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States of America
Information contained in this report is the best available as of May 2003 and is subject to change. For the latest monthly U.S. outlook by the Energy Information Administration, please see the "Short-Term Energy Outlook".
The recent difficulties experienced by the U.S. economy follow a period during the mid- and late-1990s of strong growth, low inflation, low unemployment, rapid productivity growth, and a booming stock market. Real (inflation adjusted) U.S. gross domestic product (GDP) growth for 2003 now is expected at 2.6%, up from 2.4% growth in 2002.
For Fiscal Year (FY) 2002, the federal unified budget ran an estimated deficit of $180 billion after running a surplus of around $127 billion in 2001. For FY 2003, a budget deficit of more than $300 billion is possible. The turn from surplus to deficit has come about as a consequence of several factors, including economic slowdown, tax rebates and cuts, and increased government spending on homeland security and war following the Setpember 11, 2001 terrorist attacks. Meanwhile, the U.S. merchandise trade deficit is estimated at $484 billion for 2002. This deficit mainly reflects the relative strength of the U.S. economy compared to major U.S. trading partners. The current account deficit now is running at over 4% of GDP, compared to 1.7% in 1997.
In mid-May 2001, the Bush administration issued a series of energy policy recommendations as part of its new National Energy Policy Report, developed by a task force led by Vice President Dick Cheney. In August 2001, the U.S. House of Representatives passed an energy bill (the "Securing America's Future Energy" -- SAFE -- Act of 2001) which contained many of the energy plan's recommendations. In April 2002, the U.S. Senate passed its own version of an energy bill, which must be reconciled with the House version.
During 2002, the United States produced around 8.1 million barrels per day (MMBD) of oil, of which 5.8 MMBD was crude oil, and the rest natural gas liquids and other liquids. U.S. total oil production in 2002 was down sharply (around 2.5 MMBD, or 24%) from the 10.6 MMBD averaged in 1985. U.S. crude oil production, which declined following the oil price collapse of late 1985/early 1986, leveled off in the mid-1990s, and began falling again following the sharp decline in oil prices of late 1997/early 1998. With the rebound in world oil prices since March 1999, U.S. crude production basically leveled off once again in 2000 and 2001, rising slightly in 2002. Despite this increase, U.S. crude production remains near 50-year lows.
The United States contains over 500,000 producing oil wells, the vast majority of which are considered "marginal" or "stripper" wells, generally producing only a few barrels per day of oil. During 2002, top oil producing areas included the Gulf of Mexico (1.6 million bbl/d), Texas onshore (1.1 million bbl/d), Alaska's North Slope (954,000 bbl/d), California (707,000 bbl/d), Louisiana onshore (274,000 bbl/d), Oklahoma (181,000 bbl/d), and Wyoming (150,000 bbl/d).
Domestic oil exploration and development spending by U.S. major oil companies rebounded during 2001 from the deep cuts made during the oil price collapse of 1997/1998. Improved technology and new or increased offshore production in the Gulf of Mexico (including at deepwater areas beyond the continental shelf) also could help matters. In 2000, deepwater production in the Gulf of Mexico for the first time surpassed shallow water production. In January 2000, Chevron and Shell -- the largest producer in the Gulf of Mexico -- signed an agreement to share drilling rigs and to drill exploratory wells jointly in the deep-water Gulf of Mexico. In August 2002, a U.S. government lease sale for the western Gulf of Mexico produced bids totaling $182 million. Bidders included Amerada Hess, Kerr-McGee, Dominion Exploration and Production, Shell, and Nexen.
In April 2003, TotalFinaElf announced that it was the highest bidder on four deepwater Gulf of Mexico exploration blocks, located in the Mississippi Canyon and Atwater Valley areas of the Gulf. The blocks were among 561 tracts offered by the Minerals Management Service in Lease Sale 185.
Overall, production from deepwater areas of the Gulf of Mexico has been increasing rapidly, with deepwater wells accounting for about two-thirds of total U.S. Gulf output. Large fields include ExxonMobil's $1.1 billion Hoover-Diana development (which started up in May 2000 and is producing 80,000 bbl/d), plus several by BP: the $2 billion Atlantis project (scheduled to come online in 2005); Crazy Horse (the largest single field every discovered in the Gulf of Mexico), Crosby, Holstein, King, King's Peak, Mad Dog, Marlin, and Nakika fields. BP has stated that it plans to accelerate its deepwater Gulf of Mexico production plans, possibly including construction of a $1 billion deep-sea pipeline, and to increase its production from around 200,000 bbl/d currently to 750,000 bbl/d in 2007. This will require billions of dollars worth of investment.
Crude oil production in the lower 48 states is expected to increase slightly in 2003, to 4.85 million bbl/d, while Alaskan crude production falls slightly, to 0.95 million bbl/d. Alaskan production, which accounts for around 16% of the U.S. total, is down more than 50% from the 2.0 MMBD reached during the peak year of 1988. Most of Alaska's oil output comes from the giant Prudhoe Bay Field, and is transported via the Alyeska pipeline. A new oilfield, known as Alpine (owned 78% by Phillips Petroleum, 22% by Anadarko), began production in November 2000. Alpine represents the largest North American onshore oil discovery in a decade, and currently is producing aroudn 100,000 bbl/d of high quality, light crude oil. Production at Alpine is to be maintained using tie-ins to the Nanuq and Fiord satellite fields beginning in 2006. Phillips has been the largest oil producer in Alaska since acquiring Arco's Alaska fields in early 2000. In November 2000, two oil and natural gas lease sales conducted by the State of Alaska drew bids worth $11 million for offshore tracts in the Beaufort Sea and onshore in the North Slope.
