Issues in Focus
Introduction
Each year, the Issues in Focus section of the AEO provides an in-depth
discussion on topics of special interest, including significant changes
in assumptions and recent developments in technologies for energy production,
supply, and consumption. The first section compares the results of two
cases that adopt different assumptions about the future course of existing
energy policies. One case assumes the elimination of sunset provisions
in existing energy policies. The other case assumes the extension of a
selected group of existing policies—CAFE standards, appliance standards,
and PTCs—in addition to the elimination of sunset provisions.
Other sections include a discussion of end-use energy efficiency trends
in AEO2010; an analysis of the impact of incentives on the use of natural
gas in heavy freight trucks; factors affecting the relationship between
crude oil and natural gas prices; the sensitivity of the projection results
to variations in assumptions about the availability of U.S. shale gas resources;
the implications of retiring nuclear plants after 60 years of operation;
and issues related to accounting for CO2 emissions from biomass energy
combustion.
The topics explored in this section represent current, emerging issues
in energy markets; but many of the topics discussed in AEOs published in
recent years also remain relevant today. Table 3 provides a list of titles from
the 2009, 2008, and 2007 AEOs that are likely to be of interest to today’s
readers. They can be found on EIA’s web site at www.eia.gov/oiaf/aeo/otheranalysis/aeo_analyses.html.
No Sunset and Extended Policies cases
Background
The AEO2010 Reference case is best described as a “current laws and regulations”
case, because it generally assumes that existing laws and fully promulgated
regulations will remain unchanged throughout the projection period, unless
the legislation establishing them specifically calls for them to end or
change. The Reference case often serves as a starting point for the analysis
of proposed legislative or regulatory changes, a task that would be difficult
if the Reference case included “projected” legislative or regulatory changes.
As might be expected, it is sometimes difficult to draw a line between
what should be included or excluded from the Reference case. Areas of particular
uncertainty include:
- Laws or regulations that have a history of being extended beyond their
legislated sunset dates. Examples include the various tax credits for renewable
fuels and technologies, which have been extended with or without modifications
several times since their initial implementation.
- Laws or regulations that call for the periodic updating of initial specifications.
Examples include appliance efficiency standards issued by the U.S. DOE
and CAFE standards for vehicles issued by NHTSA.
- Laws or regulations that allow or require the appropriate regulatory agency
to issue new or revised regulations under certain conditions. Examples
include the numerous provisions of the CAA that require the EPA to issue
or revise regulations if they find that some type of emission is harmful
to the public health, or that standards are not being met.
To provide some insight into the sensitivity of results to different characterizations
of “current laws and regulations,” two alternative cases are discussed
in this section. No attempt is made to cover the full range of possible
uncertainties in these areas, and readers should not view the cases discussed
as EIA projections of how laws or regulations might or should be changed.
Analysis cases
The two cases prepared—the No Sunset case and Extended Policies case—incorporate
all the assumptions from the AEO2010 Reference case, except as identified
below. Changes from the Reference case assumptions in these cases include
the following.
No Sunset case
- Extension of renewable PTCs, ITCs, and tax credits for energy-efficient
equipment in the buildings sector through 2035, including:
- The PTC of 2.1 cents per kilowatthour or the 30-percent ITC available for
wind, geothermal, biomass, hydroelectric, and landfill gas resources, currently
set to expire at the end of 2012 for wind and 2013 for the other eligible
resources.
- For solar power investment, a 30-percent ITC that is scheduled to revert
to a 10-percent credit in 2016 is, instead, assumed to be extended indefinitely
at 30 percent.
- In the buildings sector, tax credits for the purchase of energy-efficient
equipment, including PV in new houses, are assumed to be extended indefinitely,
as opposed to ending in 2010 or 2016 as prescribed by current law. The
business ITC for commercial-sector generation technologies and geothermal
heat pumps are assumed to be extended indefinitely, as opposed to expiring
in 2016; and the business ITC for solar systems is assumed to remain at
30 percent instead of reverting to 10 percent.
- In the industrial sector, the ITC for CHP that ends in 2016 in the AEO2010 Reference case is assumed to be extended through 2035.
- Extension of the $0.45 per gallon blender’s tax credit for ethanol through
2035; it is set to expire at the end of 2010.
- Continued implementation of the RFS after the 2022 date currently specified
in EISA2007 until the renewable fuels target of 36 billion gallons is met.
After the 36 billion gallon level is met, the mandate is assumed to continue
increasing production in proportion to growth in overall transportation
fuel use.
- Extension of the $1.00 per gallon biodiesel excise tax credit through 2035;
rather than expiring on December 31, 2009.
- Extension of the $0.54 per gallon tariff on imported ethanol through 2035;
it is set to expire at the end of 2010.
- Extension of the $1.01 per gallon cellulosic biofuels PTC through 2035;
rather than expiring at the end of 2012.
Extended Policies case
With the exception of the blender’s and other biofuel tax credits, the
Extended Policies case adopts the same assumptions as in the No Sunset
case, plus the following:
- Federal appliance efficiency standards are updated at particular intervals
consistent with the provisions in the existing law, with the levels determined
by the consumer impact tests under DOE testing procedures, or under Federal
Energy Management Program (FEMP) purchasing guidelines.
- The efficiency levels chosen for the updated residential standards are
based on the technology menu from the AEO2010 Reference case, and whether
or not the efficiency level passed the consumer impact test prescribed
in DOE’s standards-setting process. The efficiency levels chosen for the
updated commercial equipment standards are based on the technology menu
from the AEO2010 Reference case and FEMP-designated purchasing specifications
for Federal agencies.
- The implementation of rules proposed by NHTSA and the EPA for national
tailpipe CO2-equivalent emission and fuel economy standards for LDVs, including
both passenger cars and light-duty trucks, has been harmonized.
- In the AEO2010 Reference case, which applies the NHTSA and EPA rules, the
new CAFE standards lead to an increase in fleet-wide LDV standards from
27.1 mpg in MY 2011 to 34.0 mpg in MY 2016, based on projected sales of
vehicles by type and footprint. As required by EISA2007, the fuel economy
standards increase to 35 mpg in 2020. The Extended Policies case assumes
further increases in the standards, so that the minimum fuel economy standard
for LDVs increases to 45.6 mpg in 2035. In actual practice, the new CAFE
would need to meet a test of economic practicality.
- The extension of the blender’s and all biofuels excise tax credits through
2035 adopted in the No Sunset case are not included in the Extended Policies
case. The RFS enacted in EISA2007 is an alternative instrument for stimulating
demand for biofuels, it already is represented in the AEO2010 Reference
case, and it tends to be the binding driver on biofuels rather than the
tax credits.
Analysis results
The assumption changes made in the Extended Policies case generally lead
to lower overall energy consumption, increased use of renewable fuels,
particularly for electricity generation, and reduced energy-related GHG
emissions. While this case shows lower energy prices because the impacts
of the tax credits and end-use efficiency standards lead to lower energy
demand and reduce the cost of renewable fuels, consumers spend more on
appliances that are more efficient in order to comply with the tighter
appliance standards, and the Government receives lower tax revenues as
consumers and businesses take advantage of the tax credits.
Energy consumption
Total energy consumption in the No Sunset case is close to the level in
the Reference case (Figure 7). Lower energy prices in the No Sunset case
lead to slightly higher energy consumption, but the difference never reaches
as much as 1 percent in any year of the projections.
Total energy consumption in the Extended Policies case, which assumes the
issuance of more stringent efficiency standards for end-use appliances
and LDVs in the future, is lower than in the Reference case. In 2035, total
energy consumption in the Extended Policies case is nearly 3 percent below
the projection in the Reference case. As an example of individual end uses,
the assumed future standard for residential electric water heating, which
requires installation of heat pumps starting in 2013, has the potential
to reduce their electricity use by 60 percent from the Reference case level
in 2035. Overall, delivered energy use in the buildings sector in 2035
is 5 percent lower in the Extended Policies case.
The impact on LDV energy use in the transportation sector in the Extended
Policies case is similar. In 2035, total LDV energy use in the Extended
Policies case is nearly 6 percent lower than in the Reference case (Figure
8) and less than 0.5 percent above the 2007 level. Relative to the AEO2010 Reference case, the efficiency standard for new LDVs in 2035 is 10 mpg
higher in the Extended Policies case—46 mpg versus 36 mpg (Figure 9); however,
higher fuel prices in the Reference case improve the cost competitiveness
of advanced technologies, leading to improvements in fuel economy that
are above the minimum requirements (Figure 10). As a result, the average
fuel economy of new LDVs in the Reference case increases to 40 mpg in 2035
[Reference (achieved)], which is 4 mpg above the required minimum. In the
Extended Policies case, the fuel economy standards are binding [Extended
Policies (achieved)], because increases in fuel economy above the standards
require advanced technologies that are not cost-effective given the projected
fuel prices.
Renewable electricity generation
The extension of tax credits for renewables through 2035 would lead to
more rapid growth in renewable generation than projected in the Reference
case, particularly over the longer run. When the renewable tax credits
are extended without extending energy efficiency standards, as is assumed
in the No Sunset case, there is significant growth in renewable generation
throughout the projection period relative to the Reference case projection
(Figure 11). Extending both renewable tax credits and energy efficiency
standards results in more modest growth in renewable generation, because
renewable generation in the near term is the primary source of new generation
to meet load growth, and enhanced energy efficiency standards tend to reduce
overall electricity consumption and the need for new generation resources.
In the Reference case, growth in renewable generation accounts for 45 percent
of total generation growth from 2008 to 2035. In the No Sunset and Extended
Policies cases, growth in renewable generation accounts for 61 to 65 percent
of total generation growth. In 2035, the share of total electricity sales
accounted for by nonhydroelectric renewables is 13 percent in the Reference
case, as compared with 17 percent in the No Sunset and Extended Policies
cases.
