The deregulated power market will feature large numbers of buyers and sellers. Buyers will worry that prices will rise unexpectedly above current levels; sellers will worry that prices will fall unexpectedly. Some will be interested in fixed-price forward deals that protect them from these risks. Retail marketers will want to offer fixed prices to customers for one or several years.
Power marketers will be especially interested in risk management, because offering forward price deals will make up an important part of their business. In particular, they will be interested in understanding the sources of power-price volatility and available mechanisms for managing this risk.
Nevertheless, despite predictions that electricity and natural gas will converge into a single, unified
energy market, many significant differences will likely remain between these two commodities, especially in terms of price risk and uncertainty.
The gas market is conducive to a futures market. Many parties are concerned with either unexpectedly low or high prices, and hence, very interested in nominal fixed prices. Production is also concentrated regionally to a high degree. The great majority of production lies in the Texas, Louisiana, and Oklahoma area, such that a central regional hub, the Henry Hub, has emerged as the dominant and reasonable basis for a stylized futures contracts. Such contracts are of interest and make sense for enough players to support trading on a public exchange.
But even as power marketers are waiting and hoping that the power business will change and allow for a gas-styled, commodity market, limitations are becoming more evident. In the gas business, problems can be seen increasing over differences in "basis" (em problems that could loom for power as well (see Tables 1 and 2, for a hypothetical example of "basis" problems for the power sector). The essence is that the change in the futures market price fails to track the cash market.
These limitations do not mean that the gas market model cannot serve as a valuable starting point for the power business. Nor do they diminish the extraordinary success in bringing fixed forward prices to the gas business. Rather, they indicate that other risks may become increasingly important in the gas business and play a larger role in the power business.
Because of these limitations, and differences between gas and electric power, we predict that engineering and economic analysis will prove more important in the future in assessing risk in the electric power commodity market than in the gas industry. This conclusion rests on four principal observations:
s Regional Variations. Regional differences in power markets are much more pronounced for electricity than for gas, making fundamental analysis in economics and engineering more important for electricity.
s Short-run Volatility. Power price variations in the short run reflect economic and engineering factors to a much larger degree than for gas, where short-run prices are less subject to analysis.
s Different Histories. The relative lack of statistical data on power prices (compared with gas) will place increased emphasis on the fundamentals, at least during the transition period.
s One-way Cross-Hedging. Gas as an input fuel directly affects marginal unit costs in electric generation. But, this relationship only allows for one-way, cross-commodity hedging (em i.e., hedging a power sector position by taking a gas market position.
Regional Integration: Dissimilar
Many gas-turned-power marketers are hoping that deregulation will establish a futures market so that they can function in the power business as they function in the gas market. This evolution may indeed happen. The most notable examples are trading of contracts for delivery in the West at locations near the California border.
Even so, whereas a disconnection of regional markets is the exception (em not the rule (em in the gas industry, this balkanization will occur more frequently in the power sector. The nation's electric transmission grid offers much less capacity for interregional connections than do the pipelines on the gas side. For example, gas pipeline capacity into the Northeast from the West South Central equals roughly three-quarters of the average demand for gas in this area. By contrast, electric transmission capacity from the coal-based industrial midwest (i.e., the National Electric Reliability Council [NERC] region known as ECAR) totals only 5 percent of the average demand levels in the Northeast (i.e., NEPOOL, NYPOOL, and the PJM Interconnection).
Three factors explain this discrepancy.
First, gas producing resources are concentrated to a far greater degree than generation resources. Hence, more long-distance gas transmission capacity is required. But coal is produced in over 20 states; nuclear and hydroelectric power is prominent in many others. Second, power transmission is several times more expensive on a per-Btu basis than gas transmission. As a consequence, it is easier to transport gas than power, and often almost as economic to transport coal as coal-derived power. Third, siting and permitting is much more difficult for power lines than for gas pipelines. New technologies to enhance power line capacity may ameliorate this constraint somewhat, but for the foreseeable future, power line siting is likely to remain a expected to be a significant problem.
Price Volatility: At Opposite Ends
Several factors cause volatility in a given power market. In the short run, the key factors include weather, which can strongly affect demand and hydro systems supply; fuel prices; and powerplant operations (e.g., outages of large units, such as nuclear power plants). In the longer term, electric prices can be affected by demand, regulations, and new technology. In addition, there is substantial uncertainty about the price of transmission capacity between regional markets. This uncertainty is tied both to regulations and supply and demand factors.
