Changing The Fuel Mix: Time For A Nuclear Rescue?
September 1, 2002
By Lori A. Burkhart
Gas-fired power is king today, but fuel diversity needs and new technologies may open the door for
nuclear and coal.
The nation's demand for electricity is expected to grow by over 40 percent in the next 20 years,
according to the Energy Information Administration (EIA). Meeting that need will require a great number
of new generating plants. The burning question is, what will fuel these new plants?
Gas-fired plants are the current kings of the industry. EIA in its Annual Energy Outlook 2002 projects
that the share of generation from natural gas will double in the next 20 years, increasing from 16 percent
in 2000 to 32 percent in 2020. At the same time, the share of generation from coal in the United States
is expected to decline from 52 percent to 46 percent, mostly due to more investment in the less capital-
intensive, more efficient natural gas generation technologies. Also, nuclear generation capacity at exis
ting plants has been maxed out.
Yet, nuclear and coal aren't exactly pretenders to the throne. The sleeping nuclear and coal industries
are waking up, not only because of need for new capacity, but also because they've been stirred by higher
natural gas prices, the debacle in the California power market, and the situation in the Middle East.
The renewed call for fuel diversity in light of the need to lower dependence on any one fuel source
could really buoy the coal and nuclear industries. Due to lower coal prices and with the nuclear-friendly
Bush administration in office, things already are getting interesting.
Add to the mix the fact that Congress finally voted for the Yucca Mountain nuclear waste storage
site-which could remove one of the main objections to the building of more nuclear plants-and you have the recipe to begin chipping away at the domination of natural gas as the favored fuel.
For example, the EIA reports that due to improvements in production costs over the past 17 years, exi
sting coal plants now are very economical. Their average production costs-1.8 cents per kWh-make them among the lowest-cost plants operating today. And the numbers could go lower as the average mine-mouth price of coal is projected to decline from $16.45 per ton in 2000 to $12.79 per ton in 2020.
But even if pure cost were the only factor looked at when deciding which type of plant to build, the n
umbers can be difficult to interpret. Year-by-year reduction in coal plant operating costs could stem fro
m: a) improvements in technological efficiency; b) a simple drop in the price of coal; or c) the retirem
ent of older, less efficient plants, leaving a more up-to-date fleet of surviving plants. According to D
ave Kelly, spokesman for the American Nuclear Society, the latest figures available for the average prod
uction cost of electricity powered by various types of plants are from 1999. They are:
- nuclear-1.83 cents/kWh;
- coal-fired-2.07 cents/kWh;
- oil-fired-3.18 cents/kWh; and
- natural gas-fired-3.52 cents/kWh.
So while the nuclear industry and the coal industry appear to vie for the title of "King" of the cheapes
t generating source, the EIA in a November 2001 report on the "Impact of U.S. Nuclear Generation on Greenho
use Gas Emissions," concludes that if nuclear power is to improve its advantages in mitigating greenhouse a
nd other power plant emissions, the industry will have to lower its costs even further. But the report co
ncludes that because few modern nuclear plants have been built, it is not entirely clear what building su
ch plants now costs.
According to EIA, the future is less promising for older oil and gas steam plants. Although their oper
ating costs fell significantly between 1981 and 1997, they remain uneconomical in comparison with coal pl
ants and other new plant options. Also, their total per-kWh operating costs in 1997 are nearly twice tho
se for coal plants. EIA expects their decline in use to continue, as many such units are retired when mo
re efficient natural gas combined-cycle plants displace them.
But does it make sense to invest mainly in natural gas plants? Not only is fuel diversity good for th
e economy and security, but also most experts say even gas-fired and oil-fired plants have proven to be
expensive options as prices have fluctuated and at times soared.
Pebble Bed: A Fading Promise?
There are lessons to be learned from the best intentions, however, as shown by an attempt to revive
the nuclear industry. The power industry was abuzz early in 2001 when a U.S.-based utility, Exelon, to
ok a 12.5 percent stake in the next generation of nuclear technology-a so-called "meltdown proof" plan
t called a pebble-bed modular reactor, slated to be built in South Africa. The technology appeared ideal
because it uses helium gas, instead of water, to cool the uranium fuel, which is packaged in round cylin
ders the size of tennis balls. The technology theoretically prevents meltdowns because the fuel's tempe
rature does not heat to dangerous levels. It is believed that any plant technology that could prevent a
nother Three Mile Island-type situation would go a long way toward reviving the nuclear industry.
