Home > Forecasts & Analysis > Annual Energy Outlook Early Release > Overview
|
Annual Energy Outlook Early Release Overview
|
Full Printer-Friendly Version |
Overview
Energy Trends to 2030 | Energy Investment Behavior: Impact of Concerns Over Greenhouse Gas Emissions |
Economic Growth | Energy Prices | Energy Consumption by Sector | Energy Consumption by Primary Fuel |
Energy Intensity | Energy Production and Imports | Energy-Related Carbon Dioxide Emissions |
|
|
Energy Trends to 2030 |
|
|
|
In preparing the Annual Energy Outlook 2009 (AEO-2009), the Energy Information Administration (EIA)
evaluated a wide range of trends and issues that could
have major implications for U.S. energy markets.
This overview focuses primarily on one case, the
AEO2009 reference case, which is presented and compared
with the Annual Energy Outlook 2008 (AEO-2008) reference case (see Table 1 below); however, because
of the great uncertainties in any energy market projection,
particularly in periods of high price volatility
or rapid market transformation, the reference case
results should not be given undue weight. Readers are
encouraged to review the alternative cases when the
complete AEO2009 publication is released, to gain
perspective on how variations in key assumptions can
lead to different outlooks for energy markets. |
|
Trends in energy supply and demand are affected by
many factors. The AEO2009 reference case reflects
EIA’s current thinking about trends in the economy
and in energy markets. For example, the projection of
world oil prices (the benchmark is represented by the
price of West Texas Intermediate crude oil) is higher
in the AEO2009 reference case than the AEO2008
projection. |
|
To provide a basis against which alternative cases and
policies can be compared, the AEO2009 reference
case generally assumes that current laws and regulations
affecting the energy sector remain unchanged
throughout the projection. This year’s reference case
reflects recent changes in law—including the expiration
of moratoria on offshore leasing in the Atlantic,
Pacific, and Eastern Gulf of Mexico areas of the Outer
Continental Shelf (OCS) and provisions in Public Law
110-343, the Energy Improvement and Extension Act
of 2008 (EIEA2008), related to production and investment
tax credits for renewable energy and designated
energy equipment, such as plug-in hybrid electric vehicles
(PHEVs)—as well as regulatory changes.1 |
|
Other key changes in the AEO2009 projections
include:
- 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
- Revised capital costs for capital-intensive projects
to reflect recent sharp increases in those costs
- Revised handling of hybrid vehicles, including
PHEVs
- Updated characterization of unconventional natural
gas production, in particular for natural gas
shales.
|
|
|
|
Energy Investment Behavior: Impact of Concerns Over Greenhouse Gas Emissions |
|
|
Energy companies currently are operating in a challenging
environment. Beyond the well-known uncertainties
with respect to future demand growth
and fuel, labor, and new plant costs, they also must
consider the potential impact of concerns surrounding
energy-related GHG emissions. Even without
the enactment of Federal laws and policies limiting
U.S. GHG emissions, regulators and the investment
community are beginning to push energy companies
to shift their investments towards less GH-Gintensive
technologies.
For example, many State public utility commissions
are requiring that the utilities they regulate prepare
simulations in their integrated resource plans that
include assumed carbon dioxide (CO2) allowance
fees. The utilities often prepare a range of cases,
with CO2 fees ranging widely from $0 to $80 per ton
of CO2 or more. In addition, a number of major financial
institutions (e.g., Citicorp, JPMorgan
Chase, and Morgan Stanley) have adopted “carbon
principles” under which they agree to “(1) encourage
their clients to pursue cost-effective energy efficiency,
renewable energy, and other low-carbon
alternatives to conventional generation, taking into
consideration the potential value of avoided CO2
emissions; (2) ascertain and evaluate the financial
and operational risk to fossil fuel generation
financings posed by the prospect of domestic CO2
emissions controls through the application of an ‘Enhanced Diligence Process,’a and use the results
of this diligence as a factor in determining whether a
transaction is eligible for financing and under what
terms; and (3) educate clients, regulators, and other
industry participants regarding the additional diligence
required for fossil fuel generation financings,
and encourage regulatory and legislative changes
consistent with the Principles.” b
There are two key questions: to what extent are concerns
about climate change already affecting operating
and investment decisions in energy markets,
and how should these impacts be represented in
AEO2009? Although it appears that existing assets continue to be operated without adjustments for
their GHG characteristics, there is considerable evidence
that investors and regulators reviewing proposals
for new power plants are considering GHG
emissions in their investment evaluation process by
implicitly (or explicitly) adding a cost to some plants,
particularly those that involve GHG-intensive
technologies.
