Energy Trends to 2030
In preparing projections for the
Annual Energy Outlook 2008 (AEO2008), the Energy Information
Administration (EIA) evaluated a wide range of trends and
issues that could have major implications for U.S. energy
markets between today and 2030. This overview focuses on one
case, the reference case, which is presented and compared
with the Annual Energy Outlook 2007 (AEO2007) reference case
(see Table 1). Readers are encouraged to review the full
range of alternative cases included in other sections of
AEO2008.
As in previous editions of the
Annual Energy Outlook (AEO), the reference case assumes that
current policies affecting the energy sector remain
unchanged throughout the projection period. The reference
case provides a clear basis against which alternative cases
and policies can be compared. Although current laws and
regulations may change over the next 25 years, and new ones
may be created, it is not possible to predict what they will
be or how they will be implemented [1].
EIA published an “early release”
version of the AEO2008 reference case in December 2007.
Later that month, the Energy Independence and Security Act
of 2007 (EISA2007) was enacted. The provisions in EISA2007
will have a major impact on energy markets, particularly
liquid fuels. Given the year-long life of AEO2008 and its
use as a baseline for analyses of proposed policy changes,
EIA decided to update the reference case to reflect the
provisions of EISA2007. A short summary of the impact of
including EISA2007 is provided.
Trends in energy supply and demand
are affected by many factors that are difficult to predict,
including energy prices, U.S. and worldwide economic growth,
advances in technologies, and future public policy decisions
both in the United States and in other countries. As noted
in AEO2007, energy markets are changing in response to
readily observable factors, which include, among others:
higher energy prices; the growing influence of developing
countries on worldwide energy requirements; recently enacted
legislation and regulations in the United States; changing
public perceptions on issues related to emissions of air
pollutants and greenhouse gases and the use of alternative
fuels and; and the economic viability of various energy
technologies.
Projections in the AEO2008 reference
case have been updated to better reflect trends that are
expected to persist in the economy and in energy markets.
For example, the projection for U.S. economic growth, a key
determinant of U.S. energy demand, is lower in AEO2008 than
it was in AEO2007, reflecting an updated assumption for
productivity improvement. Other key changes in the AEO2008
projections include:
- Higher price projections for
crude oil and natural gas
- Higher projections for
delivered energy prices, reflecting both higher wellhead
and minemouth prices and higher costs to transport,
distribute, and refine fuels per unit supplied
- Slower projected growth in
energy demand (particularly for natural gas but also for
liquid fuels and coal)
- Faster projected growth in the
use of nonhydroelectric renewable energy, resulting from
a revised representation of State renewable portfolio
standard (RPS) provisions
- Higher projections for domestic
oil production, particularly in the near term
- Slower projected growth in
energy imports, both natural gas and oil
- Slower projected growth in
energy-related emissions of carbon dioxide (CO2).
Coal, liquid fuels (excluding the
biofuels portion of to-tal liquids supply), and natural gas
meet 80 percent of total U.S. primary energy supply
requirements in 2030—down from an 85-percent share in 2006,
reflecting the incorporation of EISA2007 provisions, slower
economic growth, higher energy prices, lower total energy
demand, and increased use of renewable energy when compared
with AEO2007.
Energy Industry Economic Growth
The AEO2008 reference case reflects
reduced expectations for economic growth: U.S. gross
domestic product (GDP) grows at an average annual rate of
2.4 percent from 2006 to 2030—0.4 percentage points slower
than the rate in the AEO2007 reference case over the same
period. The main factor contributing to the slower rate of
growth in GDP is a lower estimate of growth in labor
productivity. Nonfarm business labor productivity grows by
1.9 percent per year in the AEO2008 reference case, compared
with 2.3 percent per year in AEO2007. Nonfarm employment
growth is 0.9 percent per year in the AEO2008 reference
case, about the same as in AEO2007. From 2006 to 2030, total
industrial shipments grow by 1.3 percent per year in the
AEO2008 reference case, as compared with 2.0 percent per
year in AEO2007.