Another advantage to the pebble-bed plant is that they are smaller than conventional nuclear plants
, both in terms of size and output. For example, a pebble-bed plant would have output of about 110 megawa
tts, compared to over 1,000 megawatts for a traditional nuclear plant, so it would be less likely to affe
ct the public's psyche negatively, and could be sited in more choice locations. The lack of the large co
oling towers alone would make a nearby plant more palatable to people in the surrounding neighborhoods.
In South Africa, the new pebble bed nuclear plant is headed by British Nuclear Fuels PLC and Industr
ial Development Corp. of South Africa, the state owned electric utility, along with affiliate, ESKOM. Ex
elon planned to build a $300 million demonstration model with ESKOM. At the time, the idea of the new nu
clear plant created enough excitement in the United States that both the Department of Energy (DOE) and
the U.S. Nuclear Regulatory Commission (NRC) sent officials to South Africa to investigate.
The future looked bright for the first time in a long time for the nuclear industry. In fact, in a
January 31, 2001 presentation to NRC staff, Exelon boldly announced it had taken the first steps toward
building a new nuclear plant in the United States. Exelon indicated it wanted to build seven new 110-MW
pebble bed reactors beginning by 2004, but stopped short of stating a final decision had been made.
But suddenly the new future of the nuclear industry crashed and burned-at least in this country. In m
id-April 2001, Exelon dropped out of the project in South Africa. Exelon didn't say much about the depar
ture from the project, just that management decided reactor development would not become part of its cor
e business strategy. But the following week, Exelon chairman and co-CEO Corbin McNeill retired, promptin
g speculation that the changing of the guard fueled the new priorities.
It turns out that Exelon may have been prescient. An international task force studying the feasibili
ty of the pebble bed modular reactor released its report the week after Exelon's withdrawal, finding th
at lack of clarity prevailed on certain technical and financial aspects of the project. Overall, the re
port found it uncertain whether the plant was feasible to build.
A Move Toward Standardization
While the nuclear industry in the United States appeared to have lost its brightest hope, it continu
ed to move toward more improved reactor technologies with standardized designs. According to the Nuclear
Energy Institute (NEI), the advanced nuclear plants contain many features that make them safer and mor
e efficient than currently operating plants. And the standardized designs significantly reduce constr
uction and operating costs.
Three standardized, advanced light-water plant designs have been certified so far by the NRC. In fa
ct, on July 2, the NRC formally accepted an application from Westinghouse Electric Co. for the certifi
cation of an advanced reactor design-the AP1000-that the company believes will be safer to run and che
aper to build. The application was submitted on March 28, but the NRC finally determined in July that
the application contained enough information to be formally processed.
The new AP1000 reactor would be capable of producing 1,100 megawatts of electricity, and is somewh
at similar to the AP600 reactor that the NRC certified in 1999 after a seven-year review. Like the AP6
00, which is a 600-MW design, the new 1,000-MW version of the plant would contain safety features that
are more passive than in existing plants, and so do not require as many pumps and valves.
AThe two other standardized designs approved by the NRC are for larger, 1,350-MW plants. The NRC iss
ued certifications to General Electric and Westinghouse for those plants in 1997. Such plants are not be
ing built in the United States, but are being built in foreign countries.
According to NEI, it is the standardization of nuclear plants that holds the key to the U.S. nuclear
future. NEI says that one of the most important lessons learned in the nuclear industry is that custo
mized designs can create inefficiencies, duplication of efforts, and higher costs. That understanding
brought about the fundamental change and move toward design standardization.
Standardization allows incorporation of the latest technologies, while making the plants easier to
operate and faster to build. Not only does standardization translate into cheaper power; but the pla
nts also will achieve even higher safety ratings than today's nuclear plants, which are mostly one-o
f-a-kind.
But for proof of the benefits of standardization, one must look overseas. To bolster NEI's argument
that standardization lowers costs and leads to greater efficiencies in all aspects of nuclear plant o
peration including safety, maintenance training, and spare parts procurement, it turns to France.
NEI points out that France built 34 standardized 900-MW units and 20 standardized 1,300-MW units ove
r the past two decades, which supply about 75 percent of the electricity to the French. It credits sta
ndardization for cutting construction times significantly. For example, the first reactor in the 900-MW
series took seven years to build, while the last reactor took only five years. NEI adds that because of
standardization, the cost of nuclear power plants in France is among the lowest in the world.
