diminish over time.
Other factors that contribute to market uncertainty and risk include: the frequency and magnitude of price spikes; the development of the demand-side of the market and its effectiveness in moderating price volatility; the presence of price caps in both the energy and ancillary services markets; the development of the rules governing congestion costs; and the mechanisms/process for deciding when upgrades to the transmission system will occur.
Regulatory actions such as changes in environmental laws, both at the regional and national level, and the pace of restructuring in other western states and the rules adopted by these states for treatment of stranded asset costs and mitigating market power, will also shape investors' perceptions of market risk and uncertainty.
Both scenarios show that market clearing prices would not be sufficient to cover the annual average revenue requirement of a new market entrant until 2010. This finding underscores three trends that the staff believes will have a significant impact on future system reliability.
- Future generation resource additions will not occur in a smooth even pattern, but will more likely occur in a cyclical pattern resulting in periods of excess and lean generation capacity.
- A new generator's profitability will depend largely on the prices it is paid for energy during the summer peak demand season, if it is relying solely on the energy market for revenue.
- Market clearing prices during the summer peak demand season may not reach a level necessary to sustain new market entry until reserve margins drop below historic levels usually regarded as necessary for reliable service.
Developers of new power plants will be closely watching how market prices respond to new entry in 2002. Should prices behave in a manner consistent with staff's modeling, subsequent additions of new capacity will most likely be fewer and more spread out than the level assumed in staff's cautious development scenario. Staff will be conducting additional analyses to estimate the impacts of other key variables on market price and supply adequacy trends.
Page Updated: June 13, 2000
| Homepage | Commission Info | Site Index | Search Site | Links |
E-mail us about our Web Site at: email@example.com
"Energia" means ENERGY in Greek and Latin.
Energy used to create this page was produced by California's electricity providers...
the most diverse in the world.