Energy Prices
EIA raised the reference case path
for world oil prices in AEO2008 (although the upward
adjustment is smaller than the last major adjustment,
introduced in AEO2006). The real world crude oil price
(which for the purposes of AEO2008 is defined as the price
of light, low-sulfur crude oil delivered in Cushing,
Oklahoma, in 2006 dollars) declines gradually from current
levels to $57 per barrel in 2016 ($68 per barrel in nominal
dollars), as expanded investment in exploration and
development brings new supplies to world markets. After
2016, real prices begin to rise (Figure 1), as demand
continues to grow and higher cost supplies are brought to
market. In 2030, the average real price of crude oil is $70
per barrel in 2006 dollars, or about $113 per barrel in
nominal dollars. Alternative AEO2008 cases address higher
and lower world crude oil prices.
In developing its oil price outlook,
EIA explicitly considered four factors: (1) growth in world
liquids consumption; (2) the outlook for conventional oil
production in countries outside the Organization of the
Petroleum Exporting Countries (OPEC); (3) growth in
unconventional liquids production; and (4) OPEC behavior.
With the forces driving demand outside the United States as
strong as, or stronger than, previously expected but with
global supply projections somewhat weaker, oil prices in
AEO2008 are higher than projected in AEO2007 [2].
As a result of recent strong
economic growth world-wide, transitory shortages of
experienced personnel, equipment, and construction materials
in the oil industry, and political instability in some major
producing regions, oil prices currently are above EIA’s
estimate of the long-run equilibrium price. EIA’s
expectations regarding the ultimate size of both
conventional and unconventional liquid resources have not
changed since last year’s AEO.
The AEO2008 reference case
represents EIA’s current judgment about the most likely
behavior of key OPEC members in the mid-term. In the
projection, OPEC countries increase production at a rate
that keeps their market share of world liquids production at
approximately 40 percent through 2030.
The AEO2008 reference case also
projects significant long-term potential for supply from
non-OPEC producers. In several resource-rich
regions—including Brazil, Azerbaijan, and Kazakhstan—high
oil prices, expanded infrastructure, and new exploration and
drilling technologies permit additional non-OPEC oil
production. Also, with the economic viability of Canada’s
oil sands enhanced by higher world oil prices and advances
in production technology, oil sands production is expected
to reach 4 million barrels per day in 2030.
The price of natural gas also is
higher in the AEO2008 reference case. The real wellhead
price of natural gas (in 2006 dollars) declines from current
levels through 2016, as new supplies enter the market. After
some fluctuations through 2021, real natural gas prices rise
to $6.63 per thousand cubic feet in 2030 ($10.64 per
thousand cubic feet in nominal dollars). The higher prices
in the AEO2008 reference case reflect an increase in
production costs associated with recent trends that were
discussed in AEO2007 but were not reflected fully in the
AEO2007 reference case [3]. The higher natural gas prices
also are supported by higher oil prices.
Minemouth coal prices in the AEO2008
reference case, both nationally and regionally, are
generally similar to those projected in the AEO2007
reference case. By region, the largest price difference is
for Wyoming’s Powder River Basin, where the projected
average minemouth price in 2030 is 12.1 percent above the
AEO2007 projection, at $0.66 (2006 dollars) per million
British thermal units (Btu), reflecting a less optimistic
outlook for improvements in coal mining productivity.
Average real minemouth coal prices
(in 2006 dollars) fall from $1.21 per million Btu ($24.63
per short ton) in 2006 to $1.14 per million Btu ($22.45 per
short ton) in 2018 in the AEO2008 reference case, as prices
moderate following a substantial run-up over the past few
years. After 2020, coal prices rise as demand increases,
reaching $1.19 per million Btu ($23.32 per short ton) in
2030. The 2020 and 2030 price projections are 2.6 percent
and 0.9 percent higher, respectively, than those in the
AEO2007 reference case. Without adjustment for inflation,
the average mine-mouth price of coal in the AEO2008
reference case is $1.91 per million Btu ($37.42 per ton) in
2030.
