Demand for distillate fuel oil (used largely for heating) for this winter, defined as the period from October 1997-March 1998, is projected to average 3.69 million bbl/d, up 160,000 bbl/d from the same period last year. This forecast assumes a return to normal weather. In the Northeastern United States -- the principal market for heating oil -- this would imply a 3.6% colder winter than last year. Beginning-of-season distillate stocks are projected at an adequate 136 million barrels, up more than 21 million barrels from last year. End-of-season inventories, on the other hand, are expected to be drawn down to 96 million barrels, or 6 million barrels less than last year. Assuming normal weather and moderate crude oil prices, retail heating oil prices should average $0.95 per gallon this winter, compared to $1.06 per gallon last winter.

Total winter natural gas demand is expected to increase 4% over last year, with first quarter 1998 gas requirements expected at 81.2 billion cubic feet/day, up from 76.5 billion cubic feet/day last year. Natural gas wellhead prices are expected to be relatively high, but still less than last winter, averaging about $2.60 per thousand cubic feet.

Electricity demand is expected to increase sharply this winter as well as in future months. First quarter 1998 electricity demand is expected to be 4.2% higher than the for the same period in 1997. This forecast assumes "normal" weather, which would contrast with a mild winter in 1996-97 followed by a cool summer in 1997. Hydroelectric power generation is expected to be down from last year's high levels, leading to increased fossil fuel -- especially coal -- use at power plants this winter. Coal plant utilization is expected to reach new highs in 1998.

The United States has 22.4 billion barrels of oil reserves, eleventh largest in the world. These reserves are concentrated primarily in Texas (26%), Alaska (26%), California (16%), and the Gulf of Mexico Federal Offshore region (9%). U.S. proven oil reserves have declined by more than 4 billion barrels since 1988, with the largest single-year decline (1.6 billion barrels) occurring in 1991.

The United States produced 9.44 million barrels per day (bbl/d) of oil in 1996, of which 6.46 million bbl/d was crude oil. Total U.S. domestic crude oil production is expected to decline by about 0.9% in 1997, with little or no decline in 1998. U.S. crude oil output of 6.3 million bbl/d in August 1997 represented the lowest output since 1954. There are signs that this decline may have leveled off, and that a slow increase may be in store due largely to improved technology and new or increased offshore production in the Gulf of Mexico (including the Auger, Mars, and Ram-Powell fields). All told, oil production in the lower 48 states is expected to increase slightly in 1998. Alaskan crude oil production, however, is expected to fall by around 7% in both 1997 and 1998. This represents the continuation of a trend which began in 1991. During this time, new discoveries in Alaska have only partly offset reduced production from Prudhoe Bay and other North Slope fields

Despite a recent trend towards lower crude output, Prudhoe Bay, Alaska remains by far the largest oil field in the United States, with about 780,000 bbl/d of production. Kuparak, Alaska ranks second, with about 270,000 bbl/d of output, followed by: Midway-Sunset, California (161,500 bbl/d); Pt. McIntyre, Alaska (157,000 bbl/d); and Kern River, California (132,000 bbl/d).

In early October 1997, a coalition of environmental groups petitioned the U.S. Department of the Interior (DOI) to prevent ARCO from drilling for oil and gas at the "Warthog" well, located in waters only a few miles offshore from the Arctic National Wildlife Refuge. ARCO was awarded a lease earlier in 1997 by DOI's Minerals Management Service to drill in the area, and ARCO had planned to begin by late October or early November. In other activies, ARCO Alaska, in partnership with Anadarko Petroleum Corp. And Union Texas Alaska LLC, plan to begin construction of the $750 million Alpine project in early 1998. Also, ARCO, Exxon and BP Exploration plan to increase Prudhoe Bay production by 20,000 bbl/d through the "Mix" project, with startup slated for the fall of 1999. These three companies are also beginning a $45 million enhanced oil recovery project at Point McIntyre.

