The Effect of the Bankruptcy of Enron on the Functioning of Energy Markets

Subcommittee on Energy and Air Quality
February 13, 2002
1:30 PM
2322 Rayburn House Office Building 

Ms. Mary Hutzler
Acting Director Office of Integrated Analysis and Forecasting Energy Information Administration
Department of Energy
1000 Independence Avenue, SW
Washington, DC, 20585

Summary of Major Points

Energy markets have experienced considerable turmoil over the past two years, with electricity price spikes and supply shortages in California, volatility in natural gas prices, and, more recently, the collapse of a major energy trader, the Enron Corporation. While it is likely that volatile natural gas prices played a role in raising wholesale electricity prices in California, it is unlikely that the Enron situation has had a major impact on energy markets, or that the outlook for electricity and natural gas supply, demand, and prices will be materially affected by Enron's problems.

An examination of electricity and natural gas price data since the fourth quarter of last year indicates no correlation between spot market prices for the two commodities and the path of Enron's stock price. Between October of 2001 and February of 2002, several measures of wholesale electricity prices from around the country (including those from the Middle Atlantic, New York, New England, and California spot markets) displayed relative stability at the same time that Enron's stock value was plummeting from nearly $37 a share in October to less than a dollar a share scarcely six weeks later. Similarly, the Henry Hub spot natural gas price, while a little more volatile than electricity prices, showed no sign of being affected by the Enron problems during this same period. Both electricity and natural gas markets appear to have shrugged off the Enron situation with little or no discernible market impacts.

In the short term, little change is expected for electricity prices. For 2002, an average decline in residential electricity prices of 1.6 percent is expected. A modest increase of about 0.5 percent is anticipated for 2003 as fuel costs increase moderately and as aggregate electricity demand begins to rise. After the large increases of the last two years, natural gas prices at the wellhead are expected to decline to about $1.85 per thousand cubic feet in 2002, then, as economic growth accelerates and as world oil prices rise, increase to nearly $2.40 in 2003.

In the longer term, electricity prices are expected to decline about 0.2 percent annually from 2000 through 2020, as more competition and lower coal prices to electricity generators offset somewhat higher natural gas prices. Natural gas prices at the wellhead are expected to rise from their current levels, reaching $3.26 per thousand cubic feet (real 2000 dollars) by 2020.

It is not clear at this point to what extent the Enron situation will affect the announced plans of States to move their electricity markets toward competitive restructuring. Clearly, the large price increases seen in California during the second half of 2000 had a chilling impact on the trend toward deregulation. There have been no recent announcements of new State-level restructuring initiatives. On the other hand, with the return to stability in the California electricity market, as well as in national natural gas markets, there have been only a few decisions to delay or reverse the announcements already made. No clear trend concerning Enron's impact on electricity prices are discernible, implying that the effects will be small at best.

Mr. Chairman and Members of the Subcommittee:

I appreciate the opportunity to appear before you today to discuss current and future electricity and natural gas prices and supplies in the United States, in light of the recent Enron situation.

The Energy Information Administration (EIA) is an autonomous statistical and analytical agency within the Department of Energy. We are charged with providing objective, timely, and relevant data, analysis, and projections for the use of the Department of Energy, other Government agencies, the U.S. Congress, and the public. We do not take positions on policy issues, but we do produce data and analysis reports that are meant to help policy makers determine energy policy. Because we have an element of statutory independence with respect to the analyses that we publish, our views are strictly those of EIA. We do not speak for the Department, nor for any particular point of view with respect to energy policy, and our views should not be construed as representing those of the Department or the Administration. However, EIA's baseline projections on energy trends are widely used by Government agencies, the private sector, and academia for their own energy analyses.

