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Annual
Energy Outlook 2004 with Projections to 2025
Market Trends - Oil and Natural Gas
Index (click to jump links)
Natural Gas Consumption and Prices
Natural Gas Production
Natural Gas Imports and Wellhead Prices
Natural Gas Alternative Cases
Oil Prices and Reserve Additions
Oil Production
Alaskan Oil Production and Oil Imports
Petroleum Refining
Refined Petroleum Products
Natural Gas Consumption
and Prices
Projected Increases in Natural Gas Use Are Led by Electricity
Generators
Total natural gas consumption is projected to increase
from 2002 to 2025 in all the AEO2004 cases. The projections
for domestic natural gas consumption in 2025 range from 29.1 trillion
cubic feet per year in the low economic growth case to 34.2 trillion
cubic feet in the rapid technology case, as compared with 22.6 trillion
cubic feet in 2002. In the reference case, natural gas consumption
in the electric power sector is projected to increase from 5.6 trillion
cubic feet in 2002 to 6.7 trillion cubic feet in 2010 and 8.4 trillion
cubic feet in 2025 (Figure 85). Demand by electricity generators
is expected to account for 29 percent of total end-use natural gas
consumption in 2025, as compared with 27 percent in 2002.
Most new electricity generation capacity is expected
to be fueled by natural gas, because natural-gas-fired generators
are projected to have advantages over coal-fired generators that
include lower capital costs, higher fuel efficiency, shorter construction
lead times, and lower emissions. Toward the end of the forecast,
however, when natural gas prices rise substantially, coal-fired
power plants are expected to be competitive for new capacity additions.
Demand growth is also expected in the residential,
commercial, industrial, and transportation sectors. In the reference
case, industrial consumption is projected to increase from 7.3 trillion
cubic feet in 2002 to 8.4 trillion cubic feet in 2010 and 10.3 trillion
cubic feet in 2025. In the residential and commercial sectors, natural
gas consumption is projected to increase by 0.9 percent and 1.1
percent per year, respectively, from 2002 to 2025.
Delivered Prices Increase More Slowly Than
Wellhead Prices
Prices for natural gas delivered to the end-use sectors
are expected to fall in the early years of the forecast as wellhead
prices decline (Figure 86). After 2006 wellhead prices are projected
to start increasing, and delivered natural gas prices begin to increase
in 2012. The increase in wellhead gas prices is expected to be offset
in part by a projected decline in average transmission and distribution
margins.
The average end-use price is projected to increase
by 54 cents per thousand cubic feet from 2006 to 2025 (in constant
2002 dollars), compared with a projected increase of 97 cents per
thousand cubic feet in the average price of domestic and imported
natural gas supplies. The slower increase in delivered prices reflects
continued depreciation of existing infrastructure, increased pipeline
utilization, and more imports of LNG directly into end-use markets.
The natural gas transmission and distribution margin
reflects both the volume of gas delivered and the infrastructure
arrangements of the sector. The industrial and electricity generation
sectors have the lowest end-use prices, because they receive most
of their natural gas directly from interstate pipelines, avoiding
local distribution charges. Summer-peaking electric generators reduce
transmission costs by using interruptible transportation rates during
the summer, when there is spare pipeline capacity. As power generators
take a larger share of the natural gas market, however, they are
expected to rely more on higher cost firm transportation service.
The compressed natural gas vehicle margin is expected to increase,
because the cost of the refueling infrastructure must be added to
serve non-fleet vehicles.
Natural Gas Production
Unconventional Production Becomes the Largest Source
of U.S. Supply
As a result of technological improvements and rising
natural gas prices, natural gas production from unconventional sources
(tight sands, shale, and coalbed methane) is projected to increase
more rapidly than conventional production. In the reference case,
lower 48 unconventional gas production is projected to grow from
5.9 trillion cubic feet in 2002 to 9.2 trillion cubic feet in 2025
(Figure 87), increasing from 32 percent of total lower 48 production
in 2002 to 43 percent in 2025. Production of lower 48 nonassociated
(NA) conventional natural gas is projected to decline from 10.0
trillion cubic feet in 2002 to 9.5 trillion cubic feet in 2025,
as resource depletion causes exploration and production costs to
increase. Offshore NA natural gas production is projected to fluctuate
around 3.7 trillion cubic feet throughout the forecast, because
sufficient reserves of natural gas must be discovered in an offshore
region to justify investment in the necessary production and transportation
infrastructure.
