Christopher Seiple and Dr. Arnold Leitner
RDI Consulting, USA
Electric power shortages and high prices in many areas of the USA have put the electric power industry in the public spotlight and sparked demands for re-regulation of the industry. Research from RDI Consulting indicates that that these price spikes and shortages will be temporary, and early next year some regions could be facing a glut of oversupply in the wholesale electricity market. This glut is likely to begin just after developers and financiers ante up more than $30 billion in investment in new generating capacity.
Critical to success in a commodity market, such as electricity generation, is knowing when to buy, sell, or build generating assets. Academic research indicates that firms that are best able to drive their strategy by understanding cyclical trends are able to increase their return on investment by three to four per cent. No one can precisely predict boom and bust cycles in the future. RDI believes that a carefully structured analysis of the supply and demand balance, that identifies the key sources of uncertainties and uses quantitative tools to assess the impact of these uncertainties, provides a strong framework within which to develop a corporate strategy.
To provide such an analysis, RDI employed a probabilistic model based on a decision tree theory. This model incorporates uncertainty by applying probabilities to possible events and analyzing these events in hundreds of possible scenarios. The factors considered in the analysis are summarized in Table 1, as are the final results from the model. The research indicates that four primary factors contribute to cyclical pricing trends in commodity industries. Table 1 provides a summary of these primary factors and the manner in which they relate to electricity markets. Each factor was considered in the probabilistic model.
The first factor that tends to drive cyclical pricing trends is the lumpiness of capacity additions in relation to a commodity’s demand growth. This typically occurs in new or small industries where there are large economies of scale associated with capacity additions in relation to overall demand growth. For instance, demand for a new product may be increasing at 30 per cent per annum, but the construction of one new manufacturing facility may double manufacturing supply. Such conditions would likely create oversupply conditions for this product.
This factor could influence generation markets that are small in size due to a lack of transmission interconnections to neighbouring regions. For instance, in eastern New York, an area where capacity is currently scarce, the peak demand is approximately 10 000 MW. Due to weak transmission interconnections, eastern New York is relatively isolated from the rest of the New York electricity grid. PG&E Generating is currently pursuing development of a 1000 MW power plant in the region. Such a plant would increase overall supply by more than ten per cent in a market that is growing at a rate of less than two per cent per year. Such a large capacity addition could meet future demand growth for as much as the next five years, causing a prolonged bust period in electricity prices.
Supply side uncertainty
A second factor contributing to cyclical pricing trends is supply side uncertainty. In some markets, the industry as a whole may be unaware of how much new supply is in the pipeline. Thus companies acting independently pursue new capacity development that results in oversupply for the market as a whole.
RDI has identified and considered in its analysis the following factors that could contribute to supply side uncertainty in electricity markets:
- The long lead time of new power plant development and the uncertainty associated with the likelihood of individual projects going forward;
- Increases in capacity at existing units are occurring without public announcements;
- The development of unanticipated distributed generation could add to existing supply;
- Improvements in plant performance combined with additional interruptable demand could reduce the amount of reserve capacity required to provide the same level of reliability.
RDI’s research indicates that the development of new power plants is currently the key driver of potential market downturns in electricity. Table 2 provides RDI’s most recent projections of new capacity additions. This Table includes plants that have begun operating, are under construction, or are in advanced stages of development. Developers have proposed a total of more than 290 000 MW of new capacity.
Availability of capital
A third factor contributing to cyclical pricing trends is the availability of capital. Companies tend to invest only when returns are high and funds are available either internally or from capital markets. As a result, too much capacity is typically added at the top of a cycle and too little is added at the bottom. In most commodity industries, this is the primary driver of boom and bust cycles.
In electricity markets it is clear that substantial amounts of capital are currently available for investment. Electricity marketers, such as PECO Energy, Williams, and Coral, have played a large role in supporting the availability of capital due to their willingness to sign 20 to 30-year power purchase agreements that limit the risk of the developer and of the banks financing the project. The substantial cash flow of utilities, especially those collecting stranded costs, has also contributed to capital availability. Finally, the general fondness the stock market has shown for companies like Calpine and AES are signs that capital markets are willing to make substantial amounts of capital available for merchant developers.
The final factor driving cyclical pricing trends is incorrect demand forecasts. These have played a substantial role in contributing to the current price spikes of the market. In some regions of the USA, electricity demand recently increased by more than four per cent annually, higher than anticipated by most forecasters.
Many factors contribute to uncertainty regarding future demand. For instance, incorrect forecasts of gross domestic product. Other factors that influence demand in electricity markets that have been considered include price elasticities, the feasibility of developing dispatchable demand, the impact of computers on electricity demand, and the weather.