In September 1997, the U.S. Forest Service banned oil and gas exploration on a large portion of Montana's Rocky Mountain front. Oil exploration is also banned beneath the Continental Shelf along coastal California, in the Gulf of Mexico off Florida, and offshore North Carolina. These three areas may contain more than 13 billion barrels of oil. On October 28, 1997, the U.S. Senate passed legislation extending the existing moratorium on offshore oil and gas drilling in parts of the Gulf of Mexico and Alaska for one more year.

In August 1997, Baker Hughes Inc. (an oil field service company which has tallied weekly U.S. drilling activity since 1940) reported that domestic drilling had broken through the 1,000-rig mark, the highest level of activity since January 1991. U.S. drilling activity peaked in December 1981, with an average of 4,521 rigs operating at that time. Following this peak, drilling declined steadily, bottoming out at 670 in the spring of 1995.

During the second quarter of 1997 (2Q97), overall net income of 19 major U.S. petroleum companies reached $7.7 billion, up 9% from the second quarter of 1996 (Q296). This increase in income occurred despite lower crude oil and natural gas prices and therefore lower upstream (oil and gas production) earnings compared to Q296. Increases in downstream (refining and marketing) earnings for the major oil and gas companies, on the other hand, more than compensated for the upstream decrease. Meanwhile, income for independent oil and gas producers fell 23.4% from 2Q96 to 2Q97, while income for independent refiners increased 26.9% during the same period.

Consumption/Marketing

The United States consumed 18.3 million bbl/d of oil in 1996. Of this, 7.9 million bbl/d (or 43% of the total) was motor gasoline, 3.4 million bbl/d (18%) distillate fuel oil, 1.6 million bbl/d (9%) jet fuel, and 850,000 bbl/d (5%) residual fuel oil. U.S. oil demand is expected to increase by about 300,000 bbl/d (1.6%) in 1997, and another 270,000 bbl/d (1.5%) in 1998.

U.S. petroleum marketers are attempting to upgrade their underground storage tanks (UST's) in order to comply with new regulations by the U.S. Environmental Protection Agency (EPA) scheduled to take effect on December 22, 1998. As of August 1997, the Petroleum Marketers Association of America (PMAA) reported that 73% of UST's are in compliance, up from 65% in 1996, 61% in 1995, and 56% in 1994.

Imports/Exports

Slightly lower U.S. crude oil production combined with a strong increase in oil demand led the United States to import 8.5 million bbl/d of oil (on a net basis) in 1996. During the first 8 months of 1997, U.S. net imports of crude oil and refined petroleum products were 9.0 million bbl/d, up 4.7% from the same period in 1996. These oil imports represented 48% of U.S. oil consumption. Slightly less than half of this oil came from OPEC nations, with Persian Gulf sources accounting for about 19% of U.S. oil imports during the period, down from 25% on average during 1990. Overall, the top suppliers of oil to the United States for January-August 1997 were Venezuela (1.7 million bbl/d), Canada (1.45 million bbl/d), Saudi Arabia (1.4 million bbl/d), and Mexico (1.4 million bbl/d).

U.S. Energy Sanctions Issues

Two developments in 1997 raised serious questions for U.S. energy sanctions' policy. First, in late July, the issue of a possible $2 billion natural gas pipeline from Turkmenistan across northern Iran to Turkey came to the fore. This deal, if it is actually consummated by Royal Dutch/Shell, could constitute a possible (depending on interpretation) violation of a U.S. law passed in July 1996 that called for sanctions against foreign companies which invest in Libya or Iran. In theory, the legislation requires the President to impose sanctions on firms investing $20 million or more during a given 1-year period in either country's oil industry. These sanctions include a ban on doing business with the U.S. government or on exporting goods to the United States, as well as restrictions on borrowing from U.S. financial institutions or receiving equipment requiring U.S. export licences. In the case of the pipeline, the situation is ambiguous because no Iranian gas would utilize the line, but on the other hand Iran will make money from transit fees. As of late October 1997, Administration policy on this case remained somewhat unclear.