AEO2008 projects higher prices for
most energy fuels delivered to consumers. For example, in
2030, the average delivered price of natural gas (in 2006
dollars) is more than $1 per million Btu higher in the
AEO2008 reference case than was projected in AEO2007. In
part, the higher delivered prices result from higher prices
paid to fossil fuel producers at the wellhead or minemouth;
but they also result from updates made to assumptions about
the costs to transport, distribute, and refine the fuels to
make them more consistent with recent trends. For example,
as a result of declining use per customer and the growing
cost of bringing supplies from new regions to market,
margins between the delivered and wellhead prices of natural
gas are higher than previously projected. Factors
contributing to higher margins for liquid fuels include
continued growth in the use of heavier and sourer crudes,
growing demand for cleaner products, and the rising cost of
refinery safety and emissions abatement.
Increases in diesel fuel prices in
recent years have led railroads to implement fuel adjustment
surcharges on coal shipments, which are incorporated in the
AEO2008 reference case. The average real delivered price of
coal to power plants (in 2006 dollars) increases from $1.69
per million Btu ($33.85 per short ton) in 2006 to $1.78 per
million Btu ($35.03 per short ton) in 2030, 2.3 percent
higher than in the AEO2007 reference case. In nominal
dollars, the average delivered price of coal to power plants
is projected to reach $2.86 per million Btu ($56.22 per
short ton) in 2030.
Electricity prices follow trends in
the delivered prices of fuels to power plants in the
reference case. From a peak of 9.3 cents per kilowatthour
(2006 dollars) in 2009, average delivered electricity prices
decline to 8.5 cents per kilowatthour in 2015 and then
increase to 8.8 cents per kilowatthour in 2030. In the
AEO2007 reference case, with slightly lower expectations for
delivered fuel prices and construction costs for all new
technologies, electricity prices reached 8.3 cents per
kilowatthour (2006 dollars) in 2030. In nominal dollars, the
average delivered electricity price in the AEO2008 reference
case reaches 14.1 cents per kilowatthour in 2030.
Energy Consumption by Sector
Total primary energy consumption in
the AEO2008 reference case grows by 19 percent between 2006
and 2030 (an average rate of 0.7 percent per year), from
99.5 quadrillion Btu in 2006 to 118.0 quadrillion Btu in
2030—13.2 quadrillion Btu less than in the AEO2007 reference
case. In 2030, the levels of consumption projected for
liquid fuels, natural gas, and coal are lower in the AEO2008
reference case than they were in the AEO2007 reference case.
Among the most important factors leading to lower total
energy demand in the AEO2008 reference case are lower
economic growth, greater use of more efficient appliances
and vehicles, higher energy prices, and slower growth in
energy-intensive industries.
Residential delivered energy
consumption in the AEO2008 reference case grows from 10.8
quadrillion Btu in 2006 to 12.9 quadrillion Btu in 2030, or
by 0.7 percent per year (Figure 2). Higher delivered energy
prices, slower growth in the housing stock, increases in
lighting efficiency to meet the standards estab-lished in
EISA2007, and a revised accounting of heating and cooling
degree-days to better reflect recent temperature trends
contribute to the lower level of residential energy use in
the AEO2008 projection, which is 0.9 quadrillion Btu lower
than the AEO2007 projection.
Higher delivered energy prices and
slower growth in commercial square footage lead to slower
growth in commercial energy consumption in the AEO2008
reference case than in the AEO2007 reference case. Delivered
commercial energy consumption grows from 8.3 quadrillion Btu
in 2006 to 11.3 quadrillion Btu in 2030, over 1 quadrillion
Btu less than in the AEO2007 reference case.
Since 1997, delivered energy
consumption in the U.S. industrial sector has trended
downward, falling from about 27 quadrillion Btu in 1997 to
25 quadrillion Btu in 2006, despite rising output. A number
of factors have worked to reduce industrial energy
consumption since 1997: economic weakness between 2000 and
2003, the hurricanes of 2005 that reduced activity in some
industrial subsectors, and rising energy prices.
Industrial delivered energy
consumption increases to 27.7 quadrillion Btu in 2030.
Although the AEO2008 reference case includes steady economic
growth and declining energy prices in the near term, growth
in the energy-intensive industries continues to be weak,
reflecting increased competition from foreign regions with
lower relative energy prices. Growth in the energy-intensive
U.S. manufacturing industries averages 0.7 percent per year
from 2006 to 2030, slower than the 1.3-percent average
growth in AEO2007.
