Country Analysis: The United States of America

Nov 20, 2002 01:00 AM

The United States of America is the world's largest energy producer, consumer, and net importer. It also ranks twelfth worldwide in reserves of oil, sixth in natural gas, and first in coal.

As of early November 2002, the US economy appeared to be growing slowly and uncertainly. On November 6, 2002, the US Federal Reserve cut its interest rate target by a half percentage point in an effort to stimulate an economic recovery. The move came following data in September and October indicating an increase in the unemployment rate (from 5.6 % to 5.7 %), slower-than-expected economic growth (3.1 % in the third quarter, following a 1.3 % gain in the second quarter), a decline in job creation, a sharp decrease in consumer confidence, and a reduction in consumption spending.
Among other factors which appear to be slowing the US economy are fears (since 9/11 in particular) over possible terrorism, worries over the situation in the Middle East (and the potential for an increase in oil prices), and a sharpdecline in US equity markets. On the positive side, the Labour Department reported on November 7 that US productivity grew at a rapid, 4 % rate during the third quarter of 2002, the fastest growth in this indicator since the first quarter of the year.

The recent difficulties experienced by the US 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) US gross domestic product (GDP) growth for 2002 now is expected at 2.3 %, up from 0.3 % growth in 2001.
For Fiscal Year (FY) 2002, the federal unified budget ran an estimated deficit of $ 180 bn after running a surplus of around $ 127 bn in 2001. 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. Meanwhile, the US merchandise trade deficit is estimated at $ 478 bn for 2002. This deficit mainly reflects the relative strength of the US economy compared to major US 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 US 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 US Senate passed its own version of an energy bill, which must be reconciled with the House version.

Oil
The United States had 22.4 bn barrels of proved oil reserves as of January 1, 2002, twelfth highest in the world. These reserves are concentrated overwhelmingly (over 80 %) in four states -- Texas (24 % including the state's reserves in the Gulf of Mexico), Alaska (22 %), Louisiana (20 % including the state's reserves in the Gulf of Mexico), and California (19 %, including the state's Federal Offshore reserves). US proven oil reserves have declined by around 20 % since 1990, with the largest single-year decline (1.6 bn barrels) occurring in 1991.
During 2002, the United States is estimated to be producing around 8.2 mm bpd of oil, of which 5.9 mm bpd is crude oil, and the rest natural gas liquids and other liquids. US total oil production in 2002 is down sharply (around 2.4 mm bpd, or 23 %) from the 10.6 mm bpd averaged in 1985. US crude oil production, which declined following the oil price collapse of late 1985/early 1986, levelled 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, US crude production basically levelled off once again in 2000 and 2001, rising slightly in 2002. Despite this increase, US crude production remains near 50-year lows. In 2000, there were around 534,000 producing oil wells inthe United States, the vast majority of which are considered "marginal" or "stripper" wells, generally producing only a few bpd of oil. During the first half of 2002, top oil producing areas included the Gulf of Mexico (1.6 mm bpd), Texas onshore (1.2 mm bpd), Alaska's North Slope (989,000 bpd), California (712,000 bpd), Louisiana onshore (282,000 bpd), Oklahoma (184,000 bpd), and Wyoming (153,000 bpd).
Domestic oil exploration and development spending by US 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 US government lease sale for the western Gulf of Mexico produced bids totalling $ 182 mm.
Bidders included Amerada Hess, Kerr-McGee, Dominion Exploration and Production, Shell, and Nexen. Overall, production from deepwater areas of the Gulf of Mexico has been increasing rapidly, with deepwater wells accounting for about two-thirds of total US Gulf output. Large fields include ExxonMobil's $ 1.1 bn Hoover-Diana development (which started up in May 2000 and is producing 80,000 bpd), plus several by BP: the $ 2 bn 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-bn deep-sea pipeline, and to increase its production from 200,000 bpd currently to 750,000 bpd in 2007. This will require billions of dollars worth of investment.

Crude oil production in the lower 48 states is expected to fall by about 130,000 bpd in 2003, while Alaskan crude production remains flat. Alaskan production, which accounts for around 17 % of the US total, is down about 50 % from the 2.0 mm bpd 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 was producing 80,000 bpd of high quality, light crude oil by the end of 2000. Production at Alpine could rise to 120,000 bpd with tie-ins to the Nanuk and Fiord satellite fields.

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 ofAlaska drew bids worth $ 11 mm 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 US Geological Survey study of ANWR oil resources, projected that for the mean resource case (10.3 bn barrels technically recoverable), ANWR peak production rates could range from 1.0 to 1.35 mm bpd, with initial ANWR production possibly beginning around 2010, and peak production 20-30 years after that. <<P>According to Baker Hughes, which has tallied weekly US 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 US 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 US "rig count" has fallen, reaching 843 (703 gas rigs and 137 oil rigs) as of mid-October 2002. Natural gas rigs outnumber oil rigs in the United States by more than five-fold. Historically, US 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 34,139 wells (22,083 natural gas wells, 8,060 oil wells, and nearly 4,000 dry wells) were drilled in the United States, up from the low point of 18,377 total wells drilled in 1999. For the first nine months of 2002, total wells drilled were down sharply -- 30 % -- from the same period a year earlier.

Twenty-two major energy companies reported overall net income (excluding unusual items) of $ 5.5 bn on revenues of $ 141 bn during the second quarter of 2002 (Q202). This level of net income represented a 55 % decrease relative to the second quarter of 2001 (Q201).
Domestic upstream oil and natural gas production operations accounted for $ 3.2 bn of net income, followed by foreign upstream oil and natural gas production operations ($ 2.7 bn) and worldwide downstream natural gas and power operations ($ 1.0 bn). Besides the major energy companies, independent oil and natural gas producers, oil field companies and refiner/marketers also reported declines in net income (down 42 %) during Q202 compared to Q201.
As with the majors, this decline in net income was due to sharp drops during that period in the price of natural gas, combined with weak demand for electricity and a decline in oil and gas drilling activity (see below).