A second potentially serious violation of U.S. law occurred in late September 1997, when French oil and gas company Total, along with Russia's Gazprom and Malaysia's Petronas, signed a $2 billion contract with the National Iranian Oil Co. to develop the giant South Pars natural gas field. Pars, located in the Persian Gulf adjacent to the maritime border with Qatar, has gas reserves estimated at 300 Tcf. Production is scheduled to begin in the second half of 2001. Besides South Pars, Total is also currently involved in the development of Iran's offshore Sirri oil fields.

Refining

The United States has experienced a steep decline in refining capacity since 1981. Between 1981 and 1989, the number of U.S. refineries fell from 324 to 204, representing a loss of 3 million bbl/d in operable capacity, and a concomitant increase in refining capacity utilization from 69 to 86%. Much of this decline resulted from the 1981 deregulation (elimination of price controls and allocations), which effectively removed the major prop from underneath many marginally profitable, often smaller, refineries. Between 1989 and 1992, refining capacity remained roughly stable. Since 1992, about 34 additional, mainly small U.S. refineries have shut down, for a wide variety of reasons (including environmental regulations to a minor extent). This, combined with higher refinery runs, raised average weekly capacity utilization recently to more than 98%, the highest rate in at least 20 years.

Since the mid-1980's, several U.S. refiners have joined with foreign (especially Venezuelan) companies in various joint venture arrangements. In 1986, for instance, Venezuela's state oil company PdVSA acquired a 50% interest in Citgo's U.S. refining operation. In 1988, Texaco and Saudi Aramco created Star Enterprise, an integrated refining and marketing operation with three refineries and a network of Texaco gasoline stations. Unocal and PdVSA followed suit in 1989, forming Uno-Ven Co. (in 1997, PdVSA bought out Unocal's share). In late October 1997, Mobil signed an agreement with a PdVSA subsidiary signed an agreement on joint ownership of the 170,000 bbl/d refinery in Chalmette, Louisiana. Prior to this deal, PdVSA owned around 1 million bbl/d in U.S. refining capacity.

On October 14, 1997, Energy Secretary Peña signed an agreement with Venezuela's Energy Minister, Erwin Arrieta, to expand bilateral cooperation in petroleum research and development, energy efficiency, renewable energy, and energy information systems. A meeting of Western Hemisphere energy ministers will be held in Caracas, Venezuela in January 1998, followed by a summit in Santiago, Chile, to focus further on regional energy issues.

Gasoline Prices

Retail motor gasoline prices increased sharply (about 6 cents per gallon) between the July 4 holiday and Labor Day, 1997. Reasons for this spike included refinery problems, high gasoline demand, and increased crude oil prices. For these reasons, average retail gasoline prices surpassed $1.30 per gallon by August and September, several cents above prices during the same period in 1996. Prices were even higher in California, largely due to that state's stringent reformulated gasoline (RFG) requirements, which first came into effect June 1, 1996. Pump prices began to ease a few weeks after Labor Day, the traditional endpoint of the summer driving season. Assuming no major supply disruptions, gasoline prices are expected to average a few cents per gallon below the average for 1997.

Strategic Petroleum Reserve

In the aftermath of the 1973 Arab Oil Embargo, the United States began looking at ways to enhance its energy security. As part of this effort, the U.S. Strategic Petroleum Reserve (SPR) was officially established on December 22, 1975, when then-President Ford signed the Energy Policy and Conservation Act (EPCA). EPCA declared it to be U.S. policy to establish a petroleum reserve of up to 1 billion barrels. In order to store the reserve oil, the U.S. government in April 1977 acquired several salt caverns along the Gulf of Mexico coastline. The first crude oil was delivered to the SPR on July 21, 1977, and stored at the West Hackberry storage site near Lake Charles, LA. Other major storage sites include: Bryan Mound and Big Hill in Texas; and Bayou Choctaw, Weeks Island, the St. James Terminal in Louisiana.