In all three cases, the most rapid growth in renewable capacity occurs
in the near term, then slows through 2020, before picking up again. Before
2015, ample supplies of renewable energy in relatively favorable resource
areas (windy lands, accessible geothermal sites, and low-cost biomass),
combined with the Federal incentives, make renewable generation competitive
with conventional sources. If the rapid growth in renewables is dampened
because of the economic downturn, more natural gas generation would be
expected. With slow growth in electricity demand and the addition of capacity
stimulated by renewable incentives before 2015, little new capacity is
needed between 2015 and 2020. In addition, in many regions, most attractive
low-cost renewable resources already have been exploited, leaving less-favorable
sites that may require significant investment in transmission as well as
other additional infrastructure costs. New sources of renewable generation
also appear on the market as a result of cogeneration at biorefineries
built primarily to produce renewable liquid fuels to meet the Federal RFS,
where combustion of waste products to produce electricity is an economically
attractive option.
After 2020, renewable generation in the No Sunset and Extended Policies
cases increases more rapidly than in the Reference case, and as a result
generation from fossil fuels—particularly natural gas—is reduced from the
levels projected in the Reference case (Figure 12). In 2035, electricity
generation from natural gas in the No Sunset and Extended Policies cases
is 13 percent and 16 percent lower, respectively, than in the Reference
case.
Greenhouse gas emissions
In the No Sunset and Extended Policies cases, the combination of lower
overall energy demand and greater use of renewable fuels leads to lower
levels of energy-related CO2 emissions than projected in the Reference
case. The difference grows over time, to 146 million metric tons (2 percent)
in the No Sunset case and 200 million metric tons (3 percent) in the Extended
Policies case in 2035 (Figure 13). From 2012 to 2035, energy-related CO2 emissions are reduced by a cumulative total of more than 1.9 billion metric
tons in the Extended Policies case relative to the Reference case.
Energy prices and tax credit payments
With lower levels of overall energy use and more consumption of renewable
fuels in the No Sunset and Extended Policies cases, energy prices are lower
than projected in the Reference case. In 2035, natural gas wellhead prices
are $0.56 per thousand cubic feet (7 percent) and $0.70 per thousand cubic
feet (9 percent) lower in the No Sunset and Extended Policies cases, respectively,
than in the Reference case (Figure 14), and electricity prices are 5 percent
and 6 percent lower than projected in the Reference case (Figure 15).
The reductions in energy consumption and CO2 emissions in the Extended
Policies case require additional equipment costs to consumers and revenue
reductions for the Government. From 2010 to 2035, residential and commercial
consumers spend an additional $16 billion (real 2008 dollars) per year
on average for newly purchased end-use equipment, distributed generation
systems, and residential shell improvements in the Extended Policies case
than in the Reference case.
Tax credits paid to consumers in the buildings sector in the Extended Policies
case average $10.5 billion more per year than in the Reference case, reaching
a cumulative total of $300 billion in revenue reductions to the Government
over the period from 2010 to 2035. In comparison, cumulative revenue reductions
as a result of tax credits in the buildings sector total $27 billion over
the same period in the Reference case. The largest response to Federal PTC
incentives for new central-station renewable generation is seen in the
No Sunset case, with extension of the PTC resulting in cumulative reductions
in Government tax revenues that total approximately $45 billion from 2010
to 2035, as compared with $24 billion in the Reference case. Additional
reductions in Government tax revenue in the No Sunset case result from
extension of the blenders tax credit, the biodiesel blenders tax credit,
and the cellulosic biofuels PTC, with cumulative total tax revenue reductions
from 2010 to 2035 of $156 billion, $32 billion, and $168 billion (all in
2008 dollars), respectively, compared to the Reference case.
World oil prices and production trends in AEO2010
In AEO2010, the price of light, low-sulfur (or “sweet”) crude oil delivered
at Cushing, Oklahoma, is tracked to represent movements in world oil prices.
EIA makes projections of future supply and demand for “total liquids,”
which includes conventional petroleum liquids—such as conventional crude
oil, natural gas plant liquids, and refinery gain—in addition to unconventional
liquids, which include biofuels, bitumen, coal-to-liquids (CTL), gas-to-liquids
(GTL), extra-heavy oils, and shale oil.
World oil prices can be influenced by a multitude of factors. Some tend
to be short term, such as movements in exchange rates, financial markets,
and weather, and some are longer term, such as expectations concerning
future demand and production decisions by the Organization of the Petroleum
Exporting Countries (OPEC). In 2009, the interaction of market factors
led prompt month contracts (contracts for the nearest traded month) for
crude oil to rise relatively steadily from a January average of $41.68
per barrel to a December average of $74.47 per barrel [38].
Changes in the world oil market over the course of 2009 served to highlight
the myriad factors driving future liquids demand and supply and how a change
in these factors can reverberate through the world liquids market. Over
the long term, world oil prices in EIA’s outlook are determined by four
broad factors: non-OPEC conventional liquids supply, OPEC investment and
production decisions, unconventional liquids supply, and world liquids
demand. Uncertainty in long-term projections of world oil prices can be
explained largely by uncertainty about one or more of these four broad
factors.
Recent market trends
In 2009, world oil prices were especially sensitive to demand expectations,
with producers, consumers, and traders constantly looking for any indication
of a possible recovery in the world’s economy and a likely corresponding
increase in oil demand.
On the supply side, OPEC demonstrated greater dedication to supporting
prices in 2009 than it had in other recent periods where it adopted restraints
on production. From February to June 2008, OPEC maintained 70 percent or
greater compliance as measured by the actual aggregate production cuts
achieved by quota-restricted members as a percentage of the group’s agreed-upon
production cut, before falling to average levels of just above 60 percent
after September [39]. The above-average compliance increased the group’s
spare capacity to roughly 5 million barrels per day in December 2009, and
helped boost prices to a range of $70 to $80 per barrel [40].
Since June 2009, Iraq has held two rounds of bidding for development of
its oil resources. The sum of the targeted production increase from the
awarded fields is about 9.5 million barrels per day, or almost four times
the country’s current production. Although most industry analysts do not
expect Iraq to achieve those production targets in full, the likely increase
may cause changes in OPEC quota allocations and long-term production decisions.
There were also significant developments for non-OPEC supply in 2009, some
with potentially long-lasting implications. Although oil prices rose throughout
2009, many of the projects delayed during the price slump that started
in August 2008 have not yet been revived. The time required for project
development creates a lag between investment decisions and increased oil
deliveries, indicating that medium-term supply growth may be constrained
if delayed projects are not restarted in the short term.
A related trend, which began in 2008 and continued in 2009, was a decline
in factor input costs—i.e., the costs of the materials, labor, and equipment
necessary to develop liquids projects. The decline in construction material
costs and rig rates may have encouraged the delay of some projects, as
investors played a wait-and-see game in order to secure contracts at the
lowest possible cost. That trend appears to have bottomed out at the end
of 2009, however, after producing only a slight overall reduction in costs
[41]. Before the recent reduction in production costs, an industry research
group estimated that costs had approximately doubled since 2000 [42].
Severe problems in the global credit market that began in 2008 and continued
through 2009 have made it difficult to finance some exploration and production
(E&P) projects. The full effect of limits on credit availability for oil
supply projects will not be realized for some time, as the projects stalled
due to a lack of financing, particularly exploration projects, would not
have brought supply to the market for several years. In addition to its
impact on individual E&P projects, the recent credit crisis may also have
led to an overall and possibly lasting change in risk tolerance on the
part of both lenders and investors. Still, while credit terms were being
tightened and financial risk was being trimmed, ongoing exploration efforts
in Africa resulted in a wave of discoveries and new hope for unexplored
and under-explored non-OPEC resources.
Long-term prospects
Developments in 2008 and 2009 have demonstrated the range of the uncertainties
that underlie the four broad factors underlying long-term world oil prices,
as described above. It remains unclear how the world’s economy and the
demand for liquids will recover, what non-OPEC resources will be brought
to market, what production targets OPEC will set or meet, and whether or
when individual unconventional liquids projects will come online. The price
path assumptions in AEO2010 encompass a broad range of possible production
levels and world oil price paths, with a range of $160 per barrel (in real
terms) between the High Oil Price and Low Oil Price cases in 2035 (Figure
16). Consideration of Low and High Oil Price cases allows EIA and others
to analyze a variety of future oil and energy market conditions in comparison
with the Reference case.
Reference case oil prices
The global oil market projections in the AEO2010 Reference case are based
on the assumption that current practices, politics, and levels of access
will continue in the near to mid-term, whereas long-term developments will
be determined largely by economics. The Reference case assumes that the
world economy— and liquids demand—experience significant recovery in 2010,
with total liquids consumption returning to the 2008 level of just under
86 million barrels per day.
Satisfying the growing world demand for liquids in the next decade will
require accessing higher cost supplies, particularly from non-OPEC producers.
In the Reference case, the higher cost of non-OPEC supply supports average
annual increases in real world oil prices of approximately 0.7 percent
from 2008 to 2020 and 1.4 percent from 2020 to 2035. Oil prices, in real
terms, rebound following the global recession, to $95 per barrel in 2015
and $133 per barrel in 2035 (real 2008 dollars). Although increases in
OPEC production will meet a portion of the growing world demand, the Reference
case assumes that OPEC’s limits on production growth will maintain its share of
total world liquids supply at approximately 40 percent, where it has roughly
been over the past 15 years.