Consumption/marketing
The United States is estimated to be consuming an average of about 19.7 mm bpd of oil in 2002. Of this, 8.9 mm bpd (or 45 % of the total) is motor gasoline, 4.8 mm bpd (24 %) "other oils," 3.8 mm bpd (19 %) distillate fuel oil, 1.7 mm bpd (8 %) jet fuel, and 0.7 mm bpd (3 %) residual fuel oil. US oil demand is expected to increase by about 3 % (670,000 bpd) in 2003.
Following the September 11 terrorist attacks, US jet fuel demand fell sharply. For the first nine months of 2002, US jet fuel consumption was down 6 % compared to the same period in 2001.

Imports/exports
The United States averaged total gross oil (crude and products) imports of an estimated 11.2 mm bpd during the first nine months of 2002, representing around 57 % of total US oil demand.
Around two-fifths of this oil came from OPEC nations, with Persian Gulf sources accounting for about one-fifth of total US oil imports. Overall, the top suppliers of oil to the United States during the first nine months of 2002 were Canada (1.9 mm bpd), Saudi Arabia (1.5 mm bpd), Mexico (1.5 mm bpd), and Venezuela (1.4 mm bpd).

US energy sanctions issues
The United States maintains energy sanctions against several countries, including Iran, Iraq, and Libya (an oil embargo against Serbia was lifted by President Clinton on October 12, 2000). Iraq remains under comprehensive sanctions imposed after its invasion of Kuwait in August 1990. Iran and Libya are affected by the Iran-Libya Sanctions Act (ILSA), passed unanimously by the US
Congress and signed into law by President Clinton in August 1996. ILSA imposes mandatory and discretionary sanctions on non-US companies which invest more than $ 20 mm annually (lowered in August 1997 from $ 40 mm) in the Iranian oil and natural gas sectors. The passage of ILSA was not the first US sanction against Iran.

In early 1995, President Clinton signed two Executive Orders which prohibited US companies and their foreign subsidiaries from conducting business with Iran. The Orders also banned any "contract for the financing of the development of petroleum resources located inIran."
On March 13, 2001, President Bush, citing threats posed by Iran to US national security, extended Clinton's two Executive Orders on Iran for another 6 months. On August 3, 2001, President Bush signed into law the ILSA Extension Act of 2001. This Act provides for a 5-year extension of ILSA with amendments that affect certain of the investment provisions.

Attempts by the United States to implement ILSA have run into opposition from a number of foreign governments. The 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 US reached an agreement on a package of measures to resolve the ILSA dispute at the EU/US Summit in London, but the Summit deal is contingent upon acceptance by the US 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 aScottish 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 US sanctions against Libya remain in force. On February 1, 2001, one suspect was convicted by the Scottish court, while another was acquitted. The US and British governments both said that they still expected Libya to accept responsibility for the murders, which Libya has said it would not do.

Refining
The United States experienced a steep decline in refining capacity between 1981 and the mid-1990s. Between 1981 and 1989, for instance, the number of US refineries fell from 324 to 204, representing a loss of 3 mm bpd in operable capacity, while refining capacity utilization increased from 69 % to 86 %. Much of the decline in US refining capacity 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.
Since the mid-1990s, US refinery capacity has increased, from 15.0 mm bpd in 1994 to 16.8 mm bpd in 2002. As of November 2002, utilization of operating capacity at US refineries reportedly was averaging around 88 %-92 %. 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 US refining capacity in the long-run.

Since the mid-1980s, several US 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 US 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-bpd refinery in Chalmette, Louisiana.

Strategic Petroleum Reserve (SPR)
The 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 US policy to establish a petroleum reserve of up to 1 bn barrels. In order to store the reserve oil, the US 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, the St James Terminal in Louisiana, with a total storage capacity of 700 mm barrels.

The volume of oil stored in the SPR peaked at 592 mm barrels in 1994. Approximately $ 327 mm worth of SPR oil was sold off in 1996, and an additional $ 220 mm in 1997. On September 22, 2000, President Clinton authorized the release of 30 mm barrels of oil from the SPR over 30 days in an attempt to bolster US 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 DOE to fill the SPR to its capacity of 700 mm 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 November 12, 2002, the SPR contained around 590 mm barrels of oil -- the largest emergency oil stockpile in the world.

The SPR has a maximum draw down capability of 4.3 mm bpd for 90 days, with oil beginning to arrive in the marketplace 15 days after a presidential decision to initiate a draw down. The SPR draw down rate declines to 3.2 mm bpd from days 91-120, to 2.2 mm bpd for days 121-150, and to 1.3 mm bpd for days 151-180.
Under EPCA, there is no preset "trigger" for withdrawing oil from the SPR. Instead, the President determines that draw down 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 draw down 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 4.1-4.2 mm bpd for a 90-day period (lower after that).

Oil mergers and acquisitions
Pushed in part by low oil prices during 1998 and into early 1999, but also by the desire for oil reserves, cost cutting, and higher refining/marketing shares, merger activity in the oil business accelerated sharply during 2000 and 2001 (before slowing considerably in 2002).
The largest merger/acquisition announcements came from BP and Amoco, Exxon and Mobil, BP Amoco and ARCO, and, most recently, Chevron and Texaco. BP and Amoco completed their $ 53-bn merger on December 31, 1998, a day after the deal received regulatory approval from the US Federal Trade Commission (FTC), subject to certain conditions.