The Department of Energy (DOE) has not acquired any new oil for the SPR since 1994, when the reserve peaked at 592 million barrels. In recent years, Congress has ordered DOE to sell oil in order to finance operations of the SPR. After selling off $327 million worth of SPR oil in 1996, and $220 million in 1997, the SPR now contains 563 million barrels of oil -- still the largest emergency oil stockpile in the world. However, in relative terms (i.e., the amount of imported oil the SPR could replace) the SPR has shrunk from about 115 days of import replacement in 1985 to only about 67 days now. On October 28, 1997, the U.S. Senate passed legislation directing DOE to sell $207.5 million of oil from the SPR in FY 1998. DOE has stated that it would have preferred to use revenues from the sale of the Elk Hills naval petroleum reserve (located in California) to avoid any further sales of SPR oil. DOE announced October 6, 1997 that it would sell its 78% share in Elk Hills to Occidental Petroleum Corp. for $3.65 billion. With the sale of Elk Hills, which produces about 60,000 bbl/d, the U.S. government now owns just two oil reserves (besides the SPR) -- Buena Vista in California and Teapot Dome in Wyoming.

Under EPCA, there is no preset "trigger" for withdrawing oil from the SPR. Instead, the President determines that drawdown is required by "a severe energy supply interruption or by obligations of the United States" under the International Energy Agency. EPCA defines a "severe energy supply interruption" as one which: 1) "is, or is likely to be, of significant scope and duration, and of an emergency nature;" 2) "may cause major adverse impact on national safety or the national economy;" and 3) "results, or is likely to result, from an interruption in the supply of imported petroleum products, or from sabotage or an act of God."

Should the President decide to order an emergency drawdown of the SPR, oil would be distributed mainly by competitive sale to the highest bidder(s). This would be accomplished in a 4-step process, including a "Notice of Sale," receipt of bids, selection of bidders, and finally delivery of oil. Today, the SPR can withdraw oil at a maximum sustained rate of 3.9 million bbl/d for a 90-day period. To date, the SPR has been drawn down during two test sales as well as during (and after) Operation Desert Storm in January-March 1991.

As of January 1, 1997, the United States had estimated natural gas reserves of 166 trillion cubic feet (Tcf), or 3.3% of world reserves. In 1997, the United States is expected to produce 18.9 Tcf of gas, second in the world (behind Russia). Also during 1997, the United States is forecast to consume 21.9 Tcf and to import 3.0 Tcf of gas (largely from Canada). For 1998, U.S. natural gas demand is expected to jump another 1 Tcf, or 4.3%, from 1997, while imports are expected to rise 7.6%. Overall, the United States depends on natural gas for about one-quarter of its total energy requirements.

Natural gas is considered a desirable fuel -- both for environmental and national security reasons -- by top U.S. government officials. In May 1997, U.S. Energy Secretary Peña called for expanded use of natural gas as part of a strategy to reduce U.S. dependence on imported foreign oil. In October, President Clinton also said that the United States must pursue a policy of "fuel conversion" from coal to natural gas for electric power generation. Meanwhile, thanks to improvements in exploration and development technology, new natural gas reserves continue to be added in the United States. In 1996, U.S. total discoveries of dry gas were over 12 Tcf, up 12% from 1995. Over two-thirds of these discoveries were in Texas and the Gulf of Mexico Federal Offshore region.

Natural gas wellhead prices averaged $2.25 per thousand cubic feet in 1996, and are expected to average $2.40 per thousand cubic feet in 1997. This compares to a record high level of $3.38 per thousand cubic feet reached during February 1996 (due to cold weather and low inventory levels). Natural gas wellhead prices are forecast to average $2.25 per thousand cubic feet in 1998.

During the early 1980s, relatively low natural gas demand combined with increased drilling led to a large surplus capacity coming on-line. After 1986, this large surplus began to diminish as natural gas prices fell, causing demand to increase and new gas well completions to fall sharply. On November 1, 1993, the U.S. Federal Energy Regulatory Commission (FERC) issued Order No. 636, which decoupled the various stages of the natural gas industry between wellhead and end-user. This order has led to significant restructuring of the interstate natural gas pipeline industry, including moves towards unbundled services, diversification into other energy sectors, and development of mega-pipeline systems.