The Subcommittee has requested information about current and future electricity and natural gas prices and supplies in light of the Enron situation. EIA collects and interprets data on the current energy situation, and produces both short-term and long-term energy projections. The projections in this testimony are from our Short-Term Energy Outlook, February 2002, and the Annual Energy Outlook 2002, released late last year. The Short-Term Energy Outlook provides quarterly projections of energy markets through 2003, while the Annual Energy Outlook provides projections and analysis of domestic energy consumption, supply, and prices through 2020. These projections are not meant to be exact predictions of the future, but represent a likely energy future, given technological and demographic trends, current laws and regulations, and consumer behavior as derived from known data. EIA recognizes that projections of energy markets are highly uncertain and subject to many random events that cannot be foreseen, such as weather, political disruptions, strikes, and technological breakthroughs. In addition, both short- and long-term trends in technology development, demographics, economic growth, and energy resources may evolve along a different path than assumed in the Short-Term Energy Outlook and the Annual Energy Outlook. Many of these uncertainties are explored through alternative cases with a range of assumptions concerning world oil prices and weather in the Short-Term Energy Outlook, and world oil prices, economic growth, and, technology in the Annual Energy Outlook. My testimony today will present our reference case projections, which represent current policies and trends, and are not expected to be affected by the situation surrounding the collapse of Enron Corporation.

Enron Corporation declared bankruptcy in December 2001. Our mid-term projections, which were published the same month, incorporated the most recent events in energy markets as possible, but most of our analysis was completed by the end of September 2001. At that time, the problems of Enron had not yet been made public, and were not foreseen by most energy analysts. It is our view, however, that the mid-term outlook for energy markets is not materially affected by this situation, which is essentially confined to the shareholders and employees of Enron.

Energy markets, with particular emphasis on electricity and natural gas, have experienced a great deal of volatility over the past two years. For electricity, the most dramatic ups and downs have occurred on the West Coast, particularly in California. Natural gas market changes over that period have been broader in scope and have been felt strongly across the country, although the highest price increases were in California. In general, it appears that the factors that are responsible for the very volatile and high electricity prices on the West Coast, and the spike and subsequent collapse in natural gas prices nationwide, stemmed from numerous economic and non-economic developments (some years in the making) that are not obviously related to Enron's market activity. Furthermore, these developments appear to be resolving toward a general result that would be obtained with or without the continued existence of Enron. Enron, while a large and well-known player among energy trading entities in the United States, was one among many existing and potential new players in electricity and natural gas markets. The existing array of market participants (producers, traders, marketers, distributors, consumers) should be able to interact effectively to ensure a normal (competitive) market balance in the future. The projections in this testimony are based on that premise, and there is nothing in what has occurred in energy markets since the failure of Enron that would suggest otherwise.

Electricity

Electricity markets in the United States emerged, in mid to late 2001, from a period of significant turmoil into a period of relative calm with respect to spot electricity price movements. Most of the increased volatility in spot electric prices occurred on the West Coast of the United States, particularly in California, but also in the Pacific Northwest (Figure 1). Between May 1, 2000 and June 1 2001, the average daily percent spot price change at the California/Oregon border (COB) was 20 percent with a maximum absolute change of 140 percent. For the period August 7, 1998 to December 30, 1999, the average was 12 with a daily maximum of 126. The relative calm that has characterized the West Coast market since last winter is demonstrated by the fact that between June 1, 2001 and February 8, 2002, the average daily percent change in COB electricity spot prices has been 9.6 percent with a maximum absolute change of 84 percent. Many of the conditions that contributed to the electricity market squeeze in California in late 2000/early 2001 are no longer operative and the prospects for continued calm in electricity prices through 2003 are good. Unfortunately, one of the contributors to lower electricity market volatility is the significant slowdown in the U.S. economy in 2001, particularly as demonstrated by the dramatic decline in industrial output which is still pervading the economic environment. It should be noted that, despite the volatility in some spot electricity markets, most retail electricity customers in the United States have seen only marginal increases in delivered electricity costs, and moderate declines in 2002 are likely. This result stems from the fact that at the retail level electricity prices are still regulated in many States. Some States (particularly California) have seen large changes in delivered electricity prices, but, for most areas, retail price changes have been relatively small over the last two years.