Growth in non-OPEC production will come primarily from high-cost conventional
projects in regions with unstable fiscal or political regimes and from relatively
expensive unconventional liquids projects. The return to higher price levels
in the Reference case results from limited access to prospective areas
for foreign investors, less attractive fiscal terms, and higher exploration
and production costs than have been seen in the past.
Low Oil Price case
The AEO2010 Low Oil Price case assumes that greater competition and international
cooperation will guide the development of political and fiscal regimes
in both consuming and producing nations, facilitating coordination and cooperation
among them. Non-OPEC producing countries are assumed to develop fiscal
policies and investment regimes that encourage private-sector participation
in the development of their domestic resources; and OPEC is assumed to
increase its production levels, providing 50 percent of the world’s liquids
supply by 2035. The availability of low-cost resources in both non-OPEC
and OPEC countries allows for prices to stabilize at relatively low levels,
$51 per barrel in real 2008 dollars, thereby reducing the incentive for
consuming nations to invest in unconventional liquids production as heavily
as they do in the Reference case.
High Oil Price case
The AEO2010 High Oil Price case assumes not only a rebound in world oil prices with the return of world economic growth, but also a continued rapid escala-tion in prices as a result of long-term restrictions on conventional liquids production. The restrictions re-sult from both political decisions and resource charac-teristics: the major OPEC and non-OPEC producing countries use quotas, fiscal regimes, and varying de-grees of nationalization to further increase revenues from oil production, and the consuming countries turn to domestic production of high-cost unconven-tional liquids to satisfy demand. As a result, in the High Oil Price case, world oil prices rise throughout the projection period, to $210 per barrel in 2035. Liquids demand is dampened by the high prices, but is overshadowed by the severity of limitations on access to and availability of lower cost conventional resources. OPEC’s share of production falls to 35 percent.
Components of liquid fuels supply
In the AEO2010 Reference case, total world liquid fuels consumption in 2035 is 112 million barrels per day, or 26 million barrels per day higher than in 2008, with production increases from OPEC and non- OPEC conventional sources totaling 15.5 million bar-rels per day. As a result, the conventional liquids share of world liquids supply drops from 95 percent in 2008 to 87 percent in 2035.
Production of unconventional crude oils in the AEO- 2010 Reference case is 4.0 million barrels per day higher in 2035 than in 2008 and represents 5.6 per-cent of global liquid fuels supply in 2035. Production increases from Venezuela’s Orinoco belt and Can-ada’s oil sands are limited by access restrictions inVenezuela and environmental concerns in Canada. The relatively high world oil prices in the Reference case encourage U.S. production of oil shale, with vol-umes reaching 0.4 million barrels per day in 2035. Relatively high prices also encourage growth in global CTL, GTL, and biofuel production, from a combined total of 1.8 million barrels per day in 2008 to 8.4 mil-lion barrels per day in 2035, or 8 percent of total liq-uids supplied.
In the AEO2010 Low Oil Price case, oil prices are on average more than 50 percent lower than in the Ref-erence case from 2015 to 2035. In this case, conven-tional crude oil accounts for the largest share of total liquids production in any of the three price cases in 2035, at about 90 percent. Production of conventional crude oil totals 100.5 million barrels per day in 2035, higher than the total for all conventional liquids in the Reference case. Total conventional liquids pro-duction reaches 114.8 million barrels per day, and total liquids production reaches 127 million barrels per day, in the Low Oil Price case in 2035.
Despite their generally higher costs, production of unconventional crude oils is also higher in the Low Oil Price case than in the Reference case, as a result of changes in economic access to resources. In the Low Oil Price case, Venezuela’s production of extra-heavy oil in 2035 increases from the Reference case projec-tion of 1.3 million barrels per day to 3.4 million bar-rels per day—a 160-percent increase that more than compensates for lower production of Canada’s oil sands (0.6 million barrels per day in 2035) due to reduced profitability. Total production of unconven-tional crude oil in the Low Oil Price case is 1.0 million barrels per day higher in 2035 than projected in the Reference case. Production of other unconventional liquids (CTL, GTL, and biofuels) in 2035, primarily in the United States, China, and Brazil, is 3.2 million barrels per day lower than projected in the Reference case, again due to reduced profitability.
In the High Oil Price case, oil prices from 2015 to 2035 are on average 66 percent higher than in the Reference case. The higher prices are caused by restrictions on economic access to non-OPEC con-ventional resources in countries such as Russia, Kazakhstan, and Brazil, combined with reductions in OPEC production. Conventional liquids production in the High Oil Price case totals 71.8 million barrels per day in 2035, 9.8 million barrels per day lower than the 2008 total; total liquids production reaches only 91 million barrels per day in 2035.
Access restrictions also limit the production of Vene-zuela’s extra-heavy oil from the Orinoco belt, which totals 0.8 million barrels per day in 2035, as compared with 1.3 million barrels per day in the Reference case. Higher world oil prices support increased pro-duction from Canada’s oil sands, which totals 5.5 million barrels per day in 2035, as compared with 4.5 million barrels per day in the Reference case. Produc-tion of shale oil, predominantly in the United States, does not change appreciably from the Reference case level in the High Oil Price case, because the projects are economically viable in the Reference case, and even a 66-percent increase in prices does not stimu-late additional production growth. With the increase in oil sands production outweighing the decrease in extra-heavy oil production through 2035, production of unconventional crude oil from all sources is higher in the High Oil Price case than in the Reference case.
Production of liquids from other unconventional sources, including CTL, GTL, and biofuels, is almost 50 percent (3.9 million barrels per day) higher in the High Oil Price case than in the Reference case in 2035. The increase results primarily from higher CTL production in China (approximately 1.3 million bar-rels per day above the Reference case projection in 2035) and higher biofuels production in the United States (0.9 million barrels per day above the Refer-ence case in 2035). U.S. GTL production in the High Oil Price case is notably different from the Reference case projection, with production beginning in 2017 and reaching 0.5 million barrels per day in 2035.
Energy intensity trends in AEO2010
Energy intensity—energy consumption per dollar of real GDP—indicates how
much energy a country uses to produce its goods and services. From the
early 1950s to the early 1970s, U.S. total primary energy consumption and
real GDP increased at nearly the same annual rate (Figure 17). During that
period, real oil prices remained virtually flat. In contrast, from the
mid-1970s to 2008, the relationship between energy consumption and real
GDP growth changed, with primary energy consumption growing at less than
one-third the previous average rate and real GDP growth continuing to grow
at its historical rate. The decoupling of real GDP growth from energy consumption
growth led to a decline in energy intensity that averaged 2.8 percent per
year from 1973 to 2008. In the AEO2010 Reference case, energy intensity
continues to decline, at an average annual rate of 1.9 percent from 2008
to 2035.
Definitions and classifications
Energy efficiency is defined as the ratio of the amount of energy services
provided to the amount of energy consumed [43]. Familiar examples of energy
services are the heat supplied by a furnace and the light output of a lamp.
Energy conservation is defined as the lowering of energy consumption by
reducing energy services. For example, lowering a thermostat’s setting
during the heating season is classified as energy conservation, because
less heating is provided. Because the ratio of energy services to energy
consumption is unchanged, energy efficiency does not change in this example.
As indicated above, energy intensity is defined as energy consumption per
dollar of real GDP. Any change in energy intensity that does not result
from a change in efficiency is referred to as a structural change [44].
Examples of structural change include energy conservation, a change in
the mix of economic activity among the sectors of the economy, a change
in the mix of activities within a sector, and a geographical change in
population density. Energy use is affected in these examples of structural
change, but not because of changes in energy efficiency.
CO2 emissions associated with energy production and consumption are a growing
concern. Carbon intensity is the ratio of CO2 emissions to real GDP. The
type of fuel used to provide energy services—or in the case of electricity,
the fuel used to generate it—affects carbon intensity.
As defined here, efficiency and intensity are inversely related: increases
in energy efficiency reduce energy intensity. To facilitate comparisons
among them, the efficiency index discussed below is calculated as the inverse
of the usual efficiency concept: energy consumption per unit of service
demand. In this way, both improvements in efficiency and improvements in
intensity are shown as decreases.
Results for the Reference case
Because the available data are limited, it is difficult to determine the
amount of historical decoupling of energy consumption growth from real
GDP growth that was attributable to improvements in energy efficiency [45].
With the wealth of technology detail on energy-using equipment in NEMS,
efficiency can be characterized readily [46]. Figure 18 compares indexes
of the Reference case projections for energy efficiency, energy intensity,
and carbon intensity. The average rate of decline in the index for energy
intensity from 2008 to 2035 is almost quadruple the rate of decline in the index for energy efficiency, reflecting the dominant role of structural change. The larger reduction in the index for carbon intensity reflects a shift toward
less carbon-intensive energy sources in the Reference case, especially
wind, biofuels, and solar. In the Reference case, the ratio of carbon emissions
to energy consumption in 2035 is 5 percent lower than its 2008 value.
Energy consumption increases at an average annual rate of 0.5 percent from
2008 to 2035 in the AEO2010 Reference case. The portion of the energy intensity
decline projected in the Reference case that can be attributed to structural
changes and the portion that can be attributed to changes in energy efficiency
is illustrated by comparing the growth of primary energy use in the Reference
case with estimates of constant energy efficiency and constant energy intensity,
calculated from the AEO2010 Reference case (Figure 19).
Assuming no improvement in energy intensity beyond 2008, energy consumption
would grow in the Reference case at the rate of real GDP, 2.4 percent annually,
to 192 quadrillion Btu in 2035—77.6 quadrillion Btu (68 percent) higher
than in the Reference case. Similarly, assuming no change in energy efficiency
beyond its 2008 level, energy consumption would increase to 132.8 quadrillion
Btu in 2035, or 18.3 quadrillion Btu (16 percent) higher than in the Reference
case. The intensity decline from structural change in the Reference case,
59.2 quadrillion Btu, is the difference between the projection for energy
consumption in 2035 when no change in energy intensity is assumed and the
same projection when no change in energy efficiency is assumed. Thus, structural
change accounts for 76 percent of the decline in energy intensity in the
Reference case, and efficiency improvement accounts for 24 percent.