Combined with the North American Free Trade Agreement (NAFTA), FERC Order 636 also helped make North American integration in the natural gas sector more attractive. Already, the United States and Canada are highly inter-connected, with pipeline capacity from Canada into the United States increasing by nearly 60% between 1990 and 1994. Certain regions of the United States, such as the Northeast and Pacific, depend on Canadian gas for significant amounts of their supply. Overall, the United States received about 12% of its natural gas from Canada in 1995. Mexico, on the other hand, remains a net natural gas importer from the United States, despite the potential for becoming a significant exporter given adequate development of necessary production and transportation infrastructure.

In the long-run (through 2015), U.S. natural gas production is expected to increase sharply as a result of rising prices, abundant reserves, and improved unconventional and offshore recovery technology. Increased gas production is expected to come mainly from onshore nonassociated sources, although offshore Gulf of Mexico production also is forecast to grow significantly. Alaska's North Slope fields are also a large potential gas source, with an estimated 30-35 Tcf of gas reserves.

U.S. natural gas consumption also is expected to expand substantially through 2015, with the fastest growth resulting from additional gas-fired electric power plants. In particular, new combined-cycle facilities furnished with more efficient gas turbines will help lower the cost of gas-generated electricity to levels competitive with coal-fired plants. Increased consumption of natural gas in the United States will require expansion of gas pipeline and storage capacity.

In July 1997, the Federal Energy Regulatory Commission (FERC) approved three separate gas pipeline projects. Two of these projects -- by the Natural Gas Pipeline Company of America (NGPL) and Northern Border Pipeline -- are both designed to feed gas into the upper midwestern area from Canadian sources. The third project (the Maritimes and Northeast Pipeline) is set to bring Canadian gas into northern New England by late 1998. In late September 1997, FERC approved the second phase of this project, which will bring gas from Nova Scotia into Maine beginning in the fall of 1999.

The United States is expected to produce 1,083 million short tons (mmst) of coal in 1997, the highest amount ever recorded. Of this total, the United States will consume 1,002 mmst and export 80 mmst. Wyoming was the leading U.S. coal-producing state in 1996, followed by West Virginia and Kentucky. Appalachia accounted for about 42% of total U.S. production, mainly from underground mines. Nearly all remaining U.S. coal production came from states west of the Mississippi River, overwhelmingly from surface mines. For the country as a whole, 62% of coal produced was bituminous, 29% subbituminous, and 9% lignite (brown coal).

During 1996, coal production increased in all U.S. regions -- Appalachia, the interior United States, and the West. Output growth for relatively low-sulfur western coal slowed in 1996, following strong increases in 1994 and 1995 prompted largely by Phase 1 of the Clean Air Act Amendments of 1990 (CAAA). CAAA originally took effect during 1995, and required lower sulfur emissions from coal combustion. In response, Wyoming increased its coal production sharply, particularly low-sulfur, low-ash coal from the Powder River Basin. Output growth from Appalachia in 1996 was largely a result of strong demand by eastern electric utilities, a decline in nuclear and gas-fired generation in the east, and a rise in exports.

The United States is the second largest coal exporter in the world, behind Australia. In 1996, the United States had net exports of 83.3 million short tons of coal. Of this total, about half went to Europe, one-quarter to Asia, and the remainder mainly to Canada and Brazil. During 1995, U.S. coal exports had rebounded strongly from 1993 and 1994. During 1993, coal exports fell due to labor strikes, and in 1994 exports were depressed by sluggish economic recoveries in Europe and Japan, combined with competition from other major coal-exporting countries like Australia and South Africa. Most of the recovery in 1995 coal exports was attributable to increased steam coal exports to Europe, which experienced a rebounding economy. Growth in 1996 came mostly from increased exports of steam and metallurgical coal, primarily to Asia and North America. U.S. coal exports are forecast to increase to more than 120 million short tons by 2015, largely as a result of higher demand for steam coal imports in Europe.