Delivered energy consumption in the
transportation sector grows to 33.0 quadrillion Btu in 2030
in the AEO2008 reference case, 6.3 quadrillion Btu less than
in AEO2007. The lower projected level of consumption
predominantly reflects the influence of the new corporate
average fuel economy (CAFE) standard for light-duty vehicles
(LDVs) specified in EISA2007 and slower economic growth, as
well as the impact of higher fuel prices.
EISA2007 requires new LDVs,
including both cars and trucks, to reach a combined average
fuel economy of 35 miles per gallon (mpg) by 2020, based on
the U.S. Environmental Protection Agency (EPA) test value
used to measure compliance with the CAFE standard. The EPA
CAFE test value generally differs from the estimated mpg
value on the fuel economy label and, typically, exceeds the
actual on-the-road fuel economy of a new vehicle by a
significant margin. Despite these differences, the higher
fuel economy standards in EISA2007 significantly improve the
in-use fuel economy of the LDV stock. In the reference case,
the average in-use fuel economy for the stock of LDVs in
2030 increases to 27.9 miles per gallon, almost 40 percent
above its 2006 level. To attain these fuel economy levels,
the projection reflects increases in the sale of
unconventional vehicle technologies [4], such as flex-fuel,
hybrid, and diesel vehicles, and a slowdown in the growth of
new light truck sales.
Energy Consumption by Primary Fuel
Total consumption of liquid fuels,
including both fos-sil liquids and biofuels, grows from 20.7
million bar-rels per day in 2006 to 22.8 million barrels per
day in 2030 in the AEO2008 reference case (Figure 3), less
than the AEO2007 reference case projection of 26.9 million
barrels per day in 2030. Liquid fuels consump-tion is lower
in all sectors in AEO2008 than in the AEO2007 reference
case, as a result of incorporation of the new LDV CAFE
standard specified in EISA2007, slower economic growth, and
higher deliv-ered prices for liquid fuels. Much of the
difference is in the transportation sector.
In AEO2008, natural gas consumption
increases from 21.7 trillion cubic feet in 2006 to 23.8
trillion cubic feet in 2016, then declines to 22.7 trillion
cubic in 2030 (Figure 3). The projection for natural gas
consumption in the AEO2008 reference case is sharply lower
than in AEO2007, where consumption grew to 26.1 trillion
cubic feet in 2030. Consumption is lower in all sectors in
AEO2008, and particularly in the industrial and electricity
power sectors. Industrial natural gas use is 1.7 trillion
cubic feet lower in 2030 in the AEO2008 reference case (8.1
trillion cubic feet, compared with 9.8 trillion cubic feet
in AEO2007), as a result of higher delivered prices for
natural gas, lower economic growth, and a reassessment of
natural gas use in the energy-intensive industries. In
AEO2008, electricity generation accounts for 5.0 trillion
cubic feet of natural gas use in 2030, compared with the
AEO2007 projection of 5.9 trillion cubic feet. The lower
level of consumption in AEO2008 results from higher natural
gas prices and slower growth in electricity demand.
Total coal consumption increases
from 22.5 quadrillion Btu (1,114 million short tons) in 2006
to 29.9 quadrillion Btu (1,545 million short tons) in 2030
in the AEO2008 reference case. As in the AEO2007 reference
case, coal consumption is projected to grow at a faster rate
toward the end of the projection period, particularly after
2020, as coal use for new coal-fired generating capacity
grows rapidly. In the AEO2008 reference case, coal
consumption in the electric power sector increases from 23.7
quadrillion Btu in 2020 to 27.5 quadrillion Btu in 2030, and
coal use at CTL plants increases from 0.6 quadrillion Btu in
2020 to 1.0 quadrillion Btu in 2030. The projected increase
in coal use for CTL plants is lower than in previous AEOs as
a result of EISA2007, because investment dollars that
previously would have gone into CTL capacity now flow to
biomass-to-liquids (BTL) capacity; however, there is a great
deal of uncertainty around this projection.