To reflect this behavior, the AEO2009 reference case
adds a 3-percentage point increase in the cost of capital
when evaluating investments in GHG-intensive
technologies, such as coal-fired power plants without
carbon control and sequestration (CCS) and
coal-to-liquids (CTL) plants. While the 3-percentage
adjustment is somewhat arbitrary, in levelized cost
terms its impact is similar to that of a $15-per-ton
value for CO2 emissions when investing in a new
coal plant without CCS, well within the range of the
results of simulations that utilities and regulators
have prepared. The adjustment should not be seen
as an increase in the actual cost of financing but
rather as representing an implicit hurdle being
added to GHG-intensive projects to account for the
possibility that eventually they may be required to
purchase allowances or invest in other GHG-emission-reducing projects to offset their emissions.
In previous AEOs the reference cases did not incorporate
such an adjustment. Investment decisions in
those reference cases were treated in the same way
as they would be in a world where the issue of climate
change and the role of GHG emissions as a
contributing factor did not exist. Current evidence
suggests that such a methodology is now inappropriate
to reflect business-as-usual behavior under current
laws and regulations. To facilitate comparisons
with previous AEOs, and to provide a measure of the
impact of the change in methodology, the complete
AEO2009 will also include an alternative case that
does not incorporate the new financing adjustment
factor for long-lived investments in GHG-intensive
technologies.
aAn expanded due diligence process that considers the probable risks posed by the costs of CO2 emissions and seeks to address
those risks in financing decisions.
bSee Morgan Stanley, “Leading Wall Street Banks Establish The Carbon Principles” (Press Release, February 4, 2008), web site
www.morganstanley.com/about/press/articles/6017.html.
|
|
|
|
Economic Growth |
|
|
|
Real gross domestic product (GDP) grows by 2.5 percent per year from 2007 to 2030 in the AEO2009 reference case, similar to the growth in the AEO2008 reference case, with the Nation’s population, labor force, and productivity growing at annual rates of 0.9 percent, 0.7 percent, and 1.9 percent, respectively.
|
|
The economic assumptions underlying the AEO2009 reference case beyond 2010 reflect trend projections that do not include short-term perturbations. The near-term scenario reflects four consecutive quarters of negative annualized economic growth during the first 2 years of the projection, consistent with EIA’s November 2008 Short-Term Energy Outlook. GDP growth begins to recover by 2010 and reaches trend growth by 2021. |
|
|
|
Energy Prices |
|
|
Crude Oil |
|
Although world oil prices declined sharply at the
end of 2008 with the slowing of the U.S. and world
economies, the AEO2009 reference case includes higher world oil prices by 2030, based on a reevaluation
of long-term fundamentals that support
higher prices than expected in earlier AEOs.
Prices begin to rise in 2010 (see Figure 1 on right) as the economy
rebounds and global demand is expected to
once again grow more rapidly than liquids supplies
from producers outside the Organization of
the Petroleum Exporting Countries (OPEC). In
2030, the average real price of crude oil in the reference
case is $130 per barrel in 2007 dollars, or
about $189 per barrel in nominal dollars. Alternative
AEO2009 cases address higher and lower
world crude oil prices.
|
|
The AEO2009 reference case assumes that access
limitations restrain the growth of non-OPEC conventional
liquids production between 2007 and
2030, and that OPEC targets a relatively constant
market share of about 40 percent of total world
liquids production. |
|
Contributing to world oil price uncertainty is the
degree to which non-OPEC countries and countries
outside the Organization for Economic
Cooperation and Development (OECD), such as
Russia, restrict economic access to potentially
productive resources. Other uncertain factors, including
OPEC investment decisions, will affect
the world oil price and the economic viability of
unconventional liquids. |
|
The AEO2009 reference case also includes 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 contribute
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
reaches 4 million barrels per day in 2030. |
Liquid Products |
|
Real prices (in 2007 dollars) for motor gasoline
and diesel in the AEO2009 reference case are
$3.90 per gallon and $3.91 per gallon in 2030—$1.39 and $1.16 per gallon higher, respectively,
than in the AEO2008 reference case, largely as a
result of higher crude oil prices. Despite being
almost equal in 2030, diesel prices generally are
higher than gasoline prices throughout the projection
because of continued strong growth in world
demand. |
|
Retail prices for E85 (a blend of 70 to 85 percent
ethanol and 30 to 15 percent gasoline by volume),
including the discounts on an energy-equivalent
basis relative to motor gasoline that are required
to meet the renewable fuels standard (RFS) legislated
in Public Law 110-140, the Energy Independence
and Security Act of 2007 (EISA2007),
decline to $2.39 per gallon in 2015, then rise gradually
with the cost of building additional E85 infrastructure
to expand its availability. |
Natural Gas |
|
After declining at the end of 2008, natural gas
prices stabilize through 2011, with Henry Hub
spot prices just above $6.50 per million British
thermal units (Btu). After 2011, Henry Hub spot
prices (in 2007 dollars) begin to increase, reaching
$9.25 per million Btu in 2030. |
|
The price of natural gas is generally higher in the
AEO2009 reference case than was projected in the
AEO2008 reference case, as a result of higher exploration
and development costs and a requirement
for increased natural gas production (to
meet increased consumption while imports are decreasing),
particularly during the last 10 years of
the projection. Total natural gas consumption is
about 7 percent higher in 2030 as a result of a
40-percent increase in natural gas use for power
generation, and net imports are 78 percent lower.