Some of the pressure on electricity prices that emerged in 2000 and early 2001 were related to fuel costs and the availability of adequate amounts of certain kinds of generating capacity. Throughout 2000, natural gas spot prices were rising steadily because of strong demand and stagnant or declining productive capacity. The economy was expanding rapidly and incremental natural gas demand requirements were outstripping the capacity to produce new supplies. Natural gas inventories fell steadily to very low levels at the beginning of the 2000-2001 heating season, setting the stage for significant increases in natural gas costs to end-use customers, including electric power generators. At this time, oil prices were also well above typical levels because of the tight condition of world oil markets. It should be noted that a concomitant reduction in hydroelectric resources in 2000 (due of course to exogenous weather factors) only served to tighten electricity markets by, in effect, removing an important component of everyday electricity supply capacity. This was particularly true on the West Coast. In late 2000, very cold temperatures shocked energy markets by moving heating demand-related energy use to well above normal levels. The resulting squeeze on natural gas markets resulted in one of the most dramatic runups in natural gas prices ever seen in the United States, with the result that industrial and power generating companies (as well as other energy users) saw fuel costs soar. For power generators, some alternatives to natural gas alleviated some of the pressure. In fact, the 2000-2001 winter turned out to be one of the busiest winters for oil-burning power stations in many years. While oil-fired generating capacity represents only a marginal source of alternative electricity supply, this development nevertheless helped prevent gas price runups from being even worse than they actually were last winter.

Since last winter, the onset of economic recession and relatively mild weather (including unusually warm heating season temperatures beginning in November of 2001) has reduced electricity (and other energy) demand and changed the cost/price environment for electricity and other energy sources. Average U.S. natural gas spot prices are currently between one fourth and one fifth the level seen at the height of the runup last winter. Oil prices are noticeably lower now than during the winter of 2000-2001 as well. Electricity spot prices now generally between $18 and $24 per megawatt-hour compared to $40-$50 in the South and East, and $400-$500 on the West Coast during mid January 2001. Cost conditions in the near term (2002 and 2003) are expected to be such that average energy prices remain much closer to current levels than to anything resembling the high prices of late 2000 to early 2001. Moreover, current supplies (inventories) are relatively high right now for most fuels in the United States, particularly natural gas. Although some tightening in natural gas markets is anticipated for 2003, prices are likely to remain quite low on average through most of 2002.

Until the U.S. economy begins to recover in earnest and domestic fuel inventories are pared to more normal levels, the probability of sharp price runups is minimal. In addition to the demand and fuel cost factors that have reduced the level of electricity price volatility since last winter, there has been a significant number of new electric generating plants added to the U.S. inventory over the last year or so. Current estimates are that there has been about a 73,500-megawatt (9.3-percent) increase in generating capacity between the end of 1999 and the beginning of 2002. Approximately 2,000 megawatts (3.9 percent) have been added in California. Furthermore, it is generally expected that a significant recovery in hydroelectric power availability on the West Coast is likely this year. Such a development would further reduce the likelihood of renewed pressure on electricity prices in the region regardless of the specific entities engaged in trading there.

Despite a period of wide variability and sharp runups in spot electricity prices since 1999, for most retail electricity consumers, price movements have been much less dramatic. For example, between 1999 and 2001, U.S. residential electricity prices have risen an average of 1.9 percent per year. The highest monthly year-over-year increase in the last two years for average residential prices has been 4.6 percent (February 2001). For 2002, an average decline in residential electricity prices of 1.6 percent is expected. A modest increase of about 0.5 percent is anticipated for 2003 as fuel costs increase moderately and as aggregate electricity demand begins to rise. U.S. electricity demand is currently estimated to have fallen by 0.6 percent in 2001. Much of that decline is expected to be reversed in 2002 and reach a more normal annual growth rate of 2.7 percent in 2003. This projection presumes that the U.S. economy will begin to recover in 2002 and post a 4.0-percent real GDP growth rate in 2003.

Average wholesale electricity prices across the Nation have been relatively stable since October 2001 (Figure 2). Monthly average electric power prices during this period ranged from a high of about $38.00 a megawatthour to a low of about $18.00 a megawatthour in response to changing demand and supply conditions.

Enron's stock traded at $36.79 per share on October 11, 2001. Its price continued its downward spiral during the months of October and November. The stock has not recovered since then. This performance is also in sharp contrast with the stock's performance in September 2000 when its price reached a high of nearly $90.

The rate of decline accelerated as information about Enron's accounting practices emerged and Federal agencies began looking closely into Enron's affairs. Failure of a merger agreement between Enron and Dynegy also contributed to a decline in Enron's stock. Given the relative stability of wholesale electricity prices together with the collapse of Enron's stock price, it is not possible to establish any meaningful correlation between electric power prices and Enron's performance in the stock market.

