Issues in Focus
Introduction
This section of the AEO provides discussions on selected topics of interest
that may affect future projections, including significant changes in assumptions
and recent developments in technologies for energy production, supply,
and consumption. Issues discussed this year include trends in world oil
prices and production; the economics of plug-in electric hybrids; the impact
of reestablishing the moratoria on oil and natural gas drilling on the
Federal OCS; expectations for oil shale production; the economics of bringing
natural gas from Alaska’s North Slope to U.S. markets; the relationship
between natural gas and oil prices; the impacts of uncertainty about construction
costs for power plants; and the impact of extending the renewable PTC for
10 years. Last, in view of growing concerns about GHG emissions, the topics
discussed also include the impacts of such concerns on investment decisions
and their handling in AEO2009.
The topics explored in this section represent current, emerging issues
in energy markets; however, many of the topics discussed in AEOs published
in recent years remain relevant today. Table 4 provides a list of titles
from the 2008, 2007, and 2006 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.
World Oil Prices and Production Trends in AEO2009
The oil prices reported in AEO2009 represent the price of light, low-sulfur
crude oil in 2007 dollars [50]. Projections of future supply and demand
are made for “liquids,” a term used to refer to those liquids that after
processing and refining can be used interchangeably with petroleum products.
In AEO2009, liquids include conventional petroleum liquids—such as conventional
crude oil and natural gas plant liquids—in addition to unconventional liquids,
such as biofuels, bitumen, coal-to-liquids (CTL), gas-to-liquids (GTL),
extra-heavy oils, and shale oil.
Developments in the world oil market over the course of 2008 exemplify
how the level and expected path of world oil prices can change even over
a period of days, weeks, or months. The difficulty for projecting prices
into the future continues when the period of interest extends through 2030.
Long-term world oil prices are determined by four fundamental factors:
investment and production decisions by the Organization of the Petroleum
Exporting Countries (OPEC); the economics of non-OPEC conventional liquids
supply; the economics of unconventional liquids supply; and world demand
for liquids. Uncertainty about long-term world oil prices can be considered
in terms of developments related to one or more of these factors.
Recent Market Trends
The first 6 months of 2008 saw the continuation of the previous years’
increases in oil prices, spurred by rising demand that was satisfied by
relatively high-cost exploration and production projects, such as those
in ultra-deep water and oil sands, at a time when shortages in everything
from skilled labor to steel were driving up costs of even the most basic
production projects. An apparent lack of demand response to high prices
in developing countries, China and India in particular, led to expectations
of continuing high oil prices and the bidding up of prices for the inputs
needed to increase supply, such as labor, drilling rigs, and other factors.
Given the apparent lack of consumer response to price increases, lags in
increasing supply, and the limited availability of light crude oils, some
analysts believed that a price of $200 per barrel was plausible in the
near term.
By July 2008, when world oil prices neared $150 per barrel, it had become
apparent that petroleum consumption in the first half of the year was lower
than anticipated, and that economic growth was slowing. August saw the
beginning of the current global credit crisis and a further weakening of
demand; and since September 2008, the global economic downturn has reduced
consumers’ current and prospective near-term demand for oil while at the
same time the global credit crunch has restricted the ability of some suppliers
to raise capital for projects to increase future production.
In the second half of 2008, producer and consumer expectations regarding
the imbalance of supply and demand in the world oil market were essentially
reversed. Before August, market expectations for the future economy indicated
that demand would outpace supply despite planned increases in production
capacity. After September, expectations became so dismal that OPEC’s October
24 announcement of a 1.5-million-barrel-per-day production cut was followed
by a drop in oil prices.
Although the impacts of the current economic downturn and credit crisis
on petroleum demand are likely to be large in the near term, they also
are likely to be relatively short-lived. National economies and oil demand
are expected to begin recovering in 2010. In contrast, their impacts on
oil production capacity probably will not be realized until the 2010-2013
period, when current new investments in capacity, had they been made, would
have begun to result in more oil production. As a result, just at the time
when demand is expected to recover, physical limits on production capacity
could lead to another wave of price increases, in a cyclical pattern that
is not new to the world oil market.
Long-Term Prospects
Developments in past months demonstrate how quickly and drastically the
fundamentals of oil prices and the world liquids market as a whole can
change. Within a matter of months, the change in current and prospective
world liquids demand has affected the perceived need for additional access
to conventional resources and development of unconventional liquids supply
and reversed OPEC production decisions. The price paths assumed in AEO2009 cover a broad range of possible future scenarios for liquids production
and oil prices, with a difference of $150 per barrel (in real terms) between
the high and low oil price cases in 2030. Although even that large difference
by no means represents the full range of possible future oil prices, it
does allow EIA to analyze a variety of scenarios for future conditions
in the oil and energy markets in comparison with the reference case.
Reference Case
The AEO2009 reference case is a “business as usual” trend case built on
the assumption that, for the United States, existing laws, regulations,
and practices will be maintained throughout the projection period. The
reference case assumes that growth in the world economy and liquids demand
will recover by 2010, with growth beginning in 2010 and continuing through
2013, when world demand for liquids surpasses the 2008 level. In the longer
term, world economic growth is assumed to be roughly constant, and demand
for liquids returns to a gradually increasing long-term trend. As the global
recession fades, oil prices (in real 2007 dollars) begin rebounding, to
$110 per barrel in 2015 and $130 per barrel in 2030.
Meeting the long-term growth of world liquids demand requires higher cost
supplies, particularly from non-OPEC producers, as reflected in the reference
case by a 1.1-percent average annual increase in the world oil price after
2015. Increases from OPEC producers will also be needed, but the organization
is assumed to limit its production growth so that its share of total world
liquids supply remains at approximately 40 percent.
The growth in non-OPEC production comes primarily from increasingly high-cost
conventional production projects in areas with inconsistent fiscal or political
regimes and from expensive unconventional liquids production projects.
The return to historically high price levels would encourage the continuation
of recent trends toward “resource nationalism,” with foreign investors
having less access to prospective areas, less attractive fiscal regimes,
and higher exploration and production costs than in the first half of this
decade.
Low Price Case
The AEO2009 low price case assumes that oil prices remain at $50 per barrel
between 2015 and 2030. The low price case assumes that free market competition
and international cooperation will guide the development of political and
fiscal regimes in both consuming and producing nations, facilitating coordination
and cooperation between them. Non-OPEC producers are expected to develop
fiscal policies and investment regulations that encourage private-sector
participation in the development of their resources. OPEC is assumed to
increase its production levels, providing 50 percent of the world’s liquids
in 2030. The availability of low-cost resources in both non-OPEC and OPEC
countries allows prices to stabilize at relatively low levels, $50 per
barrel in real 2007 dollars, and reduces the impetus for consuming nations
to invest in the production of unconventional liquids as heavily as in
the reference case.
High Price Case
The AEO2009 high price case assumes not only that there will be a rebound
in oil prices with the return of world economic growth but also that they
will continue escalating rapidly as a result of long-term restrictions
on conventional liquids production. The restrictions could arise from political
decisions as well as resource limitations. Major producing countries, both
OPEC and non-OPEC, could use quotas, fiscal regimes, and various degrees
of nationalization to increase their national revenues from oil production.
