AmerCon : United States

U.S. Energy Sanctions Issues

The United States maintains energy sanctions against several countries. Iran and Libya
are impacted by the Iran-Libya Sanctions Act (ILSA), passed unanimously by the U.S.
Congress and signed into law by President Clinton in August 1996. ILSA imposes
mandatory and discretionary sanctions on non-U.S. companies which invest more than $20
million annually (lowered in August 1997 from $40 million) in the Iranian oil and natural gas
sectors. The passage of ILSA was not the first U.S. sanction against Iran. In early 1995,
President Clinton signed two Executive Orders which prohibited U.S. 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 in Iran." On
March 13, 2001, President Bush, citing threats posed by Iran to U.S. 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 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). 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. On August 14, 2003, Libya reportedly agreed to compensate families
of the 1988 Lockerbie airplane bombing with $2.7 billion total. The money was to be
released in three tranches, the first following a lifting of United Nations sanctions, the
second after possible lifting of U.S. sanctions, and the third after Libya is removed from the
U.S. State Department's state sponsors of terrorism list. On September 12, 2003, the U.N.
Security Council lifted sanctions against Libya, but U.S. sanctions remained in place. On
February 26, 2004, the United States rescinded a ban on travel to Libya and authorized U.
S. oil companies with pre-sanctions holdings in Libya to negotiate on their return to the
country if and when the United States lifts economic sanctions.

Refining/Downstream

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 U.S. refineries fell from
324 to 204, representing a loss of 3 MMBD in operable capacity, while refining capacity
utilization increased from 69% to 86%. Much of the decline in U.S. 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.

Refinery closures have occurred every year over the past two decades. Since 1988, the
United States has lost over 1.6 MMBD of capacity, which is about 10% of today’s total
refining capacity. Several factors are driving this situation: 1) refineries that have closed
are smaller and have less favorable economics than other refineries in their market area;
2) even though refinery utilization has improved since the 1980’s, refinery margin
improvements have been modest; and 3) in recent years, some smaller, less-economic
refineries that faced additional investments for environmental reasons in order to stay in
business found closing preferable because they predicted that they could not stay
competitive in the long term.

While some refineries have closed, and no new refineries have been built in nearly 30
years, many existing refineries have expanded their capacities. As a result of "capacity
creep," whereby existing refineries create additional refining capacity from the same
physical structure, capacity per operating refinery increased by 28% over the 1990 to
1998 period, for example. Overall, since the mid-1990s, U.S. refinery capacity has
increased from 15.0 MMBD in 1994 to 16.7 MMBD (as of January 1, 2004). In early April
2004, utilization of operating capacity at U.S. refineries was averaging around 88%-89%.
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.

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 U.S. policy
to establish a petroleum reserve of up to 1 billion barrels. In order to store the reserve oil,
the U.S. government in April 1977 acquired several salt caverns along the Gulf of Mexico
coastline. The first crude oil was delivered to the SPR on July 21, 1977, and stored at the
West Hackberry storage site near Lake Charles, LA. Other major storage sites include:
Bryan Mound and Big Hill in Texas and Bayou Choctaw in Louisiana, with a total storage
capacity of 700 million barrels.

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 April 9, 2004, the SPR contained around 653 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.

NATURAL GAS

As of January 1, 2004, the United States had estimated proven natural gas reserves of
187 trillion cubic feet (Tcf), or 3.1% of world reserves (6th in the world). For 2003, U.S.
production of dry natural gas is estimated at 19.1 Tcf. Natural gas consumption is
estimated at 21.9 Tcf, with gross imports of 3.8 Tcf. Around 87% of U.S. natural gas
imports come from Canada, mainly the western provinces of Alberta, British Columbia, and
Saskatchewan. Overall, the United States depends on natural gas for about 23% of its
total primary energy requirements (oil accounts for around 40% and coal for 23%).

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. As of April 2, 2004, natural gas
inventories in the Lower-48 states were about 5.7% (63 Bcf) below the 5-year average of
1,097 Bcf, but 50% higher than one year earlier. Working gas stocks hit their low point on
March 14, 2003, at 50% below the 5-year average.