A review of average retail electricity prices (calculated as average revenue per kilowatthour) in relation to Enron's stock price during January 1999 through October 2001 also fails to exhibit any correlation between average retail electricity prices and Enron's stock's performance (Figure 3). As electricity prices are still regulated by many State public utility commissions, they do not appear to be influencing or being influenced by the Enron stock price.

Natural Gas

Spot wellhead prices are currently averaging around $2.00-$2.20 per million Btu, or about one-quarter of what they were in January of last year when prices at the wellhead reached record levels (Figure 4). These prices are measured at the Henry Hub-a major upstream trading center, the prices of which are often used as representative of U.S. natural gas markets. Very mild winter weather during the fourth quarter of last year through January of this year has lowered heating demand considerably. Heating degree-days in the fourth quarter 2001 were about 26 percent below levels from the previous fourth quarter and about 16 percent below normal, while January 2002 heating degree-days were about 14-17 percent below normal (depending on the region) and below year-ago levels. The low heating demand, a weak economy, and the ensuing excess storage levels for natural gas during the winter of 2001-2002 through the spring of 2002 should result in rather tepid natural gas prices in the near term. At the end of last November, working gas in storage was 30 percent above levels during the previous November. By the end of January, the storage level was almost 80 percent above that of the previous year and about 35 percent above a 5-year normal (Figure 5). We expect that by the end of the heating season-less than 2 months away - working gas in storage will be double the level at the end of last March. Another factor that helped to temper natural gas prices is the relatively low price for petroleum. Both crude and product prices are considerably less than they were this time last year, thus relieving any upward competitive price push on natural gas.

With the heating season nearly over (given the high storage levels and weak demand), it is perhaps surprising that natural gas prices have not fallen further. It is true that average daily spot prices at the Henry Hub have slipped below $2 per million Btu on more than one occasion since November, most recently on January 29 of this year. Yet for much of the heating season to date (mid-December through mid-February), Henry Hub spot prices have remained in the $2.30-$3.00 per million Btu range. Our current view for natural gas prices is that for much of the rest of 2002, spot wellhead prices will hover near (or perhaps slightly below) the $2.00-per-million-Btu level. A modest recovery in prices by late 2002 or early 2003 depends largely upon the speed of recovery in the U.S. economy, weather, and the net effect on gas productive capacity of the slowdown in U.S. drilling. The latest statistics from Baker Hughes show that gas-directed drilling in the United States has fallen to levels not seen since July 2000. We believe that room for some continued declines exists over the next several months because, on balance, aggregate lease revenues for oil and gas producers aren't likely to turn upward again until mid-summer. This will be particularly true if oil prices remain flat or weaken instead of increasing gradually as expected. For 2003, we project that, as economic growth accelerates and as world oil prices rise, natural gas wellhead prices will rise accordingly, gaining about 50 cents per thousand cubic feet on average compared to 2002.

Very little information regarding Enron's true financial status was available to natural gas markets prior to October 16, 2001. In the period from that day through February 9, 2002, natural gas spot prices have fluctuated between $2 and $3 per million Btu (MMBtu) at the Henry Hub, with only a few brief exceptions.

The price fluctuations during this period do not appear to have a clear correspondence with important dates involving Enron (Figure 6). While all daily variation is not necessarily easily explained, the price trends over weeks relate well to market conditions. Spot prices were increasing during October, which is a typical occurrence as the markets prepare for the heating season. Weather forecasts at the time were calling for a cold winter and prices reacted accordingly. As low temperatures failed to materialize, prices subsided to levels around $2. In December, as temperatures declined, once again forecasts were calling for cold winter temperatures in the near future, and natural gas prices rose in reaction.

Since the beginning of the year, weather has tended to be warmer than normal, which has kept prices from increasing greatly. Further, the generally higher-than-normal temperatures during the heating season caused operators to limit withdrawals of natural gas from storage. The exceptionally large volumes of gas remaining in storage pose a substantial supply cushion that has mitigated the impact of any demand pressures on the market.

Looking back over the past 2 years, natural gas markets have experienced a remarkable period in which prices rose from just above $2 per MMBtu in January 2000 to more than $10 by the end of the year. After beginning 2001 at these elevated levels, prices returned to below $2 by the end of September 2001 (Figure 7). EIA examined gas market conditions and prices in two studies, U.S. Natural Gas Markets: Recent Trends and Prospects for the Future (May 2001), and U.S. Natural Gas Markets: Mid-Term Prospects for Natural Gas Supply (December 2001). These reports concluded that the high natural gas prices experienced in 2000 were caused by constrained domestic productive capacity that resulted from a sustained period of relatively low oil and natural gas prices, followed by unusually high demand-the result of strong economic growth and an unusually warm summer and cold winter-and a poor storage position heading into the winter season (November 2000 through February 2001).