In other news from Alaska, the critical Trans-Alaska Pipeline System (TAPS) shut down briefly in early November 2002 due to an earthquake. In October 2001, TAPS also was shut down for a short time after being punctured by a gunshot.
In early 2000, the Energy Information Administration (EIA), in response to a Congressional request, issued a report on potential oil reserves and production from the Arctic National Wildlife Refuge (ANWR). The report, which cited a 1998 U.S. Geological Survey study of ANWR oil resources, projected that for the mean resource case (10.3 billion barrels technically recoverable), ANWR peak production rates could range from 1.0 to 1.35 MMBD, with initial ANWR production possibly beginning around 2010, and peak production 20-30 years after that.
According to Baker Hughes Inc., which has tallied weekly U.S. drilling activity since 1940, domestic oil and natural gas drilling has rebounded sharply since the low point of 488 reached in late April 1999 following the oil price collapse of late 1997. In mid-October 2001, for instance, the U.S. weekly "rig count" reached the 1,141 mark (933 for natural gas and 208 for oil), close to the highest number since late 1990. Since then, however, the U.S. "rig count" fell, reaching 843 (703 gas rigs and 137 oil rigs) as of mid-October 2002, then rose again, reaching 1,021 for the week ending May 9, 2003. Natural gas rigs outnumber oil rigs in the United States by more than five-fold. Historically, U.S. drilling activity peaked in 1981, with a total of 91,553 wells (43,598 oil, 20,166 natural gas, 27,789 dry wells) drilled in that year. For 2001, a total of 34,179 wells (22,083 natural gas wells, 8,060 oil wells, and 4,036 dry wells) were drilled in the United States, up from the low point of 18,377 total wells drilled in 1999. For 2002, total wells drilled (24,540) were down sharply -- 28% -- from the same period a year earlier.
Twenty-two major energy companies reported overall net income (excluding unusual items) of $6.6 billion on revenues of $149 billion during the fourth quarter of 2002 (4Q02). This level of net income represented a 296% increase relative to the fourth quarter of 2001 (4Q01) (see EIA's "Performance Profiles for Major Energy Producers 2000"). Foreign upstream oil and natural gas production operations accounted for $3.6 billion of net income, about the same as domestic upstream oil and natural gas production operations ($3.6 billion) and domestic downstream natural gas and power operations ($0.6 billion).
Independent oil and natural gas producers, oil field companies and refiner/marketers reported a decrease in net income (down 39%) during 4Q02 compared to 4Q01. This decline in net income was due to a sharp decline in oil and gas drilling activity (see below). Refining margins, on the other hand, increased due in part to higher oil product prices.
U.S. Energy Sanctions Issues
Attempts by the United States to implement ILSA have run into opposition from a number of foreign governments. The European Union (EU) opposes the enforcement of ILSA sanctions on its members, and on November 22, 1996 passed resolution 2271 directing EU members to not comply with ILSA. On May 18, 1998, the EU and the U.S. reached an agreement on a package of measures to resolve the ILSA dispute at the EU/U.S. Summit in London, but the Summit deal is contingent upon acceptance by the U.S. Congress before full implementation may take place.
On April 5, 1999, following the Libyan handover of two suspects in the 1988 bombing of Pan Am flight 103 to stand trial before a Scottish Court in the Netherlands, the United States modified its Libya sanctions on April 28, 1999 to allow shipments of donated clothing, food and medicine for humanitarian reasons (trade in informational materials such as books and movies is also allowed). However, all other U.S. sanctions against Libya remain in force. On February 1, 2001, one suspect was convicted by the Scottish court, while another was acquitted. The U.S. and British governments both said that they still expected Libya to accept responsibility for the murders, which Libya has said it would not do.
Since the mid-1990s, U.S. refinery capacity has increased, from 15.0 MMBD in 1994 to 16.6 MMBD in early 2003. As of May 2003, utilization of operating capacity at U.S. refineries reportedly was averaging around 92-94%%. Although financial, environmental, and legal considerations make it unlikely that new refineries will be built in the United States, expansion at existing refineries likely will increase total U.S. refining capacity in the long-run.
Since the mid-1980s, 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 on joint ownership of the 170,000-bbl/d refinery in Chalmette, Louisiana.
Strategic Petroleum Reserve (SPR)
Approximately $327 million worth of SPR oil was sold off in 1996, and an additional $220 million in 1997. On September 22, 2000, President Clinton authorized the release of 30 million barrels of oil from the SPR over 30 days in an attempt to bolster U.S. oil supplies and to alleviate possible shortages of heating oil during the upcoming winter. The release took the form of a "swap" (bidding results were announced on October 4) in which crude oil volumes drawn from the SPR is to be replaced by the recipients at a later date.