Table 4 shows average annual growth rates from 2008 to 2035 for real GDP,
population, and major indicators for energy consumption in the end-use
sectors in the Reference case. Because the growth rate for real GDP is
higher than any of the other growth rates, energy consumption in each sector
would be expected to grow more slowly than real GDP, and energy intensity
would be expected to decline, even in the absence of efficiency gains.
In each of the end-use sectors, most of the improvement (decline) in energy
intensity results from structural change: 82 percent in the buildings sectors,
where average annual increases in residential and commercial floorspace
are only about one-half the average increase in real GDP; 82 percent in
the industrial sector, where output from non-energy-intensive manufacturing
grows at twice the rate of output from energy-intensive manufacturing;
and 53 percent in the transportation sector, where structural change is
slower and improvements in fuel efficiency as a result of tightening fuel
economy standards account for 47 percent of the decline in energy intensity.
(For further discussion of efficiency in the AEO2010 buildings cases, see
"Comparing efficiency projections".)
Results for the Integrated Technology cases
The AEO2010 Low Technology case assumes that the efficiency of newly purchased
equipment does not improve beyond what is currently available (although
end-use or process efficiency does improve to some extent as a result of
stock turnover, because replacement equipment nearly always is more efficient
than the equipment it replaces). The High Technology case assumes earlier
availability of high-efficiency technologies and lower technology costs
than in the Reference case. Also, in a departure from previous AEOs, the AEO2010 High Technology case assumes that consumers are more likely to
choose advanced technologies, because they evaluate efficiency investments
at a 7-percent real discount rate, which is generally lower than assumed
in the Reference case.
In the Low Technology and High Technology cases, projections for energy
consumption in 2035 are 2.4 quadrillion Btu (2 percent) higher and 5.7
quadrillion Btu (5 percent) lower, respectively, than in the Reference
case. Energy efficiency and intensity trends in the Reference, Low Technology,
and High Technology cases are shown in Figure 20. From 2008 to 2035, there
is a 12- to 17-percent improvement in energy efficiency across the three
cases and a 39- to 43-percent reduction in intensity.
The relatively narrow range of projections in Figure 20 indicates that,
although technology advances play a role in reducing energy intensity and
carbon intensity, structural components are much more significant. Population
shifts to more moderate climates, smaller households, less energy-intensive
manufacturing, and more fuel-efficient LDVs and high-speed rail could further
reduce energy intensity. Policies governing future CO2 emissions and deployment
of low- and no-carbon technologies will be the main determinant of future
carbon intensity.
Natural gas as a fuel for heavy trucks: Issues and incentives
Environmental and energy security concerns related to petroleum use for
transportation fuels, together with recent growth in U.S. proved reserves
and technically recoverable natural gas resources, including shale gas,
have sparked interest in policy proposals aimed at stimulating increased
use of natural gas as a vehicle fuel, particularly for heavy trucks. In
2008, U.S. freight trucks used more than 2 million barrels of petroleum-based
diesel fuel per day. In the AEO2010 Reference case, they are projected
to use 2.7 million barrels per day in 2035. Petroleum-based diesel use
by freight trucks in 2008 accounted for 15 percent of total petroleum consumption
(excluding biofuels and other non-petroleum-based products) in the transportation
sector (13.2 million barrels per day) and 12 percent of the U.S. total
for all sectors (18.7 million barrels per day). In the Reference case,
oil use by freight trucks grows to 20 percent of total transportation use
(13.7 million barrels per day) and 14 percent of the U.S. total (19.0 million
barrels per day) by 2035. The following analysis examines the potential
impacts of policies aimed at increasing sales of heavy-duty natural gas
vehicles (HDNGVs) and the use of natural gas fuels, and key factors that
lead to uncertainty in these estimates.
Historically, natural gas has played a limited role as a transportation
fuel in the United States. In 2008, natural gas accounted for 0.2 percent
of the fuel used by all highway vehicles and 0.2 percent of the fuel used
by heavy trucks—the market that many observers believe to be the most attractive
for increasing the use of natural gas. Because there are relatively few
heavy vehicles that use natural gas for fuel currently, there has been
very little development of natural gas fueling infrastructure. Currently
there are 827 fueling stations for CNG and 38 fuel stations for LNG in
the United States. Most are privately owned and are used for central refueling
[48]. Further, they are not distributed evenly: 24 percent (201) of the
CNG facilities and 71 percent (27) of the LNG facilities are in California.
Unless more natural gas vehicles enter the market, there will be little
incentive to build more natural gas fueling infrastructure nationally or
in local or regional corridors.
Despite the price advantage that natural gas has had over diesel fuel in
recent years (an advantage that is projected to increase over time in the
Reference case), other factors—including higher vehicle costs, lower operating
range, and limited fueling infrastructure— have severely limited market
acceptance and penetration of natural gas vehicles. As of 2008, trucks
powered by natural gas made up only 0.3 percent of the heavy truck fleet,
or about 27,000 of the 8.7 million registered heavy trucks. Although their
share grows in the Reference case projections, high incremental costs keep
the fleet of HDNGVs relatively small, at 1.7 percent (260,000 vehicles)
of the total stock of 15 million heavy trucks on the road in 2035.
Characteristics and usage of heavy-duty natural gas vehicles
HDNGVs have significant incremental costs relative to their diesel-powered
counterparts in the AEO2010 Reference case: $17,000 for light-heavy (class
3, GVWR of 10,000 to 14,000 pounds), $40,000 for medium-heavy (classes
4 through 6, GVWR of 14,001 to 26,000 pounds), and $60,000 for heavy trucks
(classes 7 and 8, GVWR of 26,001 pounds and greater). By far the largest
component of incremental cost is the fuel storage system, which consists
either of cylindrical tanks to hold CNG at high pressure or of highly insulated
tanks to hold LNG. Because tank technology is fairly mature and, in the
case of cylindrical tanks to hold gases at high pressure, is already widely
deployed, the Reference case does not assume significant reductions in
incremental vehicle costs over time.
Natural gas for use in transport vehicles currently costs 42 percent less
than diesel fuel (on an energy-equivalent basis and considering only existing
taxes), and with oil prices rising at a significantly faster rate than
U.S. natural gas prices, the gap is projected to widen to 50 percent in
2035 in the AEO2010 Reference case (Figure 21). Consequently, the payback
period for incremental vehicle costs becomes shorter when natural gas trucks
are used more intensively.
The Department of Transportation’s Vehicle Inventory and Use Survey (VIUS),
last completed in 2002, suggests a wide range for the intensity of heavy
truck use. Notably, in the 2002 VIUS, trucks reporting a primary range
of operation that extended more than 500 miles from their base averaged
91,000 vehicle-miles traveled (VMT), or more than 5 times the average of
17,000 VMT for trucks reporting a primary range of operation range within
100 miles of their base.
Although long-distance trucking offers a potentially faster payback of
the incremental capital costs for HDNGVs, their penetration and acceptance
in the long-distance freight market faces two significant barriers: limited
driving range without refueling and a lack of available fueling infrastructure.
A diesel truck with one 150-gallon diesel tank and a fuel economy of 6
to 7 mpg can drive approximately 1,000 miles without refueling, which can
be extended readily with an auxiliary fuel tank. In contrast, a CNG-fueled
truck with a frame-rail-mounted storage tank can drive only about 150 miles
without refueling, while one with a back-of-cab frame-mounted storage tank
can drive about 400 miles without refueling, similar to an LNG-fueled truck
with frame-rail-mounted tanks. In addition, regardless of fuel type, long-distance
trucks are less likely to be fueled at central bases, which makes them
more dependent on fueling infrastructure that is open to the public.
In addition to concerns about driving range and refueling, the residual
value of HDNGVs in the secondary market is likely to be an important consideration
for buyers. Also, purchase decisions can be influenced by other factors,
such as weight limits on highways and bridges, which can make the considerable
additional weight of CNG or LNG tanks a significant drawback in some market
segments.
The importance of range and refueling infrastructure barriers suggests
that the best near-term market penetration opportunity for HDNGVs, some
of whose incremental costs are already covered by tax credits, could be
in the market for centrally fueled fleets that operate primarily within
a limited distance from their base. The 2002 VIUS reported a total of 145
billion truck VMT (not counting light trucks used primarily for personal
transportation), of which about 50 percent was made up by trucks with a
primary operating range of 200 miles or less and about one-third by trucks
fueled at private facilities (presumably, with considerable overlap between
the two groups). Accordingly, the following analysis focuses on “fleet
vehicles” in the short-range (less than 200 miles), centrally fueled segment
of the heavy truck market.
Sensitivity cases with incentives for heavy-duty natural gas vehicles
Policies that provide economic incentives—such as tax credits for vehicles,
fuel, and fueling infrastructure—could stimulate sales of HDNGVs and the
development of additional natural gas fueling infrastructure. AEO2010 includes
several sensitivity cases that examine the potential impacts of such incentives.
The Reference Case 2019 Phaseout With Base Market Potential is a modified
Reference case that incorporates lower incremental costs for all classes
of HDNGVs (zero incremental cost relative to their diesel-powered counterparts
after accounting for incentives) and tax incentives for natural gas refueling
stations ($100,000 per new facility) and for natural gas fuel ($0.50 per
gallon of gasoline equivalent) that begin in 2011 and are phased out by
2019.
