[Economic Report of the President (2006)]
[Administration of George W. Bush]
[Online through the Government Printing Office, www.gpo.gov]

 
CHAPTER 11


Recent Developments in Energy


Energy is essential to the U.S. economy. It provides light and heat
for our homes and businesses, brings our computers and appliances
to life, and powers life-saving medical devices. It propels the
automobiles, buses, and trains that carry us to home, work, and
school, and the aircraft that fly us from city to city. It fuels
the tractors that harvest our food, the machines we use to turn
raw materials into final products, and the trucks, trains,
and ships that carry these goods across our Nation and around the
world. All told, the United States spent about $870 billion on
energy in 2004, an amount equivalent to 7.4 percent of GDP, and
was on pace to spend an estimated $1.1 trillion on energy in 2005,
or about 8.6 percent of GDP.


Over the past several decades, the U.S. economy has seen a steady
decline in its energy intensity-that is, the ratio of total physical
units of energy consumed per dollar of real GDP. Nonetheless,
households and businesses remain keenly aware of the prices they
pay for energy products and the impact of rising energy prices on
their budgets and bottom lines. When prices change gradually,
households and businesses have time to adapt their energy consumption
levels, fuel choices, and purchases of energy-using products to new
price levels. Sometimes, however, disruptions to our energy
production and distribution infrastructure, such as those caused by
the recent hurricanes Katrina and Rita, result in temporary but sharp
price increases to which households and businesses cannot adjust
quickly.
This chapter discusses energy markets-systems that connect
consumers and suppliers of energy products, where prices are
determined by what buyers will pay and what sellers will accept.
The chapter reviews recent developments in energy markets for crude
oil, refined petroleum products, and natural gas, as well as recent
developments in the electricity-generation sector. It considers
these developments in the context of historical experience, and
offers an economic perspective on energy market, policy, and
technological innovations that benefit the Nation.
The key points in this chapter are:
 Crude oil prices have risen steadily over the past several
years due to growing world demand, leading to rising prices for
gasoline and other refined petroleum products and stimulating
further development of alternative energy sources. Recent price
increases have occurred more gradually than in the past.
 Disruptions to energy supply and distribution networks can
lead to sharp short-term price increases. Recent hurricanes Katrina
and Rita demonstrate that competitive markets connecting energy
producers, distributors, and consumers play a central role in
encouraging conservation and allocating scarce energy resources,
especially during times of natural disaster or national emergency.
 The continued expansion of natural gas and other energy
markets through regional and global trade can improve our economic
security by increasing access to low-cost energy resources and
mitigating the impacts of local energy shortages and price
increases. Innovative market instruments designed to insure against
market volatility can also help lessen these impacts.
 Absent policy, individual energy market participants may
not have an incentive to tackle certain problems associated with
their energy production and consumption. Carefully targeted
policies that reduce U.S. vulnerability to energy disruptions,
encourage energy efficiency, and protect the environment can
therefore be beneficial supplements to markets. These policies can
be made more effective and less costly when designed based on
economic incentives.
The first section below provides an overview of U.S. energy
sources and uses. The second section discusses the world market for
crude oil. The third section examines markets for refined petroleum
products, including the impact of crude oil prices on refined
product prices. The fourth section considers the expansion of
natural gas markets from limited geographic regions to a more global
level. The fifth section describes challenges and recent changes in
the electricity-generation sector, and the final section concludes
with a look toward the future.


Energy Sources and Uses


One British thermal unit (Btu) is the amount of energy required
to raise the temperature of one pound of water one degree Fahrenheit.
The United States used approximately 100 quadrillion Btu of energy
in 2004 (see Table 11-1)-the energy equivalent of about 17 billion
barrels of oil or 60 barrels of oil per person. Eighty-six percent
of this energy came from fossil fuels, including 40 percent from
petroleum, 23 percent from coal, and 23 percent from natural gas.
The remaining 14 percent of this energy came from nuclear and
renewable sources, such as hydroelectric power, wind, biomass
(e.g., wood and agricultural crops), and solar energy.


On the consumption side, 39 percent of total U.S. energy use in
2004 passed through the electricity-generation sector. Roughly
one-third of electricity-sector energy input was converted into
electricity and delivered to end-use customers. The remaining
two-thirds was lost due to inefficiencies in the production and
transmission of electricity. Of the 73 quadrillion Btu of energy
delivered to




end-use customers, 38 percent went to the transportation sector (to
power vehicles used to transport people and goods), 35 percent went
to industry (for manufacturing, agriculture, mining, and
construction), 16 percent was used in residences, and 11 percent was
used by the commercial sector (in business, government, schools, and
other public and private organizations).

Crude Oil

U.S. crude oil consumption in 2004 was 15.5 million barrels per
day, approximately 65 percent of which was imported. Crude oil is
used to produce a wide array of petroleum products, including
gasoline, diesel and jet fuels, heating oil, lubricants, asphalt,
plastics, and many other products used for their energy or chemical
content. Not surprisingly, crude oil markets are monitored closely
by consumers, businesses, and governments, because the prices of
petroleum-based products depend heavily on the price of crude oil.

A Global Market in Crude Oil
Crude oil can be transported long distances cheaply. Transportation
costs average roughly $2 per barrel for crude oil imported into the
United States. As a result, oil prices generally are determined by
the balancing of supply and demand at the global level, where prices
are roughly uniform for a given grade of oil. U.S. refiners, and
ultimately U.S. consumers, realize great benefit from having the
option of purchasing crude oil from both nearby sources, such as
Texas or Oklahoma, and from sources halfway around the globe, such
as Russia or the Middle East.
The international crude oil market is very active. Out of a total
global crude oil production of 67 million barrels per day in 2002,
roughly 60 percent was traded internationally. However, crude oil is
produced in large quantities for export in a relatively limited number
of locations around the world. In the first nine months of 2005, the
top ten oil-producing countries accounted for over 50 percent of
global production, and nearly 30 percent of global production
originated in the Persian Gulf. Although the United States was the
world's third-largest oil producer in 2004, trailing only Saudi
Arabia and Russia, the United States ranks eleventh in total proven
oil reserves, with just 2 percent of total proven world reserves
(Chart 11-1).