In mid-November 2001, President Bush directed the Department of Energy (DOE) to fill the SPR to its capacity of 700 million barrels in order to "maximize long-term protection against oil supply disruptions." Under the DOE plan, the SPR is to be filled with "royalty in kind" (RIK) oil. As of May 14, 2003, the SPR contained around 600 million barrels of oil -- the largest emergency oil stockpile in the world. The SPR has a maximum drawdown capability of 4.3 million bbl/d for 90 days, with oil beginning to arrive in the marketplace 15 days after a presidential decision to initiate a drawdown. The SPR drawdown rate declines to 3.2 million bbl/d from days 91-120, to 2.2 million bbl/d for days 121-150, and to 1.3 million bbl/d for days 151-180.
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" (including an oil price spike); 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.
Oil Mergers and Acquisitions
In September 2002, U.S. regulators approved the purchase of Pennzoil-Quaker State Co. by Shell Oil Co. The deal, first reported in March 2002, was for $1.8 billion (with Shell also assuming $1.1 billion of Pennzoil-Quaker State debt). The transaction combines Shell's 3% share of the U.S. market for passenger car motor oil with Pennzoil-Quaker State's 35% share, making Shell the No. 1 U.S. lubricants company. Shell also adds Pennzoil-Quaker State's 46,200 barrels-per-day Shreveport, Louisiana refinery and more than 2,000 Jiffy Lube outlets. In October 2002, Shell announced that it would close or sell seven U.S. blending and packaging plants as part of its ongoing merger.
In November 2001, Phillips Petroleum and Conoco Inc. agreed to merge in a $15.2 billion transaction. The merger was completed in August 2002, creating a new company called ConocoPhillips. ConocoPhillips ranks as the sixth-largest oil and gas company in the world, the largest U.S. refiner, and the third-largest U.S.-based energy company.
Another major oil industry merger/acquisition was announced in October 2000, this time between Chevron and Texaco. According to the announcement, Chevron is to buy Texaco for $35 billion in stock, creating the world's fourth largest energy company (behind ExxonMobil, Shell, and BP). The deal received regulatory approval in early October 2001, and was approved by shareholders of the two companies on October 9, 2001, creating ChevronTexaco.
In November 2000, Russia's Lukoil announced that it intended to purchase Getty Petroleum Marketing for $71 million. Lukoil eventually intends to switch Getty's 1,300 retail outlets in the Northeastern and Middle Atlantic states to the Lukoil brand name. The purchase represents the first takeover of a publicly traded U.S. company by a Russian firm. In late January 2001, Getty shareholders approved the the buyout.
On April 13, 2000, the FTC approved the $27.6 billion BP Amoco-ARCO deal. This followed the March 15, 2000 announcement by Phillips Petroleum that it had agreed to purchase ARCO's assets in Alaska for $6.5 billion. The sale was made as part of an effort to secure approval from the FTC. On the same day, the FTC announced that it had suspended its antitrust lawsuit seeking to block the merger, citing progress in talks with the companies involved. Among other issues, the FTC was concerned that the BP Amoco-ARCO merger would control about 75% of Alaskan North Slope crude oil output and over 70% of the critically important TAPS line, potentially hurting consumers on the U.S. west coast. BP Amoco agreed to sell some pipeline and oil storage holdings in Cushing, Oklahoma. The new company (now called BP) will rank in the top three private oil companies in the world, along with ExxonMobil and Royal Dutch/Shell.
Meanwhile, the $81 billion merger between Exxon and Mobil, which formed the world's largest privately owned petroleum company (in terms of revenues), was approved by the FTC on December 1, 1999, subject to the divestiture of 2,400 service stations and other assets (on December 3, 1999, 1,740 of these stations were sold to Tosco, the largest U.S. independent oil refiner). In a related development, in April 2000, Duke Energy said that it had agreed to acquire Mobil's European natural gas trading and marketing business. The sale of Mobil's natural gas operations in Europe was required by the European Commission as part of its approval of the ExxonMobil merger.
Besides these large mergers, several defensive mergers among smaller, independent oil companies also have been unveiled recently, including Kerr-McGee Corp.'s (KMG) $1.86 billion takeover of Oryx Energy Co. (ORX), and an agreement between Seagull Energy Corp. (SGO) and Ocean Energy Inc. (OEI) to merge in a $1.1 billion deal (approved by shareholders in March 1999). On July 14, 2000, Anadarko Petroleum announced the closing of its merger transaction with the Union Pacific Resources Group. Union Pacific became a wholly owned subsidiary of Anadarko, creating one of the largest U.S. independent oil and natural gas companies. In January 2001, Amerada Hess announced that it was withdrawing a $3.5 billion offer to purchase Britain's Lasmo P.L.C., a move which would have created a "super-independent" oil company. Instead, Lasmo was purchased by Italy's ENI for $4 billion.
Due to low profitability in the refining/marketing line of business, U.S. integrated major energy companies began a process during the 1990s of selective refining/marketing divestiture, and numerous U.S. refineries were shut down. Among independent refiners, growth largely has been concentrated in the following group of companies: Citgo/PDV America, Clark Refining and Marketing, Diamond Shamrock (merged with Ultramar during 1996, creating Ultramar Diamond Shamrock), Koch Industries, Tesoro Petroleum, Ultramar, and Valero Energy. In May 2001, Valero agreed to acquire Ultramar Diamond Shamrock for $6 billion. Another company, Tosco Corporation, was purchased by Phillips Petroleum for $7.5 billion in September 2001, creating the second largest refining group in the United States, behind ExxonMobil.