The wellhead price of natural gas in 2030 is 23
percent higher in the AEO2009 reference case
than in the AEO2008 reference case. |
Coal |
|
Coal prices are expected to moderate somewhat in
the near term from their recent very high levels,
but they remain well above the price projections
of recent AEOs and rise toward the end of the
projection as consumption grows. Average real
minemouth coal prices (in 2007 dollars) in the
AEO2009 reference case increase from $1.27 per
million Btu ($25.82 per short ton) in 2007 to $1.47
per million Btu ($30.01 per short ton) in 2009,
then level off and even decline somewhat, bottoming
out at $1.39 per million Btu ($27.94 per short
ton) in 2020. Much of the moderation in coal
prices after 2009 is attributable to a shift from
more expensive coal production from the Central
Appalachian supply region to regions with lower
production costs, such as Northern Appalachia,
the Eastern Interior, and Wyoming’s Powder River Basin. After 2020, coal prices rise to $1.45
per million Btu ($28.94 per short ton) in 2030. |
Electricity |
|
From a peak of 9.6 cents per kilowatthour (2007
dollars) in 2009, average delivered electricity
prices in AEO2009 decline to 9.0 cents per kilowatthour
in 2012 and then increase to 10.5 cents
per kilowatthour in 2030. In the AEO2008 reference
case, with lower delivered fuel prices and
construction costs for all new technologies, electricity
prices reached 9.1 cents per kilowatthour
(2007 dollars) in 2030. |
|
Higher costs for fuel and new plant construction
in the AEO2009 reference case lead to higher electricity
prices than in AEO2008. In the early years
of the projection, real electricity prices decline
slightly as the recent rapid increase in fuel and
new plant costs begins to wane. Over the longer
run, real electricity prices rise as demand grows
and the price of delivered fuels increases, leading
to higher production costs. |
|
|
figure data
|
Energy Consumption by Sector |
|
|
Residential |
|
The incorporation of tax credits for renewable
systems and energy-efficient appliances in EIEA-2008, along with higher prices for natural gas and
heating oil, contributes to a reduction in energy
use in the AEO2009 reference case relative to the
AEO2008 reference case (0.5 quadrillion Btu or
4 percent of delivered energy). Residential delivered
energy consumption in the AEO2009 reference
case grows from 11.4 quadrillion Btu in 2007
to 12.4 quadrillion Btu in 2030 (see Figure 2 on right). |
|
Increased use of compact fluorescent lamps and
the incorporation of efficiency standards for residential
lighting from EISA2007 that promote the
widespread use of light-emitting diode (LED)
bulbs later in the projection significantly reduce
electricity demand in the residential sector. |
|
EIEA2008 removes the existing tax credit cap
for the installation of solar photovoltaic systems,
causing the installed stock of the systems to increase to 1.65 million (from fewer than 75,000
in a case without the tax credit) in 2016, the last
year in which the credit is available. |
|
Ground-source (geothermal) heat pumps also
benefit from a large increase in the allowable
credit in EIEA2008 (from $300 to $2,000 per
unit), fostering nearly a threefold increase in the
stock of very efficient heat pumps by 2016, relative
to a case without the tax credit. Even though
the tax credit spurs additional purchases of
ground-source heat pumps, however, their market
share remains low, reaching 1.0 percent of the
single-family heating market by 2016. |
|
Commercial |
|
Despite faster growth in commercial square footage,
higher energy prices lead to slower growth in
commercial energy consumption in the AEO2009
reference case relative to the AEO2008 reference
case, along with increased adoption of energy
conservation and efficiency measures. Delivered
commercial energy consumption grows from
8.5 quadrillion Btu in 2007 to 10.6 quadrillion Btu
in 2030, about 0.7 quadrillion Btu less than in the
AEO2008 reference case. |
|
The 8-year extension of investment tax credits for
solar, fuel cell, and microturbine technologies and
the addition of tax credits for wind, conventional
combined heat and power (CHP) systems, and
ground-source heat pumps in EIEA2008 lead to
increased adoption of the technologies in the commercial
sector. |
|
Higher electricity prices lead to an overall increase
in commercial distributed generation and
CHP in the AEO2009 reference case. The EIEA-2008 tax credits for those systems spur additional
adoption. |
Industrial |
|
About one-third of delivered energy in the United
States is consumed in the industrial sector, and
one-half of that is consumed in just three
industries: bulk chemicals, petroleum refining,
and paper products. Petroleum refining, which includes
heat and power for coal-and naturalgas-based petroleum liquids and ethanol, becomes
the single largest energy-consuming industry in
2030 in the AEO2009 reference case, overtaking
bulk chemicals. |
|
Collectively, the energy-intensive manufacturing
industries—bulk chemicals, refineries, paper
products, primary metals, food, glass, and cement—produce about one-fifth of the dollar value
of industrial shipments while accounting for more
than two-thirds of delivered energy consumption.