Production of associated-dissolved (AD) natural gas
from lower 48 crude oil reserves is projected to increase from 2.7
trillion cubic feet in 2002 to 3.2 trillion cubic feet in 2008 [115].
After 2008, both onshore and offshore AD gas production are projected
to decline, and total lower 48 AD gas production falls to 2.6 trillion
cubic feet in 2025.
The North Slope Alaska natural gas pipeline is expected
to begin transporting Alaskan gas to the lower 48 States in 2018.
In 2025, total Alaskan gas production is projected to be 2.7 trillion
cubic feet in the reference case.
Growing Production Is Expected from the Rocky
Mountain Region
In the reference case, total foreign and domestic
natural gas supplies are projected to grow by 3.5 trillion cubic
feet from 2002 to 2010 and by 8.7 trillion cubic feet from 2002
to 2025. Domestic natural gas production is expected account for
57 percent of the total growth in supply, and net imports are projected
to account for the remaining 43 percent.
Over the forecast period, the largest increase in
lower 48 onshore natural gas production is projected to come from
the Rocky Mountain region, predominantly from the large volume of
unconventional resources located in the region [116]. Rocky
Mountain natural gas production is projected to increase from 3.3
trillion cubic feet in 2002 to 4.6 trillion cubic feet in 2010 and
6.3 trillion cubic feet in 2025 (Figure 88).
The other lower 48 onshore production regions are
projected either to show moderate increases in production, followed
by declines after 2020, or to remain relatively constant through
2020 and decline thereafter. The regional declines after 2020 largely
reflect the depletion of the conventional natural gas resource base.
Because production from the Rocky Mountain region
is projected to increase throughout the forecast while the other
lower 48 onshore regions do not, Rocky Mountain production makes
up an increasing share of total lower 48 onshore natural gas production.
In 2002, Rocky Mountain production was 24 percent of total lower
48 onshore production. Its share is projected to increase to 32
percent in 2010 and 39 percent in 2025.
Natural Gas Imports and
Wellhead Prices
Net Imports of Natural Gas Grow in the Projections
Net imports of natural gas make up the difference
between U.S. production and consumption. Imports are expected to
be priced competitively with domestic sources. Supplies of natural
gas from overseas sources, imported through U.S. LNG terminals,
account for most of the projected increase in net imports in the
reference case (Figure 89). When planned expansions at the four
existing terminals are completed, new LNG terminals are projected
to start coming into operation in 2007, and net LNG imports increase
from 0.2 trillion cubic feet in 2002 to 2.2 and 4.8 trillion cubic
feet in 2010 and 2025, respectively.
Net imports of natural gas from Canada are projected
to peak at 3.7 trillion cubic feet in 2010, then decline gradually
to 2.6 trillion cubic feet in 2025. The depletion of conventional
resources in the Western Sedimentary Basin is expected to reduce
Canada’s future production and export potential, and prospects
for significant production increases in eastern offshore Canada
have diminished over the past few years. There is also considerable
uncertainty about the economic viability and timing of coalbed methane
production in western Canada. The reference case does project that
a MacKenzie Delta natural gas pipeline will begin moving supplies
to U.S. buyers in 2009.
Historically, although Mexico has considerable natural
gas resources, the United States has been a net exporter of gas
to Mexico. In the reference case, net exports of U.S. natural gas
to Mexico are projected to grow until 2006, when imports of natural
gas from western Mexico are projected to begin entering the United
States from an LNG import terminal in Baja California, Mexico [117].