NEI holds out high hopes for the AP600, noting that it will need 50 percent less building volume, 5
0 percent fewer valves, 80 percent fewer pipes, 35 percent fewer large pumps, and 70 percent less cont
rol cable. Also, quick construction would be enhanced because many systems will be assembled in the fac
tory, not on-site, further cutting costs. Finally, the construction timetable for AP600 nuclear plants i
s estimated at three years.
But for now, the United States still is stymied in efforts to construct new nuclear plants. The last
nuclear reactor ordered for a commercial power plant in the United States was in 1978. As Asia adds nu
clear plants, and Finland's parliament in May approved the building of its fifth nuclear plant, the U.S
. going forward is sticking to extending the life of some of its 103 operating nuclear plants, which su
pply 20 percent of the nation's electricity.
Use What You've Got
Many U.S. owners of nuclear plants are finding the best strategy is to apply to renew their operat
ing licenses beyond the original 40-year terms, and also to increase output via use of enhanced technol
ogies.
NRC commissioner Nils J. Diaz addressed the pressure that reactor licensees are under to reduce or c
ontain costs to remain competitive at a meeting of the Southeastern Association of Regulatory Utility Commissioners (SEARUC) in June 2002. He pointed to license fees levied on plant owners by the NRC as a primary example of direct costs, while indirect costs include those cost impacts arising from regulatory actions taken by the NRC. In an effort to make power produced by nuclear plants more affordable, Diaz explained that the NRC has initiated several actions to reduce regulatory burdens and thus cut costs. That includes an initiative to improve its regulatory system, and another initiative to improve NRC's reactor inspection and oversight program.
Rather than building new plants and dealing with the resulting political backlash, nuclear plant ow
ners are instead looking toward increasing the life span of plants already built. Nuclear plant license
renewal streamlining by the NRC also allowed costs to be brought down by enabling the owner to clear t
he licensing process in a reasonable time period, while adding 20 years to the life of the plant. So f
ar, the licenses that have been renewed include the three Oconee units in South Carolina, Arkansas Nuc
lear Unit 1, and Hatch 1 and 2 in Georgia.
Fifteen license renewal applications currently are being processed, including Florida's Turkey Point
3 and 4 and St. Lucie 1 and 2, all in Florida, the Surry and North Anna plants in Virginia, and McGuir
e 1 and 2 and Catawba in North Carolina. The NRC also anticipates processing 20 more applications, som
e for multiple reactors, in the next few years.
Another cost-saving factor for nuclear plants has to do with power uprates, which allows increased
electricity to be produced at an already existing plant. "The NRC has completed over 70 power uprate
reviews for approximately 9,800 megawatts, or an equivalent of three nuclear plants," Diaz said. NRC
staff expects licensees will submit 35 more power uprate requests in the next five years, resulting
in 1,590 megawatts of added capacity. Also, upgrades totaling 20 percent increases in full power to p
lants are under consideration, with one already granted.
Early Site Permits
So it remains to be seen whether brand-new nuclear plants of any technology will be built in the Uni
ted States, notwithstanding issues concerning nuclear waste transportation and storage. Recent activit
y in Congress toward passage of a bill allowing storage of nuclear waste at Yucca Mountain adds to hope
s in the nuclear industry that a main stumbling block will be removed.
Those in the nuclear industry remain optimistic. On April 16 of this year, Entergy, which operates n
ine nuclear units at seven plant sites, announced that it plans to prepare an early site permit at the
Grand Gulf Nuclear Station in Port Gibson, Mississippi, in order to keep the option open for a new ad
vanced nuclear reactor to be built.
"We have not made a decision to start building a new nuclear unit," stressed Randy Hutchinson, a sen
ior vice president of business development at Entergy. But he likes keeping that option open for the sa
ke of customers, the company, and the nation's energy independence. "Almost all new power plants being
built will run on natural gas," he said, "and that puts this country's future supply of electricity at
some risk."
The early site permit process marks the first step in the new, streamlined licensing process impleme
nted by the NRC to reduce the regulatory uncertainty. It allows a company to complete environmental and ot
her site-specific work prior to making a final decision to build. An early site permit, which is valid for
20 years, does not permit construction of a nuclear plant; rather, it allows a company to be prepared in
case the nuclear option gains steam, while engaging in a licensing process that is predictable, timely, a
nd efficient.