Crude Oil Prices
Crude oil prices generally change gradually in response to slowly
evolving domestic and international trends in oil demand and supply,
though prices have spiked sharply on a limited number of occasions.
Some of these spikes were short-lived, while others persisted for
several years.
Recent Price Rises
Because crude oil is traded in a global market, long-term trends in
demand by other consuming nations and unexpected events in other
countries affect the world market price that U.S. refiners pay and
the price that domestic oil



producers receive. Due to robust economic growth in the United
States, China, and other high-growth countries in Asia, world
consumption of petroleum products grew strongly over the past
several years.
On the supply side, industrial countries have exhausted most
low-cost opportunities for profitable domestic exploration and
development, and international energy companies often face
considerable risk when making investments for exploration,
development, and production in less-developed countries. Some
countries, particularly those with national oil companies, prohibit
or restrict foreign investment. Consequently, new production
capacity has been slow to emerge. World crude oil production in
2005 stood at about 74 million barrels per day, while the
Department of Energy estimates that current world oil production
capacity is only 1-1.5 million barrels per day higher-the lowest
level of world spare capacity in more than three decades. Most of
this spare capacity is in Saudi Arabia. As a result of this tight
market, crude oil prices have increased roughly threefold since
the beginning of 2002.
Past Oil Price Spikes
Although high, the current price of West Texas Intermediate (WTI)
crude oil (a common pricing benchmark) is lower than the historic
peak of over $87 per barrel (in 2005 dollars) reached in 1980. Oil
prices more than doubled from the last quarter of 1973 to the
first quarter of 1974 as a result of the Arab Oil Embargo. Oil
prices more than doubled again from mid-1979 to mid-1980 following
the 1979 Iranian Revolution. Prices fell gradually from this point
until 1985-1986, and then they fell rapidly after Saudi Arabia and
other oil-exporting countries increased production. A short-lived
shock in 1990 was associated with the Persian Gulf War. The recent
increase in crude oil prices, which has come largely through a
surge in world oil demand, has occurred much more gradually than
past price spikes, which resulted from abrupt reductions in
production in oil-exporting countries.
The Strategic Petroleum Reserve
Sudden oil supply shocks are potentially damaging to the U.S.
economy. The Strategic Petroleum Reserve (SPR) provides the United
States with an insurance policy should a severe energy supply
disruption occur. These Federally owned crude oil stocks, which
totaled 684 million barrels in late 2005, are sufficient to cover
about 68 days of U.S. crude oil imports or 44 days of total U.S.
crude oil consumption. The President of the United States has
authorized an emergency drawdown of the SPR on two occasions: once
during Operation Desert Storm in 1991, and a second time in
September 2005 following Hurricane Katrina, which temporarily shut
down crude oil production facilities in the Gulf of Mexico
(See Box 11-2). The Secretary of Energy has also approved a number
of short-term loans of SPR oil to help companies address short-term
disruptions to their operations, including after hurricanes Lili in
2002, Ivan in 2004, and Katrina in 2005. The Administration
recognizes the critical importance of the SPR, and has increased
SPR stocks by about 25 percent since January 2001.

Future Price Expectations and Incentives for
Nonconventional Fuels
Although world oil production capacity is expected to increase,
world demand is expected to increase as well, and we are likely to
face tight crude oil markets for a number of years. Prices on
contracts for future deliveries of crude oil (called crude oil
futures) indicate that market participants expect oil prices to
remain elevated at or near current levels through at least the end
of 2006. Box 11-1 looks at the development of energy futures
markets, which can help energy suppliers and users manage the
risks associated with market fluctuations, and which can help
facilitate investment in new conventional and alternative sources
of energy.
In the longer term, an expectation of high future petroleum
prices serves as a signal to potential developers of alternative
fuels and producers of petroleum from nonconventional sources that
investment in exploration, research, development, production, and
marketing of such alternatives is likely to be profitable. Chart
11-2 presents cost estimates for commercial production of potential
alternative fuels and nonconventional petroleum sources. Commercial
production of some of these alternatives has already begun. For
other alternatives, such as coal-to-liquids and oil shale, the
technologies needed for production are not yet mature, and their
production cost estimates do not include research, development,
and initial demonstration costs. In all cases, the production
cost estimates reflect expenditures on variable inputs (e.g.,
raw materials and labor), as well as capital costs for production
facilities. These production costs vary widely.
Although oil prices have risen to more than $60 per barrel in
recent months, they have averaged as low as $25 per barrel within
the last five years. Having experienced past volatility in oil
prices, oil companies report using a working assumption of $15-$30
per barrel for the future price of oil when making long-term
investment planning decisions. Only a handful of alternative fuels
and nonconventional sources of petroleum are profitable at these
prices, including petroleum from Canadian oil sands and ethanol
(when subsidized at current levels). Canadaï¿½s petroleum industry
reports that production of crude oil from oil sands is currently at
1 million barrels per day and is expected to approach 2.7 million
barrels per day by 2015.
Ethanol-an alcohol fuel made from the sugars found in corn and
other crops-can be burned by most automobile engines in the United
States when blended with gasoline. U.S. ethanol production, which
is supported by

_____________________________________________________________________
Box 11-1: Energy Futures Markets

A futures contract is a legal agreement to buy or sell a
particular, precisely defined commodity at a specified price and
location at a specified date in the future.  Trading in energy
futures allows suppliers or consumers of energy to lock in a
specific price at which they can sell or purchase energy products,
thereby reducing or eliminating price risk. This can aid in
investment planning for energy production.
The market for crude oil futures in organized exchanges, such as the
New York Mercantile Exchange (NYMEX) and the International
Petroleum Exchange in London, is well developed and increasing in
size. For example, the quantity of oil committed under NYMEX
futures contracts with maturities of three months or less increased
from a value equal to 30 percent of U.S. oil production in 1997 to
80 percent in mid-2005. The expansion of markets for contracts with
longer maturities is even more striking, with the quantity of oil
committed under NYMEX futures contracts with six-year maturities
growing from less than 1 percent of U.S. production in 1997 to 9
percent in 2005.
Although there is very little trading in crude oil futures with
longer maturities, futures contracts for horizons of longer than
six years can be arranged privately with the assistance of
investment banks or other financial intermediaries in so-called
over-the-counter transactions.
Energy futures are examples of financial instruments known as
derivatives, which firms use to manage risks associated with
market fluctuations. Weather derivatives also have been used by
firms in recent years in order to manage risks associated with
fluctuations in temperature and precipitation, which can have a
significant effect on energy markets.
----------------------------------------------------------------------



various Federal subsidies, currently stands at about 250,000 barrels
per day. Ethanol production is expected to increase substantially in
response to a mandate included in the Energy Policy Act of 2005
that gasoline sold in the United States contain at least 7.5
billion gallons of renewable fuels in 2012 (about half-a-million
barrels per day).