Table 3 summarizes the results of the probabilistic boom/bust model based on the decision tree theory that considers all of the factors described. It predicts which regions of the USA will be in boom portions of the cycle and which regions will be in bust portions of the cycle in 2000, 2001, and 2002.
Key findings from the analysis are as follows:
- This year most of the USA will either be in the boom portion of the cycle or at least close to market equilibrium levels in which prices are high enough to support new capacity development. With almost 30 000 MW of new capacity coming on-line, 2000 is expected to be the year in which supply catches up with demand.
- Due primarily to new capacity development, it is extremely likely that many regions of the country will enter bust portions of the cycle next summer. In 2000 and 2001 a minimum of 60000 MW of new capacity will come on-line. It is likely that the total capacity additions by the end of next year will reach 75 000 MW. Total capacity additions during all of the 1990s were only slightly higher than 75 000 MW. In Texas and the northeast, the electricity market will have at least 20 per cent more capacity than is required. Almost all of this additional capacity is already under construction. Only the retirement of large amounts of capacity in these regions could provide price recovery.
- By 2002, nearly all large electricitymarkets in the USA will be in the bust portion of the cycle. SERC and the western US are the only large markets that may be at equilibrium levels. However, this finding must be heeded with a bit of caution as surplus capacity in ECAR/MAIN and SPP could potentially depress pricing in SERC as well. In smaller regions such as MAPP, where equilibrium conditions are expected, it would only take one or two large projects to move the market into over-supply conditions.
- The most attractive regions for new development efforts include the southeast, mid-Atlantic, and the west.
Based on insights gained from the analysis, RDI identified a long-term scenario that could create a prolonged period of low prices and low returns for generators.
The first requirement for this scenario to occur is that the electricity markets must be deregulated. That is, generators must be subjected to the disciplining force of market prices and consumers must be exposed to the volatility of these same prices. Price caps, standard offer rates, and partial deregulation in only a few states would impede the development of this scenario.
Because this scenario is driven by the imposition of supply and demand economics on the electric business, this is the economic rationalization scenario.
In this scenario, the imposition of supply and demand economics have the following impacts:
- Prior to 2003, generators build new capacity to meet expected demand as it is occurring now;
- Persistent price spikes cause some level of dynamic demand to develop so that peak firm demand is reduced by five per cent from expected levels between 2003 and 2008;
- Producers, trying to improve profitability, increase availability factors from an average of 82 per cent to 88 per cent between 2003 and 2008;
- Generators are able to increase the capacity of their existing facilities by one per cent per year between 2003 and 2008.
To consider the implications of this scenario, RDI utilized its electric simulation model to forecast future electricity prices in the midwest US. In RDI’s base case scenario, prices are at relatively high levels today due to shortages of capacity and high turbine prices. By 2002, prices reach long run equilibrium levels and stay at that level over the forecast horizon. In the economic rationalization scenario, however, the combination of factors described above leads to substantial over-supply conditions for the duration of the forecast horizon. Prices are approximately 20 per cent lower than in the base case forecast.
This over-supply occurs for several reasons. First, the development of dynamic demand causes modest reductions in firm demand. Second, generators are able to produce more capacity from the existing system and improvements in availability also create more capacity. Third, the development of dynamic demand in combination with more reliable generators results in the market being able to provide the same level of reliability to customers with less capacity. Thus, overall target reserve margins are reduced.
It is difficult to assess the likelihood of this scenario actually occurring, but it is an important scenario to watch for. Early signs would include the development of the infrastructure to facilitate dispatchable demand, continued price spikes, and improvements in plant performance.
Developers, marketers, and capital markets have responded to power shortage conditions and are rapidly building new plants that will provide customers with a reliable supply of electricity.
New power plants are getting built in markets with regulated reserve requirements (like Nepool) and in markets with no reserve requirements (Texas and the west). They are getting built in regions with ISOs and in regions without ISOs. New power plants are even getting built in markets with significant regulatory risk (like California) or significant permitting and environmental hurdles (the northeast). RDI’s analysis indicates that developers should worry more about their investment returns than regulators should worry that plants will not get built in a deregulated market. Policy makers just need to ensure that the power plant development process is as easy, quick, and fair as possible.
Even though RDI expects most regions of the USA to head into a period of low electricity prices, boom conditions will again return to the electricity market. The analysis indicates that slight changes in the supply/demand balance can cause large changes in electricity prices. Markets with a two per cent capacity shortfall have experienced significant price spikes, but regions with a two per cent surplus have experienced very low electricity prices.
RDI’s analysis finds that there is one unknown that could reduce the threat of extreme price spikesà‚– if customers begin to develop demand that can be curtailed during peak hours, price spikes could be diminished. Development of such demand should therefore be an important policy imperative.