In that event, consuming countries probably would turn to high-cost unconventional
liquids to meet some of their domestic demand. As a result, in the high
price case, oil prices rise throughout the projection period, to a high
of $200 per barrel in 2030. Demand for liquids is reduced by the high oil
prices, but the demand reduction is overshadowed by severe limitations
on access to, and availability of, conventional resources.
Components of Liquid Fuels Supply
In the reference case, total liquid fuels production in 2030 is about 20
million barrels per day higher than in 2007 (Table 5). Decisions by OPEC
member countries about investments in new production capacity for conventional
liquids, along with limitations on access to non-OPEC conventional resources,
limit the increase in production to 11.3 million barrels per day, and their
share of total global liquid fuels supply drops from 96 percent in 2007
to 88 percent in 2030.
Global production of unconventional petroleum liquids rises in the reference
case. Production from Venezuela’s Orinoco belt and Canada’s oil sands increases
but remains less than is economically viable because of access restrictions
in Venezuela and environmental concerns in Canada. As a result, unconventional
petroleum liquids production increases by only 3.6 million barrels per
day, to 6 percent of global liquid fuels supply in 2030. Relatively high
prices also encourage growth in production of CTL, GTL, biofuels, and other
nonpetroleum unconventional liquids (which include stock withdrawals, blending
components, other hydrocarbons, and ethers) from 1.7 million barrels per
day in 2007 to 7.4 million barrels per day (7 percent of total liquids
supplied) in 2030.
In the low price case, from 2015 to 2030, oil prices are on average almost
60 percent lower than in the reference case. As described above, a lower
price path could be caused by increased access to resources in non-OPEC
countries and decisions by OPEC member countries to expand their production.
In the low price case, conventional crude oil production rises to 93.6 million
barrels per day in 2030, the equivalent of 89 percent of total liquids
production in 2030 in the reference case. Total conventional liquids production
in the low price case rises above 100 million barrels per day in 2024 and
continues upward to 108.1 million barrels per day in 2030.
Production of unconventional petroleum liquids is also higher in the low
price case than in the reference case, despite their generally higher costs.
The increase is based on assumed changes in access to resources. In the
low price case, Venezuela’s production of extra-heavy oil in 2030 increases
to 3.0 million barrels per day, compared with 1.2 million barrels per day
in the reference case—a 150-percent increase that more than compensates
for a decrease of 0.5 million barrels per day in production from Canada’s
oil sands. As a result, total production of unconventional petroleum liquids
in 2030 is 1.1 million barrels per day higher in the low price case than
in the reference case. Production of CTL, GTL, biofuels, and other unconventional
liquids in 2030 (primarily in the United States, China, and Brazil) is
2.9 million barrels per day lower than in the reference case, because the
profitability of such projects is reduced.
In the high price case, from 2015 to 2030, oil prices average 56 percent
more than in the reference case because of severe restrictions on access
to non-OPEC conventional resources and reductions in OPEC production. Conventional
liquids production in 2030 is 71.9 million barrels per day, down by 9.2
million barrels per day from 2007 production. Access limitations also constrain
production of Venezuelan extra-heavy oil, which in 2030 totals 0.8 million
barrels per day, or 0.4 million barrels per day less than in the reference
case. Production of unconventional liquids from Canada’s oil sands in 2030
is 0.9 million barrels per day higher than in the reference case, however,
at 5.1 million barrels per day in 2030, which more than makes up for the
decrease in production of extra-heavy oil.
Production of CTL, GTL, biofuels, and other unconventional liquids totals
3.5 million barrels per day more in 2030 in the high price case than in
the reference case, primarily because China’s CTL production in 2030 is
approximately 0.8 million barrels per day more than in the reference case,
and Brazil’s biofuels production is 1.0 million barrels per day more than
in the reference case. In the United States, GTL production starts in 2017
and increases to 0.4 million barrels per day in 2030 in the high oil price
case.
Economics of Plug-In Hybrid Electric Vehicles
PHEVs have gained significant attention in recent years, as concerns about
energy, environmental, and economic security—including rising gasoline
prices— have prompted efforts to improve vehicle fuel economy and reduce
petroleum consumption in the transportation sector. PHEVs are particularly
well suited to meet these objectives, because they have the potential to
reduce petroleum consumption both through fuel economy gains and by substituting
electric power for gasoline use.
PHEVs differ from both conventional vehicles, which are powered exclusively
by gasoline-powered internal combustion engines (ICEs), and battery-powered
electric vehicles, which use only electric motors. PHEVs combine the characteristics
of both systems.
Current PHEV designs use battery power at the start of a trip, to drive
the vehicle for some distance until a minimum level of battery power is
reached (the “minimum state of charge”). When the vehicle has reached its
minimum state of charge, it operates on a mixture of battery and ICE power,
similar to some hybrid electric vehicles (HEVs) currently in use. In charge-depleting
operation, a PHEV is a fully functioning electric vehicle. Some HEVs also
can operate in charge-depleting operation, but only for limited distances
and at low speeds. Also, PHEVs can be engineered to run in a blended mode
of operation, where an onboard computer determines the most efficient use
of battery and ICE power.
PHEVs are unique in that their batteries can be recharged by plugging a
power cord into an electrical outlet. The distance a PHEV can travel in
all-electric (charge-depleting) mode is indicated by its designation. For
example, a PHEV-10 is designed to travel about 10 miles on battery power
alone before switching to charge-sustaining operation.
Although PHEV purchase decisions may be based in part on concerns about
the environment or national energy security, or by a preference for the
newest vehicle technology, a comprehensive evaluation of the potential
for wide-scale penetration of PHEVs into the LDV transportation fleet requires,
among other things, an analysis of economic costs and benefits for typical
consumers. In general, consumers will be more willing to purchase PHEVs
rather than conventional gasoline-powered vehicles if the economic benefits of doing so exceed the costs incurred. Therefore, an understanding
of the economic benefits and costs of purchasing a PHEV is, in general,
a fundamental factor in determining the potential for consumer acceptance
that would allow PHEVs to compete seriously in LDV markets.
The major economic benefit of purchasing a PHEV is its significant fuel
efficiency advantage over a conventional vehicle (Table 6). The PHEV can
use rechargeable battery power over its all-electric range before entering
charge-sustaining mode, and its all-electric operation is more energy-efficient
than either a conventional ICE vehicle or the hybrid mode of an HEV (or
the hybrid operation of the PHEV itself).
On a gasoline-equivalent basis (with electricity efficiency estimated “from
the plug”) a PHEV’s charge-depleting battery system gets on average about
105 mpg, well above even the most efficient petroleum-based ICE. When the
PHEV enters charge-sustaining mode, it also takes advantage of its hybrid
ICE-battery operation to achieve a relatively efficient 42 mpg. As a result,
the total annual fuel expenditures for a PHEV, combining both electricity
costs and gasoline, are lower than those of a conventional ICE vehicle
using gasoline. The fuel savings are amplified when the PHEV’s all-electric
range is increased, when gasoline prices are high, or when the difference
between gasoline prices and electricity prices increases (Figure 7).