On June 10, 2003, Federal Reserve Chairman Alan Greenspan noted that rising natural
gas prices in the United States could have a negative impact on the economy in the
months ahead if prices remain at high levels. Greenspan stated, "I have no doubt that...if
we stay at these very elevated prices we're going to see some erosion in a number of
macroeconomic variables which are not evident at this stage. A very significant amount of
natural gas using infrastructure in the American economy was based on $2 [per mcf] gas.
That means a lot of noncompetitive structures are sitting out there." Greenspan
emphasized the need for greater imports of liquefied natural gas (LNG) in order to boost
domestic supplies and keep prices under control.

For all of 2003, the average natural gas wellhead price averaged $4.98 per mcf, up from
$2.96 per mcf in 2002. An average natural gas wellhead price of about $5.03 per mcf is
projected for 2004, assuming modest growth in domestic production.

Natural Gas Production and Storage

Dry natural gas production is expected to increase by about 1.2% in 2004, to 19.31 Tcf,
from 19.08 Tcf in 2003. High natural gas prices resulted in strong natural gas-directed
drilling activity during 2003, following the downturn in 2002. Natural gas production is
expected to continue to rise slightly through 2005 as natural gas well completions, which
totaled an estimated 20,000 in 2003, continue to grow to between 22,000 and 23,000 wells
per year over the next 2 years.

Strong increases in U.S. natural gas production and net imports are needed over the next
two decades to meet demand. 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
million 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 resources. Alaska's Governor Tony Knowles has stated that he supports a $17.2
billion natural gas pipeline running from the North Slope along the Alaska Highway into
Alberta and on to markets in the U.S. Midwest (another option would be to route the
pipeline via the MacKenzie Delta in northern Canada).

In the near term, 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.

The Rocky Mountain area is projected to have the largest estimated surplus capacity in
2003 at 1.4 Bcf/d followed by Texas with 1.3 Bcf/d, New Mexico at 0.5 Bcf/d, and Oklahoma
at 0.4 Bcf/d. Estimated surplus capacity in the rest of the Lower-48 States and Gulf of
Mexico is roughly 2.0 Bcf/d. While the Lower-48 States taken together are likely to have a
small surplus or unutilized capacity, specific areas may have little or none. Because of the
limitations in the transportation network, surplus capacity in one area may not be available
to all other areas.

In 2003, Gulf of Mexico production are expected to be limited by effective productive
capacity. Lower drilling rates in the Gulf are the cause of the expected loss of surplus
effective capacity. However, deep water prospects now being developed appear to
produce at higher rates than completions in the recent past. Future completions in the
study are modeled after recent past completions. Therefore, if the new wells are sufficiently
more productive, some of the declining capacity could be alleviated. Adding to pipeline
infrastructure could also increase effective productive capacity in the Gulf.

Natural Gas Demand

From 1990 through 2003, natural gas consumption in the United States increased by
about 14%, although consumption fell 5% during 2003 in large part as a result of high gas
prices. Still, growth in U.S. natural gas demand is likely in coming years along with
economic growth, and also as gas prices level off. 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. An expanding transmission and
distribution network have also helped expand its acceptance and use. Natural gas is
consumed in the United States mainly in the industrial (34%), electric power (24%),
residential (21%), and commercial (14%) sectors.

U.S. natural gas consumption and imports, overwhelmingly from Canada -- and to a far
lesser extent from Trinidad, Algeria, Qatar, and others in the form of LNG -- 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.

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 billion cubic feet per day (Bcf/d) 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.

Despite a national economic slowdown and a 4.9% drop in overall U.S. natural gas
consumption in 2001, more than 3,571 miles of pipeline and a record 12.8 Bcf/d of natural
gas pipeline capacity were added to the national pipeline network during 2002. Five major
new natural gas pipeline systems were completed and placed in operation during 2002.
They were: Gulfstream Pipeline, 1,130 MMcf/d–560 miles, which carries natural gas under
the Gulf of Mexico from gas-processing facilities located on the gulf coasts of the States of
Mississippi and Alabama to west central Florida; North Baja Pipeline, 500 MMcf/d–80 miles
(in U.S.), which exports gas to electric power plants located in Baja California, Mexico;
Questar Southern Trails Pipeline, 87 MMcf/d–405 miles, which transports gas from the four
corners area of New Mexico/Utah (San Juan Basin) to the California/Arizona border area;
and the Guardian, 750 MMcf/d–142 miles, and Horizon, 380 MMcf/d—29 miles, pipelines,
which expanded the flow of gas supplies between the Chicago (Illinois) hub and the
growing market of northern Illinois and southern Wisconsin.