EIA does not believe that the Enron situation has had a strong detrimental impact on natural gas markets. The major events involving Enron do not appear to have a correlation with natural gas markets and prices. Further, gas price patterns during the past 2 years have reasonable explanations that did not require an extraordinary role for Enron.

In many ways, Enron was deemed a very large company. Among the 33 major energy companies reporting to the Financial Reporting System (FRS) in 2000, Enron ranked second in total revenues (11 percent share), third on total assets (9 percent share), seventh on capital expenditures (4 percent share), and tenth on the basis of net income (2 percent share). However, as the table below shows, Enron accounted for less than 1 percent of total retail electricity sales, generating capacity, and electricity generation in the United States in 2000. Enron mainly operated in wholesale trading markets, without owning or operating physical assets.

In the natural gas business, Enron was a major player in the interstate gas pipeline business. Overall it had interests in 10 percent of the interstate gas pipeline capacity in the United States (Table 2). However, some of this capacity has already been sold. In January 2002, the largest pipeline Enron owned was sold to Dynegy, reducing its interests to 7 percent. Enron also has interests in some gas storage and intrastate pipeline facilities. Enron operates underground storage facilities through Northern Natural in the States of Iowa and Kansas. Midwest Natural Gas Transmission operates one storage field in Indiana. The total capacity of these storage operations is approximately 2.5 percent of the total underground storage capacity for the nation. On a State basis, the fields operated by Enron entities account for more then 40 percent of the 273 billion cubic feet (Bcf) of capacity in Iowa and more then 25 percent of the 301 Bcf of capacity in Kansas. Operations in Indiana amount to less then 1 percent of the total storage capacity for the State. No storage operations are associated with either Florida Gas Transmission or Northern Border. All of these facilities are expected to continue to operate regardless of their future ownership.

Between 2000 and 2020, the national average price of electricity in real 2000 dollars is projected to decline from 6.7 cents per kilowatt-hour to 6.5 cents per kilowatt-hour, an average reduction of 0.2 percent per year, mainly as a result of competition among electricity suppliers (Figure 8). By sector, projected prices in 2020 are 6.4, 3.9, and 0.2 percent lower than 2000 prices for residential, commercial, and industrial customers, respectively.

The cost of producing electricity is a function of fuel costs, operating and maintenance costs, and the cost of capital. In 2000, fuel costs typically represented $22 million annually--or 76 percent of the total operational costs (fuel and variable operating and maintenance)--for a 300-megawatt coal-fired unit, and $66 million annually--or 93 percent of the total operational costs--for a natural-gas-fired combined-cycle unit of the same size. For nuclear units, fuel costs are typically a much smaller portion of total production costs. Nonfuel operations and maintenance costs are a larger component of the operating costs for nuclear power units than for plants that use fossil fuels.

The impact of rising natural gas prices in the forecast is more than offset by a combination of falling coal prices and stable nuclear fuel costs. After the price spikes of 2000 and 2001, natural gas prices to electricity suppliers are projected to rise by 2.2 percent per year in the forecast, from $2.64 per thousand cubic feet in 2002 to $3.94 in 2020 (Figure 9). The natural gas price increases after 2002, however, are offset by forecasts of declining coal prices, declining capital expenditures, and improved efficiencies for new plants.

Before 2001, 14 States, including California, instituted competition in their retail electricity markets. Both the District of Columbia and Ohio began retail competition in 2001, and Texas and Virginia are scheduled to begin in 2002. Since the beginning of 2000, however, 7 States have delayed the opening of competitive retail markets beyond the dates originally planned, and in the fall of 2001, California suspended retail competition. Specific restructuring plans differ from State to State and utility to utility, but most call for a transition period during which customer access will be phased in. The transition period reflects the time needed for the establishment of competitive market institutions and the recovery of stranded costs as permitted by regulators. It is assumed that competition will be phased in over 10 years, starting from the inception of restructuring in each region. In all the competitively priced regions, the generation price is set by the marginal cost of generation. Transmission and distribution prices are assumed to remain regulated.