With strong growth in refinery-related fuel use,
the share of industrial energy use by the energy intensive
industries increases slightly, from 71
percent in 2007 to 77 percent in 2030. |
|
Industrial delivered energy consumption increases
by just 4 percent from 2007 to 2030 in the
AEO2009 reference case, while industrial shipments
increase by 47 percent. Cumulative economic
growth in energy-intensive manufacturing
industries (23 percent) is much slower, reflecting
increased foreign competition from regions with
lower energy costs. Most significant is the 10-percent decline in bulk chemical industry shipments,
currently the largest energy-consuming
industry in the United States. The composition of
the chemical industry also shifts to less energyintensive
products and becomes more efficient. As
a result, energy consumption in bulk chemicals,
including feedstock usage, declines by 25 percent
from 2007 to 2030. |
|
Energy consumption in the refining industry runs
counter to the trends in the rest of the industrial
sector, increasing by more than one-half while
shipments are largely unchanged, as the industry
becomes more energy-intensive to meet environmental
requirements and increasingly produces
synthetic fuels in the latter half of the projection
period. |
Transportation |
|
Delivered energy consumption in the transportation
sector grows to 31.9 quadrillion Btu in 2030 in the AEO2009 reference case, 1.1 quadrillion
Btu less than in the AEO2008 reference case, due
to higher energy prices and the revised handling
of the EISA2007 corporate average fuel economy
(CAFE) standards. |
|
Growth in industrial output is expected to increase
energy demand for heavy truck travel,
which accounts for a majority of the growth in
transportation energy demand in the reference
case. |
|
Recent changes in airfare pricing and their impact
on the cost of air travel diminish growth in air
travel in AEO2009 relative to AEO2008. |
|
EIEA2008 provides tax credits for PHEVs between
2009 and 2014. In the AEO2009 reference
case, the PHEV credit increases sales of those
vehicles to the cumulative maximum by 2014 and
increases market penetration of PHEVs throughout
the projection. |
|
The proposal by the National Highway Traffic
Safety Administration (NHTSA) for implementation
of the EISA2007 CAFE standard, which has
been adopted in AEO2009, reflects a more rapid
increase in light-duty vehicle CAFE than was anticipated
in AEO2008. To attain the mandated
fuel economy levels, the AEO2009 reference case
includes a sharp increase in sales of unconventional
vehicle technologies,2 such as flex-fuel, hybrid,
and diesel vehicles, and a slowdown in the
growth of new light truck sales. Hybrid vehicle
sales, including PHEVs, increase from 2 percent
of new light-duty vehicle sales in 2007 to 38 percent
in 2030. PHEV sales grow rapidly as a result
of the EIEA2008 tax credits, increasing to 90,000
vehicles annually in 2014. In 2030, PHEVs account
for 2 percent of new light-duty vehicle sales. |
|
|
figure data
|
Energy Consumption by Primary Fuel |
|
|
|
Coal, oil, and natural gas meet 79 percent of total
U.S. primary energy supply requirements in
2030—down from 85 percent in 2007, reflecting
higher energy prices that reduce consumption,
the incorporation of the EIEA2008 and EISA2007
provisions, and increased use of renewable energy
when compared with the AEO2008 reference case.
|
|
Total U.S. consumption of liquid fuels, including
both fossil liquids and biofuels, grows from 40.8
quadrillion Btu (20.6 million barrels per day) in 2007 to 41.6 quadrillion Btu (21.6 million barrels
per day) in 2030 in the AEO2009 reference case
(see Figure 3 on right). Excluding growth in biofuel consumption,
consumption of petroleum-based liquids is
essentially flat. The transportation sector dominates
demand for liquid fuels, which grows from a
69-percent share of total consumption in 2007 to a
75-percent share in 2030. |
|
Rapid growth in the consumption of renewable
fuels results mainly from the implementation of
the Federal RFS for transportation fuels and
State renewable portfolio standard (RPS) programs
for electricity generation. Given the anticipated
level of technology improvement, the rate of
investment, and the current schedule of mandates
in the RFS, the requirement for cellulosic biofuels
will be met at a level lower than the original EISA-2007 mandate through the implementation of
waivers and adjustments. Growth in renewable
electricity other than hydropower provides 33 percent
of the growth in electricity demand between
2007 and 2030, and its share in meeting demand
growth probably would be higher if existing production
tax credits scheduled to expire in 2009
were extended, or if policies were implemented to
limit GHG emissions. |
|
Total primary energy consumption in the AEO2009
reference case grows by 11.2 percent, from 101.9
quadrillion Btu in 2007 to 113.3 quadrillion Btu in
2030 (4.7 quadrillion Btu less than in the AEO2008
reference case). Among the most important factors
leading to lower total energy demand in the AEO2009
reference case are significantly higher energy prices
and greater use of more efficient appliances and
vehicles in response to the requirements of EISA2007
and EIEA2008. |
|
In the AEO2009 reference case, natural gas consumption
ranges between 22.5 and 23.4 trillion cubic
feet through 2020 before increasing gradually to 24.4
trillion cubic feet in 2030—1.7 trillion cubic feet more
than projected in the AEO2008 reference case.