Technology Advances Could Moderate Future Natural
Gas Prices
In the reference case, average lower 48 wellhead natural
gas prices are projected to decline from 2003 levels to $3.40 per
thousand cubic feet (2002 dollars) in 2010 and then increase to
$4.40 per thousand cubic feet in 2025 (Figure 90). Technically recoverable
natural gas resources (Table 22) are expected to be adequate to
support projected production increases. As lower 48 natural gas
resources are depleted, wellhead prices increase, causing an increasing
proportion of U.S. natural gas supply to come from Alaska, as well
as imports from Canada and other countries.
In the slow oil and gas technology case, advances
in exploration and production technologies are assumed to be 50
percent slower than in the reference case. As a result, natural
gas development costs are higher, wellhead prices are higher ($3.58
and $5.10 per thousand cubic feet in 2010 and 2025), natural gas
consumption is reduced, and construction of liquefied natural gas
(LNG) import terminals is advanced relative to the reference case
projections.
The rapid technology case assumes 50 percent faster
technology progress than in the reference case, resulting in lower
development costs, lower wellhead prices ($3.25 and $3.80 per thousand
cubic feet in 2010 and 2025), and increased consumption of natural
gas. LNG imports are reduced in the rapid technology case, and construction
of LNG terminals is slowed relative to the reference case projections.
Natural Gas Alternative
Cases
Natural Gas Supply Projections Reflect Technological
Progress
Because the impacts of technological progress are
cumulative, the rapid and slow technology cases diverge increasingly
from the reference case path in the later years of the forecast
(Figure 91). In the reference case, lower 48 natural gas production
is projected to total 21.3 trillion cubic feet in 2025. The corresponding
projections are 25.1 trillion cubic feet in the rapid technology
case and 19.5 trillion cubic feet in the slow technology case.
The cost-reducing effects of rapid technological
progress primarily affect the economic recoverability of the large
resource base of unconventional natural gas, because the conventional
gas resource base is farther along the depletion curve than the
unconventional resource base, especially in the later years of the
forecast. In 2025, the rapid and slow technology cases project 12.9
and 8.4 trillion cubic feet of unconventional natural gas production,
respectively.
The rate of technological progress also affects the
contributions of other natural gas supply sources. Because rapid
progress is projected to increase the rate of production of lower
48 natural gas resources, both an Alaska gas pipeline and new LNG
terminals are less viable economically in the rapid technology case
than in the reference case, and their construction is delayed. In
the slow technology case, with lower 48 wellhead prices projected
to increase more rapidly, earlier completion is expected for the
Alaska pipeline and for new LNG terminals, and more LNG facilities
are built. Projected LNG imports in 2025 total 3.8 trillion
cubic feet in the rapid technology case and 5.5 trillion cubic
feet in the slow technology case.
Rapid Technology Assumptions Raise Natural Gas
Reserve Projections
The AEO2004 projections for lower 48 natural
gas reserves reflect expected levels of natural gas well drilling
resulting from projected cash flows and profitability. In the reference
case, lower 48 reserves grow to 204 trillion cubic feet in 2013,
remain relatively constant until 2018, and then decline slowly to
194 trillion cubic feet in 2025 (Figure 92).
In the rapid technology case, the finding and success
rates for gas well drilling are improved and exploration and production
costs are reduced, resulting in more drilling activity and reserve
additions. In this case, lower 48 reserves are projected to peak
at 241 trillion cubic feet in 2023, then decline to 239 trillion
cubic feet in 2025.
In the slow technology case, finding and success
rates are lower, exploration and production costs are higher and
drilling activity and reserve additions are lower than projected
in the reference case. Lower 48 reserves are projected to peak at
194 trillion cubic feet in 2013, then decline to 172 trillion cubic
feet in 2025.
In all three cases, the natural gas resource base
is sufficient in the early years of the forecast to support the
increases in drilling activity and reserve additions that are stimulated
by higher projected prices, and additions generally exceed production.
In later years, rising costs of gas well development reduce drilling
activity, and resource depletion reduces reserve additions per well.
As a result, total reserves are projected to decline.