In late 2002 and early 2003, several smaller companies announced or closed deals to purchase refining and/or related assets. For instance, Valero said in March 2003 that it would pay $289 million to buy El Paso's 102,500-bbl/d Corpus Christi refinery. This follow's Valero's sale of its 168,000-bbl/d Golden Eagle refinery and related assets in northern California to Tesoro Petroleum for $1.1 billion in May 2002. In other news, Canada's Suncor announced in April 2003 that it would buy ConcoPhillips' 58,000-bbbl/d Commerce City, Colorado reinfery and related assets for $150 million. And on April 30, 2003, Sunoco announced that it had signed a letter of intent to buy El Paso's 150,000-bbl/d Eagle Point refinery and related assets in New Jersey for $130 million.
Natural gas wellhead prices reached record highs of nearly $10.00 per thousand cubic feet (mcf) in late 2000/early 2001, but fell sharply soon thereafter to around $2.50 per mcf. Cold weather in the U.S. Northeast and Midwest during the winter of 2002/2003 raised prices once again, particularly in late February, as gas storage levels hit unusually low levels and cold weather limited pipeline operations.
For all of 2002, the average natural gas wellhead price averaged $2.96 per mcf, compared to over $4.00 per mcf in 2001. In 2003, wellhead prices are projected to average $4.79 per mcf. At the end of April 2003, working gas in storage stood about 52% below end-of-April 2002 levels and 41% below the previous 5-year average. The exceptionally large current shortfall in natural gas storage relative to normal levels continues to place unusually strong upward pressure on near-term gas prices because companies will need to obtain large amounts of natural gas from other uses in order to refill storage for the next heating season. Moreover, if abnormally warm weather prevails this summer the current market may become highly sensitive to demand, particularly in the Western and South Central United States, where natural gas is heavily used for power generation. Such conditions could cause a mid-year spike in prices.
Natural Gas Production and Storage
Future increases in natural gas production likely will come mainly from lower 48 sources, with increased use of cost-saving technologies expected to result in continuing large natural gas finds, including in the deep waters of the Gulf of Mexico but also in conventional onshore fields. Currently, top natural-gas-producing states (in descending order) include Texas, Oklahoma, New Mexico, Louisiana, Wyoming, Colorado, Alaska, Kansas, California, and Alabama.
September 2002 hurricanes in the Gulf of Mexico temporarily shut in some natural gas production, causing spot prices at the Henry Hub and elsewhere to rise above the $4.00 per million btu mark for most of October 2002. Early cold weather in October 2002, particularly in the Midwest, also helped raise prices even as storage levels remained relatively high. With storage levels well above 3 Tcf at the end of October, further large price increases were not expected in the near term. However, cold weather, particularly in the Northeast for much of the 2002-2003 heating season, and high prices for competing fuel oil increased natural gas demand and rapidly depleted gas in storage. Spot natural gas prices surged, averaging near $7 per million Btu in February and March 2003. The shift from adequate to below-normal storage levels and the burden of exceptionally high prospective injection demand has pushed spring and expected summer natural gas prices to nearly $6 per million Btu for all of 2003.
Natural Gas Demand
With high natural gas prices, natural gas demand is expected to fall slightly in 2003, despite sharply higher weather-related gas demand during the first quarter of 2003. Natural gas demand in 2004 is expected to rise about 1% as industrial demand recovers from its 2002/2003 lows. Sluggish near-term natural gas demand is expected to delay the startup of some planned natural gas pipeline extension projects, at least until economic conditions pick up. Still, around 3,571 miles in natural gas pipelines were added during 2002, at a cost of $4.4 billion. Five major new natural gas pipeline systems were completed and placed in operation during 2002, accounting for 34% of total new gas pipeline mileage in that year. These pipelines were: Gulfstream (1,130 MMcf/d capacity; Gulf of Mexico to Florida); North Baja (500 MMcf/d, southeastern California to Baja California); Questar Southern Trails (87 MMcf/d); New Mexico/Utah to California/Arizona); Guardian (750 MMcf/d; Chicago hub to northern Illinois and southern Wisconsin); and Horizon (380 MMcf/d; same as Guardian).
U.S. natural gas consumption and imports, overwhelmingly from Canada -- and to a far lesser extent from liquefied natural gas, or LNG, from Trinidad, Algeria, Qatar, and others -- are expected to expand substantially in coming decades, with the fastest volumetric growth resulting from additional natural-gas-fired electric power plants. Increased U.S. natural gas consumption will require significant investments in new pipelines and other natural gas infrastructure. The largest natural gas pipeline project currently under construction is the $1.2 billion Gulf Stream pipeline, which will run 564 miles from Alabama to Florida.
Domestic and Import Pipelines
During the past decade, interstate natural gas pipeline capacity has increased substantially. From January 1996 through August 1998 alone, at least 78 projects were completed adding approximately 11.7 billion cubic feet per day of capacity, and much more will be needed in coming years. Recently completed pipelines include the Pony Express project and the Trailblazer system expansion, providing access from the Wyoming and Montana production regions. Also, the Transwestern and El Paso natural gas pipeline expansions have increased capacity from New Mexico's San Juan Basin.
On December 1, 2000, the $2.9 billion, 1.3-Bcf/day Alliance Pipeline from western Canada (Fort St. John, British Columbia) to the Chicago area entered service. Another pipeline, the Independence Pipeline ($678 million) received FERC approval in July 2000, but was cancelled in June 2002 due to lack of customer interest.