In September 2002, US regulators approved the purchase of Pennzoil-Quaker State by Shell Oil. The deal, first reported in March 2002, was for $ 1.8 bn (with Shell also assuming $ 1.1 bn of Pennzoil-Quaker State debt). The transaction combines Shell's 3 % share of the US market for passenger car motor oil with Pennzoil-Quaker State's 35 % share, making Shell the No. 1 US lubricants company.
Shell also adds Pennzoil-Quaker State's 46,200 bpd Shreveport, Louisiana refinery and more than 2,000 Jiffy Lube outlets. In October 2002, Shell announced that it would close or sell seven US blending and packaging plants as part of its ongoing merger.
On November 19, 2001, Phillips Petroleum and Conoco agreed to merge in a $ 15.2 bn transaction. This transaction 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 US refiner, and the third-largest US-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 bn 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 mm. LUKoil eventually intends to switch Getty's 1,300 retail outlets in the North-eastern and Middle Atlantic states to the LUKoil brand name. The purchase represents the first takeover of a publicly traded US company by a Russian firm. In late January 2001, Getty shareholders approved the buyout.

On April 13, 2000, the FTC approved the $ 27.6 bn 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 bn. 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 US 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 Shell.

Meanwhile, the $ 81 bn 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 US 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’s $ 1.86 bn takeover of Oryx Energy, and an agreement between Seagull Energy and Ocean Energy to merge in a $ 1.1-bn deal.
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 US independent oil and natural gas companies. In January 2001, Amerada Hess announced that it was withdrawing a $ 3.5-bn offer to purchase Britain's Lasmo, a move which would have created a "super-independent" oil company. Instead, Lasmo was purchased by Italy's ENI for $ 4 bn.

Due to low profitability in the refining/marketing line of business, US integrated major energy companies began a process during the 1990s of selective refining/marketing divestiture, and numerous US 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 bn. Another company, Tosco Corporation, was purchased by Phillips Petroleum for $ 7.5 bn in September 2001, creating the second largest refining group in the United States, behind ExxonMobil.

Natural gas
As of January 1, 2002, the United States had estimated proven natural gas reserves of 177 tcf, or 3.2 % of world reserves (6th in the world). For all of 2002, US production of dry natural gas is estimated at 19.2 tcf. Natural gas consumption is estimated at 21.6 tcf, and net imports at around 3.5 tcf, mainly from Canada. Overall, the United States depends on natural gas for about 23 % of its total primary energy requirements (oil accounts for around 39 % and coal for 22 %).
Natural gas wellhead prices reached record highs of nearly $ 10.00 per thousand cf (mcf) in late 2000/early 2001, but fell sharply soon thereafter to around $ 2.50 per mcf. Early cold weather in October 2002, particularly in the Midwest and Northeast, raised natural gas prices even as storage levels remained at relatively high levels. With natural gas storage levels well above 3 bn cf at the end of October, further large price increases are not expected in the near term.
The current level of storage is only slightly higher than last year but about 6 % higher than the previous 5-year average. Assuming normal weather for the remainder of the 2002/2003 heating season, winter natural gas wellhead prices are expected to average $ 3.54 per mm cf, or $ 1.12 per mm cf above last winter’s price. For all of 2002, the average natural gas wellhead price is projected to be $ 2.92 per mcf compared to over $ 4.00 per mcf last year. In 2003, wellhead prices are projected to average $ 3.37 per mcf.

Natural gas production and storage
September 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 mm Btu mark for most of October 2002.
Early cold weather in October, 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 are not expected in the near term, unless the weather turns abnormally cold for a prolonged period. A level of 3-3.2 tcf of working gas in storage by November 1, 2002 is considered sufficient to ensure adequate natural gas supplies for the winter.
The current (end of October) storage level for working gas is 3.15 tcf, about the same level as year ago, when the wellhead price was $ 2.45 per thousand cf, and about 5 % higher than the previous 5-year average. Domestic dry natural gas production is projected to increase by about 2.7 % in 2003 after falling by about 1.3 % in 2002.

US natural gas production and net imports are likely to increase sharply over the next two decades in response to strong demand, abundant reserves, and improved unconventional and offshore recovery technology. Increased natural gas production is expected to come mainly from onshore sources, although offshore Gulf of Mexico production also is forecast to grow significantly.
In August 2001, for instance, ExxonMobil began production at its $ 330 mm Mica natural gas project in the deepwater Gulf of Mexico. Alaska's North Slope fields also represent a large potential natural gas source, with an estimated 30-35 tcf of natural gas reserves.

Alaska's GovernorTony Knowles has stated that he supports a $ 17.2 bn natural gas pipeline running from the North Slope along the Alaska Highway into Alberta and on to markets in the US Midwest (another option would be to route the pipeline via the MacKenzie Delta in northern Canada).
Increased 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, Louisiana, Oklahoma, New Mexico, Wyoming, Colorado, Kansas, Alaska, California, and Alabama.

Natural gas demand
From 1990 through 2001, natural gas consumption in the United States increased by about 14 %, and this growth is likely to continue in coming years. Greater use of natural gas as an industrial and electricity generating fuel can be attributed, in part, to its relatively clean-burning qualities in comparison with other fossil fuels.
Lower costs resulting from greater competition and deregulation in the natural gas industry and an expanding transmission and distribution network have also helped expand its acceptance and use. In 2001, natural gas consumption fell by over 1.1 tcf, after a 0.9 tcf increase in 2000. During 2001, natural gas consumption by electric utilities fell sharply, to 2,675 bn cf, down 368 bn cf from 2000.