The Reference Case 2027 Phaseout With Expanded Market Potential is another
modified Reference case with the same added assumptions of lower incremental
costs for HDNGVs and subsidies for fueling stations and natural gas fuel
as in the first modified Reference case, but with the subsidies extended
to 2027 before phaseout. In addition, it assumes increases in the potential
market for natural gas vehicles, for both “fleet vehicles” and “nonfleet
vehicles” (see Table 5).
In the following text and data presentations, the cases above are referred
to more briefly as the 2019 Phaseout Base Market case and 2027 Phaseout
Expanded Market case.
HDNGVs cannot gain a major share of the heavy truck market in the absence
of major investments in natural gas fueling infrastructure. The assumed
$100,000 tax credit per filling station is a relatively small percentage
of the estimated $1 million to $4 million cost for such facilities. Assuming
an initial cost of $2 million per station, Table 6 shows the levelized
capital cost of the station per gallon of diesel equivalent refueling capacity
with and without the $100,000 tax credit, for station fuel throughput capacities
of 1,250, 5,000, and 12,500 gallons per day [49].
As indicated in Table 6, increasing the throughput capacity of a fueling
station from 1,250 to 5,000 gallons diesel equivalent per day lowers the
capital cost recovery component of supplying natural gas fuel to HDNGVs
by more than $1.00 per gallon of diesel equivalent. The infrastructure
tax credit lowers the capital cost recovery component by only an additional
8 cents per gallon for the smallest facility size shown in the table and
by only 1 cent per gallon for the largest facility size. This suggests
that throughput capacity (demand) is a far more important consideration
for decisions about investment in natural gas fueling stations than are
potential tax credits on the order of about $100,000.
Impacts of incentives in the Base Market and Expanded Market cases with
Reference case world oil price assumptions
In the 2019 Phaseout Base Market and 2027 Phaseout Expanded Market cases,
both of which use oil price assumptions from the AEO2010 Reference case,
HDNGV sales increase with the availability of incentives. Assuming a 2019
phaseout date for tax credits and the base characterization of maximum
penetration of the new truck market, sales of new HDNGVs in the 2019 Phaseout
Base Market case increase from about 500 in 2008 to 32,500 in 2035, versus
22,000 in the Reference case (Figure 22). Assuming a 2027 phaseout of tax
credits and the expanded characterization of maximum market penetration,
HDNGV sales in the 2027 Phaseout Expanded Market case increase to 270,000
in 2035, or roughly 35 percent of all new heavy truck sales. The HDNGV
share of the total U.S. heavy truck stock in 2035 is 2.8 percent in the
2019 Phaseout Base Market case and 23.3 percent in the 2027 Phaseout Expanded
Market case (versus 1.7 percent in the Reference case).
As a result of the projected increases in new HDNGV sales, natural gas
demand in the heavy truck sector increases from about 0.01 trillion cubic
feet in 2008 to 0.15 trillion cubic feet in 2035 in the 2019 Phaseout Base
Market case and to 1.6 trillion cubic feet in 2035 in the 2027 Phaseout
Expanded Market case (Figure 23). In the Reference case, the natural gas
share of total fuel consumption by heavy trucks increases from 0.2 percent
in 2008 to 1.8 percent in 2035; in the 2019 Phaseout Base Market and 2027
Phaseout Expanded Market cases, it increases to 3.3 percent and 40.0 percent,
respectively.
Roughly speaking, 1 trillion cubic feet of natural gas replaces 0.5 million
barrels per day of petroleum (predominantly, diesel fuel). Thus, natural
gas consumption by HDNGVs in the 2027 Phaseout Expanded Market case displaces
about 0.67 million barrels per day of petroleum product consumption in 2035
(Figure 24). Without a major impact on world oil prices, which is not expected
to result from the significant but gradual adoption of natural gas as a
fuel for U.S. heavy-duty vehicles, nearly all (more than four-fifths) of the
reduction in U.S. oil consumption would result in a decline in oil imports.
In the longer term, increased demand for natural gas in the transportation
sector would tend to stimulate increases in U.S. natural gas production
and imports, as well as higher natural gas prices in all the end-use sectors.
As a result, natural gas demand in the other sectors would decrease—particularly
in the electric power sector, where some generators would switch to coal—and
expenditures for natural gas would increase. In the AEO2010 Reference case,
total U.S. natural gas consumption increases from 23.3 trillion cubic feet
in 2008 to 24.9 trillion cubic feet in 2035. In the 2019 Phaseout Base
Market case and 2027 Phaseout Expanded Market case, total natural gas consumption
increases by 0.4 percent, to 25.0 trillion cubic feet, and by 4.8 percent,
to 26.1 trillion cubic feet, respectively, in 2035.
In the 2019 Phaseout Base Market case and 2027 Phaseout Expanded Market
case, more than two-thirds of the additional natural gas used by HDNGVs
is produced domestically, and less than one-third is provided by increases
in pipeline imports from Canada and LNG imports. U.S. natural gas prices
rise modestly in both cases.
Impacts of incentives in the Base Market and Expanded Market cases with
low world oil price assumptions
Lower oil prices tend to make HDNGVs a less attractive option, and higher
oil prices tend to make them more attractive. In the two sensitivity cases
discussed above, which assumed Reference case world oil prices, market
penetration by HDNGVs reaches or nearly reaches its assumed maximum market
potential. As a result, higher oil prices would not lead to further increases
in HDNGV sales, unless the large price advantage of natural gas were sufficient
to open additional segments of the heavy truck transportation market to
the use of natural-gas-fueled vehicles.
On the other hand, if oil prices were lower than projected in the Reference
case, there would be less incentive to switch from diesel to natural gas
fuel in heavy trucks. With no tax incentives or assumed market expansion
for HDNGVs, there are almost no sales of new HDNGVs in 2035 in the AEO2010 Low Oil Price case. To analyze the impact of lower oil prices, EIA ran
two sensitivity cases that were identical to those discussed earlier but
instead used the Low Oil Price case. In the 2019 Phaseout Base Market Low
Price case, sales of new HDNGVs total about 17,000 in 2035. In the 2027
Phaseout Expanded Market Low Price case, sales of new HDNGVs total about
205,000 in 2035. Similarly, natural gas consumption by HDNGVs increases
to 0.1 trillion cubic feet in 2035 in the 2019 Phaseout Base Market Low
Price case and to 1.2 trillion cubic feet in the 2027 Phaseout Expanded
Market Low Price case, as compared with almost no demand for natural gas
in the heavy vehicle sector in 2035 in the AEO2010 Low Oil Price case.
Incentive costs and impacts on energy expenditures
Increased use of natural gas as a transportation fuel changes the levels
of demand for, and consequently the prices of natural gas and other fuels
used in transportation and other sectors of the economy. Depending on the
amount of natural gas used in the transportation sector, the sum of incentive
payments to the transportation sector plus higher energy costs to other
sectors may be more than offset by savings in the transportation sector
from fuel switching from diesel to natural gas. Figure 25 shows annual vehicle
and fuel tax incentive payments and net changes in economy-wide energy
expenditures for the 2027 Phaseout Expanded Market case [50]. The graph shows how changes
in transportation demand for natural gas and petroleum products may affect
energy expenditures throughout the economy while the incentives are in
effect. The significant increase in transportation natural gas use and associated
reductions in petroleum product use result in increases in economy-wide
natural gas prices and expenditures that are more than offset by economy-wide
decreases in petroleum product prices and expenditures.
The projections in Figure 25 do not reflect many of the factors that could
be important for policymakers’ evaluations of incentives for HDNGVs, such
as the cost of infrastructure tax credits, productivity losses resulting
from more frequent refueling, impacts on net energy costs, incremental
vehicle costs beyond the period when incentives are provided, or environmental
benefits of reducing emissions of conventional pollutants and GHGs. Also,
they do not consider potential effects on royalty and severance payments
as a result of changes in domestic natural gas production or oil imports,
or effects on GDP and other relevant indicators of economic welfare and
energy security.
Factors affecting the relationship between crude oil and natural gas prices
Background
Over the 1995-2005 period, crude oil prices and U.S. natural gas prices
tended to move together, which supported the conclusion that the markets for the two commodities were
connected. Figure 26 illustrates the fairly stable ratio over that period
between the price of low-sulfur light crude oil at Cushing, Oklahoma, and
the price of natural gas at the Henry Hub on an energy-equivalent basis.
The AEO2010 Reference and High Oil Price cases, however, project a significantly
longer and persistent disparity between the relative prices of low-sulfur
light crude oil and natural gas on an energy-equivalent basis [51]. The
apparent disconnect in prices between seemingly similar commodities varies
over a wide range between 2010 and 2035 [52]. Over much of the projection
period in the Reference case, the crude oil price is about 2.8 times the
natural gas price on an energy equivalent basis—115 percent higher than
the historical average price ratio of 1.3 from 1995 to 2005. In the High
Oil Price case, the ratio widens to as much as 4.8; in the Low Oil Price
case, it narrows from nearly 3.0 in 2009 to 1.1 in 2035.
Such an apparent lack of responsiveness of natural gas prices to changes
in crude oil prices in all cases reflects the changes that have occurred
in the underlying uses of the two commodities. The divergence of crude
oil and natural gas markets also reflects the fact that opportunities for
the substitution of natural gas for crude oil products are limited by the
large infrastructure investments that would be required to allow substitution
on a significant scale and bring the prices of the two commodities closer
together in the U.S. market in the Reference and High Oil Price cases. In
the absence of such investments, EIA expects the gap between oil and natural
gas prices in U.S. energy markets to remain wide.