Columbia Gas System’s Millennium project ($700 million), which is to connect Canadian natural gas sources to New York and Pennsylvania, received FERC go-ahead on September 19, 2002. When complete, Millennium will transport up to 700 million cubic feet of natural gas per day, providing an environmentally preferred option for generating electricity. According to the Millennium Pipeline consortium's Web site, more than 90% of the pipeline’s 425-mile overland route uses existing utility corridors, with about 224 miles of the project replacing and upgrading a 50-year-old pipeline system owned and operated by Columbia Gas Transmission Corp. That existing system serves several major gas end-users, utilities and their customers in New York’s Southern Tier region.
Growing U.S. demand for Canadian natural gas has been a dominant factor underlying many of the pipeline expansion projects this decade. The U.S. and Canadian natural gas grids are highly interconnected and Canadian natural gas has become an increasingly important component of the total natural gas supply for the United States. This is especially true for certain U.S. regions such as the Northeast, Midwest, and Pacific, which depend on Canadian natural gas for significant amounts of their supply. Overall, the United States received about 3.8 Tcf of natural gas (net) from Canada during 2002, up slightly from 3.7 Tcf in 2001. Mexico is a small net importer of natural gas from the United States.
There has been considerable progress in recent years on natural gas interconnections between Canada and the United States. The Northern Border Pipeline, an extension of the Nova Pipeline, came onstream in late 1999 and connects to Chicago through the upper Midwest. A further extension to Indiana entered service in 2001.
The Maritimes and Northeast Pipeline came onstream in January 2000, running from Sable Island to New England, with further extensions into the Boston area to be completed during 2003. The pipeline has a capacity of 400 MMcf/d.
The $2.5 billion Alliance Pipeline, at 1,875 miles, is the longest pipeline ever built in North America, and is designed to carry about 1.3 billion cubic feet per day (Bcf/d) of gas from western Canada (Fort St. John, British Columbia) to the Chicago area. The pipeline began commercial service on December 1, 2000. The U.S. utility Pacific Gas & Electric imports natural gas from British Columbia via the Alliance pipeline. To date, the Alliance system has been operating at close to its capacity of 1,630 MMcf/d.
The long-delayed 714 MMcf/d Millennium Pipeline project could be placed in service sometime in late 2004. Millenium is slated to connect Canadian sources to southern New York and Pennsylvania. Indecision over the final route of the pipeline in New York has been one factor stalling progress.
Another possibility for future U.S. natural gas supplies lies in northern Canada, which contains around one third of that country's recoverable gas reserves. The Mackenzie Valley pipeline, being developed by Shell, ConocoPhillips, ExxonMobil and Imperial Oil, would carry about 1.9 Bcf/d of gas from Canada's far north to southern Canada and the United States.
On October 12, 2001, the U.S. Coast Guard lifted the ban on LNG tankers from Boston harbor. The ban, in effect since September 26 (two weeks after the terrorist attacks in New York and Washington, DC), was established in response to security and safety concerns about the ships that bring LNG to the import facility of Distrigas of Massachusetts (a Division of Tractebel, Inc.). The decision enabled the reopening of the Distrigas facility in Everett, Massachusetts, which received 45 shipments containing 99 Bcf of natural gas in 2000, mostly from Trinidad, accounting for 44% of total LNG imports into the United States that year. The Distrigas facility is one of three currently active LNG facilities in the United States. The other two active facilities are located in Lake Charles, Louisiana, and the recently reopened facility in Elba Island, Georgia. An additional LNG facility, in Cove Point, Maryland, is currently used as a storage and peak shaving facility, but is being upgraded into the nation's largest LNG facility, scheduled to open in mid-2003. In August 2002, Williams announced that it was selling Cove Point (including an 87-mile pipeline) for $217 million to a subsidiary of Dominion Resources.
Overall, there is growing interest in LNG to supply natural gas for U.S. electric power generation and provide supply flexibility. EIA expects that LNG imports to the United States will increase at an average 11% annual rate, to 2.14 Tcf by 2025 from 0.14 Tcf in 2002. Overall, during 2002, the United States received 169 Bcf of LNG in 2002, mainly from Trinidad and Tobago, Qatar, and Algeria.
Natural Gas Mergers, Acquisitions, Bankruptcies
On December 2, 2001, Enron, formerly the world's largest electricity and natural gas trading company, filed for Chapter 11 bankruptcy in the Southern District of New York for 14 affiliated entities, including Enron, Enron North America, Enron Energy Services, Enron Transportation Services, Enron Broadband Services, and Enron Metals & Commodity Corporation. Enron had been the seventh-largest publicly-traded energy company in the world. Also in early December 2001, Enron filed a $10 billion lawsuit against Dynegy, alleging breach of contract, in connection with Dynegy's November 28 termination of its proposed merger with Enron. On November 9, 2001, Enron had agreed to an all-stock takeover by former competitor Dynegy. ChevronTexaco, a 27% stakeholder in Dynegy, was to inject $1.5 billion of cash immediately into Enron, and an additional $1 billion into the combined entity. The merged company was to be called Dynegy Inc., and Dynegy executives were to occupy all top positions. On November 28, 2001, however, Dynegy withdrew from the merger deal.