Natural gas is consumed in the United States mainly in the industrial (42 %), residential (22 %), commercial (15 %), and electric utility (13 %) sectors (note: EIA generally places consumption of natural gas for power generation by non-utilities, including natural gas used for industrial cogeneration, in the "industrial" category).
Total natural gas demand for the first half of 2002 fell by 610 bn cf. That translates into a decline of 5.2 % from 2001 levels, although nearly 50 % of the first-half decline in total demand was due to weather effects in the residential and commercial sectors. Second-half strength in the residential and commercial sectors, fed by weather-related increases in the fourth quarter, remains highly probable. Total natural gas demand growth for 2002 is expected to be 1.1 %. Weakness in the industrial sector prevents the growth rate from being more substantial.

US natural gas consumption and imports, largely from Canada -- and to a far lesser extent from LNG, 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.
In particular, new combined-cycle facilities furnished with more efficient natural gas turbines will help lower the cost of natural-gas-generated electricity to levels competitive with coal-fired plants. Increased US natural gas consumption will require significant investments in new pipelines and other natural gas infrastructure -- $ 1.5 t over the next 15 years according to the National Petroleum Council. The largest natural gas pipeline project currently under construction is the $ 1.2 bn Gulf Stream pipeline, which will run 564 miles from Alabama to Florida.
Mexico could potentially become a significant natural gas exporter to the United States in the long term. One US-Mexican natural gas pipeline proposal currently on the table is the $ 230 mm, 220-mile North Baja line connecting south-eastern California and Tijuana, Mexico. Companies involved in this project include Sempra Energy, PG&E, and Mexico's Proxima Gas. The project began service in September 2002, with initial capacity of 200 mm cfpd. This should rise to 500 mm cfpd shortly, with completion of the pipeline's compressor station.

Domestic and import pipelines
On November 1, 1993, 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.
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 bn cfpd 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-bn, 1.3-bn cfpd Alliance Pipeline from western Canada (Fort St. John, British Columbia) to the Chicago area entered service. Another pipeline, the Independence Pipeline ($ 678 mm) 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 mm), 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 mm cfpd of natural gas, providing an environmentally preferred option for generating electricity.
According to the Millennium Pipeline consortium, 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. That existing system serves several major gas end-users, utilities and their customers in New York’s Southern Tier region.

Growing US demand for Canadian natural gas has been a dominant factor underlying many of the pipeline expansion projects this decade. The US 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 US 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 2.2 tcf of natural gas (net) from Canada during the first seven months of 2002, about the same year-over-year as 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. The Maritimes and Northeast Pipeline came onstream in January 2000, running from Sable Island to New England, with further extensions into New England planned (Phase III construction is set to begin in the fall of 2002). In February 2002, Enbridge shelved plans to build a pipelineconnection between Sable Island and Quebec.

The $ 2.5-bn Alliance Pipeline, at 1,875 miles, is the longest pipeline ever built in North America, and is designed to carry about 1.3 bn cfpd of gas from western Canada (Fort St John, British Columbia) to the Chicago area. The pipeline began commercial service on December 1, 2000. The US utility Pacific Gas & Electric imports natural gas from British Columbia via the Alliance pipeline.
The Millennium Pipeline remains in the regulatory approval stage of development; it is slated to connect Canadian sources to southern New York and Pennsylvania. Indecision over the final route of the pipeline in New York currently is stalling progress.

On October 12, 2001, the US Coast Guard lifted the ban on LNG tankers from Boston harbour. 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).
The decision enabled the reopening of the Distrigas facility in Everett, Massachusetts, which received 45 shipments containing 99 bn cf 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. In August 2002, Williams announced that was selling Cove Point (including an 87-mile pipeline) for $ 217 mm to a subsidiary of Dominion Resources.

Overall, there is growing interest in LNG to supply natural gas for US electric power generation and provide supply flexibility. EIA expects that LNG importsto the United States will increase at an average 8.6 % annual rate, to 830 bn cf by 2020.

Natural gas mergers, acquisitions, bankruptcies
As with oil, a number of major natural gas market participants are engaging in various forms of corporate combinations, such as mergers, acquisitions, and strategic alliances. The value of mergers and acquisitions within the natural gas industry quadrupled from $ 10.4 bn in 1990 to $ 39 bn in 1997.
This increase parallels an enormous surge in corporate combinations (mergers, acquisitions, joint ventures and strategic alliances) across the energy sector. In August 2001, Devon Energy announced the acquisition of Mitchell Energy for $ 3.1 bn, forming the second largest independent natural gas producing company in the United States, behind Anadarko Petroleum.
In late January 2001, El Paso Energy completed its $ 24-bn merger with Coastal, creating the fourth-largest US energy company by market capitalization (after BP, ChevronTexaco, and Enron at the time).The October 1999 merger between El Paso Energy and Sonat had created the largest transporter of natural gas in the country.

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.
Enron had been the seventh-largest publicly-traded energy company in the world. Also in early December 2001, Enron filed a $ 10 bn 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 bn of cash immediately into Enron, and an additional $ 1 bn into the combined entity. The merged company was to be called Dynegy, 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 US 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 US 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.

Coal
The United States is forecast to produce 1,089 mm short tons of coal in 2002, down from 1,121 mm short tons in 2001. Also in 2002, the United States is expected to consume 1,063 mm short tons (up from 1,051 mm short tons in 2001) and to export (net) 24 mm short tons.Led by Wyoming, the West is the leading US coal-producing region (with about half of the US total), overwhelmingly from surface mines.
Appalachia (led by West Virginia and Kentucky) accounts for about 37 % of total US coal production, mainly from underground mines. Around three-fifths of US coal production is bituminous, one-third subbituminous, and about one-tenth lignite (brown coal). Around 80,000 miners work in the $ 20 bn US coal industry, down from a peak of 700,000 in 1923, when US coal production was half what it is today.
Major US coal companies include Peabody Energy (the largest in terms of production), Arch Coal (the second largest coal producer); and Kennecott Energy.