Private-sector development of nonconventional fuels, such as
coal-to-liquids or oil shale, may accelerate if high oil prices are
sustained over the long term. For the time being, however, these
alternatives are in a developmental stage and their future
commercial success will depend on future energy prices,
technological advances, and environmental and other regulatory
requirements.
High energy prices also provide incentives for expanded domestic
production of conventional oil and gas. The Administration supports
greater access to oil and natural gas resources in Federal waters
off shore states that support such




development and supports opening a small portion of the Arctic
National Wildlife Refuge (ANWR) in Alaska for environmentally
responsible oil and gas exploration. According to estimates by the
U.S. Geological Survey (USGS), the 1.5-million-acre coastal plain
of ANWR and adjacent Native lands and state offshore waters hold
between 5.7 and 16 billion barrels of technically recoverable
reserves, with a mean estimate of 10.4 billion barrels-enough to
supply 1 million barrels per day for over 28 years.


Gasoline and Other Refined Products
The United States derives approximately 40 percent of the energy
it uses from petroleum, making petroleum the single largest source
of energy for our Nation. Refined petroleum products, such as
gasoline, diesel, and jet fuel, provide 96 percent of the energy
used in the U.S. transportation sector, and are also important for
the industrial sector, which gets 37 percent of its energy from
petroleum. The residential sector gets 14 percent of its energy
from refined petroleum products (mainly home heating oil), while
petroleum supplies 10 percent of the energy used in the commercial
sector.

Gasoline Prices

The prices that consumers and other end users pay for gasoline
depend heavily on the prices that petroleum refiners pay for crude
oil. During the first eleven months of 2005, the cost of crude oil
accounted for about 53 percent of the retail price of gasoline (the
most recent available data from the Department of Energy). Refining
costs and profits accounted for 20 percent, Federal and state taxes
another 20 percent, and distribution and marketing about 8 percent
of the retail price of gasoline.
Crude oil price changes are passed directly through to consumers
in the form of changing prices for gasoline and other refined
products, at the rate of about 2.4 cents per gallon of refined
product for every $1 per barrel change in the price of crude oil.
According to Department of Energy data, rising crude oil prices
explain roughly two-thirds of the increase in average gasoline
prices between 2000 and 2005.
In addition to crude oil prices, other factors have a lesser but
sometimes pronounced effect on the price that consumers pay for
gasoline. Refinery or pipeline shutdowns caused by damaging weather,
such as hurricanes Katrina and Rita, can impede the ability of
refiners to produce or distribute refined petroleum products,
leading to short-term local or regional spikes in the price of
gasoline and other refined products that do not coincide with spikes
in the price of crude oil (Box 11-2).
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Box 11-2: The Effects of Hurricanes Katrina and Rita on
Energy Supplies

In late August 2005 the states of Alabama, Louisiana, and
Mississippi were struck by Hurricane Katrina, a powerful storm that
disrupted, damaged, or destroyed portions of our Nation's energy
infrastructure. Hurricane Rita followed almost exactly one month
later, while recovery from Katrina was still underway. The impact
of these disruptions on prices for crude oil, gasoline, other
refined petroleum products, and natural gas varied substantially,
and the divergent impacts help illustrate key differences in markets
for these energy sources (see Chapter 1 for a discussion of the
effects on the economy generally).
Due to evacuations and subsequent damage of oil rigs and platforms,
virtually all of Gulf-region oil production-about 28 percent of
total U.S. production-was shut down. Because there is a robust
world market for crude oil, however, the effect on world prices and
the prices that U.S. refiners pay for crude oil was relatively small.
The Administration approved several temporary loans of oil from the
Strategic Petroleum Reserve (SPR) to help refineries offset short-term
physical supply disruptions. The President also authorized the
emergency sale of up to an additional 30 million barrels of crude
oil from the SPR. These actions also helped to moderate any impact
the production shut-downs had on U.S. oil supplies.
About two dozen Gulf region refineries were also shut down by
flooding and electricity outages associated with the hurricanes,
so that following Hurricane Rita more than half of Gulf region
refining capacity and roughly one-quarter of total U.S. refining
capacity were shut down. Katrina initially led to a shutdown of the
Colonial and Plantation pipelines, which deliver most of the
refined petroleum products consumed on the East Coast, as well as
the Capline pipeline, which delivers crude oil from the Gulf region
to pipeline systems serving refineries in the Midwest. After the
storm passed and safety assessments revealed no damage, these
pipelines began operation substantially below capacity due to
electricity outages and product shortages. Hurricane Rita
subsequently led to shutdowns in several other pipelines. As a
result of these shutdowns of refineries and pipelines, gasoline and
refined product price increases were particularly pronounced in
regions served by these refineries and pipelines-namely, the East
Coast, Midwest, and Gulf regions. The effects on West Coast
refined product prices were less pronounced.
The International Energy Agency (IEA) of the Organisation for
Economic Cooperation and Development responded by coordinating the
release of IEA members'reserve stocks of petroleum. The United
States made SPR crude oil available, while other IEA countries
primarily offered refined petroleum products. These and other
imports of refined petroleum products helped ease the impact of the
hurricanes on gasoline and refined product prices, and prices
declined further as petroleum refineries and pipelines came back on
line.
Offshore natural gas production faced similar disruptions, with
shutdowns of up to about 85 percent of Gulf daily natural gas
production or 16 percent of total U.S. production. Onshore natural
gas processing facilities and gathering lines were also damaged,
further disrupting natural gas markets. Unlike crude oil prices,
however, natural gas prices rose by over half as a result of the
hurricane-related supply disruptions, due to the regional isolation
of U.S. natural gas markets.
By the end of 2005, less than 10 percent of U.S. oil production
capacity, less than 5 percent of U.S. refining capacity, and less
than 5 percent of U.S. natural gas production capacity remained
off-line, and further recovery was expected. Prices for crude oil,
gasoline, and natural gas had returned to pre-Katrina levels,
although natural gas prices were still experiencing volatility.
--------------------------------------------------------------------