On January 2, 2002, the U.S. Department of Justice confirmed that a criminal probe of Enron had been launched. A task force was formed to investigate whether the former giant energy company defrauded investors by deliberately withholding or falsifying crucial financial information. The U.S. Securities and Exchange Commission has been investigating Enron since October 2001. A number of civil suits already have been filed against Enron. In October 2002, the Justice Department filed a criminal complaint against Enron's former CFO, Andrew Fastow, alleging multiple counts of financial fraud.
Around three-fifths of U.S. coal production is bituminous, one-third subbituminous, and about one-tenth lignite (brown coal). Around 80,000 miners work in the $20 billion U.S. coal industry, down from a peak of 700,000 in 1923, when U.S. coal production was half what it is today. Major U.S. coal companies include Peabody Energy (the largest in terms of production), Arch Coal (the second largest coal producer); and Kennecott Energy.
During 2003, coal production is expected to fall in Appalachia and the U.S. Interior, and to rise in the West. In 1998, low-sulfur western coal production surpassed relatively higher-cost, higher-sulfur, Appalachian coal for the first time, following strong increases since 1994, 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 (and low cost) coal from the Powder River Basin, where coal is strip-mined.
The electric power sector (made up of electricity producers whose primary business is producing power for public distribution) accounts for the vast majority (over 90%) of U.S. coal consumption, with independent power producers (IPPs) and manufacturing taking nearly all the rest. This pattern is expected to continue through 2020 at least, with coal maintaining a fuel cost advantage over oil and natural gas. As sulfur dioxide emissions standards are tightened (in 2000, for instance, Phase 2 of CAAA took effect), the share of low-sulfur coal in the U.S. coal consumption mix is expected to increase. In 1999, low and medium-sulfur coals had approximately the same share of the U.S. coal market, with high-sulfur coal far behind.
U.S. coal exports have fallen precipitously since 1995 due mainly to lower world coal prices and increased competition from other coal-producing nations (i.e., Australia, South Africa, China, Venezuela, Colombia), plus natural gas -- especially in Europe. In 2001, total U.S. coal exports dropped to the lowest level since 1978, largely due to 1) a strong U.S. dollar, which gave an edge to other coal-exporting countries; and 2) the tight supply market in the United States, which resulted in increased spot prices of coal, influencing some producers to shift their output to the domestic market. Metallurgical coal exports experienced the greatest decline in 2001, accounting for 75% of the total decline. Export markets for metallurgical coal have been declining over the past few years because of the expansion of new steel-making technologies requiring less high-grade coking coal. Consequently many U.S. metallurgical coal operations have closed, and increased amounts of metallurgical coal have been sold into the domestic utility steam coal market. The U.S. coal industry is expected to continue to face strong competition from other coal-exporting countries, with limited or negative growth in import demand in Europe and the Americas. Given this, it is likely that the U.S. share of world coal exports will decline in coming years.
U.S. gross coal imports, at 39.9 Mmst, are expected to be about about the same in 2003 than they were in 2002. Coal imports continue to rise, in part attributable to the heightened demand for low-sulfur coal, and in part to the need to meet stricter sulfur emission requirements of Phase II of the CAAA.
On January 29, the Fourth Circuit Court of Appeals ruled in favor of the coal industry and the Department of Justice by overturning Judge Charles Haden's May 2002 ban on new valley fill permits at coal mines in West Virginia and eastern Kentucky. The three-judge panel ruled that the 2002 ruling had been "over broad" and essentially supported the existing policies that the Army Corps of Engineers has followed for many years in issuing fill permits under the Clean Water Act. This action is not, however, expected to result in an immediate increase in new permits. The Corps has not accepted most new applications during the appeal period and the normal 45-day processing time could go to several months if a flood of applications is received.
Further, a new issue has developed during the off time. Last year, the Corps introduced a new impact mitigation policy that applies to both existing and new permits. Under the Nationwide 21 program, the new Corps policy applies to the Central Appalachian coalfields of West Virginia and eastern Kentucky. Operators will be required to save a stream or wetland at another location to compensate for those it fills during coal mine operations, or to pay "in lieu" fees if compensating wetlands cannot be preserved. The most pressing issue related to this is a February 11 deadline, after which no new fill can be done. Under Congressional pressure from the affected States, and now that the Haden ruling has been overturned, the Corps is free to move ahead and may extend the February 11 deadline.
Natural gas-fired power plants have been gaining share rapidly over the past few years. Coal-fired power plants generally have been less attractive than natural-gas-fired plants due to relatively high capital costs, longer construction periods, and lower efficiencies than natural gas combined-cycle plants, and has been losing share. Nuclear power has been growing only slowly, far behind the rate of natural gas-fired power.
On a national level, the average retail price of electricity during 2002 averaged 7.25 cents per Kwh, down slightly from 7.32 cents per Kwh in 2001. Electricity prices in the United States fell every year between 1993 and 1999, but this trend reversed in 2000 and 2001.
As of 2001, U.S. total installed electric generating capacity was 813 gigawatts (GW). Of this total, 74% was thermal (mainly coal and natural gas), 12% nuclear, 12% hydro, and 2% "renewables" (geothermal, solar, wind). The amount and geographical distribution of capacity by energy source is a function of availability and price of fuels and/or regulations. Capacity by energy source generally shows a geographical pattern such as: significant nuclear capacity in New England, coal in the central U.S., hydroelectric in the Pacific West, and natural-gas-fired capacity in the Coastal South.