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 MMcf/d of natural
gas, 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. Though the pipeline won FERC
endorsement in 2002, the New York Department of Environmental Conservation found that
Millennium's proposed crossing of the Hudson River at Haverstraw Bay was not consistent
with the Coastal Zone Management Act (CZMA) and, accordingly, denied the pipeline a
state permit. In response, in June 2003 the Millennium group filed an appeal with the U.S.
Department of Commerce. This appeal, however, was rejected on December 15, 2003.
The Millennium group still remains hopeful that it can find an amenable alternative route.

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, the Pacific Northwest and
California, which depend on Canadian natural gas for significant amounts of their supply.
Overall, the United States received about 4.0 Tcf of natural gas (gross) from Canada
during 2002, the same 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. 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 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.

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, for instance, could carry as much as 1.9 Bcf/d of gas from Canada's far
north to southern Canada and the United States, possibly beginning in 2008. However,
Canada is consuming increasing volumes of gas itself for such activities as oil sands
extraction and processing. So, the assumption that imported natural gas from Canada
might be the answer to U.S. gas needs in coming years may not prove to be correct. A
competing pipeline would transport natural gas from Alaska's North Slope to the lower-48
states, with possible capacity as high as 4-5 Bcf/d, and potentially beginning sometime
around 2012.

On October 12, 2001, the U.S. Coast Guard lifted a ban on LNG tankers from Boston
harbor. The ban, in effect starting September 26, 2001 (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 four currently active LNG
facilities in the United States (plus one in Puerto Rico). The other three active U.S. LNG
facilities are located in Lake Charles, Louisiana; Elba Island, Georgia; and Cove Point,
Maryland, which received its first commercial LNG cargo in 23 years in August 2003. Cove
Point is now the nation's largest LNG import facility, and a new 2.5-Bcf storage tank is
scheduled to be added in January 2005 by its owner, Dominion. Expansion is also planned
for the Lake Charles and Elba Island LNG facilities.

All in all, 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 sharply beginning in 2007, growing to 2.2 Tcf in 2010 and 4.8 Tcf in 2025.
During 2003, the United States received about 507 Bcf of LNG, mainly from Trinidad and
Tobago, Algeria, and Qatar.

Currently, there are around two dozen LNG terminals on the drawing board to serve North
America (mainly the United States), including the Sempra Energy Cameron LNG project in
Hackenberry, LA, approved in September 2003 by the Federal Energy Regulatory
Commission (FERC). Sempra's LNG terminal marks the first new LNG plant granted
approval in the United States in 25 years. Besides the Hackenberry facility, Sempra signed
a deal with BP in December 2003 to supply Indonesian LNG to a proposed receiving
terminal in Baja California. The gas would then be piped to U.S. West Coast markets. Also
in December 2003, Shell announced plans to build a $700 million LNG receiving terminal,
called Gulf Landing, 38 miles off the coast of Louisiana. The project is slated to handle 1
Bcf/d of LNG starting in 2008 or 2009. Also, ChevronTexaco is planning an offshore LNG
receiving terminal called Port Pelican, 40 miles off the Louisiana coast, and ExxonMobil
may build a $600 million facility near Port Arthur, Texas.

In December 2003, EIA issued a report, "The Global Liquefied Natural Gas Market: Status
and Outlook, in conjunction with a Department of Energy LNG summit. At the summit,
Energy Secretary Spencer Abraham pledged to make the process of licensing and building
LNG receiving terminals easier than it is now. In March 2004, an agreement between
FERC, the Coast Guard, and the Department of Transportation aims at streamlining the
process regarding environmental, safety, and security reviews of proposed LNG projects.

COAL

The United States produced 1,069 million short tons (Mmst) of coal in 2003, down 2.3%
from 1,094 Mmst in 2002. Also in 2003, the United States consumed 1,090 Mmst (up 2.3%
from 1,066 Mmst in 2002). Led by Wyoming (376 Mmst of production in 2003), the West is
the leading U.S. coal-producing region, with about half of the U.S. total, overwhelmingly
from surface mines. Appalachia (led by West Virginia and Kentucky) accounts for about
35% of total U.S. coal production, mainly from underground mines. 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.