Opportunities to substitute natural gas for petroleum
In the United States, the capability to substitute natural gas supplies
directly for petroleum, particularly in the electric power sector, has
eroded over time. In 1978, 4.0 quadrillion Btu of petroleum was consumed
to produce electricity, representing nearly 17 percent of total energy
use for U.S. electricity generation, as compared with 14 percent for natural
gas [53]. In 2008, only 0.5 quadrillion Btu of petroleum was consumed for
electricity generation, representing 1.2 percent of total energy use for
generation [54, 55], while natural gas has grown to 17 percent of generation.
The trend has been similar in the commercial and industrial sectors where
there are a declining number of opportunities to substitute natural gas
for petroleum.
Still, there are potential opportunities for natural gas to displace petroleum.
First, direct use of natural gas in the U.S. transportation sector could
provide an opportunity for substitution. Second, natural gas could be exported
to countries where petroleum is widely used for thermal applications. Third,
natural gas can be converted directly to petroleum-like liquid fuels that
could be substituted for diesel and gasoline in the existing vehicle fleet
using the existing distribution infrastructure.
The physical properties of natural gas are such that it is more difficult
and costly than liquid fuels to transport and consume. As shown in Figure
27, the energy density of natural gas is much lower than that of most liquid
fuels. To match the energy equivalent of a 1-gallon container of diesel
fuel, a balloon of natural gas at atmospheric pressure would have to be
nearly a thousand times larger than the gallon container. At a pressure
of 3,600 pounds per square inch (psi), however, which is the pressure rating
for the fuel tanks used in CNG vehicles, only 4 times as much space is
required to match the energy equivalent of 1 gallon of diesel fuel. And
when the gas is converted to LNG by chilling to about -260 degrees Fahrenheit,
its energy density increases to the point where it requires only 50 percent
more volume to match the energy content of diesel fuel. However, the materials
used for the handling and storage of LNG differ significantly from those
used for CNG or petroleum-like liquid fuels.
An expanded market for CNG or LNG would require additional investment in
vehicles and infrastructure for compression and storage of CNG or for liquefaction
and storage of LNG. Some of the issues, challenges, and opportunities surrounding
the use of natural gas as a substitute for diesel fuel are described in
the Issues in Focus section, “Natural gas as a fuel for heavy trucks: Issues
and incentives.”
Barriers to U.S. exports of LNG
World crude oil and natural gas prices could converge if barriers to the
flow of natural gas between U.S. and world markets were eliminated through
the combined use of the existing pipeline network, existing LNG terminals,
and investment in new U.S. LNG liquefaction capacity (and possibly LNG
tankers) to allow exports of U.S. natural gas when it is economical. Currently,
there is one liquefaction facility in Alaska that exports LNG from the
United States. Investment in new U.S. liquefaction capacity would face
significant risk, however, because there are large quantities of “stranded
gas” in remote regions of the world that can be priced well below the expected
cost of resources in the lower 48 States.
Potential for production of liquid fuels from natural gas
Another opportunity to substitute natural gas for crude oil would be to
convert it to petroleum-like liquid products similar to gasoline and diesel
fuel, for use in the liquid fuel infrastructure and end-use equipment.
Such a transformation is possible through use of the GTL process.
There are several GTL processes, the best known using a Fischer-Tropsch
reactor. The reactor produces a paraffin wax that is hydrocracked to form
liquid products that resemble petroleum liquids. Distillates, including
diesel, heating oil, and jet fuel, are the primary products, making up
50 to 70 percent of the total volume produced, and naphtha usually represents
about 25 percent of the volume. The process efficiency is about 57 percent
(43 percent of the energy content of the natural gas is lost in the process)
[56]. Thus, the price ratio of liquid products to natural gas would have
to exceed about 1.8 to justify operation of the plant, excluding consideration
of other operating costs and the cost of capital investment. To appreciate
the price risk faced by investors, one can consider the effects of recent
fluctuations in energy prices on investments in U.S. natural gas turbine
and combined-cycle generating units and ethanol production facilities [57].
Indeed, AEO2010 examines the potential impacts of lower energy prices in
the Low Oil Price case, which shows the ratio of crude oil prices to natural
gas prices declining to 1.1 in 2035, indicating that if any GTL plants were
built they would not be operated under those price conditions.
The technologies and equipment used in the best-known GTL technology are
similar to those that have been employed for decades in methanol and ammonia
plants, and most are relatively mature; however, the scale on which previous
GTL plants have been implemented is relatively small. The newest GTL plants
have been expanded to much larger sizes, including one in excess of 100,000
barrels per day, to take advantage of economies of scale, but recent attempts
to build projects at those larger sizes have encountered technology or
project execution risks [58]. Currently, there are four GTL plants in operation
worldwide, with 96,200 barrels per day of total capacity [59]. In addition,
two projects with 174,000 barrels per day of capacity are under construction
or ready for startup [60]. However, the construction of GTL plants at sites
with available stranded gas reserves has been limited, indicating investor
reluctance to pursue this option fervently, especially when investments
in less capital-intensive LNG capacity are possible. Indeed, some GTL projects
have been canceled or deferred in the past few years [61].
The overnight capital costs for a new GTL plant situated on the U.S. Gulf
Coast would range from $50,000 per barrel-stream day of capacity [62] to
an estimated $104,000 per barrel-stream day [63]. Accordingly, a relatively
modest unit with a capacity of 34,000 barrels per day represents an estimated
overnight capital cost [64] of $1.7 billion to $3.5 billion. With financing
included, the estimated total investment would be $2.2 billion to $4.4
billion. In addition, construction of the facility would take 4 years or
more, imposing further market risk. The risk-adjusted discount factor used
by investors will be critical to determining whether investors would proceed
with GTL investments.
Figure 28 shows the maximum “breakeven” average price of natural gas that
could be tolerated over a 10-year plant operating period [65] in order
to justify the risk associated with investing in a GTL facility, based
on the range of capital costs discussed above and a 10-percent hurdle rate
[66]. Profitable cases lie below the line. At $100 per barrel for crude
oil, the breakeven price for natural gas that would justify investment
in a GTL facility is -$1.20 to $5.80 per million Btu. At higher crude oil
prices, the range of the breakeven natural gas price also rises. At a crude
oil price of $200 per barrel, the breakeven price for natural gas is $10.20
to $17.30 per million Btu. At a crude oil price of $60 per barrel, the
breakeven natural gas price ranges from -$5.80 to $1.30 per million Btu,
illustrating the substantial impact of oil price uncertainty on the profitability
of investment in a GTL facility.
Figure 28 also shows how investment in a GTL facility would fare with the
natural gas and crude oil price projections in the AEO2010 Reference, Low
Oil Price, and High Oil Price cases. With the prices in the Low Oil Price
case, GTL is a poor investment. With the prices in the Reference case,
GTL is a marginal investment. Only with the highest prices in the Reference
case and the low end of GTL plant costs do the breakeven economics favor
the project. In the High Oil Price case, however, the combination of higher
crude oil prices and lower natural gas prices implies that investment in
a GTL plant on the U.S. Gulf Coast could be profitable.
A large investment in GTL would be needed in order to produce an appreciable
effect on worldwide prices for crude oil and U.S. natural gas. Construction
of sufficient new GTL capacity to affect world crude oil prices, about
1 million barrels per day, would require a total investment between $50
billion and $135 billion. That level of capacity would still represent
only 1.2 percent of the 85.9 million barrels per day of the world’s estimated
total liquids production in 2007 [67], and less than 1 percent of projected
2035 production in the Reference case [68].
Another option is the potential use of stranded natural gas in Alaska to
produce GTL. Because of Alaska’s severe weather conditions, construction
of GTL (or any other) facilities is likely to be much more expensive than
the construction of GTL plants on the U.S. Gulf Coast or in the Middle
East. Some estimates suggest that doubling the construction costs and extending
the construction period by at least 2 years would be reasonable assumptions.
Construction of GTL facilities in Alaska, therefore, seems unlikely given
the cost uncertainties mentioned above and the crude oil price projections
in the AEO2010 Reference case.
Looking forward
A large disparity between crude oil and natural gas prices, as projected
in the AEO2010 Reference and High Oil Price cases, will provide incentives
for innovators and entrepreneurs to pursue opportunities that, in the longer
term, could increase domestic or international markets for U.S. natural
gas. For example, a scenario with relatively high oil prices would tend
to increase the value of CO2 used for EOR as well as GTL production. Because
GTL processing plants can accommodate natural gas feedstocks with relatively
high CO2 content and can target fields smaller than those required for
LNG production, such circumstances would provide incentives for the development
of smaller GTL systems that produce both liquid products and a valuable
CO2 co-product. Because EIA cannot predict whether or when such innovations
might arise, they are not included in the AEO2010 analysis cases.
Importance of low-permeability natural gas reservoirs
Introduction
Production from low-permeability reservoirs, including shale gas and tight
gas, has become a major source of domestic natural gas supply. In 2008,
low-permeability reservoirs accounted for about 40 percent of natural gas
production and about 35 percent of natural gas consumption in the United
States. Permeability is a measure of the rate at which liquids and gases
can move through rock. Low-permeability natural gas reservoirs encompass
the shale, sandstone, and carbonate formations whose natural permeability
is roughly 0.1 millidarcies or below. (Permeability is measured in “darcies.”)
The use of hydraulic fracturing in conjunction with horizontal drilling
in shale gas formations and the use of hydraulic fracturing in tight gas
formations has opened up natural gas resources that would not be commercially
viable without these technologies. As shale gas production has expanded
into more basins and recovery technology has improved, the size of the
shale gas resource base in the AEO has increased markedly. Because the
exploitation of shale gas resources is still in its initial stages, and
because many shale beds have not yet been tested, there is a great deal
of uncertainty over the size of the recoverable shale gas resource base.