Another related factor is that surplus refining capacity has declined
substantially during the last 25 years. In the early 1980s, U.S.
petroleum refiners were producing at only about 70 percent of their
total potential production capacity. In contrast, total refiner
output has been over 90 percent of capacity for the last decade.
Several factors explain this trend. First, many small, inefficient
refineries exited the industry in the early 1980s following the
removal of poorly conceived Federal petroleum price and allocation
controls that had favored such refineries. Without these controls,
inefficient refineries were no longer profitable, and total U.S.
refining capacity fell by 19 percent from roughly 19 million barrels
per day at its peak in 1981 to about 15 million barrels per day in
1994. Second, low profitability in the refining sector during the
early to mid 1990s did not provide the necessary incentive to expand
total refining capacity. Finally, local concerns about environmental
quality have made it increasingly difficult to site new heavy
industrial facilities, including refineries. Constraints on the
expansion of refining capacity to keep pace with growing demand can
lead to higher prices for refined products in the long run.
Refinery profitability increased in the late 1990s, however. As a
result, domestic refining capacity rose 12 percent from 1994 to 17
million barrels per day in 2004. This increase in capacity has come
exclusively through the expansion of existing refineries, as no new
refinery has been built in the United States since 1976. In response
to more-stringent clean-air regulations over the last two decades,
much of the recent investment in refining has been directed toward
increased capacity for producing cleaner fuels, even while using
heavier crude oils with higher sulfur contents. Rising refinery
costs and profits explain roughly one-quarter of the increase in
average gasoline prices between 2000 and 2005.
Short-Run Impacts of High Gasoline Prices
When gasoline prices increase unexpectedly, households and
businesses are not able to cut their gasoline consumption quickly
enough to fully offset the higher costs. In the short term, then,
gasoline price increases cut into household budgets and increase
business costs. Price increases can have a substantial impact over
the longer term, as well. Mirroring year-to-year changes in
gasoline prices, household gasoline expenditures have increased
recently after declining for several years from a peak of about 6
percent of mean household income in 1981 (Chart 11-3).
Fuel-intensive transportation industries, such as airlines and
trucking, also face substantially higher costs when prices of
refined petroleum products increase.
When such price increases occur in response to a natural disaster
or a failure of energy supply infrastructure, sellers are often
accused of "price gouging." Following hurricanes Katrina and Rita,
which caused energy supply disruptions and price spikes, the
Administration remained vigilant to pursue and



investigate reports of illegal pricing practices, while recognizing
that competitive markets are the most effective means for delivering
energy supplies to areas of greatest need. Rising prices encourage
consumers to conserve fuel and provide domestic producers and
importers with incentives to increase supply. If prices are
controlled artificially and not allowed to increase, however,
consumers will demand more than suppliers are willing to deliver,
leading to nonprice rationing (e.g., long lines) and potentially
exacerbating the shortage. At least 28 states currently have statutes
that address potential market manipulation in the aftermath of a
disaster, and a number of these states have initiated investigations
of anticompetitive behavior. The Federal Trade Commission has also
launched an investigation to scrutinize the refining industry for
evidence of unlawful and anticompetitive behavior.

Refining Capacity and Trade
Efficiency improvements and restructuring in the refining industry
have led to lower operating costs per barrel. Excluding oil and other
energy inputs, refinery operating costs fell roughly 20 percent
between the early 1980s and 2003. These cost reductions tend to
reduce the price of gasoline for consumers. Lower surplus capacity
may, however, increase the sensitivity of gasoline prices to
temporary disruptions in production at particular refineries. When
production at one refinery is disrupted, it is difficult for other
refineries to compensate by ramping up production. As a result, we
are more likely to see short-term spikes in the price of gasoline.
Although U.S. refining capacity and utilization have increased
since the early 1990s, these increases in production have not kept
pace with U.S. demand for gasoline and other refined products. As a
consequence, U.S. imports of refined petroleum products, including
gasoline, have grown from 11 percent of total refined product
consumption in 1993 to 15 percent in 2004.
Demand for various types of petroleum products within a country and
the configuration of its domestic refining capacity drive much of
this international trade. For instance, Europe has moved toward
consuming more diesel fuel relative to gasoline. According to
industry sources, diesel-powered vehicles increased from roughly 30
percent of European new car sales in 2000 to 40 percent in 2005.
This has resulted in an excess supply of gasoline at European
refineries, which Europe now exports to the United States. At the
same time, Europe imports diesel fuel from the United States and
other countries. Likewise, other countries have differences between
domestic consumption patterns and production capacity. These
patterns have resulted in the United States exporting certain
refined petroleum products to North America, South America, and
Europe, while importing other refined products from these same
countries, as well as from the Middle East and the Caribbean.
Transport costs for refined petroleum products are sufficiently
low that international trading can moderate the effects of regional
price spikes. For example, when supplies of gasoline and other
refined petroleum products ran short in the United States following
Hurricane Katrina, and prices began to rise quickly, importers
responded to this price incentive by delivering significantly more
product to the United States.
Price-Induced Substitution and Technological Change
In the long run, households and businesses respond to higher fuel
prices by cutting consumption, purchasing products that are more
efficient, and switching to alternative energy sources. Higher
energy prices also encourage entrepreneurs to invest in the research
and development of new energy-conserving technologies and alternative
fuels, further expanding the opportunities available to households
and businesses to reduce energy use and switch to low-cost energy
sources.
The energy intensity of the U.S. economy-that is, the ratio of
total Btu of energy consumed per dollar of real GDP-has declined
substantially over the past several decades (Chart 11-4). And, as
one might expect, energy intensity declined most rapidly from the
mid-1970s though the mid-1980s, when energy prices were at their
highest in real terms. Reductions in overall energy intensity
result from both shifts in economic activity toward less
energy-intensive sectors, as well as from energy efficiency
improvements within particular sectors. Recent research suggests
that energy efficiency improvements account for roughly one-third
of the reduction in energy intensity between 1985 and 2002, after
controlling for shifts in economic activity between different sectors.
Although reductions in energy consumption are made primarily in
response to changes in market conditions, government policy may
also play a role in facilitating improvements in energy efficiency.
This role has included supporting the development of new technologies,
encouraging investment in improved efficiency, and in some areas,
mandating efficiency improvements to new appliances, equipment,
buildings, and vehicles. For example, on-road fuel efficiency for new
cars and light trucks (e.g., minivans, pickup trucks, and SUVs)
increased from an average of 13 miles per gallon in 1975 to 21 miles
per gallon in 2005. This rise is due in part to higher fuel prices,
technological improvements, and Corporate Average Fuel Economy (CAFE)
standards, which mandate fuel efficiency in passenger cars and light
trucks (Box 11-3). The benefits of any such government policy must
be weighed carefully against the costs to U.S. taxpayers, consumers,
workers, and businesses. The Administration recently proposed new
CAFE standards for light trucks in model years 2008-2011 based on
a careful accounting of these benefits and costs.