The AEO2008 reference case projects
substantially greater use of renewable energy than was
projected in AEO2007. Total consumption of marketed
renewable fuels—including ethanol for gasoline blending,
biodiesel [5], and diesel from biomass [6], of which 2.8
quadrillion Btu in 2030 is included with liquids fuel
consumption—grows by 3.0 percent per year in the reference
case, from 6.8 quadrillion Btu in 2006 to 13.7 quadrillion
Btu in 2030, compared with 9.9 quadrillion Btu in AEO2007.
About 45 percent of the demand for renewables in 2030 is for
grid-related electricity generation (including combined heat
and power).
The rapid growth in the use of
renewable fuels for transportation in AEO2008 reflects the
EISA2007 RFS, which sets a requirement for 21 billion
gallons of advanced biofuels and 36 billion gallons of total
renewable fuels by 2022. Included are requirements for 1
billion gallons of biodiesel and 16 billion gallons of
cellulosic biofuels, both of which count toward the advanced
biofuels requirement. The remaining 4 billion gallons of
advanced biofuels may come from any source. The difference
between advanced biofuels and total renewable fuels may be
met by corn ethanol. Diesel fuels derived from biomass
feedstocks count for 1.5 times their physical volume in the
calculation of credits toward the RFS requirements, because
die-sel has a higher energy content per gallon than ethanol
does.
Although the situation is very
uncertain, the current state of the industry and EIA’s
present view of projected rates of technology development
and market penetration of cellulosic biofuel technologies
suggest that available quantities of cellulosic biofuels
before 2022 will be insufficient to meet the new RFS targets
for cellulosic biofuels, triggering both waivers and a
modification of applicable volumes, as provided for in
Section 211(o) of the Clean Air Act as amended by EISA2007.
The modification of volumes reduces the overall target in
2022 from 36 billion gallons to 32.5 billion gallons in the
AEO2008 reference case.
Ethanol use in the AEO2008 reference
case, grows from 5.6 billion gallons in 2006 to 23.9 billion
gallons in 2030—about 16 percent of total gasoline
consumption by volume and about 65 percent more than in
AEO2007. Ethanol use for gasoline blending grows to 13.4
billion gallons and E85 consumption to 10.5 billion gallons
in 2030. The ethanol supply is expected to be produced from
both corn and cellulose feedstocks, with corn accounting for
15.0 billion gallons and cellulose 6.9 billion gallons of
ethanol production in 2030. Biodiesel use increases to 1.2
billion gallons in 2030, or about 1.5 percent of total
diesel consumption by volume. In addition, consumption of
BTL diesel grows to 4.5 billion gallons in 2030, or 5.3
percent of total diesel consumption by volume.
Excluding hydroelectricity,
renewable energy con-sumption for electric power generation
grows from 0.9 quadrillion Btu in 2006 to 3.2 quadrillion
Btu in 2030, as compared with 2.1 quadrillion Btu in
AEO2007. The higher level of nonhydroelectric renewable
energy consumption in the AEO2008 reference case reflects
primarily a revised representation of State RPS programs,
which require that specific and gener-ally increasing shares
of electricity sales be supplied by renewable resources,
such as wind, solar, geothermal, and sometimes biomass or
hydropower. Previous AEOs placed more weight on the “escape
clauses” incorporated in many State RPS programs, given that
the consumer costs of the programs would increase
significantly if the Federal production tax credit (PTC) for
qualifying renewable energy expired as provided for under
current law. The new representation, which assumes that the
State RPS goals will be met absent a clear contrary
indication, results in significant additional growth of
renewable generation from wind, biomass, and geothermal
resources.
Energy Intensity
Energy intensity, measured as
primary energy use (in thousand Btu) per dollar of GDP (in
2000 dollars), declines by about one-third from 2006 to 2030
in the AEO2008 reference case (Figure 4). Although energy
use generally increases as the economy grows, continuing
improvement in the energy efficiency of the U.S. economy and
a shift to less energy-intensive activities are projected
to keep the rate of energy consumption growth lower than the
rate of GDP growth.
Since 1992, the energy intensity of
the U.S. economy has declined on average by 2.0 percent per
year, in part because the share of industrial shipments
accounted for by the energy-intensive industries has fallen
from 30 percent in 1992 to 21 percent in 2006. In the
AEO2008 reference case, the energy-intensive industries’
share of total industrial shipments continues to decline,
although at a slower rate, to 18 percent in 2030.