Although the lower fuel costs of PHEVs provide an obvious economic benefit,
currently they are significantly more expensive to buy than a comparable
conventional vehicle. The price difference results from the costs of the
PHEV’s battery pack and the hybrid system components that manage the use
and storage of electricity. The incremental cost of the battery pack depends
on its storage capacity, power output, and chemistry. For example, the
electricity storage requirements for a PHEV-40, designed to travel about
40 miles on battery power alone before switching to charge-sustaining operation,
are considerably larger than those for a PHEV-10. In terms of power output,
PHEV batteries will be engineered to meet the typical performance needs
of LDVs, such as acceleration.
Currently two competing chemistries are seen as viable options for PHEV
batteries—nickel metal hydride (NiMH) and lithium-ion (Li-Ion)—with different
strengths and weaknesses. NiMH batteries are cheaper to produce per kilowatthour
of capacity and have a proven safety record; however, their relative weight
may limit their use in PHEVs. Li-Ion batteries have the potential to store
significantly more electricity in lighter batteries; however, their use
in PHEVs currently is limited by concerns about their calendar life, cycle
life, and safety. Different vehicle manufacturers have reached different
conclusions about which battery chemistry they will use in their initial
PHEV offerings, but the majority consensus is that Li-Ion batteries have
the most promise for the long term [51], and in this analysis they are
assumed to be the battery of choice.
The second cost element associated with PHEVs is the cost of the additional
electronic components and hardware required to manage vehicle electrical
systems and provide electrical motive power. The conventional vehicle systems
on a PHEV may be less costly than those on conventional gasoline vehicles,
because the PHEV’s engine and (if required) transmission are smaller, but
the saving is negated by the additional costs associated with the electric
motor, power inverter, wiring, charging components, thermal packaging to
prevent battery overheating, and other parts.
An example of the differences in various vehicle system costs (excluding
the battery pack) between a PHEV-20, designed to travel about 20 miles
on battery power alone before switching to charge-sustaining operation,
and a similar conventional vehicle is shown in Table 7 [52]. The estimated
incremental cost of the PHEV-20 shown in the table represents the combined
incremental costs of all vehicle systems other than the battery, at production
volumes expected in 2020 or 2030.
The combined costs of the PHEV battery and battery supporting systems together
represent the total incremental costs of a PHEV compared to a conventional
gasoline vehicle. In the long run, however, the costs of PHEV battery and
vehicle systems are not expected to remain static. Successes in research
and development are expected to improve battery characteristics and reduce
costs over time. In addition, as more Li-Ion batteries and system components
are produced, manufacturers are expected to improve production techniques
and decrease costs through economies of scale (Figure 8).
To incentivize purchases of initial PHEV offerings, the recently passed
EIEA2008 grants a tax credit of $2,500 for PHEVs with at least 4 kilowatthours
of battery capacity (about the size of a PHEV-10 battery), with larger
batteries earning an additional $417 per kilowatthour up to a maximum of
$7,500 for light-duty PHEVs, which would be reached at a battery size typical
for a PHEV-40 [53]. The credit will apply until 250,000 eligible PHEVs
are sold or until 2015, whichever comes first.
ARRA2009, which was enacted in February 2009, modifies the PHEV tax credit
so that the minimum battery size earning additional credits is 5 kilowatthours
and the maximum allowable credit based on battery size remains unchanged
at $5,000. ARRA2009 also extends the number of eligible vehicles from a
cumulative total of 250,000 for all manufacturers to more than 200,000
vehicles per manufacturer, with no expiration date on eligibility. After
a manufacturer’s cumulative production of eligible PHEVs reaches 200,000
vehicles, the tax credits are reduced by 50 percent for the preceding 2
quarters and to 25 percent of the initial value for the preceding third
and fourth quarters. ARRA2009 is not considered in AEO2009.
As a result of the EIEA2008 tax credit, the combined cost of a PHEV battery
and PHEV system in 2010 will be lower than it would be without the credit.
Moreover, even after the credit has expired, incentivizing the purchase
of PHEVs in the near term will allow both battery and battery-system manufacturers
to achieve earlier economies of scale through greater initial sales, thus
allowing battery and systems costs to decline more quickly than would have
been the case without the tax credit. As a result, the combined incremental
costs for PHEVs are expected to be significantly lower in 2030, when economies
of scale and learning have been fully realized (Figure 9).
A typical consumer may be willing to purchase a PHEV instead of a conventional
ICE vehicle when the economic benefit of reduced fuel expenditures is greater
than the total incremental cost of the PHEV. On that basis, PHEVs face
a significant challenge. Even in 2030, the additional cost of a PHEV is
projected to be higher than total fuel savings unless gasoline prices are
around $6 per gallon (Figure 10). In the meantime, the cost challenge for
PHEVs is even greater (Figure 11), which leads to an important problem:
if consumers do not choose to buy PHEVs because they are not cost-competitive
with conventional vehicles in the near term, then PHEV sales volumes will
not be sufficient to induce the economies of scale assumed for this analysis.
In addition to the economic challenge, PHEVs also face uncertainty with
respect to Li-Ion battery life and safety [54]. Further, they will continue
to face competition from other vehicle technologies, including diesels,
grid-independent gasoline-electric hybrids, FFVs, and more efficient conventional
gasoline vehicles, all of which are likely to become more fuel-efficient
in the next 20 years.
Future advances in Li-Ion battery technology could address economic, lifetime,
and safety concerns, paving the way for large-scale sales and significant
penetration of PHEVs into the U.S. LDV fleet. For example, a technological
breakthrough could conceivably allow for smaller batteries with the same
capacity and power output, thus lowering incremental costs and making PHEVs
attractive on a cost-benefit basis. Also, there are at least two non-economic
arguments in favor of PHEVs. First, PHEVs could significantly reduce GHG
emissions in the transportation sector, depending on the fuels used to
produce electricity. Second, PHEVs use less gasoline than conventional
ICE vehicles (Figure 12). If PHEVs displaced conventional ICE vehicles,
U.S. petroleum imports could be reduced [55].
Impact of Limitations on Access to Oil and Natural Gas Resources in the
Federal Outer Continental Shelf
The U.S. offshore is estimated to contain substantial resources of both
crude oil and natural gas, but until recently some of the areas of the
lower 48 OCS have been under leasing moratoria [56]. The Presidential ban
on offshore drilling in portions of the lower 48 OCS was lifted in July
2008, and the Congressional ban was allowed to expire in September 2008,
removing regulatory obstacles to development of the Atlantic and Pacific
OCS [57, 58].
Although the Atlantic and Pacific lower 48 OCS regions are open for exploration
and development in the AEO2009 reference case, timing issues constrain
the near-term impacts of increased access. The U.S. Department of Interior,
MMS, is in the process of developing a leasing program that includes selected
tracts in those areas, with the first leases to be offered in 2010 [59];
however, there is uncertainty about the future of OCS development. Environmentalists
are calling for a reinstatement of the moratoria. Others cite the benefits
of drilling in the offshore. Recently, the U.S. Department of the Interior
extended the period for comment on oil and natural gas development on the
OCS by 180 days and established other processes to allow more careful evaluation
of potential OCS development.