During 2002, coal production is expected to fall in all regions of the United States, particularly Appalachia. Low-sulphur western coal production surpassed relatively higher-cost, higher-sulphur, Appalachian coal for the first time in 1998, 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 sulphur emissions from coal combustion. In response, Wyoming increased its coal production sharply, particularly low-sulphur, low-ash (and low cost) coal from the Powder River Basin, where coal is strip-mined.

The electric power sector (utilities and non-utilities) accounts for the vast majority (around 90 %) of US 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, and coal demand reaching 1,365 mm short tons.
As sulphur dioxide emissions standards are tightened (in 2000, for instance, Phase 2 of CAAA took effect), the share of low-sulphur coal in the US coal consumption mix is expected to increase. In 1999, low and medium-sulphur coals had approximately the same share of the US coal market, with high-sulphur coal far behind.

US 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 US coal exports dropped to the lowest level since 1978, largely due to 1) a strong US 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 US metallurgical coal operations have closed, and increased amounts of metallurgical coal have been sold into the domestic utility steam coal market.

The US 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 US share of world coal exports will decline in coming years.
US gross coal imports, at 16.5 mm short tons, are expected to be about 17 % lower in 2002 than they were in 2001. The rise in imports is attributable to both the heightened demand for low-sulphur coal to meet the stricter sulphur emission requirements of Phase II of the CAAA, and to the tight coal supply market that existed for most of 2001.

Electricity
In 2001, the United States generated 3,779 bn kWh of electricity, including 2,661 bn kWh at electric utilities plus an additional 1,116 bn kWh at non-utility producers. For utilities, coal-fired plants accounted for 60 % of generation, nuclear 20 %, natural gas 10 %, hydroelectricity 7 %, oil 3 %, geothermal and "other" 0.1 %.
For non-utilities, natural gas plants accounted for around 32 % of generation, coal 32 %, nuclear 21 %, "geothermal and other" (including geothermal, wind, solar, wood and waste) about 8 %, oil 5 %, hydroelectric at 2 %, and "other gaseous fuels" (including refinery still gas and LPGes) 1 %.
During the first 6 months of 2002, total US net generation of electricity was 1,836 bn kWh (1,235 bn kWh from utilities and 600 bn kWh from non-utilities), about the same as for the corresponding period in 2001. Roughly half of this generation was accounted for by coal-fired power plants. This was followed by 21 % from nuclear, 17 % % from natural gas, 8 % from hydroelectricity, 3 % from renewables, and 2 % from petroleum.

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 price of electricity sold by utilities during the first half of 2002 averaged 7.06 cents per kWh, about the same as during the first half of 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, US total net summer electric generating capacity was 854.7 GW. Of this total, 37 % was coal-fired, 16 % natural-gas-fired capacity, 11 % nuclear; 9 % hydroelectric, 4 % petroleum, 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 petroleum-fired capacity in the East, hydroelectric in the West, and natural-gas-fired capacity in the Coastal South.
Total annual electricity demand (retail sales plus industrial generation for own use and other direct sales) is expected to show growth of 2.2 % for all of 2002. Abnormally high summer temperatures and high cooling demand increased electricity demand sharply in the third quarter of 2002. Based on Edison Electric Institute data on weekly electricity output, US electricity production rose 6.5 %for the third quarter 2002 compared to the year-earlier level.

EIA's estimate for third-quarter 2002 growth in total demand has been revised to 5.0 %. Total US electricity demand is expected to be 3.5 % higher this winter than it was last winter, due to the slowly rising economy and assumptions of normal temperatures for the remainder of the winter, which would imply 13 % colder conditions this winter than last, contributing to higher heating-related electricity demand.
In 2003, while the economy is expected to continue to recover, electricity demand is expected to grow by a relatively subdued rate of about 1 %since little or no net summer demand growth would be expected under normal levels of cooling degree-days.

Over the long term, US power demand is increasing steadily (although well below average economic growth), with EIA forecasting 1.8 % average annual growth in electricity sales through 2020. This increase will require a significant addition in generating capacity, with EIA forecasting that 1,300 new power plants will be needed over the next 20 years.
Whether these plants are natural-gas-fired, coal-fired, "renewable," or nuclear depends on a mix of factors, including economics and government policy, but if recent trends continue, it is likely that the vast majority of new plants will be natural-gas-fired, with oil accounting for less than 1 % of power generation by 2020.

The changing structure of the US electric power industry has resulted in many electric utilities restructuring their companies and selling their generating assets, primarily to non-utility companies. During 2001, approximately 28,186 MW of capacity was sold to non-utility companies, including nuclear facilities in Illinois, Pennsylvania, New York and Connecticut.
An additional 27,206 MW of generating capacity, all in Texas, was sold/transferred to non-utilities in 2002. On January 1, 2002, retail competition for customers of investor-owned utilities (IOUs) began in Texas. Municipal and cooperative electricity providers are not affected by the law, unless they choose (after January 2002) to open their territories to competition.

In March 2002, FERC delayed deregulation in Southeast Texas from September 15, 2002 until 2003 because no consensus has been reached on the formation of a regional transmission organization (RTO). The District of Columbia began allowing customers direct access to competitive electricity suppliers on January 1, 2001, and in Maryland legislation was enacted that called for a 3-year phase-in for competition beginning in July 2000 and becoming complete by July 2002.
Meanwhile, legislatures and/or public utility commissions in 22 other states also have approved or implemented plans to move toward retail competition. California's problems have caused several states (Arkansas, Montana, Nevada, New Mexico, Oklahoma, and West Virginia to delay full implementation of electricity sector deregulation.