Electric utilities account for the vast majority (89%) of U.S. coal consumption, with independent power producers (IPPs) and manufacturing taking nearly all the rest. This pattern is expected to continue through 2015 at least, with coal maintaining a fuel cost advantage over oil and natural gas.

Recently, significant problems have surfaced in transporting coal from Wyoming's Powder River Basin to utilities in Texas and other U.S. Southwest states. The problem has been blamed on a 1996 merger of two railroads -- Union Pacific and Southern Pacific -- and apparently has worsened as winter approaches. In early October, for instance, the Texas Railroad Commission indicated that the state's largest consumer of western coal, Houston Lighting and Power, is operating with less than a week's supply of coal. In early September, the Federal Railroad Administration issued a report criticizing Union Pacific for a "fundamental breakdown" in rail safety, after a series of collisions caused the deaths of 12 people in the first 8 months of the 1997. On October 17, Union Pacific suspended traffic between Chicago and Texas as part of a plan to resolve most the recent congestion problems by December.

In late December 1995, the Office of Surface Mining (OSM) issued final rules on coal remining and land reclamation, as required under the Energy Policy Act of 1992. OSM's new rules encourages coal mining companies to recover additional coal from unreclaimed and abandoned mining sites if they agree to reclaim the land as part of the process. Many of these sites were mined and unreclaimed prior to enactment of the 1977 Surface Mining Control Act.

In 1997, the United States is forecast to produce 3,485 billion kilowatthours of electricity. Of this, about two-thirds will be generated by fossil fuels (mainly coal), with the remainder produced primarily by nuclear and hydroelectric plants. Geothermal and other "renewables" will account for about 2.9% of U.S. electricity generation in 1997.

Like other energy industries, the U.S. electric power sector in recent years has begun its own deregulation process. On April 24, 1996, FERC issued a final rule, Order No. 888, requiring electric utilities to open their transmission systems to power generated by other companies. Order No. 888 (and the related Order No. 889) is intended to help promote competition in the electric power industry and to increase demand for transmission services.

In the aftermath of FERC's deregulation order, Enron Corporation, the nation's largest natural gas supplier, announced on July 22, 1996 that it would purchase the Portland General Corporation, Oregon's largest power producer, for $2.1 billion in stock and the assumption of $1.1 billion in debt. Enron, although primarily involved in natural gas, has moved in recent years to increase its investment in electric power projects worldwide. At the same time, Enron has been attempting to integrate the two industries, and to increase the penetration of natural gas into the electric power generation sector. Purchase of Portland General appears to be part of that strategy, as well as an attempt by Enron to become a major marketing force in the $270 billion per year U.S. electricity industry.

Another important step towards deregulation and restructuring of the electric power sector in the United States will begin on January 1, 1998, when California will become the first state to completely end utility monopolies and allow all consumers to buy electric power from the cheapest supplier. On October 30, 1997, FERC gave the final go-ahead to this move. Analysts believe, however, that due to technicalities in implementing the law, results of this deregulation on consumer prices will most likely be limited, at least in the short-term.

Nuclear

In 1997, nuclear power is estimated to accounted for about 17.8% of U.S. electricity generation, second only to coal in the U.S. electricity generation mix, but down from 19.4% in 1996. Nuclear power's share of U.S. utility electric generating capacity in 1996 was highest in New England (40.6%), followed by New York/New Jersey (32.3%), the West (30.2%), the Middle Atlantic (29.1%), the South Atlantic (26.1%), the Midwest (22.9%), the Central Region (18.1%), the Southwest (14.4%), the Northwest (3.2%), and the North Central Region (0.0%). Nuclear plants operated at 76.4% capacity in 1996, down slightly from 77.5% in 1995, but up sharply from only 66% in 1990.