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Box 11-3: Automobile Fuel Economy Standards
For three decades, Corporate Average Fuel Economy (CAFE) standards
have mandated separate average fuel economy targets for passenger
cars and light trucks sold in the United States, and each domestic
and foreign manufacturer must meet these same targets in every
model year. Congress has established a default level of 27.5 miles
per gallon for passenger cars, and passenger car standards have
remained at this default level since 1990. The Department of
Transportation (DOT) sets CAFE standards for light trucks for each
model year, and the Administration raised those standards from 20.7
miles per gallon in 2004 to 22.2 miles per gallon by model year 2007.
There are concerns that the structure of current CAFE standards
encourages manufacturers to build minivans, SUVs, and other light
trucks instead of cars, because the fuel economy standard for light
trucks is lower than the standard for cars. This could lead to an
overall decrease in average fuel economy. There are also concerns
that manufacturers might meet higher CAFE targets primarily by
reducing vehicle size and weight, rather than by applying fuel-saving
technologies, and that these size and weight reductions could have a
negative impact on the safety of vehicle occupants.
Motivated by these concerns, DOT has proposed a new CAFE rule for
light trucks for model years 2008-2011 (to be finalized by April
2006) that incorporates two notable reforms. First, DOT has proposed
that CAFE standards for light trucks depend on vehicle size, whereby
smaller light trucks will face higher fuel economy standards than
larger light trucks. Size-dependent CAFE standards will reduce the
incentive to build light trucks instead of cars, discourage
manufacturers from achieving CAFE standards only by selling smaller
vehicles, encourage greater fuel savings in small light trucks, and
spread the burden of achieving CAFE standards more evenly across
manufacturers. Second, proposed standards for 2011 would be set using
a new economic model developed by DOT that sets CAFE standards to
maximize economic benefits minus costs-a milestone in the use of
benefit-cost analysis in the rule-making process. The model takes
into account the impact of mandated fuel economy improvements on
vehicle costs, the value of fuel savings, environmental benefits and
costs, and other factors. The proposed rule will save an estimated
10 billion gallons of fuel over the lifetime of the light trucks
affected by the rule.
The Administration has requested authority from Congress to
implement further reforms to the CAFE system, including utilization
of market-based incentives, such as trading of fuel economy credits,
to obtain fuel savings at the lowest possible cost to consumers. The
Energy Policy Act of 2005 signed by the President calls for a report
on CAFE reform ideas to be delivered to Congress within one year.
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Reform of the New Source Review Program
Unfortunately, government mandates sometimes lead unintentionally to
outcomes that are contrary to their environmental goals. An example of
this is the New Source Review (NSR) component of the 1977 Clean Air Act
Amendment. NSR requires that new refineries, electric generating units,
and other industrial sources of air emissions apply the best-available
air emissions control technology. Existing facilities that undertake
significant modifications are also required to apply the best-available
technology. NSR requirements were designed to ensure that new emissions sources are appropriately controlled so that the local air quality is not compromised. Unfortunately, NSR has led over time to sources seeking to avoid its requirements because the permitting process was complicated, potentially expensive, and time-consuming, especially for sources modifying their facilities. This can provide an incentive for existing sources of emissions to continue their business operations for longer than would have been the case under normal market conditions without the regulation. It also provides an incentive for existing plants to forgo modifications.
New production sources tend to be less polluting than old ones even
in the absence of regulations, so extending the business operations
of older plants without making modifications could result in higher
emissions. Applying different regulations for "routine" versus
"major" modifications also leads to ambiguity, litigation delays,
and uncertainty in business planning, all of which can harm the
economy and may impede environmental improvements. The Administration
recently addressed this problem by establishing clear rules that
remove disincentives for facilities to modify and undertake routine
equipment replacement activities that could improve the safety,
reliability, and efficiency of the plants. The Administration also
established rules that provide facilities with greater flexibility
to modernize their operations without increasing air pollution,
encourage the installation of state-of-the-art pollution controls,
and base NSR requirements more accurately on actual facility
emissions levels. These changes will help to address the extreme
demands being placed on our Nation's energy supply infrastructure
by assuring that the NSR program provides greater regulatory
certainty and flexibility for business investment decisions, while
protecting the environment.

Natural Gas

Nearly a quarter of U.S. energy consumption is supplied by natural
gas. Natural gas has numerous uses in homes, industry, commerce,
electricity production, and transportation and is a vital component
of fertilizer and chemical production. The United States consumed 61
billion cubic feet of natural gas per day in 2004: 38 percent in
industry (roughly one-tenth of which was used as a feedstock), 24
percent in electricity generation, 22 percent by households, 13
percent in the commercial sector, and the remaining 3 percent in
transportation. U.S. natural gas consumption is projected to grow
to 74 billion cubic feet per day by 2025.
Natural gas is produced from underground reservoirs that are
sometimes associated with crude oil; much smaller amounts are
generated from landfills, coal mines, and other sources. Domestic
onshore production totaled about 42 billion cubic feet per day in
2004, while offshore production totaled 12 billion cubic feet per
day. Total domestic production of 54 billion cubic feet per day is
enough to heat about 300 million typical Midwestern homes for one
year. After extraction, natural gas is processed to remove
impurities (e.g., heavier hydrocarbons) and distributed via
pipelines to retailers and eventually to end-use consumers in all
sectors of the economy.

Regionalized Natural Gas Markets
Unlike crude oil, which trades on a global market at roughly
uniform world prices, the current natural gas marketplace is highly
regionalized. As a point of comparison, about 60 percent of global
crude oil production was traded internationally in 2002, whereas
only 28 percent of global natural gas production was traded. These
differences stem from relatively high shipping costs for natural
gas and a less-developed infrastructure for natural gas trade.
International trade in natural gas occurs mainly within the regions
of North America, Western Europe/Russia, and Asia-Pacific/Japan,
each with its own unique pricing system and other market
characteristics.
In North America, pipelines move natural gas between the United
States, Canada, and Mexico with subregions of the continent
supplying the majority of their own consumption needs. U.S. net
imports of natural gas were 9.3 billion cubic feet per day in 2004,
representing 15 percent of total U.S. natural gas consumption. Most
imports came by gas pipeline from Canada. Only a relatively small
amount was imported from beyond North America, as liquefied natural
gas (LNG) from Trinidad, Algeria, and other countries. The United
States also exports small amounts of natural gas to Canada and
Mexico by pipeline and to Japan as LNG from Alaska.