Total annual electricity demand (retail sales plus industrial and commercial generation for own use and other direct sales) grew 3.9% for all of 2002. Abnormally high summer temperatures and high cooling demand increased electricity demand sharply in the third quarter of 2002. Total U.S. electricity demand is estimated to have been 5.8% higher this past winter than during the 2001-2002 winter, due mostly to weather related demand. In 2003, electricity demand is expected to grow by a relatively subdued rate of about 1.8%. Due to the sluggish economy and a huge increase in electric power generating capacity, the southeastern United States is even expecting a large-scale power oversupply problem in the near term.
As a result of the Federal and State initiatives, the electric power industry is transitioning from highly regulated, local monopolies which provided their customers with a total package of all electric services and moving towards competitive companies that provide the electricity while utilities continue to provide transmission or distribution services. States are moving away from regulations that set rates for electricity and toward oversight of an increasingly deregulated industry in which prices are determined by competitive markets. Almost half of the States have passed major legislation and/or regulations to restructure their electric power industry. States that historically had higher than average U.S. prices, such as California, Pennsylvania, New York, and most of New England, have opened their retail electricity markets to competition allowing customers to choose their electricity supplier, while other States are beginning with a limited number of consumers. One of the major goals in restructuring is to lower the price for electricity. Industry analysts have cited Pennsylvania as the most successful State in achieving its goals in restructuring.
In March 2001, the Energy Secretaries of Canada, Mexico, and the United States met to discuss a common energy strategy for the three countries, including integration of the three countries' power grids and creation of a US-Mexican working group to focus on promoting cross-border electricity trade. At present, power trade between Mexico and the United States is severely limited by infrastructure constraints, including inadequate power transmission capability (there are only two cross-border transmission lines: San Diego-Tijuana and El Paso-Matamoros). In January 2001, a small (50-MW), natural-gas-fired power plant in Baja California began exporting power to California. Canada exported about 36 bkwh of electricity to the United States in 2002, mostly from Quebec, Ontario, and New Brunswick to New England and New York. Smaller volumes are exported from British Columbia and Manitoba to Washington state, Minnesota, California, and Oregon. There is considerable reciprocity between the Canadian and U.S. power markets, as the United States also exports smaller volumes of electricity to Canada.
Nuclear power in the United States grew rapidly after 1973, when only 83 billion kWh of nuclear power was produced. As of 2002, nuclear power had grown nine-fold, with 104 licensed nuclear power units generating 780 billion kWh 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, with Watts Bar I (1996) the last plant completed. In late March 2000, the Nuclear Regulatory Commission (NRC), in a positive signal to the U.S. nuclear power industry, granted the first-ever renewal of a nuclear power plant's operating license. The 20-year extension (until 2034 and 2036 for two reactors) went to the 1,700-MW Calvert Cliffs plant in Maryland.
On July 9, 2002, the U.S. Congress voted to formally approve Yucca Mountain, located 100 miles north of Las Vegas, as the nation's permanent nuclear waste depository. Studies on Yucca Mountain as a possible nuclear power plant waste site have been going on for over two decades, with concerns centering on the dangers of transporting nuclear materials to the site via rail or highway. Nuclear utilities have complained that they are running out of nuclear waste storage capacity at their nuclear plants, with many being forced to resort to "dry cask" storage of spent fuel assemblies after water-storage pools reached capacity.
On November 7, 2002, South Carolina's Governor-elect, Mark Sanford, announced that he "would be inclined" to drop a legal suit against the Energy Department regarding plutonium shipments to the Savannah River nuclear site. The plutonium would be shipped from other nuclear weapons sites across the United States.
Overall, hydropower made up around 45% of total U.S. renewable consumption in 2002, with biofuels (including wood and waste), solar, wind, and geothermal making up most of the remainder. In the summer of 2002, the U.S. Northeast experienced a serious drought, calling into question the adequacy of hydroelectricity supplies during the summer cooling season. By early November, however, the drought had eased significantly following heavy rains in much of the region. Overall, total hydro generation rose by around 23% during 2002 compared to 2001, a bad drought year. For 2003, total hydropower generation is expected to rise by 12% as heavy rains in much of the eastern part of the country have raised water levels.
Wind, solar, biomass, and geothermal power, although growing, still supply only a tiny fraction of U.S. energy needs. In January 2000, however, the U.S. Department of Energy's National Renewable Energy Laboratory (NREL) released a report which said that the domestic photovoltaic (PV) industry could provide up to 15% of "new U.S. peak electricity capacity expected to be required in 2020." In 2001, shipments of solar PV cells and modules expanded by 11%, to around 98,000 peak kilowatts, according to EIA's Renewable Energy Annual 2001. Wind, geothermal, and biomass energy sources also have significant potential in the United States.
In 2002, 410 MW of wind power was installed in the United States, representing strong (10%) growth, but down from the record growth (an additional 1,694 MW) of 2001, according to the American Wind Energy Association (AWEA). The slowdown in growth during 2002 was driven in part by the uncertain status of a federal wind Production Tax Credit, or PTC, first established in 1992, and currently set to expire on December 31, 2003. The PTC, among other factors, has helped boost total U.S. installed wind generating capacity to 4,685 MW (as of December 31, 2002), up from 1,584 MW in 1992, with wind turbines now located in 26 states.