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 coke plants and "other industrial" taking nearly all the rest. In
coming years, as sulfur dioxide emissions standards are tightened (in 2000, for instance,
Phase 2 of the Clean Air Act Amendments -- CAAA -- took effect), the share of low-sulfur
coal (mainly from the western U.S.) in the country's coal consumption mix is expected to
increase. In 2002, production of medium- and high-sulfur coal was 578 Mmst (52%), while
low-sulfur coal output was 527 Mmst (48%). By 2025, medium- and high-sulfur coal is
expected to make up just 43% of total U.S. coal output, with low-sulfur coal accounting for
57% of the total.

U.S. gross coal exports fell sharply starting in the mid-1990s 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 2002, the
United States exported 40 Mmst of coal, down from 108 Mmst of exports in 1991. In 2003,
U.S. coal exports increased slightly, to 43 Mmst, of which nearly half went to Canada. In
coming years, 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. U.S. gross coal imports are estimated at 25.0 Mmst in 2003, up
48% from 16.9 Mmst in 2002. The continued rise in U.S. gross coal imports is partly
attributable to heightened demand for low-sulfur coal, and in part to the need to meet
stricter sulfur emission requirements of Phase II of the CAAA.

During 2004, coal production is expected to rise slightly in Appalachia, fall slightly in the U.
S. Interior, and increase strongly 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 CAAA (1990). 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.

There were several issues that had an impact on coal production in 2003. Some of them
were minor and had temporary effects (weather and transportation), while some were
major and could affect the coal industry well into the future (legal and financial). Among the
minor issues were weather (rain or the lack thereof), transportation bottlenecks, and a one-
day disruption in the electric power grid. The weather played a part in some of the
transportation bottlenecks. The lack of rain lead to low water levels in the river
transportation system, in particular on the Mississippi River in January and again in
August, which resulted in delayed coal barge shipments. There were severe rains in the
Powder River Basin in June that impacted both coal production (causing some mine pit
flooding and collapsing highwalls) and transportation (delays in train deliveries). Rail
congestion problems continued to occur periodically in some States in the Western Region
during the year. In August of 2003, there was an electricity blackout that affected over 50
million customers in the northeast U.S. and portions of Canada.

On January 29, 2003, 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.

Besides the valley fill issue, there were other legal challenges to the coal industry in 2003.
A new lawsuit was filed over the level of environmental review needed in the permitting
system as well as new challenges to the New Source Review program requirements for
power plants. A coalition of environmental groups filed a lawsuit stating that all applications
for permits should get full environmental review, while a coalition of several States and
local governments sued the Environmental Protection Agency (EPA) to block the
implementation of the new rule published at the end of October.

Bankruptcies continued to exert their influence on the coal industry as several producers
and a few consumers were still trying to emerge from Chapter 11 during the year and
another mid-sized coal company filed for bankruptcy protection in 2003 as it tried to realign
its finances. The year also saw the continuing effort of several companies trying to exit the
coal business by selling their mining interests to other parties. Adverse geological
conditions and equipment problems continue to trouble some mining operations in both the
Appalachian and Western Regions, while underground fires in Appalachia caused some
mining operations to temporarily suspend production during 2003.

ELECTRICITY

In 2003, the United States generated 3,848 billion kilowatthours (Kwh) of electricity,
including 3,691 billion Kwh from the electric power sector plus an additional 157 billion Kwh
coming from combined heat and power (CHP) facilities in the commercial and industrial
sectors. For the electric power sector, coal-fired plants accounted for 53% of generation,
nuclear 21%, natural gas 15%, hydroelectricity 7%, oil 3%, geothermal and "other" 1%.

Natural gas-fired power generation has greatly increased its share of the U.S. power mix
over the past few years, from just 9% in 1988 to 18% in 2002, although it fell back in 2003,
to 16%, due in large part to higher gas prices during 2003. Investment in coal-fired power
generation generally has been less attractive than natural gas in recent years due to
relatively high capital costs and longer construction periods. As a result, coal's share in the
U.S. power mix has fallen from 57% in 1988 to 51% in 2003. The share of nuclear power
generation in the U.S. power mix has remained relatively flat over the past 15 years or so,
increasing slightly from 19% in 1988 to 20% in 2003. Oil's share has fallen from 5% in
1988 to 3% in 2003.

On a national level, the average retail price of electricity during the first eleven months of
2003 averaged 7.43 cents per Kwh, up 3% from 7.21 cents per Kwh in 2002 and up 1.5%
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, 2001, and 2003.