Low-permeability gas wells typically produce at high initial flow rates,
which decline rapidly and then stabilize at relatively low levels for the
remaining life of the wells.
To illustrate the importance of low-permeability natural gas reservoirs
for future U.S. natural gas supply, consumption, and prices, three alternative
cases were developed for AEO2010: a No Shale Gas Drilling case, a No Low-Permeability
Gas Drilling case, and a High Shale Gas Resource case. The No Shale Gas
Drilling and No Low-Permeability Gas Drilling cases examine the implications
of no new drilling in low-permeability formations. The High Shale Resource
case examines the possibility that shale gas resources could be considerably
greater than those represented in the Reference case. The three alternative
cases are not intended to represent any expected future reality. Rather,
they are intended to illustrate the importance of low-permeability formations
for EIA’s projections of future U.S. natural gas supply and are likely
to be extremes. All the cases assume no change from the Reference case
assumptions about the size of, and access to, Canadian and other international
natural gas resources. Specific assumptions in the three cases are as follows.
No Shale Gas Drilling case. Starting in 2010, in this case no new onshore
lower 48 shale gas production wells are drilled. Natural gas production
from shale gas wells drilled before 2010 declines continuously through
2035.
No Low-Permeability Gas Drilling case. Starting in 2010, in this case no
new onshore lower 48 low-permeability natural gas production wells are drilled,
including shale gas wells and “tight” sandstone and carbonate gas wells.
Natural gas production from low-permeability wells drilled before 2010
declines continuously through 2035.
High Shale Gas Resource case. In this case, the unexploited portion of
each shale formation supports twice as many new wells as in the Reference
case. The lower 48 shale gas resource base increases by 88 percent, from
347 trillion cubic feet in the Reference case to 652 trillion cubic feet
in the High Shale Gas Resource case. The estimated recovery per well in
each formation is the same as in the Reference case.
Natural gas supply, consumption, and prices
Low-permeability natural gas resources are more abundant and less expensive
than other domestic natural gas supply alternatives that could replace
them, and they are expected to play a significant role in future domestic
natural gas markets. Consequently, their future absence or presence is
expected to have a significant impact on the average cost of natural gas
production and prices, which in turn would affect natural gas imports and
consumption. In the No Shale Gas Drilling and No Low-Permeability Gas Drilling
cases, lower 48 onshore natural gas productive capacity is less than in
the Reference case, and as a result average U.S. natural gas prices are
higher, more natural gas is imported, and natural gas consumption is reduced
(Table 7). Conversely, in the High Shale Gas Resource case, natural gas
productive capacity is higher, natural gas prices and imports are lower,
and consumption is higher than projected in the Reference case.
No Shale Gas Drilling and No Low-Permeability Gas Drilling cases
In the No Shale Gas Drilling and No Low-Permeability Gas Drilling cases,
total domestic natural gas production in 2035 is 18 percent and 25 percent
lower, respectively, and onshore lower 48 production is 27 percent and
39 percent lower, respectively, than in the Reference case. The loss of
onshore lower 48 productive capacity leads to higher natural gas prices
and lower consumption levels. In the No Shale Gas Drilling and No Low-Permeability
Gas Drilling cases, the Henry Hub spot price for natural gas in 2035 is
$1.49 and $2.00 per million Btu higher, respectively, than the Reference
case price of $8.88 per million Btu. The significantly higher natural gas
prices are a result of the removal of considerable low-cost natural gas
resources, leaving a smaller natural gas resource base that is more expensive
to produce.
Because higher domestic natural gas prices make other supply sources more
competitive, both offshore Gulf of Mexico production and net natural gas
imports increase in the No Shale Gas Drilling and No Low-Permeability Gas
Drilling cases. Offshore natural gas production levels in 2035 are 7 percent
and 18 percent (0.3 trillion cubic feet and 0.8 trillion cubic feet) higher,
respectively, than in the Reference case, and net imports are 154 percent
and 207 percent higher (2.2 trillion cubic feet and 3.0 trillion cubic
feet). In 2035, net imports make up 6 percent of total U.S. natural gas
supply in the Reference case, 16 percent in the No Shale Gas Drilling case,
and 20 percent in the No Low-Permeability Gas Drilling case. The higher
levels of net imports in the two alternative cases are the result of increases
in LNG imports and imports from Canada, as well as a reduction in exports
to Mexico.
In 2035, net LNG imports in the No Shale Gas Drilling and No Low-Permeability
Gas Drilling cases are more than double those in the Reference case (1.8, 2.4,
and 0.8 trillion cubic feet, respectively), and net natural gas imports
from Canada are 52 percent and 59 percent greater, respectively, in the
two alternative cases than in the Reference case. Because the assumptions
in these cases are not applied to the Canadian natural gas resource base,
higher U.S.prices lead to more natural gas production in Canada (including Canadian
shale gas). In addition, Canada’s Mackenzie Delta natural gas pipeline
begins operating before 2035 in the two alternative cases, which does not
occur in the Reference case. Net natural gas exports to Mexico in 2035
are 35 percent and 47 percent lower in the No Shale Gas Drilling and No
Low-Permeability Gas Drilling cases, respectively, than in the Reference
case.
The impact on natural gas consumption of restricted drilling in low-permeability
reservoirs is less pronounced than the impact on domestic supply, for two
reasons. First, the increase in net imports partially offsets the reduction
in domestic natural gas productive capacity. Second, long-lived natural
gas consumption equipment responds more slowly to changes in natural gas
prices than does natural gas supply—although the electric power sector,
where natural gas consumption responds relatively quickly to changes in
natural gas prices, is an exception. In 2035, natural gas consumption in
the electric power sector is 1.3 trillion cubic feet (17 percent) lower
in the No Shale Gas Drilling case and 1.9 trillion cubic feet (26 percent)
lower in the No Low-Permeability Gas Drilling case than the Reference case
level of 7.4 trillion cubic feet.
High Shale Gas Resource case
Relative to the Reference case, both natural gas production costs and prices
are reduced in the High Shale Gas Resource case. Consequently, domestic
natural gas production is more competitive, and U.S. natural gas consumption
is higher. In 2035, onshore lower 48 and total natural gas production are
17 percent and 11 percent higher, respectively, in the High Shale Gas Resource
case than in the Reference case, and Henry Hub spot prices are $1.26 per
million Btu lower than in the Reference case. Increased domestic production
and lower natural gas prices reduce net imports in 2035 by 44 percent from
their level in the Reference case, to 0.8 trillion cubic feet, and offshore
natural gas production in 2035 is reduced by 7 percent, to 4.0 trillion
cubic feet. The decline in net imports results from a 19-percent reduction
in net imports from Canada, an 8-percent reduction in net LNG imports,
and a 25-percent increase in net exports to Mexico in the High Shale Gas
Resource case, relative to the Reference case.
Because of the lower natural gas prices in the High Shale Gas Resource
case, U.S. natural gas use in 2035 is 2.0 trillion cubic feet (8 percent)
higher than in the Reference case. The majority of the increase is in the
electric power sector, which accounts for 1.3 trillion cubic feet (18 percent)
of the total increase.
U.S. nuclear power plants: Continued life or replacement after 60?
Background
Nuclear power plants generate approximately 20 percent of U.S. electricity,
and the plants in operation today are often seen as attractive assets in
the current environment of uncertainty about future fossil fuel prices,
high construction costs for new power plants (particularly nuclear plants),
and the potential enactment of GHG regulations. Existing nuclear power
plants have low fuel costs and relatively high power output. However, there
is uncertainty about how long they will be allowed to continue operating.
The nuclear industry has expressed strong interest in continuing the operation
of existing nuclear facilities, and no particular technical issues have
been identified that would impede their continued operation. Recent AEOs
had assumed that existing nuclear units would be retired after 60 years
of operation (the initial 40-year license plus one 20-year license renewal).
Maintaining the same assumption in AEO2010, with the projection horizon
extended to 2035, would result in the retirement of more than one-third
of existing U.S. nuclear capacity between 2029 and 2035. Given the uncertainty
about when existing nuclear capacity actually will be retired, EIA revisited
the assumption for the development of AEO2010 and modified it to allow
the continued operation of all existing U.S. nuclear power plants through
2035 in the Reference case.
The modified assumption in the Reference case implies that the operating
lives of some nuclear plants will be more than 60 years. To address the
uncertainty about whether such life extensions will be allowed, an alternative
Nuclear 60-Year Life case was developed, assuming that all the existing
U.S. nuclear power plants will be retired after 60 years of operation.
Discussion
The Atomic Energy Act of 1954 authorized the U.S. Nuclear Regulatory Commission
(NRC) to issue operating licenses for commercial nuclear power plants for
a period of 40 years. The 40-year time frame was derived from accounting
and anti-trust concerns, not technical limitations [69]. The law allows
the NRC to issue operating license renewals in 20-year increments, provided
that reactor owners demonstrate that continued operations can be conducted
safely. As of July 2009, the NRC had granted license renewals to 50 of
the 104 operating reactors in the United States, allowing them to operate
for 60 years. Fifteen additional applications are under review, and the
owners of 21 other units have announced that they intend to file for 20-year
license extensions. The NRC has yet to deny an application for a 20-year
extension [70]. Previous AEOs assumed that all of the 104 existing units
would operate for a total of 60 years, provided that they remained economical.
In December 2009, the Oyster Creek Generating Station in Lacey Township,
New Jersey, became the first nuclear power plant in the United States to
begin its 40th year of operation. With Oyster Creek and other nuclear plants
of similar vintage just beginning to enter their first period of license
renewal, it probably will be at least 5 to 10 years before there is any
clear indication as to whether plant operators will be likely to seek further
extensions of their plants’ operating lives.