Assuming that leasing actually goes forward on the schedule contemplated
by the previous Administration, the leases must then be bid on and awarded,
and the wining bidders must develop exploration and development plans and
have them approved before any wells can be drilled. Thus, conversion of
the newly available OCS resources to production will require considerable
time, in addition to financial investment. Further, because the expected
average field size in the Pacific and Atlantic OCS is smaller than the
average field size in the Gulf of Mexico, a portion of the additional OCS
resources may not be as economically attractive as available resources
in the Gulf.
Estimates from the MMS of undiscovered resources in the OCS are the starting
point for EIA’s estimate of the OCS technically recoverable resource. Adding
the mean MMS estimate of undiscovered technically recoverable resources
to proved reserves and inferred resources in known deposits, the remaining
technically recoverable resource (as of January 1, 2007) in the OCS is
estimated to be 93 billion barrels of crude oil and 456 trillion cubic
feet of natural gas (Table 8). The OCS areas that were until recently under
moratoria in the Atlantic, Pacific, and Eastern/Central Gulf of Mexico
are estimated to hold roughly 20 percent (18 billion barrels) of the total
OCS technically recoverable oil—10 billion barrels in the Pacific and nearly
4 billion barrels each in the Eastern/Central Gulf of Mexico and Atlantic
OCS. Roughly 76 trillion cubic feet of natural gas (or 17 percent) is estimated
to be in areas formerly under moratoria, with nearly 37 trillion cubic
feet in the Atlantic, 18 trillion cubic feet in the Pacific, and 21 trillion
cubic feet in the Eastern/Central Gulf of Mexico. It should be noted that
there is a greater degree of uncertainty about resource estimates for most
of the OCS acreage previously under moratoria, owing to the absence of
previous exploration and development activity and modern seismic survey
data.
To examine the potential impacts of reinstating the moratoria, an OCS limited
case was developed for AEO2009. It is based on the AEO2009 reference case
but assumes that access to the Atlantic, Pacific, and Eastern/Central Gulf
of Mexico OCS will be limited again by reinstatement of the moratoria as
they existed before July 2008. In the OCS limited case, technically recoverable
resources in the OCS total 75 billion barrels of oil and 380 trillion cubic
feet of natural gas.
The projections in the OCS limited case indicate that reinstatement of
the moratoria would decrease domestic production of both oil and natural
gas and increase their prices (Table 9). The impact on domestic crude oil
production starts just before 2020 and increases through 2030. Cumulatively,
domestic crude oil production from 2010 to 2030 is 4.2 percent lower in
the OCS limited case than in the reference case. In 2030, lower 48 offshore
crude oil production in the OCS limited case (2.2 million barrels per day)
is 20.6 percent lower than in the reference case (2.7 million barrels per
day), and total domestic crude oil production, at 6.8 million barrels per
day, is 7.4 percent lower than in the reference case (Figure 13). In 2007,
domestic crude oil production totaled 5.1 million barrels per day.
With limited access to the lower 48 OCS, U.S. dependence on imports increases,
and there is a small increase in world oil prices. Oil import dependence
in 2030 is 43.4 percent in the OCS limited case, as compared with 40.9
percent in the reference case, and the total annual cost of imported liquid
fuels in 2030 is $403.4 billion, 7.1 percent higher than the projection
of $376.6 billion in the reference case. The average price of imported
low-sulfur crude oil in 2030 (in 2007 dollars) is $1.34 per barrel higher,
and the average U.S. price of motor gasoline price is 3 cents per gallon
higher, than in the reference case.
As with liquid fuels, the impact of limited access to the OCS on the domestic
market for natural gas is seen mainly in the later years of the projection.
Cumulative domestic production of dry natural gas from 2010 through 2030
is 1.3 percent lower in the OCS limited case than in the reference case.
Because the volume of technically recoverable natural gas in the OCS areas
previously under moratoria accounts for less than 5 percent of the total
U.S. technically recoverable natural gas resource base, the impacts for
natural gas volumes are smaller, relative to the baseline supply level,
than those for oil volumes.
In 2030, dry natural gas production from the lower 48 offshore totals 4.1
trillion cubic feet in the OCS limited case, as compared with 4.9 trillion
cubic feet in the reference case. The reduction in offshore supply of natural
gas in the OCS limited case is partially offset, however, by an increase
in onshore production. Reduced access in the OCS limited case results in
higher natural gas prices, which increase the projection for U.S. onshore
production in 2030 by 0.2 trillion cubic feet over the reference case projection.
The average U.S. wellhead price of natural gas in 2030 (per thousand cubic
feet, in 2007 dollars) is 21 cents higher in the OCS limited case, and
net imports increase by 240 billion cubic feet. The higher average wellhead
price for natural gas from the lower 48 States in the OCS limited case
is associated with a decrease in consumption of 360 billion cubic feet
in 2030 relative to the reference case. Total U.S. production of dry natural
gas is 210 billion cubic feet less in 2020 and 600 billion cubic feet less
in 2030 in the OCS limited case than projected in the reference case (Figure
14).
Offshore production, particularly in the OCS, has been an important source
of domestic crude oil and natural gas supply, and it continues to be a
key source of domestic supply throughout the projections either with or
without the restoration of leasing moratoria as they existed before 2008.
Expectations for Oil Shale Production
Background
Oil shales are fine-grained sedimentary rocks that contain relatively large
amounts of kerogen, which can be converted into liquid and gaseous hydrocarbons
(petroleum liquids, natural gas liquids, and methane) by heating the rock,
usually in the absence of oxygen, to 650 to 700 degrees Fahrenheit (in
situ retorting) or 900 to 950 degrees Fahrenheit (surface retorting) [60].
(“Oil shale” is, strictly speaking, a misnomer in that the rock is not
necessarily a shale and contains no crude oil.) The richest U.S. oil shale deposits
are located in Northwest Colorado, Northeast Utah, and Southwest Wyoming
(Table 10). Currently, those deposits are the focus of petroleum industry
research and potential future production. Among the three States, the richest
oil shale deposits are on Federal lands in Northwest Colorado.
The Colorado deposits start about 1,000 feet under the surface and extend
down for as much as another 2,000 feet. Within the oil shale column are
rock formations that vary considerably in kerogen content and oil concentration.
The entire column ultimately could produce more than 1 million barrels
oil equivalent per acre over its productive life. To put that number in
context, Canada’s Alberta oil sands deposits are expected to produce about
100,000 barrels per acre.
The recoverable oil shale resource base is characterized by oil yield per
ton of rock, based on the Fischer assay method [61]. Table 10 summarizes
the approximate recoverable oil shale resource within the three States,
based on the relative oil concentration in the oil shale rock. In addition
to oil, the estimates include natural gas and natural gas liquids, which
make up 15 to 40 percent of the total recoverable energy, depending upon
the specific shale rock characteristics and the process used to extract
the oil and natural gas. The three States contain about 800 billion barrels
of recoverable oil in deposits with expected yields of more than 20 to
25 gallons oil equivalent per ton, which are more attractive economically
than deposits with lower concentrations of oil. In comparison, on December
31, 2007, U.S. crude oil reserves were 21 billion barrels, or roughly 2.5
percent of the amount potentially recoverable from oil shale deposits in
the three States [62].