Population is a key determinant of
energy consumption, influencing demand for travel, housing,
consumer goods, and services. Since 1990, the population has
increased by about 20 percent and energy consumption by a
comparable 18 percent in the United States, with annual
variations in energy use per capita resulting from
variations in weather and economic factors. The age, income,
and geographic distribution of the population also affect
the growth of energy consumption. Aging of the population, a
gradual shift from the North to the South, and rising per
capita income will influence future trends. Overall, the
U.S. population increases by 22 percent from 2006 to 2030 in
the AEO2008 reference case. Over the same period, energy
consumption increases by 19 percent. The result is a
decrease in energy consumption per capita at an annual rate
of 0.1 percent per year from 2006 to 2030, a drop from the
0.3-percent yearly increase in the AEO2007 reference case.
Recently, as energy prices have
risen, the potential for more energy conservation has
received increased attention. Although additional energy
conservation is induced by higher energy prices in the
AEO2008 reference case and by the passage of EISA2007, no
further policy-induced conservation measures are assumed
beyond those in existing legislation and regulation, nor
does the reference case assume behavioral changes beyond
those observed in the past.
Energy Production and Imports
Net imports of energy are expected
to continue meeting a major share of total U.S. energy
demand (Figure 5). The increased use of biofuels resulting
from EISA2007, much of which is domestically produced, and
the reduction in demand for transportation fuels due to the
new CAFE standards both serve to moderate growth in energy
imports. Higher fuel prices over the projection period also
spur increased domestic energy production (Figure 6) and
moderate energy demand growth, further tempering growth in
imports. The projected net import share of total U.S. energy
consumption in 2030 is 27 percent, a decline from the
30-percent share in 2006.
The projection for U.S. crude oil
production in the AEO2008 reference case is higher than in
the AEO2007 reference case, primarily as a result of more
production from the expansion of enhanced oil recovery (EOR)
operations and, to a lesser extent, higher crude oil prices.
U.S. crude oil production in the AEO2008 reference case
increases from 5.1 million barrels per day in 2006 to a peak
of 6.3 million barrels per day in 2018, with production
increases from the deep waters of the Gulf of Mexico and
from onshore EOR projects. Domestic production subsequently
declines to 5.6 million barrels per day in 2030, as
increased production from new, smaller discoveries is
inadequate to offset declines in production from large
fields in Alaska and the Gulf of Mexico.
Total domestic liquids supply,
including crude oil, natural gas plant liquids, refinery
processing gains, and other refinery inputs (including
ethanol, bio-diesel, BTL, and liquids from coal) generally
increase through 2022 in the AEO2008 reference case, while
imports of crude oil and other petroleum products remain
flat. Total domestic liquids supply grows from 8.2 million
barrels per day in 2006 to 10.4 million bar-rels per day in
2030.
In the AEO2008 reference case, the
net import share of total liquids supplied, including crude
oil and refined products, drops from 60 percent in 2006 to
51 percent in 2022 and then increases to 54 percent in 2030.
Net imports of crude oil and net imports of petroleum
products in 2030 each are about 2.0 million barrels per day
lower in the AEO2008 reference case than in the AEO2007
reference case. The primary reasons for the difference
between the AEO2008 and AEO2007 projections for net imports
of liquid fuels are a lower level of total liquids
consumption and a higher level of biofuels consumption in
the transpor-tation sector in the AEO2008 reference case.
Total domestic production of natural
gas (including supplemental natural gas supplies) increases
from 18.6 trillion cubic feet in 2006 to 20.0 trillion cubic
feet in 2022 before declining to 19.5 trillion cubic feet in
2030 in the AEO2008 reference case. The projections are
lower than in the AEO2007 reference case, which showed
production increasing to 20.6 trillion cubic feet in 2030,
primarily because of higher costs associated with
exploration and development and, particularly in the last
decade of the projection, lower demand for natural gas in
AEO2008. Onshore production of unconventional natural gas is
expected to be a key contributor to the growth in U.S.
supply, increasing from 8.5 trillion cubic feet in 2006 to a
peak of 9.6 trillion cubic feet in 2018 and generally
holding at about that level through 2030.