Nuclear power in the United States grew rapidly after 1973, when only 83 billion kilowatthours of nuclear power was produced. By 1996, nuclear power had grown more than 8-fold, with 110 nuclear power units generating a record 675 billion kilowatthours of electricity. This rapid growth in nuclear power generation, however, obscures serious underlying problems in the U.S. nuclear industry. After 1974, many planned units were canceled, and since 1977, there have been no orders for any new nuclear units, and none are currently planned. The 1979 Three Mile Island accident greatly increased concerns about the safety of nuclear power plants in the United States. The regulatory reaction to those concerns contributed to the decline in the number of planned nuclear units.

The long-term (through 2015) nuclear power outlook in the United States is for nuclear capacity to decline sharply, with no new nuclear units expected to come on-line during the forecast timeframe. By 2015, the United States is expected to have 59 nuclear units (compared to 110 at the end of 1996) providing only 10% of total electricity generation. Several reasons for this projected decline in nuclear power in the United States are: 1) nuclear generation is more capital intensive, with longer lead-times for licensing and construction, than fossil-fueled generation; 2) this, along with other factors, leads to higher financing costs, placing nuclear power at a severe cost disadvantage to fossil-fuel plants; 3) safety and nuclear waste disposal are also a serious issue; 4) decontamination and decommissioning also are problematic issues for the nuclear industry.

As of late October 1997, several U.S. nuclear plants remained offline due to safety concerns. These plants include: 1) Northeast Utilities' (NU) three Millstone nuclear units (capacity: 2,700 megawatts), which it began shutting down in November 1995 due to safety concerns (NU hopes to restart the plants beginning in early 1998); 2) NU's 580-megawatt Connecticut Yankee plant, closed in December 1996, and now in the midst of controversy over allegations that NU covered up information on radiation leaks from the plant; and 3) the 1,150-megawatt Maine Yankee plant, shut down since July 21, 1995 for safety reasons (in August 1997, the plants' owners voted to close the facility permanently). In late September, a federal prosecutor said he will not file criminal charges against managers of the plant for allegedly lying about problems with the plant's cooling system. At the same time, however, a shareholder suit was filed against Maine Yankee's largest owner (Central Maine Power), alleging that the company's management acted in a "reckless" manner and cost the company tens of millions of dollars.

A U.S. federal appeals court ruled in late July 1996 that the federal government must begin accepting tons of spent nuclear fuel even though a permanent storage site will not be ready by then. A 1982 law requires the Department of Energy (DOE) to dispose of spent fuel as of January 31, 1998; however, feasibility studies have yet to be completed for an underground site in Nevada's Yucca Mountain, located 100 miles north of Las Vegas. DOE argues that the 1998 deadline is contingent upon completion of an acceptable storage facility. Meanwhile, Congress continues to debate a plan to establish an interim waste storage facility at Yucca Mountain pending agreement on a permanent repository.

Nuclear proliferation remains an important issue, both in its own rights as well as for the implications it has regarding sales of U.S. nuclear technology overseas, particularly to China. On October 29, 1997, President Clinton met with Chinese President Ziang Zemin. At their meeting, President Clinton agreed that China is in compliance with nuclear non-proliferation and other conditions which, under U.S. law, are a necessary precondition towards allowing U.S. exports of nuclear power technology to China. China represents a potentially giant market for U.S. nuclear sales. With Chinese electricity demand forecast to grow at a 5.7% annual rate through 2015, China has plans to greatly expand its nuclear power capacity, and U.S. manufacturers are anxious to gain access to this market.

Hydroelectricity/Other "Renewables"

The United States consumed 7.2 quadrillion Btu of renewable energy in 1996. About half of this total was hydropower, one-third wood, with waste and "other" (ethanol, geothermal, solar, wind, etc.) accounting for the rest. These renewable energy sources made up about 8% of total U.S. energy consumption in 1996.

Renewable energy use is expected to grow 2.8% in 1997, mainly due to increased hydroelectric generation resulting from above-normal snowfall and rainfall, particularly in the Pacific Northwest. In the long run (through 2015), renewable energy is expected to roughly maintain its share of U.S. energy demand.