Oil Shale Production Techniques
Liquids and gases can be produced from oil shale rock by either in situ or surface retorting. During the mid-1970s and early 1980s, the petroleum
industry focused its efforts primarily on underground mining and surface
retorting, which consumes large volumes of water, creates large waste piles
of spent shale, and extracts only the richest portion of the oil shale
formation. There were also some experiments using a “modified in situ process,”
in which rock was mined from the base of the oil shale formation, explosive
charges were set in the mined-out area (causing the roof to collapse and
fragmenting the rock into smaller masses), and underground fires were set
on the rubble to extract natural gas and petroleum liquids. The combustion
proved difficult to control, however, and the process produced only low
yields of petroleum liquids. Surface subsidence and aquifer contamination
were additional issues.
The in situ processes now under development raise the temperature of shale
formations by using electrical resistance or radio wave heating in wells
that are separate from the production wells. Also being considered are
“ice walls”—commonly used in construction—both to keep water out of the
areas being heated and to keep the petroleum liquids that are produced
from contaminating aquifers. The benefits of those methods include uniform
heating of the formation; high yields of gas and liquid per ton of rock;
production of high-quality liquids that commingle naphtha, distillates,
and fuel oil and can be upgraded readily to marketable products; production
yields of more than 1 million barrels per acre in some locations; no requirement
for disposal and remediation of waste rock; reduced water requirements;
scalability, so that additional production can be added readily to an existing
project at production costs equal to or less than the cost of the original
project; and lower overall production costs. Given these advantages, an in situ process is likely to be used if large-scale production of oil shale
is initiated.
Although the technical feasibility of in situ retorting has been proved,
considerable technological development and testing are needed before any
commitment can be made to a large-scale commercial project. EIA estimates
that the earliest date for initiating construction of a commercial project
is 2017. Thus, with the leasing, planning, permitting, and construction
of an in situ oil shale facility likely to require some 5 years, 2023 probably
is the earliest initial date for first commercial production.
Economic Issues
Because no commercial in situ oil shale project has ever been built and
operated, the cost of producing oil and natural gas with the technique
is highly uncertain. Current estimates of future production costs range
from at least $70 to more than $100 per barrel oil equivalent in 2007 dollars.
Therefore, future oil shale production will depend on the rate of technological
progress and on the levels and volatility of future oil prices.
Technology progress rates will determine how quickly the costs of in situ oil shale extraction can be brought down and how quickly natural gas and
petroleum liquids can be produced from the process. The in situ retorting
techniques currently available require the production zone to be heated
for 18 to 24 months before full-scale production can begin.
In addition to price levels, the volatility of oil prices is particularly
important for a high-cost, capital-intensive project like oil shale production,
because price volatility increases the risk that costs will not be recovered
over a reasonable period of time. For example, if oil prices are unusually
low when production from an oil shale project begins, the project might
never see a positive rate of return.
Public Policy Issues
Development of U.S. oil shale resources also faces a number of public policy
issues, including access to Federal lands, regulation of CO2 emissions,
water usage and wastewater disposal, and the disturbance and remediation
of surface lands. If the petroleum industry were not permitted access to
Federal lands in the West, especially in Northwest Colorado, the industry
would be excluded from the largest and most economical portion of the U.S.
oil shale resource base.
In addition, current regulations of the U.S. Bureau of Land Management
require that any mineral production activity on leased Federal lands also
produce any secondary minerals found in the same deposit. On Federal oil
shale lands, deposits of nahcolite (a naturally occurring form of sodium
bicarbonate, or baking soda) are intermixed with the oil shales. Relative
to oil and other petroleum products, nahcolite is a low-value commodity,
and its price would fall even further if its production increased significantly.
Thus, co-production of nahcolite could increase the cost of producing oil
shale significantly, while providing little revenue in return.
Bringing Alaska North Slope Natural Gas to Market
At least three alternatives have been proposed over the years for bringing
sizable volumes of natural gas from Alaska’s remote North Slope to market
in the lower 48 States: a pipeline interconnecting with the existing pipeline
system in central Alberta, Canada; a GTL plant on the North Slope; and a
large LNG export facility at Valdez, Alaska. NEMS explicitly models the
pipeline and GTL options [63]. The “what if” LNG option is not modeled
in NEMS.
This comparison analyzes the economics of the three project options, based
on the oil and natural gas price projections in the AEO2009 reference,
high oil price, and low oil price cases. The most important factors in
the comparison include expected construction lead times, capital costs,
and operating costs. Others include lower 48 natural gas prices, world
crude oil and petroleum product prices, interest rates, and Federal and
State regulation of leasing, royalty, and production tax rates. Each option
also presents unique technological challenges.
Natural Gas Resources and Production Costs
Natural gas exists either in oil reservoirs as associated-dissolved (AD)
natural gas or in gas-only reservoirs as nonassociated (NA) natural gas.
Of the 35.4 trillion cubic feet of AD gas reserves discovered on the Central
North Slope in conjunction with existing oil fields, 93 percent is located
in four fields: Prudhoe Bay (23 trillion cubic feet), Point Thomson (8
trillion cubic feet), Lisburne (1 trillion cubic feet), and Kuparak (1
trillion cubic feet) [64]. Together, those resources are sufficient to
provide 4 billion cubic feet of natural gas per day for a period of 24
years, at an expected average cost of $1.12 per thousand cubic feet (2007
dollars) [65]. The cost estimate is relatively low, because an extensive
North Slope infrastructure has been built and paid for with revenues from
oil production, and because there is considerably less exploration, development,
and production risk associated with known deposits of AD natural gas.
Although additional AD natural gas might be discovered offshore or in the
Arctic National Wildlife Refuge, most of the “second tier” discoveries
in areas to the west and south of the Central North Slope are expected
to consist of NA natural gas in gas-only reservoirs. Production costs for
gas-only reservoirs are expected to be considerably higher than those for
AD natural gas, because they are in remote locations. In addition, the
full costs of their development will have to be paid for with revenues
from the natural gas generated at the wellhead.
For the first tier of North Slope NA natural gas (29.2 trillion cubic feet)
production costs are expected to average $7.91 per thousand cubic feet
(2007 dollars). For the second tier, production costs are expected to average
$11.03 per thousand cubic feet. Because the cost of producing NA natural
gas is substantially greater than the cost of producing AD natural gas,
this analysis uses the lower production costs for AD natural gas to evaluate
the economic merits of the three facility options examined.
Facility Cost Assumptions
Of the three facility options, the costs associated with an Alaska gas
pipeline are reasonably well defined, because they are based on the November
2007 pipeline proposals submitted to the State of Alaska by ConocoPhillips
and TransCanada Pipelines, in compliance with the requirements of the Alaska
Gasline Inducement Act. Costs associated with GTL and LNG facilities are
more speculative, because they are based on the costs of similar facilities
elsewhere in the world, adjusted for the remote Alaska location and for
recent worldwide increases in construction costs (Table 11).