As of 2002, U.S. net summer electric generating capacity was 905 gigawatts (GW). Of this
total, 76% was thermal (35% coal, 19% natural gas, 18% "dual-fired," 4% petroleum), 11%
hydro, 11% nuclear, and 2% "other renewables" (geothermal, solar, wind). The amount
and geographical distribution of capacity by energy source is a function of, among other
things, 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 U.S. annual electricity demand grew only slightly -- about 0.8% -- during 2003. For
2004, electricity demand is expected to increase about 2% from 2003 levels, driven by
accelerated growth in the economy and weather-related increases in the first and the
fourth quarters.

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 billion Kwh 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.

On August 14, 2003, a huge electric power blackout hits large parts of the northeastern
United States, the Midwest, and southern Canada late in the afternoon. Power was
knocked out for at least several hours in major cities like New York, Detroit, Cleveland, and
Toronto. President Bush called the blackout a "wake-up call" and promised, "we will figure
out what went wrong and we will address it." On August 19, U.S. Energy Secretary Spencer
Abraham said that his agency would head up a sweeping investigation into what caused
the blackout, adding, "The electric transmission grid is quite possibly the most vital piece of
infrastructure we have." On September 3, the House of Representative’s Energy and
Commerce Committee launched an investigation into what caused the power to go out.

Nuclear

In 2003, U.S. nuclear power generation was 766 billion kWh, or about 20% of total U.S.
electricity generation, second only to coal in the U.S. electricity generation mix. Nearly
40% of U.S. nuclear output was generated in just five states: Illinois, Pennsylvania, South
Carolina, North Carolina, and New York. The average capacity factor for all nuclear units
nationwide increased from 88.1% in 2000 to over 90% in 2002, an all-time record high
utilization rate. For 2003, the nuclear capacity utilization rate fell slightly, to 89%. Following
the September 11, 2001 terrorist attacks on the United States, security at nuclear power
plants around the United States was increased dramatically.

Annual nuclear generation in the United States dropped from 780 billion kWh in 2002 to
766 billion kWh in 2003. Possible explanations for the decline are still under study, but part
of the decline could have come from the fact that several nuclear plants were shut down
for 3-8 days during the Northeast power outage in August 2003.

Nuclear power in the United States grew rapidly after 1973, when only 83 billion kWh of
nuclear power was produced. As of 2003, nuclear power output 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 (on
December 2, 2003, President Bush signed a $27.3 billion energy and water bill that
included funding for the Yucca Mountain facility).   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. The
repository also remains a source of controversy between state and federal officials. In
February 2002, Nevada Governor Kenny Guinn indicated that he would oppose the
project, making congressional approval necessary for Yucca Mountain to go forward. The
site's selection is also being challenged in Federal Appeals court by the state of Nevada.
Overall, the project is expected to cost $40 to $50 billion and be able to store 77,000 tons
of radioactive waste.

Hydroelectricity / Other "Renewables"

The United States consumed 6.1 quadrillion Btu of renewable energy in 2003, about 6% of
total domestic gross energy demand, with the largest component used for electricity
production. As of February 2003, eleven states had adopted renewables portfolio
standards (RPS) aimed at increasing the share of renewable power in the energy mix.
Several other states are considering adoption of an RPS, while others with RPS already in
place are looking to accelerate renewables development even faster. Growth in renewable
energy continues to be challenged by little or no development of new hydroelectric sites, a
slow but lengthy decline in the use of biomass for non-electric purposes, and the high
capital costs of most renewable energy production facilities, compared with fossil-fueled
alternatives.

Overall, hydropower made up around 45% of total U.S. renewable consumption in 2003,
with biofuels (including wood and waste), solar, wind, and geothermal making up most of
the remainder. Total hydropower generation rose by around 4% during 2003 compared to
2002, and 27% compared to 2001, a bad drought year. In 2003, about 61% of U.S.
hydroelectric output was supplied by just four states: Washington, California, and Oregon
on the Pacific coast, plus New York. For 2004, total hydropower generation is expected to
rise by 10% compared to 2003.

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 2002, shipments of solar PV cells and
modules expanded by 15%, to around 112 megawatts, according to EIA's Renewable
Energy Annual 2002. The average unit price of PV cells decreased in 2002 by 14%, to
$2.12 per peak megawatt. Solar thermal collector manufacturing rose modestly in 2002,
consistent with the general pattern seen since 1992 (except for a sharp rise between 2000
and 2001). Total shipments of solar thermal collectors rose 4%, to 11.7 million square feet.