It is not clear at this point to what extent the Enron situation will affect the announced plans of these States to move their electricity markets toward competitive restructuring. Clearly, the large price increases seen in California during the second half of 2000 had a chilling impact on the trend toward deregulation. There have been no recent announcements of new State-level restructuring initiatives. On the other hand, with the return to stability in the California electricity market, as well as in national natural gas markets, there have been only a few decisions to delay or reverse the announcements already made. No clear trend concerning Enron's impact on electricity prices are discernible, implying that the effects will be small at best.

The continuing saturation of electric appliances, the availability and adoption of more efficient equipment, and efficiency standards are expected to hold the growth in electricity sales to an average of 1.8 percent per year between 2000 and 2020, compared with a 3.0-percent annual growth in GDP. By 2020, electricity sales are expected to be 4916 billion kilowatt-hours, compared to 3413 billion kilowatt-hours in 2000, a 44 percent increase. During the 1960s, electricity demand grew by more than 7 percent per year, nearly twice the rate of economic growth (Figure 10). In the 1970s and 1980s, however, the ratio of electricity demand growth to economic growth declined to 1.5 and 1.0, respectively. Several factors have contributed to this trend, including increased market saturation of electric appliances, improvements in equipment efficiency and utility investments in demand-side management programs, and more stringent equipment efficiency standards. Throughout the forecast, growth in demand for office equipment and personal computers, among other equipment, is dampened by slowing growth or reductions in demand for space heating and cooling, refrigeration, water heating, and lighting.

With the number of U.S. households projected to rise by 1.0 percent per year between 2000 and 2020, residential demand for electricity is expected to grow by 1.7 percent annually, to 1672 billion kilowatt-hours (Figure 11). Electricity demand in the commercial sector is projected to grow by 2.3 percent per year between 2000 and 2020. Projected growth in commercial floorspace of 1.7 percent per year contributes to the expected increase. Electricity is projected to account for three-fourths of commercial primary energy consumption throughout the forecast. Expected efficiency gains in electric equipment are expected to be offset by the continuing penetration of new technologies and greater use of office equipment. In the industrial sector, electricity consumption is projected to grow 1.4 percent annually over the forecast period, stimulated by growth in industrial output of 2.6 percent per year. Industrial delivered electricity use is projected to increase by 32 percent, with competition in the generation market keeping electricity prices low.

From 2000 to 2020, 355 gigawatts of new generating capacity (excluding cogenerators) is expected to be needed to meet growing demand and to replace retiring units (Figure 12), bringing total capacity to about 1060 gigawatts. Between 2000 and 2020, 10 gigawatts (10 percent) of current nuclear capacity and 37 gigawatts (7 percent) of current fossil-fueled capacity are expected to be retired, nearly all before 2010. Of the 185 gigawatts of new capacity expected by 2010, 10 percent is projected to replace retired oil- and natural-gas-fired steam capacity.

Because of their favorable economics, natural gas-fired combined-cycle units are projected to be used for most new baseload requirements. The average efficiency for combined-cycle units is expected to approach 54 percent by 2010, compared with 49 percent for coal-steam units, and the expected construction costs for combined-cycle units are about 44 percent of those for coal-steam plants. As a result, most (59 percent) of the projected combined-cycle additions are expected before 2010. As natural gas prices rise later in the forecast, new coal-fired capacity is projected to become more competitive, and 80 percent of the projected additions of new coal-fired capacity are expected to be brought on line from 2010 to 2020.

A total of 31 gigawatts of new coal-fired capacity is projected to come on line between 2000 and 2020, accounting for almost 9 percent of all the capacity expansion expected. Competition with low-cost gas-turbine-based technologies and the development of more efficient coal gasification systems have compelled vendors to standardize designs for coal-fired plants in efforts to reduce capital and operating costs in order to maintain a share of the market. Renewable technologies account for 3 percent of expected capacity expansion by 2020--primarily wind, geothermal, and municipal solid waste units. About 19 gigawatts of distributed generation capacity is projected to be added by 2020, as well as a small amount (less than 1 gigawatt) of fuel cell capacity.

In addition to building new capacity, electricity generators are expected to use other options to meet demand growth--maintenance of existing plants, power imports from Canada and Mexico, and purchases from cogenerators.