Hutchinson said the decision on whether to build a nuclear plant will depend on economic condi
tions in three to five years, based on regional power demand, certification of advanced reactor d
esigns, power prices from competing generation resources, and expected cost of power from a new nu
clear unit.
Early site permit applications also support the Bush administration's Nuclear 2010 program, whi
ch calls for construction of new nuclear plants by that date to reduce American energy dependency f
rom imported natural gas and oil. Under the program, the DOE is offering to share the cost of prepar
ing an early site permit with nuclear power operating companies.
Two other nuclear operating companies, Dominion Resources and Exelon, also have expressed interes
t in seeking early site permits at their existing sites. According to Richard Zuercher, a spokesman f
or Dominion Energy, the company has told the NRC it plans to file an early site permit application i
n the fall of 2003 for its North Anna nuclear plant site in Louisa County, Va. "We're putting the appli
cation together, but that's it right now," Zuercher said. But there is room-the North Anna site holds t
wo reactors, but originally was designed for four.
Exelon Generation selected its Clinton nuclear plant in Illinois as the site where it would put a ne
w reactor. It chose the Clinton site because it, too, originally was scheduled for more than the one re
actor it now holds.
The suppliers already are jockeying for position, should an order be placed for a nuclear plant. Ro
ger Gale, a partner in GF Energy who represents Canada-based AECL Technologies, is touting AECL's next
generation CANDU reactor, the ACR-700. The ACR-700's features, such as the steam and turbine generat
or systems, are similar to those in pressurized water reactors. But its design makes it less expensiv
e to build. Gale points out that the ACR-700 is the first reactor to be sold at a fixed price-install
ed for $1,000/kW for two 700-MW units. He compares that to General Electric's Advanced Boiling Water
Reactor (ABWR), which costs about $1,400/kW, while the AP1000 would be priced at between $1,200 to $1,
400/kW.
Gale says the key is being competitive to gas. He estimates a price of $2,010/kW to build a gas-fir
ed plant. "If the price of gas is low, no one will build a nuclear plant-end of story," Gale concludes
. "But if the price of gas is at $3.50 in 2010 or higher, then a 1,000-megawatt nuclear plant can make
it."
Gale points out that the ACR-700 is in competition with the AP1000 for British Energy's planned re
placements of all 14 of their reactors in the United Kingdom. "Take this with a bit of bias if you wan
t," Gale said, "but there are really three contenders for the next generation nuclear plant-if there is
a next generation, which is a whole other issue." Gale adds that pebble bed is "going away," although
it may become possible to build over the next 20 years. But at present he believes that the ABWR, the
AP1000, and the ACR-700 are most likely to be built.
In fact, AECL has contacted the three companies filing the early site permits, and Exelon, which w
ill file its application at the NRC in June 2003, will include the ACR-700 as a contender in its perm
it package. Dominion also has confirmed they will include it, and while AECL expects Entergy also will,
the negotiations are continuing. Gale explained the companies all will file at the NRC using a plant pa
rameter envelope (PPE), which characterizes all the variables of the units, such as size and water dema
nds. The companies will include a group of reactors that all fit within that envelope. PPE was develop
ed along with NEI and the Electric Power Research Institute, and is in Excel spreadsheet form as a st
ep toward fitting plants within certain conventions.
Plant Construction Downturn
Although the need for electricity is proven, will enough plants be built? The generating plant cons
truction industry is suffering at present from a downturn. The U.S General Accounting Office (GAO) in
late June released a report examining the addition of generating plants in states that have embraced re
tail competition. Concerns have been raised that in restructured states, where decisions on new power p
lants are left now to independent developers, rather than decided by utilities and state regulators, th
e result may be a lack of generation capacity. The report focused on Pennsylvania, Texas, and Californi
a. But recently, because of the national economic slowdown, the September 11 terrorist attacks, and col
lapse of Enron, GAO said that developers have canceled or postponed 23,000 of the 68,000 megawatts of p
roposed capacity not yet under construction in those three states alone.1
Two companies that keep track of power plant construction agree the industry overall is experienci
ng a slump. According to Industrial Information Resources, Inc. of Houston, while developers of new po
wer plants take a cautious approach to new plant construction beyond 2003, the industry will still have
more capacity added in 2002 than last year. In 2001, new power units coming online accounted for over
44,000 megawatts of capacity. Brit Burt, manager of power for Industrialinfo.com says, "In comparison
, we have identified new units, at grassroot and existing plants, with a total capacity of over 58,000
megawatts, scheduled to come online before the end of 2002." Burt adds that "the most active U.S. NE
RC regions for adding new capacity in 2002 include the Southeastern U.S. (SERC) with almost 13,000 m
egawatts, the Western U.S. (WSCC) with over 7,000 megawatts, and the Northeast (NPCC) with just over
6,000 megawatts." He explained that many states in those regions are adding new capacity to address pro
jected energy shortfalls, some are replacing older inefficient units, and others have opened generati
on to competition. Also, almost 70 percent of capacity coming online are fueled by natural gas combi
ned-cycle plants.