Key assumptions for all the options analyzed include natural gas feedstock
requirements of 4 billion cubic feet per day, natural gas heating values,
characteristics of the operations, and State and Federal income tax rates.
The time required for planning, obtaining required permits, and facility
construction is unique to each facility. Other key assumptions that are
unique to each option include the following: for the Alaska pipeline option,
the tariff rate for the existing pipeline from Alberta to Chicago and the
spot price for natural gas in Chicago; for the LNG facility option, capital
and operating costs, including the cost of building a pipeline from the
North Slope to liquefaction and storage facilities in Valdez, and the value
of LNG delivered in Asia and Valdez (which is contractually tied to oil
prices); and for the GTL facility option, the time required to conduct
tests to determine whether the Trans Alaska Pipeline System (TAPS) should
be operated in batch or commingled mode with GTL, the production level
and mix of product, the oil pipeline tariff and tanker rates to U.S. West
Coast refiners, and the price of GTL products relative crude oil prices.
The costs of testing and possibly converting TAPS into a batching crude/product
pipeline are not included for the GTL option.
Discussion
To compare the economics of the three options, an internal rate of return
(IRR) was calculated for each alternative, based on the projected average
price of light, low-sulfur crude oil and the projected average price of
natural gas on the Henry Hub spot market in the AEO2009 reference, high
oil price, and low oil price cases for the 2011-2020 and 2021-2030 periods
(Table 12). The IRR calculations (Figures 15 and 16) assume that the average
prices for the period in which a facility begins operation will persist
throughout the 20-year economic life of the facility. Projected crude oil
prices show considerably more variation across the cases and time periods
than do Henry Hub natural gas prices, affecting the relative economics
of the three options. In 2030, in the low and high oil price cases, crude
oil prices are $50 and $200 per barrel, respectively, and lower 48 natural
gas prices are $8.70 and $9.62 per million Btu, respectively (all prices
in 2007 dollars).
The AEO2009 projections show wide variations in oil prices, which are set
outside the NEMS framework to reflect a range of potential future price
paths. For natural gas prices, variations across the cases are smaller,
reflecting the feedbacks in NEMS that equilibrate supply, demand, and prices
in the natural gas market model. Natural gas price increases are held in
check by declines in demand (especially in the electric power sector) and
increases in natural gas drilling, reserves, and production capacity. Conversely,
natural gas price declines are held in check by increases in demand and
decreases in drilling, reserves, and production capacity. Natural gas prices
are also restrained because only a small portion of the natural gas resource
base is consumed through 2030, and the marginal cost of natural gas supply
increases slowly.
IRRs for the pipeline option respond to natural gas price levels, whereas
IRRs for the GTL and LNG options respond to crude oil prices (Figures 15
and 16). From 2021 through 2030, IRRs for the pipeline option vary by 15
to 17 percent across the three price cases, whereas those for the GTL and
LNG options vary by 4 to 24 percent and 7 to 27 percent, respectively.
On that basis, the pipeline option would be considerably less risky than
either the GTL or LNG option. Also, the pipeline would involve significantly
less engineering, construction, and operation risk than either of the other
options.
The potential viability of an Alaska natural gas pipeline is bolstered
by the fact that BP, ConocoPhillips, and TransCanada Pipelines already
have committed to building a pipeline. All three have extensive experience
in building and financing large-scale energy projects, and both BP and
ConocoPhillips have access to substantial portions of the less expensive
North Slope AD natural gas reserves. Given that institutional support,
along with the prospect for adequate rates of return, the natural gas pipeline
option appears to have the greatest likelihood of being built.
Because the GTL option does not include the cost of testing and adapting
the existing TAPS oil pipeline to GTL products—which would require third-party
cooperation and likely cost reimbursement—the GTL rates of return are overstated.
In addition, the GTL results include considerable uncertainty with regard
to capital and operating costs and future environmental constraints on
GTL plants. Prospects for Alaska GTL facilities are further clouded by
the current absence of project sponsors.
Of the three options, an LNG export facility shows the highest rates of
return in the reference and high price cases; however, it shows low rates
of return in the low price case. The project risk associated with the LNG
option is considerably less than that for the GTL option but greater than
for the pipeline option. The LNG option is further undermined by the fact
that there are large reserves of stranded natural gas elsewhere in the
world that have a significant competitive advantage both because of their
proximity to large consumer markets and because they would not require
construction of an 800-mile supply pipeline through difficult terrain.
Although there is definite interest in the LNG export option in Alaska,
current advocates of the project have not yet secured letters of intent
from potential buyers to purchase the LNG, nor do they have ownership of
low-cost AD reserves, extensive experience in the management of large-scale
projects, or strong financial backing. Finally, if shale deposits in the
rest of the world turn out to be as rich in natural gas as those in the
United States, worldwide demand for LNG could be reduced considerably from
the levels that were expected just a few years ago.
Other Issues
The analysis described here focused primarily on the relative economics
and risks associated with each of three options for a facility to bring
natural gas from Alaska’s North Slope to market. There are, in addition,
a number of other issues that could be important in determining which facility
option could proceed to construction and operation, four of which are described
briefly below.
Resolving ownership issues for the Point Thomson natural gas condensate
field lease. The State of Alaska has revoked the Point Thomson lease from
the original leaseholders. Point Thomson holds approximately 8 trillion
cubic feet of recoverable natural gas reserves, and without that supply,
the existing North Slope AD reserves would be insufficient to supply a
natural gas pipeline over a 20-year lifetime. The 35.4 trillion cubic feet
of existing AD natural gas reserves on the Central North Slope includes
Point Thomson’s 8 trillion cubic feet, and without those reserves only
27.4 trillion cubic feet of North Slope gas reserves would be available,
providing just 18.8 years of supply for a facility with a capacity of 4
billion cubic feet per day. As long as the ownership issue of the Point
Thomson lease remains unresolved, the possibility of pursuing construction
of any of the three options is diminished.
Obtaining permits for an Alaska natural gas pipeline in Canada. The pipeline
option could encounter significant permitting issues in Canada, similar
to those that have already been encountered by the Mackenzie Delta natural
gas pipeline, whose construction has been significantly delayed as the
result of a failure to secure necessary permits. Because there have been
no filings for Canadian permits by any Alaska natural gas pipeline sponsor,
the severity of this potential problem cannot be determined.
Exporting Alaska LNG to foreign consumers. Some parties in the United States
have called for a halt to current exports of LNG from Alaska to overseas
markets. If Alaska were prohibited from exporting LNG to overseas consumers,
the financial risk associated with any new Alaska LNG facility would increase
significantly, because the financial viability of an LNG facility would
be tied solely to lower 48 natural gas prices, which are considerably lower
than overseas natural gas prices.
Shipping GTL products through TAPS. The joint ownership structure of TAPS
could prevent a minority owner from using the pipeline to ship GTL from
the North Slope south to Valdez and on to market.