The United States, with the world's largest economy, is also the largest single source of anthropogenic (human-caused) greenhouse gas emissions in the world. In June 1992, the United States pledged at the U.N.-sponsored "Earth Summit" in Rio de Janeiro (along with other industrial nations) to reduce greenhouse gas emissions to 1990 levels by the year 2000. Quantitatively, the most important anthropogenic greenhouse gas emission is carbon dioxide, which is released into the atmosphere when fossil fuels (i.e., oil, coal, natural gas) are burned. Current projections indicate that U.S. emissions of carbon (mainly in the form of carbon dioxide) will reach 1,543 million metric tons in 2000, an increase of more than 200 million metric tons from the 1,337 million metric tons emitted in 1990. Thus, it appears highly unlikely that the United States will meet the goal it agreed to in Rio de Janeiro (and ratified by the U.S. Senate on October 7, 1992).

On October 22, 1997, President Clinton essentially acknowledged this by announcing a new plan to reduce greenhouse gas emissions to 1990 levels by 2008-2012. The proposal includes as much as $5 billion in tax breaks and other incentives to cut emissions as well as a pollution trading system. Clinton's proposal was presented in advance of the climate summit scheduled for December 1997 in Kyoto, Japan. New energy saving technologies are also encouraged in the Clinton plan. One example of such technologies was the fuel cell unveiled by Secretary of Energy Peña on October 22, 1997. The fuel cell, developed by Arthur D. Little Co. in conjunction with a government weapon's lab, would use an electro-chemical process to convert hydrogen and oxygen into energy and could achieve twice the fuel efficiency of an internal combustion engine with as little as 30% of the carbon emissions. A vehicles using this technology could be on the road within ten years, and could run on gasoline, ethanol, methanol, natural gas, or other fuels. A recent U.S. DOE study concluded that a technology-based strategy would produce energy use and carbon emissions savings without causing major economic problems.

U.S. energy-related carbon emissions have been increasing faster than hoped for at the Rio Summit for three main reasons. First, the U.S. economy has experienced strong economic growth since the recession of 1990-1992; as a result, energy consumption has increased. Second, the energy "efficiency gains" of the 1980s, which were prompted largely by the oil price spikes of the 1970s, have been leveling off and even eroding for several years, particularly since the 1985/86 oil price collapse. Low gasoline prices have been a factor in the rapid growth in sales of sport-utility vehicles, minivans, and small trucks, all of which are less fuel efficient than small cars. Third, nuclear power generation (which emits no carbon), has now stagnated and is expected to decline after expanding rapidly during the 1970s and 1980s. Hydroelectricity, the other major non-fossil energy source in the United States, also is not growing.

Meanwhile, although other non-carbon emitting renewables such as wind and solar power are growing, they still supply only a tiny fraction of U.S. energy needs. In late June 1997, President Clinton announced a campaign -- the Million Solar Roofs Initiative -- to install solar energy panels on 1 million roofs in the United States by 2010. The objective of this program is to help boost domestic solar equipment demand. Currently, about three-quarters of U.S. photovoltaic equipment output is exported, while for the most part solar power remains too expensive domestically to compete directly with electricity from the power grid. In 1996, world photovoltaic production reached 88.6 megawatts, with U.S. companies accounting for 44% of the market (followed by Japan at 24%).

On October 10, 1997, the U.S. EPA proposed rules that would require 22 states east of the Mississippi River to make deep cuts in their emissions of nitrogen, the main source of ozone, the principal ingredient in smog. Under EPA's proposed plan, certain states, particularly midwestern industrial states like West Virginia, Missouri, Ohio, Indiana, Illinois, would have to make greater proportional cuts in their emissions than so-called "downwind" states like those in New England. The EPA proposal focuses on reducing emissions mainly from electric utilities. It also recommends that these cuts be made through a market trading system for pollution permits in order to minimize cost.

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ENVIRONMENT OVERVIEW

ENERGY INDUSTRY