For the AEO2010 Reference case, EIA assumed that the operating lives of
existing nuclear power plants would be extended at least through 2035.
Assuming that the NRC continues to approve license extensions, the decision
to operate a facility is an economic one made by plant owners. Aging plants
may face increased operation and maintenance (O&M) costs and capital expenditures,
which generally decrease their profitability. Revenue projections are dependent
on electricity prices, which are uncertain due to variations in fossil
fuel prices, regional economic growth, and environmental regulations. Thus,
even if the costs of operating nuclear plants do not change, changes in
electricity prices can affect their profitability when their generation
is sold at market-based rates.
Between 1974 and 1998, 14 commercial nuclear reactors in the United States
were retired. The circumstances of each retirement were unique to the particular
plant, but the common thread was that the expected cost of continued operation
was higher than expected revenues, and there were less costly generating
options available. Highly competitive natural-gas-fired generation could
have been a factor in those retirements. Natural-gas-fired combined-cycle
plants were the favored option for new capacity during the 1990s, when
natural gas prices were relatively low and it was widely believed that
they would remain low for the foreseeable future. In contrast, real O&M
costs for nuclear power plants had increased by 77 percent during the 1980s
[71], owners faced the risk that new NRC regulations might require prohibitively
expensive retrofits, and there was widespread concern State public utility
commissions would not allow full cost recovery for expenditures on nuclear
plants.
The economics of existing nuclear power plants are more favorable today,
because natural gas prices are higher, the nuclear plants are performing
well, and the potential enactment of GHG regulations increases uncertainty
about fuel and operating costs for power plants that burn coal and natural
gas. To date, there have been no announced plans to retire any of the 104
operating U.S. commercial nuclear reactors. To the contrary, the NRC and
the nuclear power industry are preparing applications for license renewals
that would allow continued operation beyond 60 years, the first of which
is scheduled to be submitted by 2013. In February 2008, DOE and the NRC
hosted a joint workshop titled “Life Beyond 60,” with a broad group of
nuclear industry stakeholders meeting to discuss this issue [72]. The workshop’s
summary report outlined many of the technical research needs that participants
agreed were important to extending the life of the existing fleet of U.S.
nuclear plants.
Several concerns were expressed at the DOE/NRC workshop. Because heat,
water, and radiation can have long-term effects on the materials they are
in contact with in nuclear power plants, more effective monitoring may
be needed as the systems age, which could require updates to instruments
and controls. Over the next several years, research is being focused on
identifying problems that aging facilities might encounter and formulating
potential solutions. Until that research has been completed, it will be
difficult to estimate any cost increases that may result from extending
the age of reactors.
Future cost increases may reflect only routine expenditures, or they could
involve major capital projects, such as the replacement of reactor vessels,
containment structures, or buried piping and cables. To date, no plans
or cost estimates for such potential modifications have been made public;
however, they have the potential to be very expensive, and they could require
extended plant shutdowns. While a plant is out of operation, the generation
lost will have to be replaced, probably with expensive power purchased
on the spot electricity market.
For most existing nuclear plants, decisions about retirement or life extension
ultimately will be based on the cost and feasibility of all the measures
needed for a plant to continue to operate safely and economically. It is
difficult to anticipate future operating costs, but it can be helpful to
compare current operating costs with the total levelized costs of new nuclear
power plants in order to gauge the magnitude of increases in O&M costs
that would make retirement an option from an economic standpoint. For instance,
with current O&M costs at the most expensive nuclear units in operation
averaging approximately 3.5 cents per kilowatthour [73] and total levelized
costs for new baseload capacity ranging from 8 cents to 11 cents per kilowatthour,
the operating costs of existing nuclear power plants would have to increase
substantially before it would be economical to retire even the most expensive
units.
Nuclear plant owners also face the risk of future regulations that could
require expensive upgrades. Such a rule was recently the subject of the
Supreme Court case Entergy Corp v. Riverkeeper [74], which focused on whether
or not the EPA could conduct cost-benefit analyses to determine whether
a plant needed to replace open-cycle cooling water systems with closed-cycle
systems. A retrofit of such magnitude would be costly and thus could alter
the relicensing decision for a particular facility.
The AEO2010 Reference case assumes an additional O&M cost of $30 per kilowatt
for nuclear power capacity after 30 years of operation, which is meant
to represent the various programs that must be undertaken in order to ensure
continued safety. Even with this added cost, no retirements of existing
nuclear power plants are projected by 2035 in the Reference case.
Alternative case
If all the existing nuclear power plants in the United States were retired
after 60 years of operation, the impacts on electricity markets, fuel use,
and GHG emissions would be substantial. Therefore, AEO2010 includes an
alternative Nuclear 60-Year Life case, which assumes that no existing nuclear
power plant will receive a second license extension, and all of them will
be retired after 60 years. The 60-year retirement assumption is not meant
as a hard-and-fast rule but as a possibility that allows examination of
the impact of retiring existing nuclear capacity from the generation mix.
A total of 30.8 gigawatts of capacity at operating U.S. nuclear power plants—or
approximately one-third of the existing fleet—will have been in operation
for at least 60 years by 2035. The Nuclear 60-Year Life case assumes that
all of that capacity will be retired between 2029 and 2035. Figure 29 shows
the locations of the plants that would be retired, which are spread fairly
evenly across the regions where nuclear power capacity is prominent.
In the Nuclear 60-Year Life case, retirement of the plants shown in Figure
29 results in the construction of additional replacement capacity beyond
the capacity additions already projected in the Reference case (Table 8).
Of the additional capacity built in the Nuclear 60-Year Life case, only
about 2 gigawatts is nuclear. Instead, the retired nuclear capacity is replaced
almost exclusively with coal and natural gas capacity, which in the absence
of policies regulating GHG emissions remains more economical than either
nuclear or renewable plants.
Reflecting the different projections for generating capacity additions
in the two cases, the projected nuclear share of total generation in 2035
is only 13 percent in the Nuclear 60-Year Life case, compared with 17 percent
in the Reference case. Total generation in the Nuclear 60-Year Life case
is 1 percent lower than in the Reference case. CO2emissions are higher
in the Nuclear 60-Year Life case, because nuclear power is replaced with
fossil fuels. Again, however, the difference between the projections is
less than 1 percent, because most of the capacity replacing the retired
nuclear plants is fueled by natural gas.
U.S. electricity prices in 2035 in the Nuclear 60-Year Life case are 4
percent higher than those in the Reference case. In regions where the retirements
are scheduled to occur, the price increases are slightly larger: compared
to the Reference case, electricity prices in 2035 are 7 percent higher
in the North American Electric Reliability Council (NERC) Midwest Reliability
region and between 5 and 6 percent higher in the NERC regions in the Northeast,
mid-Atlantic, and Southeast. In regions where no retirements occur, there
are still small price increases relative to the Reference case, because
natural gas prices are higher in the Nuclear 60-Year Life case. Building
new capacity to replace the retired nuclear plants is more expensive than
allowing their continued operation, and the higher costs are passed on
to consumers in the form of higher electricity prices. Natural gas prices
also are higher in the alternative case than in the Reference case, by
5.4 percent, because the additional new capacity is predominantly natural-gas-fired,
and the increase in demand pushes up the price of natural gas.
Finally, the assumed absence of new Federal policies to limit GHG emissions
is crucial to the results of this analysis. In all likelihood, such policies
would increase the cost of generating electricity from fossil fuels, improving
the relative economics of new nuclear power plants and favoring construction
of more nuclear capacity to replace the retired units.
Accounting for carbon dioxide emissions from biomass energy combustion
CO2 emissions from the combustion of biomass [75] to produce energy are
excluded from the energy-related CO2 emissions reported in AEO2010. According
to current international convention [76], carbon released through biomass
combustion is excluded from reported energy-related emissions. The release
of carbon from biomass combustion is assumed to be balanced by the uptake
of carbon when the feedstock is grown, resulting in zero net emissions
over some period of time [77]. However, analysts have debated whether increased
use of biomass energy may result in a decline in terrestrial carbon stocks,
leading to a net positive release of carbon rather than the zero net release
assumed by its exclusion from reported energy-related emissions.
For example, the clearing of forests for biofuel crops could result in
an initial release of carbon that is not fully recaptured in subsequent
use of the land for agriculture. To capture the potential net emissions,
the international convention for GHG inventories is to report biomass emissions
in the category “agriculture, forestry, and other land use,” usually based
on estimates of net changes in carbon stocks over time.
This indirect accounting of CO2 emissions from biomass can potentially
lead to confusion in accounting for and understanding the flow of CO2 emissions
within energy and non-energy systems. In recognition of this issue, reporting
of CO2 emissions from biomass combustion alongside other energy-related
CO2 emissions offers an alternative accounting treatment. It is important,
however, to avoid misinterpreting emissions from fossil energy and biomass
energy sources as necessarily additive. Instead, the combined total of
direct CO2 emissions from biomass and energy-related CO2 emissions implicitly
assumes that none of the carbon emitted was previously or subsequently
reabsorbed in terrestrial sinks or that other emissions sources offset
any such sequestration.
In the future, EIA plans to report CO2 emissions from biomass combustion
alongside other energy-related CO2 emissions, but to exclude them from
the total unless their inclusion is dictated by regulation. As shown in
Figure 30, including direct CO2 emissions from biomass energy combustion
would increase the 2008 total for energy-related CO2 emissions by 353 million
metric tons (6.1 percent). In the AEO2010 Reference case, including emissions
from biomass would increase the projected 2035 total for energy-related
CO2 emissions by 813 million metric tons (12.9 percent) [78]. If in fact
these emissions are all offset by biological sequestration, the net emissions
would be zero as assumed in EIA’s totals.
Notes |