As they have since early in this century, coal-fired power plants are expected to remain the key source of electricity through 2020 (Figure 13). In 2000, coal accounted for 1,968 billion kilowatt-hours or 52 percent of total generation, including cogeneration. Although coal-fired generation is projected to increase to 2,472 billion kilowatthours in 2020, increasing gas-fired generation is expected to reduce coal's share to 46 percent. Concerns about the environmental impacts of coal plants, their relatively long construction lead times, and the availability of economical natural gas make it unlikely that many new coal plants will be built before about 2005. Nevertheless, slow growth in other generating capacity, the huge investment in existing plants, and increasing utilization of those plants are expected to keep coal in its dominant position. By 2020, it is projected that 23 gigawatts of coal-fired capacity will be retrofitted with scrubbers to meet the requirements of the Clean Air Act Amendments of 1990 (CAAA90).

In percentage terms, natural-gas-fired generation is projected to show the largest increase, from 16 percent of the total in 2000 to 32 percent in 2020. As a result, by 2004, natural gas is expected to overtake nuclear power as the Nation's second-largest source of electricity. Generation from oil-fired plants is projected to remain fairly small throughout the forecast.

From 1995 to 2000, the wellhead price of natural gas averaged $2.38 per thousand cubic feet (2000 dollars). Relative to that average, the price is expected to increase at an average rate of 1.6 percent per year in the reference case, reaching $3.26 in 2020 (Figure 14).

Increasing prices reflect the rising demand for natural gas; the progression of the discovery process from larger, shallower, and more profitable fields to smaller, deeper, and less profitable ones; and increasing production from higher cost sources, such as unconventional natural gas. Projected average growth in production from unconventional sources from 2000 to 2020 ranges from 3.1 to 3.6 percent per year across the cases, compared to a range of 2.0 to 2.2 percent per year for conventional sources. Technically recoverable gas resources are expected to remain more than adequate to meet the projected production increases. The price increases are expected to be tempered by technological progress in both discovering and producing natural gas.

Long-term end-use prices for natural gas are projected to be lower than the relatively high prices experienced in 2000 and 2001. Average transmission and distribution margins are generally expected to remain constant or decline through 2020, moderating the projected increase in wellhead prices. The average end-use price is expected to increase by 35 cents per thousand cubic feet from 2005 through 2020, compared with an increase of 61 cents per thousand cubic feet in the average price of domestic and imported supply in the same period. By 2020, the average end-use price is expected to be $4.92 per thousand cubic feet.

Declining margins are particularly important in restraining the rise in both residential and commercial end-use prices (Figure 15). From 2005 through 2020, residential and commercial end-use prices are projected to increase by 12 cents per thousand cubic feet, to $7.16, and 28 cents per thousand cubic feet, to $6.02, respectively.

The industrial and electricity generation sectors have the lowest end-use prices, in part because they receive most of their natural gas directly from interstate pipelines, avoiding local distribution charges. Summer-peaking electricity generators reduce their transmission costs by using lower cost interruptible transportation rates during the summer when spare pipeline capacity is available; however, as electricity generators take an increasing share of the market, they are expected to rely on higher cost firm transportation to a greater extent. Prices of natural gas for the industrial and electricity generation sectors are projected to reach $4.01 and $3.94, respectively, by 2020. The highest end-use prices are expected for compressed natural gas vehicles, because the costs of additional infrastructure requirements are expected to be added to pipeline and distribution rates.

Growth in domestic natural gas production of 9.4 trillion cubic feet between 2000 and 2020 is expected to come primarily from lower 48 onshore nonassociated (NA) sources (Figure 16). Conventional onshore natural gas production is projected to grow rapidly in the last 10 years of the forecast, increasing its share of total lower 48 production from 37 percent in 2000 to 39 percent in 2020. As a result of technological improvements, production from unconventional sources (tight sands, shale, and coalbed methane) is projected to increase more rapidly. Unconventional natural gas production is projected to increase from 25 percent of total lower 48 production in 2000 to 32 percent in 2020. Production of associated-dissolved (AD) natural gas from lower 48 crude oil reserves declines slightly in the projections, following the expected pattern of crude oil production. AD natural gas is projected to account for 9 percent of lower 48 natural gas production in 2020, compared with 16 percent in 2000.