Oil Prices and Reserve
Additions
Oil Prices Are Expected To Remain Near Recent Historical
Levels
Crude oil prices are determined largely in an international
marketplace by the balance between production in OPEC and non-OPEC
nations and demand. In the reference case, the average lower 48
crude oil price is projected to be $23.61 per barrel in 2010 and
$26.72 per barrel in 2025 (Figure 93). In the high world oil price
case, the lower 48 crude oil price increases to $32.80 per barrel
in 2010 and $34.90 per barrel in 2025. In the low world oil price
case, the lower 48 price generally declines to $16.36 per barrel
in 2010, then rises to $16.49 per barrel in 2025.
The projections for U.S. petroleum consumption vary
with changes in assumptions about economic growth; however, larger
variations result from changes in assumptions about world oil prices.
Total petroleum consumption in 2025, projected at 28.3 million barrels
per day in the reference case, ranges from 25.6 to 31.1 million
barrels per day in the high and
low world oil price cases (Figure 94).
Oil Reserve Projections Are Sensitive to
Oil Price Assumptions
Lower 48 crude oil reserves are sensitive to crude
oil price projections (Figure 95). In the reference and high and
low world oil price cases, lower 48 oil reserves decline as resources
are depleted. In the low and high oil price cases, projected lower
48 reserves are 13.6 and 15.6 billion barrels in 2025, respectively,
compared with 15.0 billion barrels in the reference case.
The variation in crude oil prices in the world oil
price cases primarily affects the development and production of
offshore oil resources (Table 23), because smaller deepwater fields
that are not profitable when price are low are expected to become
profitable when oil prices rise.
Crude oil reserve additions reflect the number of
oil wells completed during the forecast period, the size of the
crude oil resource base (Table 24), and the pace of technological
progress. In the reference case, technological progress is expected
to continue at the historical rate.
Oil Production
Lower 48 Crude Oil Production Is Expected
To Decline After 2008
In the reference case, total lower 48 crude oil production
is projected to increase from 4.6 million barrels per day in 2002
to 5.2 million barrels per day in 2008, then decline to 4.1 million
barrels per day in 2025 (Figure 96). In the low oil price case,
lower 48 production is projected to peak in 2007 at 5.0 million
barrels per day and decline to 3.6 million barrels per day in 2025.
In the high oil price case, lower 48 oil production is projected
to peak in 2008 at 5.3 million barrels per day and decline to 4.3
million barrels per day in 2025. The projected peaks in oil production
are attributable to offshore production. In the reference case,
total offshore oil production (including the Gulf of Mexico and
offshore California) rises to 2.5 million barrels per day in 2008,
then declines to 2.1 million barrels per day in 2025. Oil production
in the Gulf of Mexico is projected to peak in 2009 at 2.4 million
barrels per day and decline in the later years of the forecast (Table
25).
Offshore crude oil production is more sensitive than
onshore production to oil prices. In the low and high oil price
cases, lower 48 offshore production is projected to be 1.7 and 2.2
million barrels per day, respectively, in 2025. Onshore lower 48
oil production is projected to decline in all cases, with 2025 values
ranging from 1.9 million barrels per day in the low oil price case
to 2.1 million barrels per day in the high oil price case.
More Rapid Technology Advances Could Raise Oil
Production Slightly
Lower 48 crude oil production is projected to reach
4.3 and 3.8 million barrels per day in 2025 in the rapid and slow
technology cases, respectively, compared with 4.1 million barrels
per day in the reference case (Figure 97). The technology cases
assume the same world oil prices as in the reference case, but the
rate of technological progress is assumed to be 50 percent
higher (in the rapid technology case) or lower (in the slow
technology case) than the historical rate. With domestic oil demand
determined largely by oil prices and economic growth rates, consumption
is not expected to change significantly in the technology cases.
Thus, changes in production resulting from the different rates of
technological progress result in different levels of petroleum imports.
In 2025, net petroleum imports are projected to range from 19.0
million barrels per day in the rapid technology case to 20.4 million
barrels per day in the slow technology case.
In the lower 48 States, offshore crude oil production
is more sensitive than onshore production to changes in technology.