Conclusion
The AEO2009 price cases project greater variance in oil prices than in
natural gas prices. If those cases provide a reasonable reflection of potential
future outcomes, then the pipeline option in this analysis would be exposed
to less financial risk than the GTL and LNG options. Additionally, it is
the only option that already has the commitment of energy companies capable
of financing and constructing such a large, capital-intensive energy facility.
The balance of the factors evaluated here points to an Alaska natural gas
pipeline as being the most likely choice for bringing North Slope natural
gas to market.
Natural Gas and Crude Oil Prices in AEO2009
If oil and natural gas were perfect substitutes in all markets where they
are used, market forces would be expected to drive their delivered prices
to near equality on an energy-equivalent basis. The price of West Texas
Intermediate (WTI) crude oil generally is denominated in terms of barrels,
where 1 barrel has an energy content of approximately 5.8 million Btu.
The price of natural gas (at the Henry Hub), in contrast, generally is
denominated in million Btu. Thus, if the market prices of the two fuels
were equal on the basis of their energy contents, the ratio of the crude
oil price (the spot price for WTI, or low-sulfur light, crude oil) to the
natural gas price (the Henry Hub spot price) would be approximately 6.0.
From 1990 through 2007, however, the ratio of natural gas prices to crude
oil prices averaged 8.6; and in the AEO2009 projections from 2008 through
2030, it averages 7.7 in the low oil price case, 14.6 in the reference
case, and 20.2 in the high oil price case (Figure 17).
The key question, particularly in the reference and high oil price cases,
is why market forces are not expected to bring the ratios more in line
with recent history. A number of factors can influence the ratio of oil
prices to natural gas prices, as discussed below.
Crude Oil and Natural Gas Supply Markets
The methods and costs of transporting petroleum and natural gas are significantly
different. The crude oil supply market is an international market, whereas
the U.S. natural gas market is confined primarily to North America. In
2007, 43 percent of the oil and petroleum products consumed in the United
States came by tanker from overseas sources [66]. In contrast, only 3 percent
of total U.S. natural gas consumption came from overseas sources, by LNG
tanker. Moreover, the domestic resource bases for the two fuels are significantly
different. It is expected that lower 48 onshore natural gas resources will
play a dominant role in meeting future domestic demand for natural gas,
whereas imports of crude oil and petroleum products will continue to account
for a significant portion of U.S. petroleum consumption.
Approximately 180 billion barrels of crude oil reserves and undiscovered
resources are estimated to remain in the United States, equal to about
24 years of domestic consumption at 2007 levels; however, with more than
70 percent of those resources located offshore or in the Arctic, they will
be relatively expensive to develop and produce [67]. The remaining U.S.
natural gas resource base is much more abundant, estimated at 1,588 trillion
cubic feet or nearly 70 years of domestic consumption at 2007 levels [68].
In addition, more than 70 percent of remaining U.S. natural gas resources
are located onshore in the lower 48 States, which significantly reduces
the cost of new domestic natural gas production.
The large domestic natural gas resource base has been estimated in one
study to be sufficient to keep the long-run marginal cost of new domestic
natural gas production between $5 and $8 (2007 dollars) per thousand cubic
feet through 2030; however, the costs used in that study represent a period
when drilling was unusually expensive, because oil and natural gas prices
were high. In the future, cost for natural gas development and production
could decline significantly as the demand for well drilling equipment and
personnel comes into equilibrium with the available supply for those services
[69].
In the AEO2009 reference case, which projects a relatively low long-run
marginal cost of natural gas, domestic production increasingly satisfies
U.S. natural gas consumption. In 2030 more than 97 percent of the natural
gas consumed in the United States is produced domestically, yet only 31
percent of the currently estimated U.S. natural gas resource base is produced
by 2030. LNG imports remain a relatively small portion of U.S. natural
gas supply, with their share peaking in 2018 at 6.5 percent and then falling
to 3.5 percent in 2030.
The current opportunities for competition between oil and natural gas are
relatively small in the United States (that is, the two U.S. supply markets
are weakly linked). Although the relatively low costs projected for production
of natural gas make it economically attractive in U.S. consumption markets
where it competes with oil, particularly in the reference and high oil
price cases, they are not low enough to make the United States a competitive
source of natural gas for the world LNG market.
Also, large-scale conversion of lower 48 natural gas into liquid fuels
is expected to be precluded by the inability of project sponsors to secure
long-term natural gas supply contracts at guaranteed prices and volumes.
Natural gas producers are unlikely to be able or willing to guarantee long-term
volumes and prices.
Substitution of Natural Gas for Petroleum Consumption
In a relatively high oil price environment, as in the AEO2009 reference
and high oil price cases, consumers can reduce oil consumption through
energy conservation and by switching to other forms of energy, such as
natural gas, coal, renewables, and electricity. Natural gas is not necessarily
the least expensive or quickest option to implement (in comparison with
reducing transportation vehicle-miles traveled, for example).
In the residential, commercial, and electric power sectors, petroleum consumption
is relatively small, accounting for only 6.5 percent of total U.S. petroleum
consumption in 2007. Gradually converting all the petroleum consumption
in those sectors to other fuels would have only a modest impact on natural
gas consumption and prices.
In the industrial sector, the most feasible opportunity for substituting
natural gas for petroleum is in heat and power uses, which amount to about
0.61 quadrillion Btu per year [70]; however, most petroleum consumption
in the industrial sector (such as diesel and gasoline consumption by off-road
vehicles in agricultural and construction activities; petroleum coke; refinery
still gas, which is both produced and consumed in refineries; and road
asphalt) is not well suited for conversion to natural gas. Also, there
is considerable uncertainty about the extent to which petroleum feedstocks
for chemical manufacturing could be replaced with natural gas before 2030.
At a minimum, considerable downstream investment in chemical manufacturing
processes would be required in order to convert to natural gas feedstock.
The greatest potential for large-scale substitution of natural gas for
petroleum is in the transportation sector—especially, in local fleet vehicles
refueled at a central facility, such as local buses, which consumed 0.18
quadrillion Btu in 2006 [71]. Wider use of natural gas as a fuel for transportation
fleets also has been advocated; however, the idea faces significant hurdles
given the relatively low energy density of natural gas; the cost, size,
and weight of onboard storage systems; and the challenge of establishing
a refueling infrastructure. In addition, any significant increase in natural
gas use could raise natural gas prices sufficiently to reduce the ratio
of natural gas prices to oil prices.
The Honda Civic GX and Civic LX-S vehicles provide a uniform basis for
comparing the attributes of a natural-gas-fueled LDV (the GX) and a gasoline-fueled
LDV (the LX-S) that use the same design platform (Table 13). The Honda
GX is about 34 percent more expensive, carries 39 percent less fuel (resulting
in a much shorter refueling range of about 200 to 220 miles), and provides
50 percent less cargo space, 19 percent less horsepower, and 15 percent
less torque. Although natural gas has a high octane rating of 130, the
GX horsepower and torque are reduced by the rate at which natural gas can
be injected into the piston cylinders because of its lower energy density.