The Alaska natural gas pipeline is
expected to be completed in 2020 (2 years later than in the
AEO2007 reference case, because of delays in the resolution
of issues between Alaska’s State government and industry
participants). After the pipeline goes into operation,
Alaska’s total natural gas production in the AEO2008
reference case increases to 2.0 trillion cubic feet in 2021
(from 0.4 trillion cubic feet in 2006) and then remains at
that level through 2030.
Net pipeline imports of natural gas
from Canada and Mexico fall from 2.9 trillion cubic feet in
2006 to 0.3 trillion cubic feet in 2030 in the AEO2008
reference case (compared with the AEO2007 projection of 0.9
trillion cubic feet in 2030). The difference between the
2030 projections in AEO2008 and AEO2007 is largely the
result of a higher level of exports to Mexico and lower
demand in the United States.
Total net imports of liquefied
natural gas (LNG) to the United States in the AEO2008
reference case increase from 0.5 trillion cubic feet in 2006
to 2.8 trillion cubic feet in 2030, as compared with 4.5
trillion cubic feet in 2030 in AEO2007. The lower projection
is attributable to two factors: higher costs throughout the
LNG industry, especially in the area of liquefaction, and
decreased U.S. natural gas con-sumption due to higher
natural gas prices, slower eco-nomic growth, and expected
greater competition for supplies in the global LNG market.
The future direction of the global
LNG market is one of the key uncertainties in the AEO2008
reference case. With many new international players entering
LNG markets, the competition for available supplies is
strong, and the amounts available to the U.S. mar-ket may
vary considerably from year to year. The AEO2008 reference
case has been updated to reflect current market dynamics,
which could change considerably as worldwide LNG markets
evolve.
As domestic coal demand grows in the
AEO2008 ref-erence case, U.S. coal production (excluding
waste coal) increases at an average rate of 0.8 percent per
year, from 23.8 quadrillion Btu (1,163 million short tons)
in 2006 to 28.6 quadrillion Btu (1,455 million short tons)
in 2030—15 percent less than in the AEO2007 reference case.
Production from mines west of the Mississippi River provides
the largest share of the incremental coal production. On a
Btu basis, 59 percent of domestic coal production originates
from States west of the Mississippi River in 2030, up from
49 percent in 2006.
Typically, trends in U.S. coal
production are linked to its use for electricity generation,
which currently accounts for 91 percent of total coal
consumption. Coal consumption in the electric power sector
in the AEO2008 reference case, at 27.5 quadrillion Btu in
2030, is less than in the AEO2007 reference case (31.1
quadrillion Btu in 2030). Slower growth in overall
electricity demand, combined with more generation from
nuclear and renewable energy, underlies the reduced outlook
for electricity sector coal consumption. Another emerging
market for coal is CTL. Coal use in CTL plants grows from
0.6 quadrillion Btu (42 million short tons) in 2020 to 1.0
quadrillion Btu (64 million short tons) in 2030.
Electricity Generation
Total electricity consumption,
including both purchases from electric power producers and
on-site generation, grows from 3,814 billion kilowatthours
in 2006 to 4,972 billion kilowatthours in 2030, increasing
at an average annual rate of 1.1 percent in the AEO2008
reference case. In comparison, electricity consumption grew
by annual rates of 4.2 percent, 2.6 percent, and 2.3 percent
in the 1970s, 1980s, and 1990s, respectively. The growth
rate in the AEO2008 projection is lower than in the AEO2007
reference case (1.5 percent per year). The reduced rate of
growth in AEO2008 results from slower economic growth, the
imposition of new efficiency standards in EISA2007, and
higher electricity prices.
In the AEO2008 reference case,
electricity generation from natural-gas-fired power plants
increases sharply from 2006 to 2008 and then remains
relatively stable for the next decade, growing by 3 percent
from 2008 to 2016—less rapidly than in the AEO2007 reference
case. After 2016, however, generation from new coal,
nuclear, and renewable plants displaces some
natural-gas-fired generation (Figure 7). In the AEO2008
reference case, 741 billion kilowatthours of electricity is
generated from natural gas in 2030, 21 percent less than the
937 billion kilowatthours in 2030 in the AEO2007 reference
case.