Despite higher natural gas prices, electric power sector
consumption in 2030 is 2.0 trillion cubic feet
higher in the AEO2009 reference case than in the
AEO2008 reference case, in part because uncertainty
about potential GHG regulations and their impact on
coal use leads to an increase in natural gas use for
electric power generation, offsetting lower consumption
in the residential, commercial, and industrial
sectors. |
|
Total coal consumption increases from 22.7 quadrillion
Btu (1,129 million short tons) in 2007 to 26.4
quadrillion Btu (1,358 million short tons) in 2030 in
the AEO2009 reference case. Coal consumption,
mostly for electric power generation, grows gradually
through 2020 as existing plants are used more intensively
and new plants that are already under construction
are completed and enter service. In the
AEO2009 reference case, coal consumption in the
electric power sector increases from 22.0 quadrillion
Btu in 2020 to 24.1 quadrillion Btu in 2030, much
lower than the projection of 27.5 quadrillion Btu in
2030 in the AEO2008 reference case. |
|
The moderate increase in coal consumption from
2007 to 2030 also reflects growth in coal use at CTL
plants. In 2030, 1.1 quadrillion Btu of coal is used at
CTL plants. Despite higher CTL investment costs and
concerns about potential GHG regulations, the increase
in coal use for CTL plants in the AEO2009 reference
case is greater than in the AEO2008 reference
case, because higher liquids prices increase the economic
attractiveness of the technology. |
|
The AEO2009 reference case includes greater use of
renewable energy than the AEO2008 reference case.
Total consumption of marketed renewable fuels—including wood, municipal waste, and biomass in the
end-use sectors; hydroelectricity, geothermal, municipal
waste, biomass, solar, and wind for generation in
the electric power sector; ethanol for gasoline blending
and biomass-based diesel in the transportation
sector, of which 3.4 quadrillion Btu is included with
liquids fuel consumption in 2030—grows by 3.3 percent
per year in the reference case. |
|
Although the situation is uncertain, the current state
of the industry and EIA’s present view of the projected
rates of technology development and market penetration of cellulosic biofuel technologies suggest
that available quantities of cellulosic biofuels will be
insufficient to meet the new RFS targets for cellulosic
biofuels before 2022, triggering both waivers and a
modification of applicable volumes, as provided 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 credits to 29.8
billion credits in the AEO2009 reference case. |
|
On a volumetric basis, ethanol use in the AEO2009
reference case grows from 6.5 billion gallons in 2007
to 29.6 billion gallons in 2030—about 20 percent of
total gasoline consumption by volume and about 24
percent more than in the AEO2008 reference case.
Ethanol use for gasoline blending grows to 12.2 billion
gallons and E85 consumption to 17.5 billion gallons
in 2030. The ethanol supply is produced from
both corn and cellulose feedstocks, with corn accounting
for 15.0 billion gallons and cellulose 12.6 billion
gallons of ethanol production in 2030 (including both
domestic and imported production). Both are eligible
for RFS credits.3 |
|
Other biofuels are produced domestically and imported,
including some produced from corn that are
ineligible for RFS credits. Biodiesel use increases to
1.9 billion gallons in 2030, or about 2.3 percent of total
diesel consumption by volume. In addition, consumption
of biomass-to-liquids (BTL) diesel grows to
3.6 billion gallons in 2030, or 4.8 percent of total diesel
consumption by volume. |
|
Excluding hydroelectricity, renewable energy consumption
in the electric power sector grows from 1.0
quadrillion Btu in 2007 to 3.4 quadrillion Btu in 2030.
The projected consumption of nonhydroelectric renewable
energy in the AEO2009 reference case is a
result predominantly of State RPS programs that
require specific and generally increasing shares
of electricity sales to be supplied by renewable resources,
such as wind, solar, geothermal, and in some
States biomass or hydropower. Rising fossil fuel
prices also contribute to the growth in consumption
of renewables in the later years of the projection. The
largest source of growth in the AEO2009 reference
case is in biomass and wind. Both benefit from the
higher fossil fuel prices and concerns about GHG regulations
that dampen investment in carbon-intensive
technologies in the AEO2009 reference case, and
neither benefits from any Federal or State subsidy
beyond those in existing laws and regulations. |
|
|
figure data
|
Energy Intensity |
|
|
|
The energy intensity of the U.S. economy declines
steadily as the result of higher energy prices and
the adoption of policies that promote improved
energy efficiency in the AEO2009 reference case.
|
|
The reference case reflects observed historical relationships
between energy prices and energy
conservation. To the extent that consumer preferences
change, the improvement in energy intensity
or energy consumption per capita could be
greater or smaller. |
|
Energy intensity, measured as primary energy use (in
thousand Btu) per dollar of GDP (in 2000 dollars),
declines by more than one-third from 2007 to 2030 in
the AEO2009 reference case (see Figure 4 on right). Although
energy use generally increases as the economy grows,
higher energy prices, continuing improvement in
energy efficiency, and a shift to less energy-intensive
activities 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 24 percent in 1992 to 22 percent in 2007.