In the natural gas industry, however, most attention to price volatility is focused on basis
differentials between markets, driven by uncertainty in prices and capacity for transportation. Marketers encounter difficulty in attempting to apply short-run fundamentals to assess overall gas commodity prices.
Consider these general observations about the relative price volatility of electricity versus gas over time:
s Hourly. Power prices are quoted for hourly delivery and can double in the course of a day. Gas prices are generally quoted on a daily basis.
s Daily. The next day's power price could be two or even four times the previous day's price. Day-to-day variation in gas commodity prices are limited (em generally up to 5 percent per day.
s Monthly and Seasonal. Monthly variation in gas price is likely to be larger than for power. Seasonal variation can be significant in power markets with large amounts of hydro generation.
s Yearly. Gas prices are likely to vary more from year to year than power prices.
One reason for these discrepancies in volatility lies with the storage advantage enjoyed by gas. Working gas storage capacity runs about 20 percent of average demand; storage delivery capacity is about 40 percent of peak day demand. By contrast, pumped storage capacity in the power sector totals only about 3 percent of peak demand.
Withdrawals from storage in the gas industry can also exert a large impact on gas prices. Since the physical act carries a low cost, storage withdrawals are determined in large part by expectations of future commodity prices. And because price expectations are volatile, they add significantly to gas market volatility. In the power sector, by contrast, the competitive price is set in every hour by the variable cost of the marginal power generator. Storage plays a minor factor.
Short-run variable costs also differ significantly.
Once a well is in place, the variable costs of producing natural gas are very low relative to the full long-run costs (e.g., $0.20/MMBtu versus $2.00/MMBtu), because production is capital intensive. Thus, no variable cost floor can limit short-run competitive prices. Other factors, such as interfuel competition, keep short-run gas prices above $0.20/MMBtu. However, lack of a cost floor contributes to price volatility.
But on the other side, the variable costs of producing electrical energy are high, because once the plant is built, the variable costs are the fuel (e.g., gas or coal). Competitive electric energy prices are close to being equal to the fuel costs of the marginal unit. Thus, a significant cost floor limits the volatility of short-run prices.
Historical Data: Unequal
One common approach to assessing price uncertainty is to examine historical data. For example, stock price analysts often calculate standard deviations and correlations with other historical factors. Statistical analysis can also be applied to options, which are closely related to futures prices. An option awards the right to buy in the future at a specified price; a futures price is the commitment to buy at a fixed price in the future. Not surprisingly, the analysis for estimating option value is closely related to the process for estimating forward price uncertainty. In fact, the Black-Scholes formula for pricing options includes a standard deviation as a key input, and analysts often use statistically derived estimates.
Nevertheless, statistical estimates may prove disadvantageous for the power industry. First, underlying conditions may change as the industry deregulates, making the past an unreliable predictor of the future. For example, our recent study of historical price information for Public Service Co. of New Mexico (PSNM) indicated aver-age annual prices of $22 per megawatt-hour (Mwh) with a standard deviation of $2/Mwh. However, this year's prices were several standard deviations below $22/Mwh; historical estimates proved no guide to current conditions. Figure 1 shows our assessment of the market price volatility for PSNM, based on engineering economic fundamentals. Second, analysts may not find enough historical data.
An Alternative Approach
An alternative approach relies not on historical data, but on engineering and economics to assess the distribution of future prices. In the natural gas and other markets, fundamental analysis is used to supplement other information. Fundamental considerations can be assessed informally or use more computer-based market modeling.
In the case of gas, market modeling would rely heavily on reservoir engineering simulations and assessments of demand. In the case of power, modeling would be based on an analysis of power plant dispatch. By varying key parameters and associating a probability to each state, a probability distribution of key prices (and other parameters such as standard deviations) can be developed.
Rewriting the "Book"
To understand the limitations of futures contracts that gas marketers are experiencing, it is useful to review the two conditions that underlie the futures-oriented, gas-procurement approach. First, there must be a high regional concentration of gas production, so that the Henry Hub makes sense as a basis for a futures market. Second, there must be sufficient capacity on the transmission system for marketers to back up their offers for fixed nominal prices at other nonhub locations with physical delivery.