Consequently, as technologies change, investments are shifted between
onshore and offshore exploration and drilling, and production volumes
reflect the reallocation of capital.
Cumulative offshore production from 2002 to 2025
is projected to be 1.17 billion barrels (6.3 percent) higher in
the rapid technology case and 1.00 billion barrels (5.4 percent)
lower in the slow technology case than in the reference case. Cumulative
onshore production is about 0.3 percent lower in the rapid oil and
gas technology case and 0.3 percent higher in the slow technology
case than in the reference case.
Alaskan Oil Production
and Oil Imports
Crude Oil Production in Alaska Depends on Oil Price
Assumptions
Alaskan crude oil production is expected mainly on the Alaskan North
Slope, which includes the National Petroleum Reserve-Alaska (NPR-A)
and the State lands surrounding Prudhoe Bay. NPR-A lease sales were
held on May 5, 1999, and June 3, 2002. Because oil and gas producers
are prohibited from building permanent roads in NPR-A, oil exploration
and production is expected to be about 30 percent more expensive
than is typical for the North Slope of Alaska. Because drilling
is currently prohibited in the Arctic National Wildlife Refuge (ANWR),
AEO2004 does not project any production from ANWR.
In the reference case, crude oil production from Alaska
is expected to continue at about 900 thousand barrels per day through
2016 (Figure 98), with a projected drop in North Slope oil production
offset by new oil production from NPR-A. After 2016, total Alaskan
crude oil production is projected to decline, to 510 thousand barrels
per day in 2025. Declining production levels are projected for the
North Slope, NPR-A, and southern Alaskan oil fields from 2016 to
2025.
As in the lower 48 States, oil production in Alaska
is projected to be sensitive to changes in oil prices. Higher prices
make more of the reservoir oil in-place profitable, particularly
in the North Slope heavy oil fields. In the high oil price case,
Alaska’s oil production is above 1 million barrels per day
from 2013 to 2015, then declines to 550 thousand barrels per day
in 2025. In the low price case, with a lower expected reservoir
recovery factor, Alaska’s oil production is projected to fall
below 900 thousand barrels per day after 2009, to 460 thousand barrels
per day in 2025.
Imports Fill the Gap Between Domestic Supply and
Demand
In 2002, net imports of petroleum accounted for 53 percent
of domestic petroleum consumption. Increasing dependence on petroleum
imports is projected, reaching 70 percent in 2025 in the reference
case (Figure 99). The corresponding import shares of total consumption
in 2025 are expected to be 65 percent in the high oil price case
and 75 percent in the low oil price case.
Although crude oil is expected to continue as the
major component of petroleum imports, refined products are projected
to represent a growing share. More imports would be needed as the
projected growth in demand for refined products exceeds the expansion
of domestic refining capacity. Refined products are projected to
make up 13 percent of net petroleum imports in 2025 in the high
oil price case and 25 percent in the high growth case, compared
with 20 percent in the reference case, increasing from a 13-percent
share in 2002 (Table 26).
Petroleum Refining
New U.S. Oil Refining Capacity Is Likely To Be
at Existing Refineries
Falling demand for petroleum and deregulation of
the domestic refining industry in the 1980s led to 13 years
of decline in U.S. refinery capacity. That trend was reversed in
1996, and 1.4 million barrels per day of distillation capacity was
added between 1996 and 2002. Financial and legal considerations
make it unlikely that new refineries will be built in the United
States, but additions at existing refineries are expected to increase
total U.S. refining capacity in all the AEO2004 cases (Figure
100).
Distillation capacity is projected to grow from the
2002 year-end level of 16.8 million barrels per day to 21.8 million
barrels per day in 2025 in the reference case, 20.6 million barrels
per day in the high oil price case, and 23.8 million barrels per
day in the low oil price case, compared with the 1981 peak of 18.6
million barrels per day. Almost all the capacity additions are projected
to occur on the Gulf Coast. Existing refineries are expected to
continue to be utilized intensively (91 to 95 percent of operable
capacity) throughout the forecast. The 2002 utilization rate was
91 percent, well above the lows of 69 percent during the 1980s and
88 percent during the early 1990s but consistent with capacity utilization
rates since the mid-1990s.