In the AEO2009 reference case, the energy-intensive
industries’ share of total industrial shipments continues
to decline, 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 U.S.
population has increased by 21 percent and energy
consumption by a comparable 20 percent, 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 24 percent
from 2007 to 2030 in the AEO2009 reference case;
over the same period, energy consumption increases
by 11 percent. The result is a decrease in energy consumption
per capita at an annual rate of 0.5 percent
per year from 2007 to 2030, greater than the 0.2-percent yearly drop in the AEO2008 reference case.
The faster decline in energy consumption per capita
results from the higher energy prices in the AEO2009
reference case and revisions from the CAFE standards
that were assumed in the AEO2008 reference
case. |
|
With energy prices rising until recently, interest in
energy conservation has increased. Although additional
energy conservation is induced by higher energy
prices in the AEO2009 reference case, 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. |
|
|
figure data
|
Energy Production and Imports |
|
|
|
Net imports of energy meet a major but declining
share of total U.S. energy demand in the AEO2009
reference case (see Figure 5 on right). Increased use of biofuels,
much of which is produced domestically, demand
reductions resulting from new efficiency standards,
rapid improvement in the efficiency of appliances,
and higher energy prices act to moderate growth in energy imports. Higher fuel prices also spur increased
domestic energy production, further tempering
growth in imports. The net import share of total U.S.
energy consumption in 2030 is 17 percent, compared
with 29 percent in 2007.
|
Liquids |
|
Consistent with the AEO assumption of adopting
existing legislation and regulation, the AEO2009
reference case reflects the removal of moratoria
on offshore leasing and drilling in the Atlantic,
Pacific, and Eastern Gulf of Mexico areas of the
OCS, which results in production from those
areas. It is likely that the particulars of lifting the
moratoria will continue to be discussed in Congress
and, as applicable, in State legislatures
before any drilling occurs; however, some OCS
areas already are included in the current 5-year
leasing plan of the Mineral Management Service. |
|
Net imports of liquids meet a large but declining
share of total U.S. liquids demand. Increased use
of biofuels, reduced demand for liquids as a result
of tighter CAFE standards, and higher energy
prices act to moderate the growth in liquids demand.
Higher fuel prices also contribute to the
projected increase in domestic liquids production.
As a result, U.S. dependence on imported liquids,
measured as a share of U.S. liquids use, is expected
to continue declining over the next 25
years, from 58 percent in 2007 to less than 40 percent
in 2025, before increasing to 41 percent in
2030. |
|
Higher world oil prices drive the initiation of U.S.
oil shale production in the AEO2009 reference
case. The long-term potential for oil shale production
is one of the more uncertain areas of the projection,
considering the relatively high costs of,
and needed improvements in, extraction technologies
as well as the potential for changes in controlling
legislation. |
|
In general, U.S. crude oil production in the AEO2009
reference case projection is higher than in the AEO-2008 reference case, consistent with the projected expansion
of enhanced oil recovery (EOR) operations
and higher crude oil prices. U.S. crude oil production
increases from 5.1 million barrels per day in 2007 to a
peak of 7.4 million barrels per day in 2030, with production
increases from the deep waters of the Gulf of
Mexico, Pacific and Atlantic OCS, and onshore EOR
projects. |
|
Total domestic liquids supply, including crude oil,
natural gas plant liquids, refinery processing gain,
and other refinery inputs (including ethanol, biodiesel,
BTL, and liquids from coal) increase through
2030 in the AEO2009 reference case, while net imports
of crude oil and other liquids decline from 12.1
million barrels per day in 2007 to 8.8 million barrels
per day in 2030. Total domestic liquids supply grows
from 8.7 million barrels per day in 2007 to 12.8 million
barrels per day in 2030 (see Figure 6 on right). |
Natural Gas |
|
Total production levels are relatively stable from
2007 through 2016 at about 20.4 trillion cubic
feet. After 2016 they begin to rise, to 23.7 trillion
cubic feet in 2030—4.2 trillion cubic feet more
than projected in the AEO2008 reference case. |
|
Higher natural gas prices and a reevaluation of
the resource base result in higher unconventional
natural gas production in the AEO2009 reference
case than in the AEO2008 reference case. In 2030,
production of “tight gas” is about 28 percent
higher and production of gas shale is 85 percent
higher in AEO2009 than in AEO2008. |
|
The recent expiration of moratoria on drilling in
the Atlantic, Pacific, and Eastern Gulf of Mexico
OCS areas is reflected in the AEO2009 reference
case and contributes to increased offshore natural
gas production in the later years of the projection |
|
Net pipeline imports are lower in the AEO2009
reference case relative to the AEO2008 reference
case, in part because of a decrease in imports of
liquefied natural gas (LNG) by Mexico and Canada
that were projected to be re-exported to the
United States in the AEO2008 reference case and
were reported as pipeline imports. In addition, declining production in Canada, due in part to
lower profitability for unconventional production
than in the United States, is expected to reduce
the availability of natural gas supplies for export
to the United States. |
|
Prospects for future LNG imports are significantly
lower in the AEO2009 reference case than