On March 31, 1998, retail customers of investor-owned utilities in California (approximately three-fourths of the state's customers) were allowed direct access to an alternative energy (electricity) service provider. During much of 2000 and early 2001, California confronted a major power problem, with intermittent "rolling blackouts" and "Stage 3" (the highest level) alerts.
Causes of this situation included:
1) sharply increased (11 %) power demand in California over the past decade as a result of a surging economy and low power costs to consumers;
2) stagnant supply over the same period;
3) low hydropower output levels in the Northwest due to below-normal rainfall;
4) California's heavy reliance on out-of-state capacity and power imports;
5) high natural gas prices and lingering problems from the August 2000 El Paso natural gas pipeline explosion;
6) significant problems stemming from California's Electric Utility Industry Restructuring Act of 1996; and
7) serious financial problems at utilities (PG&E, SCE).

Serious problems, however, were largely avoided during the summer of 2001 due to conservation, a downturn in California's economy (and hence power demand), the addition of power generating capacity, and higher power prices. On September 24, 2001, as required by law, the CPUC effectively put an end to deregulation of retail electricity in California.
Although California for the most part avoided power blackouts or other major problems this past summer, financial difficulties continue at utilities like PG&E, (in bankruptcy) and SCE (close to bankruptcy). On October 22, 2001, the US Department of Energy, in partnership with PG&E, announced that it would spend $ 300 mm to upgrade Path 15, a series of power transmission lines connecting northern and southern California. As of November 2002, California had excess power generation and minimal risk of power outages.

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 42.9 bn kWh of electricity to the United States in 1999, 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 US power markets, as the United States also exports smaller volumes of electricity to Canada.

Nuclear
In 2001, US nuclear power generation reached a record 769 bn kWh, or about 20 % of total US electricity generation, second only to coal in the US electricity generation mix (for the first half of 2002, nuclear production was up about 1 % from the same period in 2001). Nuclear power's share of US utility electric generating capacity in 2001 was highest in the New England region (69 % of utility generation), followed by the Middle Atlantic (37 %), the South Atlantic (29 %), the Pacific Coast (24 %), the East South Central (20 %), the West South Central (17 %), the West North Central (16 %), the East North Central (12 %), and the Mountain region (10 %).
Approximately one-fourth of US nuclear output was provided by just three states: Illinois, Pennsylvania, and South Carolina. The average capacity factor for all nuclear units nationwide increased from 88.1 % in 2000 to 89.7 % in 2001, an all-time record high utilization rate. Following the September 11, 2001 terrorist attacks on the United States, security at nuclear power plants around the United States was increased dramatically.

Nuclear power in the United States grew rapidly after 1973, when only 83 bn kWh of nuclear power was produced. As of 2001, nuclear power had grown nine-fold, with 104 licensed nuclear power units generating 769 bn kWh of electricity. This rapid growth in nuclear power generation, however, obscures serious underlying problems in the US nuclear industry.
After 1974, many planned units were cancelled, 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. In late March 2000, the Nuclear Regulatory Commission (NRC), in a positive signal to the US 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. As of March 2002, Exelon and Dominion Resources reportedly were looking at sites to build the first new nuclear power plants in the United States in two decades.

After a period of heightened concern for the availability of nuclear generation this past summer, the prospect for normal operations appears likely. Upon discovery of corrosion in a major component in a nuclear plant in Ohio, the Nuclear Regulator Commission ordered the submission of safety information on 68 other units, implying the possible need for shutdowns for inspections. It now appears the problem is confined to one unit and the cause is being investigated.
The temporary loss of this capacity is offset by increases in capacity at several reactors due to NRC-approved upgrades ranging from 2 % to 20 % and totalling several hundred MW in each year of the projection. Total nuclear generation is expected to rise by 0.4 % from the 2001 level in 2002 and by an additional 0.9 % in 2003.

On July 9, 2002, the US 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 centring 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.

Hydroelectricity/other "renewables"
The United States consumed 6.2 quadrillion Btu of renewable energy in 2001, about 6 % of total domestic gross energy demand, with the largest component used for electricity production. Hydropower made up around 39 % of total US renewable consumption in 2001, with biofuels (including wood and waste), solar, wind, and geothermal making up most of the remainder. In 2001, total hydropower generation was down to lows not seen since 1966.
In the summer of 2002, the US Northeast experienced a serious drought, calling into question the adequacy of hydroelectricity supplies during the summer cooling season. As of early November, however, the drought had eased significantly following heavy rains in much of the region. Overall, total hydro generation rose by around 24 % during the first half of 2002 compared to the same period in 2001. For 2002 as a whole, total hydropower generation is expected to rise by 29 % as normal precipitation returns to the Pacific Census Division (Washington, Oregon and California), the main region affected by drought.

Wind, solar, biomass, and geothermal power, although growing, still supply only a tiny fraction of US energy needs. In January 2000, however, the US 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 US peak electricity capacity expected to be required in 2020." Wind, geothermal, and biomass energy sources also have significant potential in the United States.
In 2001, 1,694 MW of wind power was installed in the United States, more than twice the previous record of 732 MW installed in 1999, according to the American Wind Energy Association (AWEA). This increase was driven in part by a federal wind Production Tax Credit, or PTC, of 1.7 cents per kWh (lowered to 1.5 cents per kWh in the two-year renewal signed into law on March 9, 2002). The PTC, among other factors, has helped boost total US installed wind generating capacity to 4,258 MW (as of January 2002), with wind turbines now located in 26 states.
During the first half of 2002, wind power production increased 37 % from the same period in 2001, the fastest growing power source in the United States in percentage terms, but trailing far behind natural gas and nuclear power in absolute terms. The first US offshore windmill park reportedly is scheduled to be built off the Cape Cod coast, with 170 windmills to be installed beginning in 2004. The project could power more than 200,000 homes in Cape Cod.