In 2003, 1,687 MW of wind power capacity was added in the United States, pushing the
total to 6,374 MW, a 36% increase from 2002. This growth, while rapid, was slightly slower
than the record growth of 1,694 MW seen in 2001, according to the American Wind Energy
Association (AWEA). Fluctuations in wind power capacity additions stem in part from the
uncertain status of a key federal wind Production Tax Credit, or PTC, first established in
1992. The PTC expired on December 31, 2003, with its renewal status tied up with the
overall energy bill, now stalled in Congress. The PTC, among other factors, has helped
boost total U.S. installed wind generating capacity from 1,584 MW in 1992, with wind
turbines now located in 26 states. The AWEA estimates that by 2020, wind power could
supply at least 6% of U.S. electric power needs. California, Texas, Minnesota, and Iowa
currently are the top four states in terms of installed wind power capacity, while the largest
wind farm is located on the Oregon-Washington state line.

The first U.S. offshore windmill park, with a total capacity of 420 MW, has been proposed
for construction off the Cape Cod coast. 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 reaching at least 1,000 MW in
renewable power capacity by 2010.

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 U.S. emissions of carbon dioxide will reach 5,985 million
metric tons in 2005, an increase of 1,083 million metric tons from the 4,902 million metric
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 U.S.
delegation agreed to reduce U.S. 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, 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 March 27, 2001, the Bush administration declared that the United States had "no
interest" in implementing or ratifying the Kyoto treaty limiting greenhouse gas emissions,
but that it would pursue other ways of addressing the climate change issue. On April 12,
2001, 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. 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. On April 2,
2004, the Energy Department agreed to require new central air conditioners and heat
pumps to be 30% more efficient beginning in 2006. The Energy Department had attempted
to set the standard, lower, at 20%, but a January 2004 court ruling prevented the
Department from doing so.

ECONOMIC OVERVIEW

Currency: Dollar ($) Exchange Rates, per Dollar (4/21/2004):
British Pound (0.55957);
Canadian Dollar (1.3571);
Euro (0.84303);
Japanese Yen (108.68)

Gross Domestic Product (GDP) (2003E): $11.0 trillion

Real GDP Growth Rate:
(2002E): 2.2%
(2003E): 3.1%
(2004F): 4.7%

Inflation Rate (consumer price index)
(2002E): 1.6%
(2003E): 2.3%
(2004F): 1.4%

Unemployment Rate
(2001E): 4.8%
(2002E): 5.8%
(2003E): 6.0%
(3/04E): 5.7%

Current Account Balance
(2001E): -$394 billion
(2002E): -$481 billion
(2003E): -$550 billion

Merchandise Exports
(2002E): $682 billion
(2003E): $714 billion
(2004F): $814 billion

Merchandise Imports
(2002E): $1,165 billion
(2003E): $1,263 billion
(2004F): $1,395 billion

Merchandise Trade Balance
(2002E): -$483 billion
(2003E): -$550 billion
(2004F): -$581 billion

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

Unified Federal Budget Balance
(2002E): -$158 billion
(2003E): -$375 billion
(2004F): -$477 billion

ENERGY OVERVIEW

Secretary of Energy: Spencer Abraham (since January 20, 2001)

Proven Oil Reserves (1/1/04E): 22.7 billion barrels

Oil Production
(2003E): 7.9 million barrels per day (bbl/d), of which 5.7 million bbl/d is crude oil (NOTE:
Including "refinery gain," US oil production in 2003 is estimated at 8.8 million bbl/d)

Oil Consumption
(2003E): 20.0 million bbl/d

Net Oil Imports
(2003E): 11.2 million bbl/d (56.0% of total consumption)

Gross Oil Imports
(2003E): 12.2 million bbl/d (of which, 9.6 million bbl/d was crude oil and 2.6 million bbl/d
were petroleum products)

Crude Oil Imports from the Persian Gulf
(2003E): 2.4 million bbl/d (around 25% of gross U.S. crude oil imports)

Top Sources of U.S. Crude Oil Imports
(2003E): Saudi Arabia (1.72 million bbl/d); Mexico (1.59 million bbl/d); Canada (1.55 million
bbl/d); Venezuela (1.19 million bbl/d)

Value of Gross Oil Imports
(2003E): $132.5 billion (up from $102.7 billion in 2002)