in the AEO2008 reference case. While LNG imports
increase in the first decade of the projection
as world liquefaction capacity increases at a rapid
pace, supplies tighten in the longer term, when
rising world oil prices lead to an increase in global
demand for LNG. The future direction of the
global LNG market is one of the key uncertainties
in the AEO2009 reference case. |
|
Total domestic production of natural gas (including
supplemental natural gas supplies) is significantly
higher in the AEO2009 reference case than in the
AEO2008 reference case. Although exploration and
production costs are higher, the higher prices in the
AEO2009 reference case support the higher level of
production. |
|
AEO2009 expects the Alaska natural gas pipeline to
be completed in 2020, which is the same as in the
AEO2008 reference case. Project planning appears to
be progressing on schedule, and the economics continue
to be favorable. Once the pipeline is in service,
Alaska’s total natural gas production in the AEO2009
reference case increases to 2.0 trillion cubic feet in
2021 (from 0.4 trillion cubic feet in 2007) and remains
at that level through 2030. |
|
Total net imports of LNG to the United States in the
AEO2009 reference case are significantly lower than
in the AEO2008 reference case due to a reevaluation
of U.S. competitiveness for supplies on the world market.
U.S. imports of LNG increase as world liquefaction
capacity expands, peaking at 1.5 trillion cubic
feet in 2018; thereafter, they decline to 0.8 trillion
cubic feet in 2030, as growth in world demand outpaces
growth in liquefaction capacity. With the
decline in LNG imports, the utilization of U.S. regasification
capacity falls from 36 percent in 2007 to
16 percent in 2030. |
|
With many new international players entering LNG
markets, the competition for available supplies is
expected to be strong, and the amounts available to
the U.S. market may vary considerably from year to
year. The AEO2009 reference case has been updated
to reflect current market dynamics, which could change considerably as worldwide LNG markets
evolve. |
Coal |
|
Although coal remains the most important fuel
for U.S. electricity generation, slower growth in
electricity demand and increasing concern about
GHG emissions affect coal markets by slowing the
growth of demand for coal in the AEO2009 reference
case compared with the AEO2008 reference
case. Consequently, western coal production, typically
the source of marginal supply, does not grow
as much as in previous AEOs. |
|
As domestic coal use grows in the AEO2009 reference
case, U.S. coal production increases at an average rate
of 0.6 percent per year, from 23.5 quadrillion Btu
(1,147 million short tons) in 2007 to 26.8 quadrillion
Btu (1,336 million short tons) in 2030—6 percent less
than in the AEO2008 reference case. Production from
mines west of the Mississippi River provides the largest
share of the incremental coal production. On a Btu
basis, 52 percent of domestic coal production originates
from States west of the Mississippi River in
2030, up from 50 percent in 2007. |
|
Typically, trends in U.S. coal production are linked to
its use for electricity generation, which currently
accounts for 92 percent of total coal consumption.
Coal consumption in the electric power sector in the
AEO2009 reference case, at 24.1 quadrillion Btu in
2030, is less than in the AEO2008 reference case (27.6
quadrillion Btu in 2030). Slower growth in overall
electricity demand and reduced investment in new
coal-fired generating capacity, combined with more
generation from natural gas and renewable energy,
underlie the reduced outlook for coal consumption in
the electricity sector. |
|
Another emerging market for coal is CTL plants.
Despite higher plant costs and concerns about GHG
regulations, the higher oil prices in this year’s reference
case make new CTL plants attractive. Coal use
in CTL plants grows from 0.4 quadrillion Btu (30 million
short tons) in 2020 to 1.1 quadrillion Btu (70 million
short tons) in 2030. |
Electricity Generation |
|
Total electricity consumption, including both purchases
from electric power producers and on-site
generation, grows from 3,903 billion kilowatthours
in 2007 to 4,902 billion kilowatthours in
2030, increasing at an average annual rate of 1.0 percent in the AEO2009 reference case. The
growth rate in the AEO2009 projection is slightly
lower than in the AEO2008 reference case (1.1
percent per year). |
|
Even though the mix of investments in new power
plants relies less on coal than in recent AEOs,
coal remains the dominant fuel for electricity generation
because of continued reliance on existing
coal-fired plants and the addition of some new
ones in the absence of an explicit policy to reduce
GHG emissions (see Figure 7 on right). |
|
Natural gas plays a larger role than in recent
AEOs because it is less carbon intensive than coal,
and because new natural-gas-fired plants are
much cheaper than new renewable or nuclear
plants. Compared with the AEO2008 reference
case, electricity generation from natural gas in
2030 is 38 percent higher in the AEO2009 reference
case. The key factor in the increase is dampened
growth in coal-fired generation as concerns
about GHG emissions and the possible impact of
future policies reduce the number of new coal
plants added. |
|
Generation from renewable resources increases in
response to requirements in more than one-half of
the States for minimum renewable generation
shares. Renewable generation in the AEO2009
reference case is significantly higher than in the
AEO2008 reference case, with the share of generation
coming from renewable fuels growing from
8.5 percent in 2007 to 14.1 percent in 2030. In the
AEO2009 reference case, Federal subsidies for renewable
generation are assumed to expire as enacted.