In the AEO2008 reference case, the
natural gas share of electricity generation (including
generation in the end-use sectors) remains between 20
percent and 21 percent through 2017 before falling to 14
percent in 2030. The coal share remains between 48 percent
and 49 percent from 2006 through 2018 before increasing to
54 percent in 2030. Additions to coal-fired generating
capacity in the AEO2008 reference case total 104 gigawatts
from 2006 to 2030 (as compared with 151 gigawatts in the
AEO2007 reference case), including 4 gigawatts at CTL plants
and 29 gigawatts at integrated gasification combined-cycle
plants. Given the assumed continuation of current energy and
environmental policies in the reference case, carbon capture
and sequestration (CCS) technology does not come into use
during the projection period.
Nuclear generating capacity in the
AEO2008 reference case increases from 100.2 gigawatts in
2006 to 114.9 gigawatts in 2030. The increase includes 17
gigawatts of capacity at newly built nuclear power plants
(33 percent more than in the AEO2007 reference case) and 2.7
gigawatts expected from uprates of existing plants,
partially offset by 4.5 gigawatts of retirements.
Rules issued by the Internal Revenue
Service in 2006 for the Energy Policy Act of 2005
(EPACT2005) production tax credit for new nuclear plants
allow the credits to be shared out on a prorated basis to
more than 6 gigawatts of new capacity. In the AEO2008
reference case the credits are shared out to 8 gigawatts of
new nuclear capacity, and another 9 gigawatts of capacity is
built without credits.
Total electricity generation from
nuclear power plants grows from 787 billion kilowatthours in
2006 to 917 billion kilowatthours in 2030 in the AEO2008
reference case, accounting for about 18 percent of total
generation in 2030. Additional nuclear capacity is built in
some of the alternative AEO2008 cases, particularly those
that project higher demand for electricity or higher fossil
fuel prices.
The use of renewable technologies
for electricity generation is stimulated by improved
technology, higher fossil fuel prices, and short-term
extensions of the EPACT2005 tax credits. The reference case
also includes State RPS programs for which legislation is in
place. Total renewable generation in the AEO2008 reference
case, including combined heat and power (CHP) and end-use
generation, grows by 2.2 percent per year, from 385 billion
kilowatthours in 2006 to 656 billion kilowatthours in 2030.
The projection for renewable generation in the AEO2008
reference case, which includes State and regional programs,
is significantly higher than the AEO2007 projection.
Energy-Related Carbon Dioxide
Emissions
Absent the application of CCS
technology (which is not expected to come into use without
changes in current policies that are not included in the
reference case), CO2 emissions from the combustion of fossil
fuels are proportional to fuel consumption and carbon
content, with coal having the highest carbon content,
natural gas the lowest, and liquid fuels in between. In the
AEO2008 reference case, the coal share of total energy use
increases from 23 percent in 2006 to 25 percent in 2030,
while the share of natural gas falls from 22 percent to 20
percent, and the liquids share falls from 40 percent to 37
percent. The combined share of carbon-neutral renewable and
nuclear energy grows from 15 percent in 2006 to 17 percent
in 2030.
Taken together, projected growth in
the absolute level of primary energy consumption and a shift
toward a fuel mix with slightly lower average carbon content
cause projected energy-related emissions of CO2 (Figure 8)
to grow by 16 percent from 2006 to 2030—slightly lower than
the projected 19-percent increase in total energy use. Over
the same period, the economy becomes less carbon-intensive,
because the 16-percent increase in CO2 emissions is about
one-fifth of the projected increase in GDP (79 per-cent),
and emissions per capita decline by 5 percent. In the
AEO2008 reference case, projected energy-related CO2
emissions grow from 5,890 million metric tons in 2006 to
6,851 million metric tons in 2030. By comparison, in the
AEO2007 reference case, energy-related CO2 emissions were
projected to grow by about 35 percent, to 7,950 million
metric tons in 2030, reflecting both a higher projection of
overall energy use and, to a lesser extent, a different mix
of energy sources.
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