But Burt points to signs of a slowing industry that began in the summer of 2001. "Since June 2001,
research conducted by Industrialinfo.com has identified over eight hundred power units at 275 new an
d existing plants that have been canceled or delayed." He says it represents 114,254 megawatts of cap
acity that was scheduled for completion through 2010. Mirant, Reliant, NRG Energy, and Calpine are s
ome of the major developers to announce delays or cancellations. "Many experts agree that a great num
ber of these units will be required over the next two decades to replace capacity from units schedule
d for retirement and to meet the projected growth in electricity demand," he says.
On July 11, 2002, Energy Venture Analysis, Inc. (EVA) of Arlington, Virginia, selected by the Nort
h American Electric Reliability Council (NERC) to help track construction, released a report, "Tracki
ng the Boom of New Power Plants in the U.S.," which finds the plant construction industry in the midst
of a downturn. The report finds the industry in a "bust" cycle, despite construction or development i
n the second quarter of 2002 of a total of 241,000 megawatts of new gas-fired capacity, with 7,000 m
egawatts that began operating in that same quarter. Over the 1998 to 2007 time period, 335,000 megaw
atts of capacity either began operating or will be under development.
EVA found that further cancellations and/or delays will occur as the year advances, so that only
294,000 megawatts of the industry's planned capacity will be built. "The bust phase has, to date, mai
nly affected the long lead time activities such as engineering services and turbine orders," said Mic
hael Schall, EVA senior analyst. But he added that "the level of construction activity can be expecte
d to decline significantly over the next several quarters, as projects currently under construction a
re completed at a faster rate than ground is broken at new sites."
Lori A. Burkhart is a contributing legal editor for Public Utilities Fortnightly.
- Restructured Electricity Markets, Three States' Experience in Adding Generating Capacity, May 20
02., available on the GAO's Web site, http://www.gao.gov.
Here Comes Coal It's cheap and it's abundant, but can it overcome the environmental hurdles?
Despite bad press over dirty emissions, coal is not easy to dismiss in the energy planning mix, s
ince it supplies over 50 percent of the nation's electricity. An expected increase in demand for electr
icity, combined with little baseload generating plant added in the last twenty years, finds the power in
dustry looking with renewed interest toward coal-based generation. Bolstered by advances in technology t
hat reduce emissions, and by the Bush administration's energy plan that includes $2 billion for clean co
al research over the next 20 years, coal is making inroads in the planning process.
But while coal-fired plants operate at relatively low costs, they tend to be older plants. It rema
ins to be seen whether the costs of technologies aimed at reducing emissions will make coal-fired pla
nts less competitive. The Environmental Protection Agency reports that electricity from coal has made
enormous environmental progress in recent years. Through more than $50 billion in investments over t
he last three decades, emissions from coal-fired plants have declined by over 20 percent, even as co
al use has tripled, it said.
Fuel-Neutral Energy Policy?
One believer in the future of coal is Peabody Energy, the world's largest private sector coal co
mpany. Peabody already has in place plans to build two pulverized coal plants. The Prairie State En
ergy Campus will be a 1,500-MW baseload coal-fired plant in Washington County, Illinois and is locate
d at an adjacent underground mine. It is expected to come on-line in 2006 or 2007. The Thoroughbred En
ergy Campus will be a 1,500-MW coal-fueled plant near Central City in Kentucky, and like Prairie Stat
e will be a mine-mouth plant. It is expected to come online between 2005 and 2007.