During 2002, wind power production increased 39% from 2001, the fastest growing power source in the United States in percentage terms, but trailing far behind the growth in other major power sources in absolute terms. The first U.S. offshore windmill park, with a total capacity of 420 MW, reportedly is scheduled to be built off the Cape Cod coast, possibly by 2004. The project could power more than 200,000 homes in Cape Cod. Also, Iowa's largest utility (MidAmerican Energy) has announced plans for a 310-MW wind power facility, the country's largest to date. Both Cape Cod and Iowa are areas of the country considered to have large wind energy potentials. Iowa's governor, Tom Vilsack, has set a target for Iowa of reachying at least 1,000 MW in renewable power capacity by 2010.
In February 2002, the Bush Administration released its proposed alternative to the Kyoto Treaty, calling for significant reductions in emissions of various pollutants (mercury, nitrogen oxide, sulfur dioxide). The program, known as the "Clear Skies Initiative," would utilize a "cap and trade" system which would allow companies to trade emissions credits. In addition, the Bush Administration envisions reductions in U.S. "greenhouse gas intensity" -- the amount of greenhouse gases emitted per dollar of GDP -- by 18% over 10 years. As the graph here shows, U.S. carbon emissions per dollar of GDP have been declining steadily since at least 1980.
U.S. energy-related carbon emissions have leveled off in recent years for one main reason: the U.S. economy, which had experienced strong economic growth during the 1990s, has slowed considerably, caused energy consumption to stagnate. In contrast, carbon emissions rose sharply during the 1990s along with the economy, and also as energy "efficiency gains" of the 1980s, which were prompted largely by the oil price spikes of the 1970s, began to level off, particularly since the 1985/86 oil price collapse. Sales of sport-utility vehicles, minivans, and small trucks, for instance, all of which are less fuel efficient than small cars, have increased sharply in recent years. Meanwhile, 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 has not been growing. The implication of all this is that carbon emissions will begin to grow again as the U.S. economy picks up.
On February 28, 2001, EPA Administrator Christine Todd Whitman directed her agency to move ahead with a rule that will require U.S. refiners to reduce sulfur in diesel fuel from 500 parts per million currently, to 15 parts per million by 2006. On March 13, 2001, President Bush declared that his administration would not seek to regulate power plants' emissions of carbon dioxide, citing an EIA study that regulating these emissions could result in higher electricity prices. On March 27, the Bush administration declared that the United States had "no interest" in implementing or ratifying the Kyoto treaty, saying it would be too harmful to the U.S. economy, and that it would pursue other ways of addressing the climate change issue. On April 10, the EPA asked the U.S. Court of Appeals in Washington, DC to uphold a Clinton administration plan to regulate mercury pollution from coal-fired power plants, beginning in 2004. On April 12, the White House affirmed Clinton administration-approved energy efficiency standards for washing machines and water heaters. Under these standards, clothes washers would become 22% more efficient by 2004 and 35% more by 2007. The next day (April 13), the Department of Energy announced that it would require air conditioners to be 20% more energy efficient by 2006. The Clinton administration had mandated a 30% energy efficiency increase for air conditioners. In June 2001, President Bush announced that the federal government would lead an effort to reduce the use of energy by machines not in use (known as standby power, or "vampire," devices). In July 2001, the Interior Department announced that it would greatly reduce the scope of proposed oil leases in the Gulf of Mexico, and also would keep oil rigs at least 100 miles from the state's beaches. In January 2002, Energy Secretary Spencer Abraham announced an initiative, known as "Freedom CAR," to help automakers produce fuel-cell-powered electric vehicles. And in January 2002, President Bush proposed a new hydrogen fuel cell vehicle initiative. In February 2003, the Administration announced that U.S. businesses had pledged "ambitious commitments" to reduce greenhouse gas emissions over the next decade.
* The total energy consumption statistic includes petroleum, dry
natural gas, coal, net hydro, nuclear, geothermal, solar, wind, wood and
waste electric power. The renewable energy consumption statistic is based
on International Energy Agency (IEA) data and includes hydropower, solar,
wind, tide, geothermal, solid biomass and animal products, biomass gas and
liquids, industrial and municipal wastes. Sectoral shares of energy
consumption and carbon emissions are also based on IEA data.
Sources for this report include: Associated Press; Christian Science Monitor; Dallas Morning News; Dow Jones; EIU Viewswire; Energy Daily; Energy Report; Financial Times; Financial Times Energy Newsletters; Gas Daily; Global Insight; Houston Chronicle; Los Angeles Times; Megawatt Daily; New York Times; Oil and Gas Journal; Oil Daily; Petroleum Intelligence Weekly; Pipeline and Gas Journal; Platts Oilgram News; PR Newswire; Reuters; U.S. Energy Information Administration (numerous publications -- see links); USA Today; Washington Post; Weekly Petroleum Argus; World Gas Intelligence; World Markets Online; World Oil.
For more information on U.S. energy, see these other sources on the EIA web site:
EIA - Short-Term Energy Outlook
EIA - Annual Energy Outlook 2003
EIA - Monthly Energy Review
EIA - Petroleum Page
EIA - Natural Gas Page
Natural Gas Annual
EIA - Nuclear Page
EIA - Coal Page
EIA - Electricity Page
Electric Power Annual
EIA - Renewable Fuels Page
EIA - Energy Supply Security Page
EIA - Financial Page
EIA - Links Page
Links to other U.S. government sites:
American Petroleum Institute
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Page Last Modified: May 21, 2003
Contact: Lowell Feld