Natural Gas Prices
Wholesale natural gas prices at Henry Hub on the Louisiana Gulf
coast (a common natural gas pricing benchmark) averaged around
$2-$3 per million Btu from 1994 through the middle of 2000. One
million Btu of natural gas is equal to about one thousand cubic
feet of natural gas. Prices then spiked to a peak of $10.50 per
million Btu in December of 2000 in response to an unusually cold
winter before falling back to their previous low levels. Prices
have increased substantially since then from roughly $3 per
million Btu in early 2002 to over $10 per million Btu in November
2005. Prices rose roughly in tandem with crude oil prices due to
the presence of close substitution possibilities between natural
gas and oil in power production and heating, though there have been
some bumps along the way. Prices spiked to a peak of $19 per
million Btu in February 2003 in response to another unusually cold
winter, rose as high as $15 per million Btu in September 2005
following hurricanes Katrina and Rita, and increased to over $15
again in December 2005 with the onset of cold temperatures.
Volatility in Natural Gas Prices
Regionalization reduces the frequency and extent to which natural
gas price spikes in other regions affect U.S. natural gas prices.
However, the absence of a robust international market for natural
gas also makes the United States more susceptible to price shocks
within our own region. Disruptions to supply or increases in demand
may necessitate large price changes to reestablish equilibrium
between regional supply and demand. Opportunities for the import of
natural gas from other regions would dull these sharp price spikes,
although localized price spikes in some regions will likely never be
eliminated completely due to limitations in the natural gas
distribution infrastructure.
Volatility in natural gas prices in the United States is often
related to extreme and unexpected weather events. In the summer
months, for example, periods of extreme heat drive up demand for
electricity to power air conditioners, leading to increased demand
for natural gas for electricity production. Droughts and periods of
low rainfall deplete resources for hydroelectric power generation
and may require increased use of natural gas for replacement
electricity generation. In the winter, periods of extreme cold
drive up demand for natural gas for heating. Hurricanes, floods, and
other severe weather events may shut down natural gas production and
processing facilities and pipeline distribution networks, leading to
supply disruptions.
Liquefied Natural Gas
Liquefied natural gas (LNG)-natural gas in liquid form-is expanding
natural gas markets to a more global level, which in the future holds
potential to moderate some of this price volatility. LNG is created
by cooling natural gas to minus 260 degrees Fahrenheit, at which
point it turns into a liquid, significantly reducing its volume.
Specially manufactured double-hulled ships are then able to
transport LNG over long distances at lower cost than pipeline
transport of natural gas. Upon reaching port, LNG is pumped into a
receiving terminal where it is converted back into gas (regasified)
and then distributed to consumers via pipeline.
Although some inter-regional movement of natural gas does occur,
three key factors have limited the development of a full-scale
international market. First, natural gas resources are widely
distributed internationally, which at least until recently, has
limited the need of many countries to import natural gas from
distant sources. Second, it is still costly to transport natural
gas as LNG over long distances, which means that regional price
differentials need to be large before international trade is
cost-effective. Finally, natural gas price differentials are now
high enough to justify long-distance shipping of LNG, but the
infrastructure for liquefying natural gas into LNG is not well
developed in many countries with natural gas supplies.
Although the United States has been able to maintain a high level
of natural gas production, North America holds only 4 percent of
proven world reserves, including 3 percent of world reserves in the
United States and 1 percent in Canada (Chart 11-5). Assuming U.S.
demand continues to increase, the need for imports from sources
outside the region will grow. At present, it appears that LNG is
the best means for importing natural gas from beyond North America,
and current Department of Energy projections are that LNG imports
from various regions will increase from about 3 percent of U.S.
natural gas consumption in 2004 to 15 percent by 2025.



LNG Conversion and Transport Costs
A truly global market for natural gas will require transporting
natural gas over long distances, and LNG is superior to pipeline
transport in this regard. Currently, pipeline transport is less
expensive than LNG for distances up to about 1,300 miles in the
case of offshore pipelines and up to about 2,400 miles in the case
of onshore pipelines. Beyond these distances, LNG transport in
tankers is less expensive.
In addition to the cost of extracting and processing natural gas
at the supply source, LNG must be liquefied, transported via special
tanker, and then turned back into gas upon arrival. The costs
associated with liquefying LNG have decreased between 35 percent and
50 percent over the past ten years, while transport and
regasification costs have also fallen. These costs are still high
enough, however, that U.S. natural gas prices need to exceed
wellhead prices in LNG-supplying countries by at least $1.50 to $3
per million Btu-roughly $9 to $17 per barrel of oil equivalent-before
LNG transport is cost-effective. As these costs continue to fall,
the international marketability of LNG will grow.
U.S. LNG Terminal Capacity
Total LNG import costs are about $2-$4 per million Btu, which is
far below current domestic natural gas prices. Given sufficient LNG
infrastructure capacity, therefore, domestic prices eventually could
be reduced through increased imports. Over 150 LNG tankers were in
operation in 2003, and another 50 are under construction. Currently,
there are five existing LNG import terminals in the continental
United States (four onshore and one offshore), and these facilities
operated at about 40 percent of capacity in 2005. About a dozen
additional terminals have been approved, and about 20 others have
been proposed. The recent Energy Policy Act of 2005 signed by the
President took steps to remove unnecessary impediments to siting
LNG terminals by clarifying the role of the Federal Energy
Regulatory Commission (FERC) as the lead agency for coordinating
authorization of onshore LNG terminals and LNG terminals in state
waters. Federal approval of projects will continue to be conditional
on state approval under various environmental laws.
With ample capacity in both shipping and receiving, the current
bottleneck in LNG imports to the United States is an insufficient
supply of overseas facilities for liquefying LNG. As long as capacity
for liquefying LNG is in short supply abroad, there will be great
competition in international markets for LNG cargoes, as is already
happening among the major importers of LNG, including the United
States, Japan, Spain, and other countries. Not surprisingly, high
natural gas prices in these and other countries have led to an
expansion of capacity to liquefy LNG abroad. Qatar, which has 15
percent of proven world natural gas reserves, recently began
exporting LNG. The 12 nations that currently export LNG hold more
than one-quarter of proven world reserves, and some of the world's
largest natural gas exporters are in the process of constructing
plants to develop LNG export capacity, including Russia and Norway.
Future Prospects for an International LNG Market
Currently, LNG markets are undergoing a substantial evolution, with
demand growing and strong future growth expected. Between 1993 and
2003, international LNG trade grew at an average annual rate of 7
percent, and global LNG capacity is expected to grow by more than
one-third between 2003 and 2007. Although international trade in
LNG is expanding, the market has not yet evolved to the point where
it can respond fully to price spikes in North America and other
regional markets. The market for prompt delivery of LNG "spot
cargoes," although growing, is still less than 10 percent of world
LNG trade, with most LNG cargoes delivered under long-term contracts.
Prospects for Domestic Production of Natural Gas
The emergence of international natural gas markets does not
eliminate the need to develop domestic production. Greater domestic
natural gas production holds promise both in Alaska and on the outer
continental shelf (OCS)-Federally controlled offshore areas within
the 200-mile exclusive economic zone of the United States but
beyond the 3-mile zone under state jurisdiction-as well as other
areas. A difficulty in Alaskan production has been the lack of
infrastructure to transport remote natural gas resources to market,
which would be solved by development of the Alaska natural gas
pipeline to the lower 48 states. The Alaska Natural Gas Pipeline
Act signed by the President in October 2004 established an
expedited Federal approval process for construction of the pipeline,
and FERC has been working with state, Federal, and Canadian agencies
to establish a framework for coordinating permitting activities.
The OCS has vast additional natural gas resources. Proven Federal
offshore reserves as of 2003 were about 23 trillion cubic feet-12
percent of total U.S. proven reserves of 189 trillion cubic feet.
The Department of Interior estimates the OCS also contains 400
trillion cubic feet of undiscovered, technically recoverable
natural gas. About 20 percent of this natural gas-80 trillion cubic
feet-is currently subject to Federal offshore leasing moratoria.
The Administration supports greater access to natural gas and oil
resources in Federal waters off shore of states that support such
development. This would open up substantial additional natural gas
supplies for the Nation.