These two conditions are still in place but not fully so. The West South Central producing area is expected to continue to be the largest producing area, consistent with the conditions that led to the Henry Hub. However, forecasts we have made using our supply-based gas industry reservoir simulation models indicate a steady shift of production to the Rockies and nearby areas. By 2010 we expect that area to run a very close second.
At the same time, transmission limitations restrict the movement of gas from West to East. These restrictions may not be relieved at a rate commensurate with the increasing supply from this region. If the restrictions are not resolved, the price at a given location will deviate from the hub plus transportation price, gas transmission capacity to link the markets will be inadequate, and the marketer will be unable to back up offers with physical delivery.
This problem could be solved without the marketer taking uncovered positions:
s Create a balanced regional "book." Marketers could create a book of transactions with local area suppliers and buyers that match or nearly match. In such a case, all sell commitments are offset by buy commitments, and the marketer is protected from price risk.
s Create a regional futures contract. If the volume of transactions is high enough, one could even create another futures contract to be traded on an exchange in which the delivery location was the nonlinked region. There have been recent steps in this direction (e.g., the recently established Kansas City Gas Futures). If sufficient regional exchanges are available, marketers can become fully protected from price risk.
The Casino vs.
the Forward Price Curve
Creating new regional "books" to link buyers and sellers or using new futures contracts may not work in many cases. The volumes may not be sufficient to justify the costs of a public exchange or to prevent players from manipulating the market price (e.g., cornering the market). Books also require a minimum volume and the process of starting and maintaining a book may require taking
uncovered positions. An alternative solution (or a complement to a book) would be to create a forward price curve in which the key element is not a futures market, but market-makers that take this risk for a fee (em e.g., the marketer.
The market-maker's activities can be contrasted to those of the operator of a casino. The casino operator knows the outcomes of his game. For example, in the case of an "even" roulette table, half the outcomes would be red (i.e., the operator pays a given amount) and half the outcomes would be black (i.e., the player pays the same amount). Although the operator could have a winning streak (many blacks in a row) or a losing streak (many reds in a row), on average he breaks even. In other words, the casino operator manages risk by having enough volume that the law of large numbers will ensures a profit at the expected rate.
In casinos, the margin is set in large part by competition between casinos and by customer response to the margins. For example, few would gamble if everyone lost quickly almost all the time. Cost also is a factor. The casino needs to cover its operating costs, and this cost sets the equilibrium margin in a competitive market.
It might appear at first as if a commodity market-maker could take the same approach. If the average price of gas were $2.00 over many months, and the market-maker offered gas at $2.12, on average he would make 6 percent. In reality, commodity prices are less certain than roulette tables
because the price remains uncertain even with high volumes. Further, the prices for more distant periods may be even more uncertain than nearer-term forward prices.
In commodity markets, the margin will also reflect the extent to which the market-maker considers the value to be uncertain. The way to manage the risk is not just increasing volume, but also changing a margin so that the actual resulting average price is higher than the a priori expected price. The more uncertain the future average price, everything being equal, the higher the margin. For example, if you think the average price is $20 per megawatt-hour, but the possible range is $19 to $21, the margin will be smaller (e.g., less than 1) than if the range is $12 to $28 (e.g., 4 to 8).
Each margin level has a certain risk level (higher margins, lower risk) that can be calculated. Corporate financial staff then provide a required rate of return for this risk level to ensure that the margin is not below minimum acceptable levels. t
Judah Rose is a vice president at ICF Kaiser International, Inc., Fairfax, VA. Charles Mann is a senior vice president of ICF Kaiser, and manages the utility consulting practice of ICF Kaiser Consulting Group.
Power versus Gas
The going assumption is that there will be many similarities between the two markets-i.e., that the gas business approach will be applied to the power sectior. This intuitive guess is largely correct. However, there will be some noticeable differences:
. Regional Market Issues. Power markets are likely to be more regionalized than gas markets. Relying on a single Henry Hub futures markets is clearly not the answer, and even if several regionalized contracts develop, the role of futures markets overall is likely to be more limited in power.
. Price Volatility. Short-run (hourly, daily, weekly) power volatility will be higher than in the gas commodity market, but long-run volatility will be lower.
. Engineering Economic Fundamentals. Engineering economic fundamentals will play a larger role in power markets, in part because a transitional period will make it difficult to create a market in the absence of historical data on market volatility.
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