Additional “downstream” processing units
are expected to allow domestic refineries to produce less residual
fuel, which has a shrinking market, and more of the higher value
“light products,” such as gasoline, distillate, jet fuel,
and liquefied petroleum gas.
Asia/Pacific Region Is Expected To Surpass
U.S. Refining Capacity
Worldwide crude oil distillation capacity was 81.9
million barrels per day at the end of 2002. To meet the growth in
international oil demand in the reference case, worldwide refining
capacity is expected to increase by about 53 percent—to more
than 125 million barrels per day—by 2025. Substantial growth
in distillation capacity is expected in the Middle East, Central
and South America, and the Asia/Pacific region (Figure 101).
The Asia/Pacific region has been the fastest growing
refining center over the past decade. In the mid-1990s, it surpassed
Western Europe as the world’s second largest refining center
(after North America) in terms of distillation capacity; and in
2002, the Asia/ Pacific region surpassed even North America. While
not adding significantly to their distillation capacity, refiners
in the United States and Europe have tended to improve product quality
and enhance the usefulness of heavier oils through investment in
downstream capacity.
Future investments in the refinery operations of
developing countries must include configurations that are more advanced
than those currently in operation. Their refineries will be called
upon to meet increased worldwide demand for lighter products, to
upgrade residual fuel, to supply transportation fuels with reduced
lead, and to supply both distillate and residual fuels with lower
sulfur levels. An additional burden on new refineries will be the
need to supply lighter products from crude oils whose quality is
expected to deteriorate over the forecast period.
Refined Petroleum Products
Petroleum Use Increases Mainly in the Transportation
Sector
U.S. petroleum consumption is projected to increase
by 8.7 million barrels per day from 2002 to 2025. Most of the
increase is in the transportation sector, which accounted for two-thirds
of U.S. petroleum use in 2002 (Figure 102). Petroleum use for transportation
increases by 7.1 million barrels per day in the reference case,
as the number and usage of vehicles grow. In the industrial sector,
which currently accounts for 24 percent of U.S. petroleum use, consumption
in 2025 is projected to be higher than in 2002 by 1.4 million barrels
per day in the reference case.
In the reference case, distillate oil use for home
heating is expected to decline as oil loses market share to liquefied
petroleum gas (LPG), natural gas and electricity. Petroleum use
for electricity generation peaks in 2015 and then declines to 14,000
barrels per day below 2002 levels. Increased oil use for heating
and electricity generation is projected, however, in the low oil
price case. In the low oil price case, natural gas use for home
heating is projected to grow in the Northeast, the last stronghold
of home heating oil. Compared with 2002, U.S. residential and commercial
heating oil use is projected to be 29,000 barrels per day lower
in 2025 in the high oil price case and 147,000 barrels per day higher
in the low oil price case. For electricity generation, oil- and
gas-fired steam plants are being retired in favor of natural gas
combined-cycle units. Oil use for electricity generation (excluding
combined heat and power) is projected to be 176,000 barrels per
day lower in 2025 than in 2002 in the high price case and 1.5 million
barrels per day higher in the low price case.
Light Products Account for Most of the Increase
in Demand for Petroleum
About 93 percent of the projected growth in petroleum
consumption consists of increased consumption of “light products,”
including gasoline, diesel, heating oil, jet fuel, kerosene, liquefied
petroleum gases, and petrochemical feedstocks, which are more difficult
and costly to produce than heavy products (Figure 103). Although
refinery investments and enhancements are expected to increase the
ability of domestic refineries to produce light products, imports
of light products are expected to more than double by 2025.
In the forecast, gasoline continues to account for
about 47 percent of all the petroleum used in the United States.
From 2002 to 2025, U.S. gasoline consumption is projected to rise
from 8.9 million barrels per day to 13.3 million barrels per day.