Electricity
Although 39 percent of total U.S. energy consumption in 2004 passed
through the electricity-generation sector, only about one-third of
electricity-sector energy input was converted into electricity and
passed on to end-use customers (Table 11-1). The remaining two-thirds
was lost due to inefficiencies in the production and transmission of
electricity. Some of these losses could be avoided through further
efficiency improvements, though most are unavoidable due to the
physics of electricity production and transmission. Retail
electricity  consumption is divided roughly equally among the
residential, commercial, and industrial sectors. The residential
sector consumed 36 percent of this electricity for lighting,
heating, air conditioning, and powering household appliances, while
35 percent went to the commercial sector for similar uses. Industry
consumed 29 percent, and less than 1 percent went to the
transportation sector to power electric rail transport.
Electricity-Generation Technologies
A range of energy sources and technologies are used to produce
electricity. A total of 71 percent of generated electricity comes
from fossil fuels, including 50 percent from coal, 18 percent from
natural gas, and 3 percent from petroleum. Nuclear power provides
about 20 percent of electricity, while hydroelectric power provides
7 percent, and other renewable sources, such as wind, biomass, and
solar, provide a combined 2 percent.
With the exception of solar power and diesel-powered internal
combustion engines, all electricity is generated by the turning
of turbines that drive electric generators. Falling water drives
the turbines in a hydroelectric plant, and wind turns the turbine
of a windmill. Natural gas plants use a combustion process like
that in a jet aircraft engine to generate a high-speed stream of
combustion gases, which is used to drive a natural gas turbine. In
natural-gas-combined-cycle plants, exhaust gases exiting the gas
turbine are used to heat water, which generates high-pressure steam
that drives a second turbine. Nuclear and conventional coal plants
generate high-pressure steam to drive turbines by heating water
using the energy released by nuclear reactions and coal combustion,
respectively. Advanced coal-fired generating plants use various
alternative technologies to enhance efficiency and cut emissions.
Combined heat and power plants can very efficiently generate steam
or hot water for heating and production processes, as well as for
electricity.

The Real-Time Challenge of Electricity Markets
Most fuels, such as gasoline, home heating oil, or natural gas,
can be manufactured and then stored for later distribution and use.
Unlike these energy sources, however, the generation and consumption
of electricity must match exactly in real time. Although it is
possible to store electricity in batteries, storing electricity on a
large scale is too costly. If generation fails to provide the energy
needed to satisfy demand, the electricity production and
distribution network can become unstable, leading to outages or
system failures. Shutdowns of generating plants in one location can
therefore affect the entire network, as was the case in August 2003,
when a plant shutdown in Ohio triggered cascading failures that
ultimately forced the shutdown of at least 265 power plants. These
shutdowns left an estimated 50 million people in the United States
and Canada without power and led to economic losses of $4-$10
billion in the United States and noticeable downturns in Canadian
hours worked, manufacturing shipments, and economic output. The
Federal government took a number of actions after the blackout to
diminish the risk that a similar disruption would occur in the
future.
The demand for electricity fluctuates with the seasons and during
the course of each day. For example, the hot summer months bring
increased demand for electricity to power air conditioners, and
electricity demand peaks each afternoon and drops to its lowest
level late at night. Because the production and use of electricity
must match in real time, electricity generation fluctuates
one-for-one with these seasonal and daily consumption patterns.
Electricity-generating capacity is tuned to match these
fluctuations. Plants that have low operating costs or that are
difficult to turn on and off, such as nuclear and coal-fired steam
plants, provide the "baseload" power that is used all day every
day. Plants that have higher operating costs or that can be started
up quickly, such as natural gas turbine plants, start up
incrementally as electricity demand increases and peaks, with some
units remaining idle for much of the day or even much of the year.
Hydroelectric plants, which have low operating costs and can be
started quickly, are suitable for both baseload and peak electricity
production.
These fluctuations can have impacts in other energy markets.
Reduced hydroelectric power due to low rainfall and falling
reservoir levels can increase demand for electricity from natural
gas. Likewise, particularly hot summers increase electricity demand
to power air conditioners, increasing demand for natural gas as
gas-powered generators come on line. If the weather is drier or the
summer is hotter than marketers of natural gas anticipate, stored
levels of natural gas will be low relative to unexpectedly high
demand, and natural gas prices will increase.
Real-Time Pricing and Other Reforms
Because electricity-generating units are dispatched incrementally
in order of increasing operating cost, the marginal cost of producing
electricity-that is, the additional cost of producing one additional
unit of electricity-is highest during periods of peak production and
lowest during periods of low production. In practice, however, most
retail customers pay a fixed seasonal rate for the electricity they
use and thus have no incentive to reduce their consumption of
electricity during the times of day when it is most costly to
produce. As a result, electricity producers must invest in
generating units that remain idle most of the time, and the capital
costs of these units are passed on to consumers in the form of
higher average prices. Constraints in the electricity transmission
system, which limit the extent to which electricity can be directed
to areas of high demand or low supply, can also lead to high
electricity prices in some regions.
The recent Energy Policy Act of 2005 signed by the President
addresses the issue of inefficient pricing by requiring electric
utilities and competitive retailers to offer customers time-based
rates by February 2007. By ensuring that electricity suppliers
offer their customers rates that better reflect the cost of
electricity generation, these provisions will encourage consumers
and businesses to conserve electricity during times of peak demand.
This will reduce the need for excess generating capacity that
remains idle most of the time and will, as a result, lower average
electricity bills for retail customers. The Act also establishes
energy-efficiency standards for household products and Federal
buildings, which will reduce consumption of energy.
Environmental Protection
Combustion of fossil fuels, coal in particular, generates sulfur
oxides and nitrogen oxides, which contribute to poor air quality if
not controlled. Currently, emissions of sulfur and nitrogen oxides
from electric utilities are regulated under the 1990 amendments to
the Clean Air Act, which established a cap-and-trade system of
tradable permits that holds total annual emissions to a mandated
level at low cost. See Box 11-4, which includes a discussion of the
Clean Air Interstate Rule and the President's Clear Skies proposal,
which calls for a further 70 percent reduction in air emissions.
Fossil fuel combustion also generates emissions of carbon dioxide
and other greenhouse gases, which contribute to the warming of the
Earth's surface. The Administration is supporting the development of
various technologies that will improve power plant efficiency, while
greatly reducing air pollution and greenhouse gas emissions. For
example, the Department of Energy is supporting research and
development of technologies that turn coal into a highly enriched
hydrogen gas, which can be burned much more cleanly than burning
coal directly or can be used as an industrial feedstock. These
technologies also provide opportunities to remove and sequester
emissions of carbon dioxide and air pollutants prior to combustion.
In February 2003 the President announced FutureGen, a
government-industry partnership to build a prototype fossil fuel
power plant that will demonstrate these technologies.
----------------------------------------------------------------------
Box 11-4: Cap-and-Trade Programs for Air Pollution