Environment
The United States, with the world's largest economy, is also the world's largest single source of anthropogenic (human-caused) greenhouse gas emissions. 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 US emissions of carbon (mainly in the form of carbon dioxide) will reach 1,694 mm tons in 2005, an increase of 357 mm tons from the 1,337 mm tons emitted in 1990, and around one-fourth of total world energy-related carbon emissions.

At the December 1997 global warming summit in Kyoto, Japan, the US delegation agreed to reduce US carbon emissions 7 % from 1990 levels by 2008-2012. Given current EIA projections, it is unlikely that this goal will be met. 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, sulphur 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 US "greenhouse gas intensity" -- the amount of greenhouse gases emitted per dollar of GDP -- by 18 % over 10 years. As the graph here shows, US carbon emissions per dollar of GDP have been declining steadily since at least 1980.

US energy-related carbon emissions have been increasing in recent years for three main reasons.
First, the US economy experienced strong economic growth during the 1990s, which in combination with generally low oil prices for most of the period (until recently), caused energy consumption to increase.
Second, the energy "efficiency gains" of the 1980s, which were prompted largely by the oil price spikes of the 1970s, have been levelling off for several years now, 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.
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 has not been growing. Since taking office on January 20, 2001, the Bush Administration has taken a series of actions related to energy and the environment.

On February 28, 2001, EPA Administrator Christine Todd Whitman directed her agency to move ahead with a rule issued by President Clinton that will require US refiners to reduce sulphur in diesel fuel from 500 ppm currently, to 15 ppm 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 US economy, and that it would pursue other ways of addressing the climate change issue. On April 10, the EPA asked the US 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.

Country overview
President: George W. Bush (since January 20, 2001)
Legislative Branch: Bicameral Congress (Senate, House of Representatives)
Judicial Branch: Supreme
Court independence: July 4, 1776
Population (July 2001E): 285 mm
Location/size: North America, between Canada and Mexico/9,629,091 sq km (3,717,792 sq miles), the third largest country in the world, behind Russia and Canada
Major cities: Washington, DC (capital), New York, Los Angeles, Chicago, Houston, Miami, Philadelphia, etc.
Languages: English, Spanish (spoken by a sizable minority)
Ethnic groups (8/1/2000): White (82.2 %), Black (12.8 %), Asian (4.1 %), Native American (0.9 %). Note: Hispanics, who can be of any race, made up 11.8 % of the US population as of 8/1/2000.
Religions (1997): Protestant (58 %), Roman Catholic (26 %), Jewish (2 %), other (6 %), none (8 %)
Defence (8/98): Army, 479,400; Navy, 380,600; Air Force, 370,300; Marine Corps, 171,300 (the United States also has nearly 1.35 mm reservists)

Economic overview
Currency: Dollar ($ )
Exchange rates, per $ (11/6/2002): British Pound (0.6397); Canadian $ (1.557); Euro (0.9999); Japanese Yen (121.85)
Gross Domestic Product (GDP) (2002E): $ 10.5 tn
Real GDP growth rate: (2001E): 0.3 % (2002E): 2.3 % (2003F): 3.0 %
Inflation rate (GDP implicit price deflator) (2001E): 2.4 % (2002E): 1.3 % (2003F): 2.5 %
Unemployment rate (2001E): 4.8 % (2002E): 5.8 % (2003F): 5.9 %
Current account balance (2001E): -$ 393 bn (2002E): -$ 510 bn (2003F): -$ 535 bn
Merchandise exports (2001E): $ 719 bn (2002F): $ 693 bn
Merchandise imports (2001E): $ 1,146 bn (2002F): $ 1,171 bn
Merchandise trade balance (2001E): -$ 427 bn (2002F): -$ 478 bn
Major exports: Capital goods, automobiles, industrial supplies and raw materials, consumer goods, agricultural products
Major imports: Crude oil and refined petroleum products, machinery, automobiles, consumer goods, industrial raw materials, food and beverages
Major trading partners: Canada, Japan, European Union, Mexico
Federal budget surplus (2001E): $ 127 bn (2002E): -$ 180 bn (2003F): -$ 255 bn

Energy overview
Secretary of Energy: Spencer Abraham (as of January 20, 2001)
Proven oil reserves (1/1/02E): 22.4 bn barrels
Oil production (January-September 2002E): 8.1 mm bpd, of which 5.8 mm bpd was crude oil (Note: Including "refinery gain," US oil production in 2002 is estimated at 9.1 mm bpd)
Oil consumption (January-September 2002E): 19.6 mm bpd
Net oil imports (January-September 2002E): 10.3 mm bpd
Gross oil imports (January-September 2002E): 11.25 mm bpd (of which, 8.96 mm bpd was crude oil and 2.28 mm bpd were petroleum products)
Crude oil imports from the Persian Gulf (January-August 2002E): 2.3 mm bpd (around 26 % of total US crude oil imports)
Top sources of US crude oil imports (January-August 2002E): Saudi Arabia (1.49 mm bpd); Mexico (1.46 mm bpd); Canada (1.37 mm bpd); Venezuela (1.14 mm bpd)
Value of oil imports (January-August 2002E): $ 64 bn (down from $ 74 bn during the same period in 2001)
Crude oil refining capacity (2002E): 16.8 mm bpd (153 operable refineries)
Oil stocks (9/02E): 1.57 bn barrels (including about 585 mm barrels in the US Strategic Petroleum Reserve)
Oil wells drilled (January-September 2002E): 3,689 (down from 6,210 during the same period in 2001)
Operating oil and natural gas rotary rigs (10/02E): 852 (709 for natural gas and 140 for oil)