Peabody Energy boasts that the Prairie State and Thoroughbred Energy plants both will be equipped
with advanced generation and emission controls in order to burn the areas' higher sulfur coals. Desu
lferization technology is projected to remove about 97 percent of the plants' sulfur dioxide emissions
using a wet limestone system. Low nitrogen oxide (NOx) combustion technologies and selective catalytic
reduction significantly will cut NOx emissions by 75 percent. And advanced fabric filtration and c
ontrol devices are expected to remove 99 percent of particulate matter.
But despite such advances, Peabody Energy believes it possible that there exists a bias against coal. Pollution concerns have led to the domination of gas-fired projects in the new plant construction market in recent years. That is precisely the allegation made by Peabody Energy's subsidiary, Prairie State Generating Co., in a filing at the Federal Energy Regulatory Commission (FERC) over the proposed plant interconnection agreement with Illinois Power. Prairie State asked whether FERC's policy still is fuel-neutral. (Docket No. ER02-1400-00 filed Mar. 28, 2002, protest filed Apr.18, 2002.)
"The FERC's articulated standard interconnection polices have been skewed in favor of the needs of these smaller natural gas-fired generators and not the needs of new baseload generation that would satisfy the needs for abundant, low-cost electricity," Prairie State argues. "It is a disservice to national energy policy and its pronounced goals to create disincentives to large-scale coal-fueled generation projects," it adds.
On May 15, FERC accepted the unexecuted interconnection agreement, subject to refund. Chairman Pat Wood suggested that FERC might well make some changes in its pending generation interconnection docket to ensure that such agreements for generating plants remain "fuel-neutral," and do not discriminate in favor of gas turbines and against traditional, base-load coal boilers.
"We need coal," he added. "As we are striving to remove barriers to gas-fired generation, it is important we do it for coal-fired generation too," Wood said.
"This order comes out fine," he added, "but we want to make sure we fix it in the broad picture and rulemaking." Commissioner Linda K. Breathitt, who is from Kentucky, agreed. "Coal is such a huge part of our economy," she said.
Peabody Energy appears unique in that it is moving forward with larger plants, while most coal-fired plants planned or under construction are much smaller. For example, Bloomington, Illinois-based Corn Belt Energy Corp. plans to build a 91-MW coal-fired, mine-mouth plant at a cost of $137 million. And the Tennessee Valley Authority is preparing an environmental impact statement for PickWick Power LLC's proposed 100-MW coal-fired plant it wants to build and operate in Tennessee.
Wisconsin Company Objects
Wisconsin Energy recently has come under fire for a proposal to build three 600-MW, coal-fueled units at its Oak Creek Power plant site. The three plants are part of a 2,800-megawatt project, including two 500-MW natural gas fired plants that the utility's CEO is touting as "the largest building project in the history of Wisconsin." Wisconsin Energy, in its filing for building permits, said that constructing the coal-fired units will save customers $1 billion over the life of the units when compared to "natural gas only" plants.
But S.C. Johnson & Son, Inc. is raising strong objections to the coal plants, arguing they would add to pollution in Racine County, where the company is located. Racine County has been listed as a "severe" non-attainment area under 1990 amendments to the federal Clean Air Act due to high ozone levels. The jury is out as to whether the utility company will prevail.
But as a practical matter, if coal plants, or any plants for that matter, are to be built, cost is a main consideration. According to EIA, where once coal-fired generating plants produced power at average price of over 3.5 cents per kWh, total production costs for coal-fired plants now average less than 1.8 cents per kWh. EIA attributes that drop primarily to declining fuel costs. Between 1981 and 1997, EIA reports that mine-mouth coal prices declined by 60 percent, from $45 per short ton ($2.12 per million Btu) in 1981 to $18 per short ton ($0.88 per million Btu) in 1997. That decline continues to $16.45 per ton in 2000 and a projected $12.70 per ton in 2020. It represents a shift from eastern subsurface mines to western surface mines, as well as a rapid increase in mining productivity in all types of mines. Over the same period, the delivered price of coal to electric power plants fell from $2.61 to $1.27 per million Btu. But other factors, such as increased utilization, reductions in nonfuel expenditures, and fewer employees per plant also played a role in price declines, EIA said.
Meanwhile, EIA said that world oil prices remained relatively high in 2001 due to actions by OPEC and non-OPEC countries to restrain oil production. U.S. natural gas prices hit record levels in 2001, due to a cold winter and tight supplies caused by reduced drilling in response to low prices in 1998 and 1999. Those numbers could open the door for other fuels.
-L.A.B.
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