Crude Oil Refining Capacity
(1/1/04E): 16.7 million bbl/d (132 refineries)

Total Oil Stocks
(4/2/04E): 1.57 billion barrels (including about 651 million barrels in the U.S. Strategic
Petroleum Reserve)

Oil Wells Drilled
(2003E): 5,694 (down from 8,060 during 2001)

Operating Oil and Natural Gas Rotary Rigs in Operation
(2/04E): 1,119 (961 for natural gas and 153 for oil)

Natural Gas Reserves
(1/1/03E): 183 trillion cubic feet (Tcf)

Dry Natural Gas Production
(2002E): 19.0 Tcf
(2003E): 19.1 Tcf
(2004F): 19.3 Tcf

Natural Gas Consumption
(2002E): 23.0 Tcf
(2003E): 21.9 Tcf
(2004F): 22.3 Tcf

Gross Natural Gas Imports
(2002E): 4.0 Tcf (94% from Canada)
(2003E): 3.8 Tcf (87% from Canada)

Natural Gas Wells Drilled
(2003E): 20,011 (up from 15,947 in 2002 but down from 22,083 in 2001)

Recoverable Coal Reserves
(12/31/98): 275.1 billion short tons (54% lignite and subbituminous; 46% anthracite and
bituminous)

Coal Production (2002E): 1,094 million short tons (Mmst) (2003E): 1,070 Mmst (2004F):
1,099 Mmst

Coal Consumption
(2002E): 1,066 Mmst (2003E): 1,094 Mmst (2004F): 1,105 Mmst

Gross Coal Exports
(2002E): 40 Mmst (2003E): 43 Mmst (2004F): 44 Mmst

Gross Coal Imports
(2002E): 17 Mmst (2003E): 25 Mmst (2004F): 25 Mmst

Primary and Secondary Coal Stocks (closing; 12/03E): 164 Mmst (compared to 192
Mmst in 12/02)

Electric Net Summer Installed Capacity
(2002E): 905 gigawatts (76% thermal-fired, 11% nuclear; 11% hydroelectric, and 2%
"renewables")

Net Electricity Generation
(2002E): 3,858 bkwh
(2003E): 3,848 bkwh
(2004F): 3,919 bkwh

ENVIRONMENTAL OVERVIEW

Administrator of the U.S. Environmental Protection Agency: Michael Leavitt (since
November 6, 2003; succeeded Christie Todd Whitman)

Total Energy Consumption (2002E): 98.3 quadrillion Btu (2003E): 98.1 quadrillion Btu
(25% of world total energy consumption)

Energy-Related Carbon Dioxide Emissions (2002E): 5,796 million metric tons of
carbon (about 24% of world total carbon emissions)

Per Capita Energy Consumption (2003E): 338 million Btu

Per Capita Carbon Dioxide Emissions (2002E): 20.3 metric tons

Energy Intensity (2003E; nominal): 8,918 Btu

Carbon Dioxide Intensity (2002E; nominal): 0.55 metric tons of carbon dioxide/thousand
dollars

Sectoral Share of Energy Consumption (2003E):
Industrial (33%),
Transportation (27%),
Residential (22%),
Commercial (18%)

Fuel Share of Energy Consumption (2003E):
Oil (40%),
Coal (23%),
Natural Gas (23%),
Nuclear (8%),
Hydroelectricity (3%),
Other "renewables" (3%)

Fuel Share of Carbon Dioxide Emissions (2001E): Oil (44%), Coal (36%), Natural Gas
(20%)

Renewable Energy Consumption (2003E): 6.1 quadrillion Btu (about 45% of which was
conventional hydroelectric power)

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 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; desertification.

Major International 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 are also based on IEA data.

ENERGY INDUSTRY

Major U.S. Oil Companies (2002): ExxonMobil, ChevronTexaco, ConocoPhillips,
Marathon, Amerada Hess, Anadarko, Unocal

Major U.S. Coal Companies (2001): Peabody Coal Sales.; Arch Coal; Kennecott Energy
Co.; Consol Energy; RAG American Coal Holding; Horizon Natural Resources; A.T.
Massey; Vulcan Partners; North American Coal; TXU

Oil Pipelines (2001E): Around 2 million miles Natural Gas Transmission Pipelines
(2000E): 250,000 miles

Major Ports: Baltimore, Chicago, Hampton Roads, Houston, Los Angeles, New Orleans,
New York, Philadelphia

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