Natural gas reserves (1/1/02E): 177 tcf
Dry natural gas production (2001E): 19.5 tcf (2002F): 19.2 tcf
Natural gas consumption (2001E): 21.4 tcf (2002F): 21.6 tcf
Net natural gas imports (2001E): 3.65 tcf (over 90 % from Canada) (2002F): 3.46 tcf
Natural gas wells drilled (2001E): 21,224 (up from 15,598 in 2000)

Recoverable coal reserves (12/31/98): 275.1 bn short tons (54 % lignite and subbituminous; 46 % anthracite and bituminous)
Coal production (2001E): 1,121 mm short tons (2002F): 1,089 mm short tons
Coal consumption (2001E): 1,050 mm short tons (2002F): 1,063 mm short tons
Gross coal exports (2001E): 49 mm short tons (2002F): 41 mm short tons
Primary and secondary coal stocks (closing; 2002F): 159 mm short tons (down from 170 mm short tons in 2001)

Electric generation capacity (2001E): 855 GW (37 % coal-fired, 16 % natural-gas, 11 % nuclear; 9 % hydroelectric, 4 % petroleum, and 2 % "renewables")
Electric net generation by utilities (2002F): 2,579 bn kWh (of which coal-fired 59 %, nuclear 20 %, natural gas 10 %, hydroelectricity 10 %, oil 2 %, geothermal and "other" 0.1 %)
Non-utility power production (2002F): 1,275 bn kWh (of which natural gas-fired 35 %, coal 30 %, nuclear 21 %, "geothermal and other" 8 %, oil 3 %, hydroelectric 2 %, and "other gaseous fuels" 2 %)
Total electricity generation (2001E): 3,758 bn kWh (2002F): 3,854 bn kWh

.Environmental overview
Administrator of the US Environmental Protection Agency: Christine Todd Whitman
Total energy consumption (2001E): 97.1 quadrillion Btu (25 % of world total energy consumption) (2002F): 97.8 quadrillion Btu
Energy-related carbon emissions (2001E): 1,540 mm tons of carbon (about 25 % of world total carbon emissions)
Per capita energy consumption (2000E): 348.9 mm Btu
Per capita carbon emissions (2000E): 5.7 tons of carbon
Energy intensity (2001E): 10,530 Btu/$ 1996
Carbon intensity (2000E): 0.17 tons of carbon/thousand $ 1996
Sectoral share of energy consumption (2001E): Industrial (35 %), transportation (26 %), residential (21 %), commercial (18 %)
Fuel share of energy consumption (2001E): Oil (39 %), natural gas (23%), coal (23 %), renewables (6 %)
Fuel share of carbon emissions (2000E): Oil (42 %), coal (37 %), natural gas (21 %)
Renewable energy consumption (2001E): 6,173 tn Btu (about 39 % of which was conventional hydroelectric power)
Number of people per motor vehicle (2000E): 1.3

Status in climate change negotiations: Annex I country under the United Nations Framework Convention on Climate Change (ratified October 15th, 1992). Under the negotiated Kyoto Protocol (signed on November 12th, 1998 -- not yet ratified), the United States agreed to reduce greenhouse gases 7 % below 1990 levels by the 2008-2012 commitment period.
Major environmental issues: Air pollution resulting in acid rain in both the US and Canada; the US is the largest single emitter of carbon dioxide from the burning of fossil fuels; water pollution from runoff of pesticides and fertilizers; very limited natural fresh water resources in much of the western part of the country require careful management; desertification.
Majorinternational environmental agreements: A party to Conventions on Air Pollution, Air Pollution-Nitrogen Oxides, Antarctic-Environmental Protocol, Antarctic Treaty, Climate Change, Endangered Species, Environmental Modification, Marine Dumping, Marine Life Conservation, Nuclear Test Ban, Ozone Layer Protection, Ship Pollution, Tropical Timber 83, Tropical Timber 94, Wetlands and Whaling. Has signed, but not ratified, Air Pollution-Persistent Organic Pollutants, Air Pollution-Volatile Organic Compounds, Biodiversity, Desertification, Hazardous Wastes.

* 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 arealso based on IEA data.

Energy industry
Major US oil companies (2002): ExxonMobil, ChevronTexaco, ConocoPhillips, Anadarko, Occidental, Apache, Burlington Resources, Unocal, Devon, Marathon
Major US coal companies (2000): Peabody Holding; Arch Coal; Kennecott Energy; Consol Energy; RAG American Coal Holding; AEI Resources; A.T. Massey; Vulcan Partners
Oil pipelines (2001E): Around 2 mm miles
Natural gas pipelines (2000E): 278,000 miles
Major ports: Baltimore, Chicago, Hampton Roads, Houston, Los Angeles, New Orleans, New York, Philadelphia

Source: EIA
Market Research

The International Affairs Institute (IAI) and OCP Policy Center recently launched a new book: The Future of Natural Gas. Markets and Geopolitics.

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The book is an in-depth analysis of some of the fastest moving gas markets, attempting to define the trends of a resource that will have a decisive role in shaping the global economy and modelling the geopolitical dynamics in the next decades.

Some of the top scholars in the energy sector have contributed to this volume such as Gonzalo Escribano, Director Energy and Climate Change Programme, Elcano Royal Institute, Madrid, Coby van der Linde, Director Clingendael International Energy Programme, The Hague and Houda Ben Jannet Allal, General Director Observatoire Méditerranéen de l’Energie (OME), Paris.

For only €32.50 you have your own copy of The Future of Natural Gas. Markets and Geopolitics. Click here to order now!


 

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