Consumption of distillate fuel is projected to be 2.0 million barrels
per day higher in 2025 than it was in 2002. An even greater percentage
increase is projected for diesel fuel, as a larger portion of total
distillate supply is used for diesel production and less is used
in other sectors. With air travel also expected to increase, jet
fuel consumption is projected to be 759,000 barrels per day higher
in 2025 than in 2002. Consumption of LPG is projected to increase
by about 689,000 barrels per day from 2002 to 2025, largely for
use as a feedstock in the industrial sector. Consumption of “other”
petroleum products—including LPG, petrochemical feedstocks,
still gas used to fuel refineries, asphalt and road oil, and other
miscellaneous products—is projected to grow by 1.4 million
barrels per day. Residual fuel use is projected to increase slightly,
from about 700,000 barrels per day in 2002 to 751,000 barrels per
day in 2025, mostly for fuel in the electricity generation sector.
State Bans on MTBE Are Expected To Result
in Increased Use of Ethanol
U.S. ethanol production, with corn as the primary
feedstock, totaled 139,000 barrels per day in 2002. Production is
projected to increase to 278,000 barrels per day in 2025 (Figure
104), with about 27 percent of the growth from conversion of cellulosic
biomass (such as wood and agricultural residues). Ethanol is used
primarily in the Midwest as a gasoline volume extender and octane
enhancer and also serves as an oxygenate in areas that are required
to use oxygenated fuels (minimum 2.7 percent oxygen content by volume)
during the winter months to reduce carbon monoxide emissions. The
high renewables case projects similar production, but all the projected
growth is from cellulose, due to more rapid improvement in the technology.
In the reference case, corn-based ethanol production drops from
100 percent of total ethanol output in 2009 to 86 percent in 2025.
Ethanol is expected to replace MTBE as the oxygenate
for reformulated gasoline (RFG) in 17 States that have placed limits
on MTBE use mainly because of concerns about groundwater contamination.
It is assumed that the Federal requirement for 2 percent oxygen
in RFG will continue in all States. Ethanol consumption in E85 vehicles
is also projected to increase, from the national total of 7.8 million
gallons in 2002 to 42 million gallons in 2025.
The Federal Highway Bill of 1998 extended the excise
tax exemption for ethanol through 2007 with reductions from 54 cents
per gallon to 53 cents in 2001, 52 cents in 2003, and 51 cents in
2005. It is assumed that the exemption will continue to be extended
at 51 cents per gallon (nominal dollars).
Refining Costs for Most Petroleum Products Rise
in the Forecast
Refined product prices are determined by crude oil
costs, refining process costs (including refiner profits), marketing
costs, and taxes (Figure 105). In the AEO2004 projection,
crude oil continues as the largest part of product prices. Marketing
costs remain stable, but the contributions of processing costs and
taxes are projected to change considerably.
Refining costs for gasoline and diesel fuel, including
processing costs and profits, are expected to increase by 12 cents
a gallon from 2002 to 2025 (2002 dollars), primarily due to growth
in demand for gasoline and diesel fuels and new Federal requirements
for low-sulfur gasoline (2004 to 2007) and ultra-low-sulfur diesel
fuel (2006 to 2010). Refining costs for heating oil and jet fuel
fall by 2.6 to 2.8 cents a gallon from 2002 to 2025. Tighter gasoline
and diesel specifications cause some refiners to shift production
from gasoline and diesel to jet fuel and heating oil, which have
less stringent specifications.
Whereas processing costs tend to increase refined
product prices in the forecast, the assumption that Federal motor
fuel taxes remain at nominal 2002 levels tends to reduce prices.
Although Federal motor fuel taxes have been raised occasionally
in the past, the assumption of constant nominal Federal taxes is
consistent with history. The net impact of the assumption is an
expected decrease in Federal taxes (in 2002 dollars) from 2002 to
2025—9 cents per gallon for gasoline, 12 cents for diesel fuel,
and 2 cents for jet fuel. State motor fuels taxes are assumed to
keep up with inflation, as they have in the past.
Notes and Sources
Released: January 2004
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