Offshore production is expected to increase less rapidly, accounting for 24 percent of total lower 48 gas production in 2020. In recent years, innovative cost-saving technologies have been applied, particularly in the deep waters of the Gulf of Mexico, where significant finds are expected to continue.

Alaskan natural gas production is projected to grow by 1.7 percent per year through 2020 to meet expected State demand. Options for marketing the gas outside Alaska include transportation through a pipeline, conversion to liquefied natural gas (LNG), and conversion to synthetic petroleum products.

Imports of natural gas make up the difference between U.S. production and consumption (Figure 17). Imports are generally expected to be priced competitively with domestic sources. Imports from Canada, primarily from western Canada and the Scotian Shelf in the offshore Atlantic, are expected to make up most of the increase in U.S. imports. Because most of the producing regions in Canada are less mature than those in the United States, there is strong potential for low-cost production. Net imports from Canada are projected to provide 15 percent of total U.S. supply in 2020, about the same as in 2000.

LNG imports are expected to increase, but they are not expected to become a major source of U.S. supply through 2020. Two LNG import facilities, at Cove Point, Maryland, and Elba Island, Georgia, have been closed for many years but are expected to reopen by 2002. It is expected that those facilities, plus the other two U.S. facilities, at Everett, Massachusetts, and Lake Charles, Louisiana, will be operating at full capacity by 2010, supplying 0.8 trillion cubic feet per year through 2020.

Although Mexico has a considerable natural gas resource base, trade with Mexico has until recently consisted primarily of exports from the United States. Mexico is projected to remain a net importer of U.S. natural gas through 2020; however, U.S. exports are expected to peak in 2015 and then decline as the infrastructure is developed for Mexican natural gas to meet indigenous demand.

Total natural gas consumption is projected to reach 33.8 trillion cubic feet by 2020. Increasing demand by electricity generators (excluding cogenerators) is expected to account for 55 percent of the total consumption growth by 2020 (Figure 18). Demand growth is also expected in the residential, commercial, industrial, and transportation sectors. Most new electricity generation capacity is expected to be fueled by natural gas, and natural gas consumption in the electricity sector is projected to grow rapidly throughout the forecast as electricity consumption increases.

In the reference case, natural gas consumption for electricity generation (excluding cogeneration) is projected to increase from 4.2 trillion cubic feet per year in 2000 to 10.3 trillion cubic feet per year in 2020, an average annual growth rate of 4.5 percent. At the end of the forecast period, electricity generation is expected to surpass the industrial sector as the largest consumer of natural gas. Although coal prices to the electricity generation sector are generally projected to fall throughout the forecast, natural-gas-fired electricity generators are expected to have advantages over coal-fired generators, including lower capital costs, higher fuel efficiency, shorter construction lead times, and lower emissions.

Although more than half the increase in natural gas consumption between 2000 to 2020 is expected in the East, the West--including Canadian imports and most of the Gulf Offshore--is expected to provide approximately 80 percent of the incremental lower 48 natural gas supply in the reference case. As a result, most new natural gas pipelines are expected to be built from the West to the East. The exception is expected new pipeline capacity originating in Canada and the Rocky Mountains, which will be needed to meet growth in natural gas consumption along the Pacific Coast.

The collapse of Enron Corporation, while detrimental to the employees and shareholders of the company, has not had a noticeable impact on energy markets, especially those for electricity and natural gas, to date. An examination of wholesale price data for both electricity and natural gas indicates that, during the same period that Enron stock was declining from over $37 to less than $1 a share, spot prices for electricity and natural gas were relatively stable, showing normal fluctuations related to supply and demand. It is not expected that the Enron situation will have any lasting impact on future electricity and natural gas markets, either in the short term, or through 2020. Electricity prices are expected to remain fairly stable over the next couple of years, with a slight decline through about 2010 due to the effects of competition and falling coal prices before rising again through 2020 because of rising natural gas prices. Natural gas prices, which were highly volatile during much of 2000 and 2001, are expected to be lower in 2002 before rising about $0.50 per thousand cubic feet at the wellhead in 2003. In the long term, natural gas prices are expected to increase from current levels, reaching $3.26 per thousand cubic feet (real 2000 dollars) by 2020.

Thank you, Mr. Chairman and members of the Subcommittee. I will be happy to answer any questions you may have.

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