Title IV of the 1990 Clean Air Act Amendments established a
national cap-and-trade system for sulfur dioxide (SO2) emissions. SO2
emissions, which are generated by the burning of fossil fuels-such
as coal in an electric power plant-can lead to health concerns and
are a component of acid rain. Title IV's program caps total
allowable SO2 emissions from power plants nationwide and requires
that each facility own a permit for every unit of SO2 it emits. The
Environmental Protection Agency (EPA) monitors and enforces this cap
rigorously.
Under the Title IV program, SO2 permits can be bought and sold by
emitting facilities. Trading allows facilities with high
pollution-reduction costs to purchase permits from facilities with
low reduction costs, thereby allowing the power industry to achieve
mandated emissions reductions in a cost-effective manner. The
program does not tell power producers how to reduce pollution, but
rather they are free to choose the most cost-effective method for
achieving reductions.
The SO2 trading program has been very successful at reducing
emissions at a lower cost than direct plant-level emissions
standards. The compliance has been nearly 100 percent, and research
shows the trading program saves U.S. power producers hundreds of
millions of dollars per year relative to direct plant-level
standards. Thus, cap-and-trade programs promote clean air while
reducing the cost impact on energy consumers. A similar regional
cap-and-trade program exists in the eastern United States to control
nitrogen oxide emissions, which contribute to regional ozone and
smog problems.
In 2002, the President proposed "Clear Skies" legislation, which
would expand the Clean Air Act Title IV cap-and-trade approach for
SO2 to also include nitrogen oxide and mercury, reducing these
emissions to roughly 70 percent below 2000 levels by 2018. As
Congress has not yet enacted Clear Skies, the EPA has sought to
achieve much of the benefits of the Clear Skies legislation by
issuing the Clean Air Interstate Rule (CAIR) and the Clean Air
Mercury Rule (CAMR) in March 2005. CAIR requires 28 states in the
eastern half of the country to regulate power plant emissions of
SO2 and nitrogen oxides and encourages them to do this within the
framework of an interstate cap-and-trade system. When fully
implemented, CAIR will reduce power-plant SO2 emissions in these
states by over 70 percent and nitrogen oxide emissions by over 60
percent from 2003 levels. CAMR is the first-ever regulatory action
to reduce mercury emissions from coal-fired power plants and
includes a cap-and-trade approach as a way of achieving nearly
70-percent reductions in mercury emissions.
----------------------------------------------------------------------

The Administration is also supporting further development of
renewable sources of electricity, such as wind, solar energy, and
biomass (e.g., wood and agricultural crops), which generate little
or zero net greenhouse gas emissions. Finally, the Administration is
supporting the development of nuclear power, which does not
generate air pollution or greenhouse gases. The Nuclear Power 2010
program is a cost-shared government-industry partnership to
identify sites for new nuclear power plants, improve nuclear
technologies, and demonstrate untested regulatory processes. The
Generation IV nuclear power program supports the development of
future technologies with reduced capital costs, enhanced safety,
minimal waste, and reduced risk of weapons materials proliferation.
Electricity Markets in Transition
The electric power industry has gone through a transition over the
past several decades, evolving from a highly regulated, monopolistic
industry to a less regulated, more competitive industry.
Traditionally, electric utilities owned and operated
electricity-generating units, transmission lines, and distribution
systems, and were the sole providers of electricity to a specific
geographic area. Federal legislation and rule-making activities
during the last decade, however, have opened up access to
transmission lines and encouraged greater wholesale trade of
electricity between generators and retailers. The market changes
vary from state to state and are dynamic, with continual adjustments
being made as problems emerge. Some states continue to operate
under a traditional, integrated market structure, others are
striving to encourage greater competition among generating
companies, and some even have opened up competition between
electricity retailers.
Recent Electricity Market Policy Reforms
Successful operation of the electric power system requires
coordination among system participants. Competition can lead to
better products and lower costs for consumers. Ensuring the benefits
of competition and reliability are therefore key components of
successful reform. Provisions in the Energy Policy Act of 2005
signed by the President promote competition and investment in
transmission infrastructure by providing for reasonably priced
access to transmission grids, while providing for the establishment
of mandatory reliability rules for the electric system. In order to
further reduce costs and increase reliability, the Act repealed the
Public Utility Holding Company Act (PUHCA), which restricted the
ability of regulated utilities to invest in electricity
infrastructure, and amended the Public Utility Regulatory Policies
Act (PURPA) to allow utilities greater flexibility to purchase
wholesale electricity from producers with lower costs. The Energy
Policy Act of 2005 improves market competition by promoting the
dissemination of information about the availability and prices of
wholesale electricity and transmission services. The Act also
protects consumers by banning market manipulation, unauthorized
disclosure of consumer information, and unfair trade practices,
such as changing the electricity service providers chosen by
consumers without their consent.

Conclusion
Today, most of our energy comes from petroleum, coal, and other
fossil fuels. There are constraints on supplies of these resources
in the short term. Increased scarcity and rising prices over time
will encourage conservation, increase incentives for exploration,
and stimulate the development of new, energy-efficient technologies
and alternative energy sources. In the near term, unexpected
disruptions to energy supply and distribution networks may continue
to impact consumers and businesses. The recent hurricanes Katrina
and Rita demonstrated that competitive markets play a central role
in allocating scarce energy resources, especially during times of
natural disaster or national emergency. The continued expansion of
energy markets through regional and global trade can further
increase our resilience to energy supply disruptions. Finally,
individual energy market participants do not always have an
incentive to tackle problems associated with the production and
consumption of energy, such as environmental damage or the
potentially damaging effects of energy price spikes on the U.S.
economy. Policies that reduce U.S. vulnerability to supply
disruptions, encourage energy efficiency, and protect the
environment can therefore be beneficial supplements to markets.
Policymakers can design these policies to be more effective and
less costly by harnessing the power of economic incentives and
aiming to minimize distortion of normal market forces.