Their extension would have a large impact
on renewable generation. |
|
The AEO2009 reference case does not reflect
the December 2008 reinstatement of the Clean
Air Interstate Rule (CAIR) by the U.S. Court of
Appeals, vacating its ruling in the summer of 2008
that overturned CAIR. Although the earlier ruling
is reflected in AEO2009, it is assumed that
electricity generators will continue to retrofit existing
capacity with emission control equipment
to comply with the revised National Ambient Air
Quality Standards (NAAQS). Also, it is assumed
that plants not equipped with scrubbers will be required
ultimately to use low-sulfur coal in order to
comply with the NAAQS. |
|
A total of 46 gigawatts of coal-fired generating capacity
is added from 2007 to 2030 in the AEO2009 reference
case, less than one-half the 103 gigawatts added
in the AEO2008 reference case. Concerns about GHG
emissions significantly slow the expansion of coalfired
capacity in the AEO2009 reference case, even
under current laws and policies. Nuclear generating
capacity in the AEO2009 reference case increases
from 100.5 gigawatts in 2007 to 112.2 gigawatts in
2030. The increase includes 12.7 gigawatts of capacity
at newly built nuclear power plants and 3.4 gigawatts
from uprates of existing plants, partially offset by 4.4
gigawatts of retirements. |
|
Electricity generation from nuclear power plants
grows from 806 billion kilowatthours in 2007 to 905
billion kilowatthours in 2030 in the AEO2009 reference
case, accounting for about 18 percent of total
generation in 2030—about the same share as in 2007.
Additional nuclear capacity is built in some of the
alternative AEO2009 cases, particularly those with higher demand for electricity, higher fossil fuel
prices, or an explicit cap on GHG emissions. |
|
|
figure data
figure data
figure data
|
Energy-Related Carbon Dioxide Emissions |
|
|
|
Total energy-related CO2 emissions in 2030 are
6,410 million metric tons in the AEO2009 reference
case, as compared with 6,851 million metric
tons in the AEO2008 reference case—a decline of
6.4 percent or 441 million metric tons.
|
|
Energy-related CO2 emissions grow by 0.3 percent
per year from 2007 to 2030 in the AEO2009
reference case, and emissions per capita fall by 0.6
percent per year, as demand for electricity and
transportation fuels moderates in the face of
higher energy prices, efficiency standards, State
RPS requirements, and recently increased Federal
CAFE standards. |
|
Energy-related CO2 emissions reflect the quantities
of fossil fuels consumed and, because of their varying
carbon content, the mix of coal, petroleum, and natural
gas. Given the high carbon content of coal and its
use currently to generate more than one-half of U.S.
electricity, prospects for CO2 emissions depend in
part on growth in electricity demand. Electricity sales
growth in the AEO2009 reference case slows as a result
of a variety of regulatory and socioeconomic factors,
including appliance and building efficiency
standards, higher energy prices, housing patterns,
and economic activity. With slower electricity growth
and increased use of renewables for electricity generation
influenced by RPS laws in many States, electricity-
related CO2 emissions grow by just 0.5 percent per
year from 2007 to 2030 (Figure 8). CO2 emissions
from transportation activity also slow in comparison
with the recent past, as Federal CAFE standards increase
the efficiency of the vehicle fleet, and higher
fuel prices moderate the growth in travel. |
|
Taken together, all these factors tend to slow the
growth of the absolute level of primary energy consumption
and promote a lower carbon fuel mix. As
a result, energy-related emissions of CO2 grow by 7
percent from 2007 to 2030—lower than the 11-percent increase in total energy use. Over the same
period, the economy becomes less carbon-intensive as
CO2 emissions grow by about one-tenth of the increase
in GDP, and emissions per capita decline by 14
percent. |
|
|
figure data
|
Notes |
|
|
1 EIA has examined many proposed policies at the request of Congress; the reports are available on EIA’s web site (see “Responses to Congressional and Other Requests,” web site www.eia.doe.gov/oiaf/service_ rpts.htm).
2 Vehicles that can use alternative fuels or employ electric motors and advanced electricity storage, advanced engine controls,
or other new technologies.
3 Under the provisions of EISA2007, only 15 billion gallons of ethanol produced directly from corn is eligible for RFS credits. |
|
|
|