Although the higher cost and other disadvantages of natural gas vehicles
could be offset at least partially by their lower fuel costs, the lack
of an extensive natural gas refueling infrastructure will remain a difficult
hurdle to overcome. Consumers are unlikely to purchase natural gas vehicles
if there is considerable uncertainty as to whether they can be refueled
when and where they need to be. Similarly, service station owners are unlikely
to install natural gas refueling equipment if the number of natural gas
vehicles on the road is insufficient to pay for the infrastructure costs.
In 2008, there were only 778 service stations in the United States with
natural gas refueling capability out of a total of more than 120,000 service
stations [72]. Public refueling capability for natural gas, ethanol, methanol,
and electric vehicles has fluctuated considerably over time, as the different
vehicle options have gained and lost favor with the public. Even after
the more than 15 years that these alternative fuel options have existed,
fewer than 1 percent of the Nation’s public service stations currently
offer refueling capability for any alternative fuel.
Without an extensive public refueling network, the potential for market
penetration by natural gas vehicles will be limited, and until a substantial
number have been purchased, an extensive public refueling network is unlikely
to develop. Market penetration by natural gas vehicles is also limited
by the many alternatives that consumers have for reducing vehicle petroleum
consumption, including buying smaller vehicles, reducing vehicle-miles
traveled, and buying hybrid electric or, potentially, all-electric vehicles.
In addition, price volatility in crude oil and natural gas markets obscures
the long-term financial viability of natural gas vehicles. Consequently, AEO2009 assumes that widespread adoption of natural gas vehicles in the
United States is unlikely under current laws and policies.
Conclusion
Through 2030, an abundance of low-cost, onshore lower 48 natural gas resources,
in conjunction with a limited set of opportunities to substitute natural
gas for petroleum, is projected to raise the ratio of oil prices to natural
gas prices above the historical range, as reflected in AEO2009 reference
and high oil price cases. Unless there is large-scale growth in the use
of natural gas in the transportation sector, it is unlikely that fuel substitution
in the other end-use sectors will be sufficient to reduce the price ratio
significantly before 2030.
Electricity Plant Cost Uncertainties
Construction costs for new power plants have increased at an extraordinary
rate over the past several years. One study, published in mid-2008, reported
that construction costs had more than doubled since 2000, with most of
the increase occurring since 2005 [73]. Construction costs have increased
for plants of all types, including coal, nuclear, natural gas, and wind.
The cost increases can be attributed to several factors, including high
worldwide demand for generating equipment, rising labor costs, and, most
importantly, sharp increases in the costs of materials (commodities) used
for construction, such as cement, iron, steel, and copper. Commodity prices
continued to rise through most of 2008, but as oil prices dropped precipitously
in the last quarter of the year, commodity prices began to decline. The
most recent power plant capital cost index published by Cambridge Energy
Research Associates (CERA) shows a slight decline in the index over the
past 6 months, and CERA analysts expect further declines [74].
The current financial situation in the United States will also affect the
costs of future power plant construction. Financing large projects will
be more difficult, and as the slowing economy leads to lower demand for
electricity, the need for new capacity may be limited. The resultant easing
of demand for construction materials and equipment could lead to lower
costs for materials and equipment when new investment does take place in
the future. Fluctuating commodity prices, combined with the uncertain financial
environment, increase the challenge of projecting future capital costs.
Because some plant types—coal, nuclear, and most renewables—are much more
capital-intensive than others (such as natural gas), the mix of future
capacity builds and fuels used can differ, depending on the future path
of construction costs. If construction costs increase proportionately for
all plant types, natural-gas-fired capacity will become more economical
than more capital-intensive technologies. Over the longer term, higher
construction costs are likely to lead to higher energy prices and lower
energy consumption.
The AEO2009 version of NEMS includes updated assumptions about the costs
of new power plant construction. It also assumes that power plant costs
will be influenced by the real producer price index for metals and metal
products, leading to a decline in base construction costs in the later
years of the projections. As sensitivities to the AEO2009 reference case,
several alternative cases assuming different trends in capital costs for
power plant construction were used to examine the implications of different
cost paths for new power plant construction.
Power Plant Capital Cost Cases
For the AEO2009 reference case, initial capital costs for new generating
plants were updated on the basis of costs reported in late 2007 and early
2008. The reference case cost assumptions reflect an increase of roughly
30 percent relative to the cost assumptions used in AEO2008, and they are
roughly 50 percent higher than those used in earlier AEOs. Because there
is a strong correlation between rising power plant construction costs and
rising commodity prices, construction costs in AEO2009 are tied to a producer
price index for metals and metal products. The nominal index is converted
to a real annual cost factor, using 2009 as the base year. The resulting
reference case cost factor remains nearly flat for the next few years,
then declines by a total of roughly 15 percent to the end of the projection
in 2030. As a result, future capital costs are lower even before technology
learning adjustments are applied. The same cost factor is applied to all
technology types.
Although the correlation between construction costs and the producer price
index for metals has been high in recent years, it is possible that costs
could be affected by other factors in the future. There is also uncertainty
in the metals index forecast, as with any projection. Therefore, the sensitivity
cases do not use the metals index to adjust plant costs but instead use
exogenous assumptions about future cost adjustment factors to provide a
range of cost assumptions.
In the frozen plant capital costs case, base overnight construction costs
for all new electricity generating technologies are assumed to remain constant
at 2013 levels (which is when the cost factor peaks in the reference case).
Because cost decreases still can occur as a result of technology learning,
costs do decline slightly from 2013 to 2030 in the frozen costs case. In
2030, costs for all technologies are roughly 20 percent higher than in
the reference case.
In the high plant capital costs case, base overnight construction costs
for all new generating plants are assumed to continue increasing throughout
the projection, by assuming that the cost factor increases by 25 percentage
points from 2013 to 2030. Again, cost decreases still can occur as a result
of technology, partially offsetting the increases. For most technologies,
however, costs in 2030 are above current costs. Plant construction costs
in 2030 in the high plant capital costs case are about 50 percent higher
than in the reference case.
In the falling plant capital costs case, base overnight construction costs
for all generating technologies fall more rapidly than in the reference
case, starting in 2013. In 2030, the cost factor is assumed to be 25 percentage
points below the reference case value.
Results
Capacity Additions
Overall capacity requirements, as well as the mix of generating types,
change across the alternative plant cost cases. In the reference case,
259 gigawatts of new generating capacity is added from 2007 to 2030. In
the frozen and high plant costs cases, capacity additions fall to 247 gigawatts
and 237 gigawatts, respectively. In the falling plant costs case, additions
increase to 288 gigawatts.
In all the plant costs cases, the vast majority of new capacity is fueled
by natural gas, in part because coal, nuclear, and renewable technologies
are more capital-intensive; however, the fuel shares of total builds do
differ among the cases (Figure 18). Coal-fired plants make up 18 percent
of all the new capacity built in the reference case through 2030. Across
the alternative cases, their share ranges from 9 percent to 20 percent.
In the frozen plant costs and high plant costs cases, no nuclear capacity
is built beyond the 1.2 gigawatts of planned additions. In the falling
plant costs case, more than 20 gigawatts of nuclear capacity is built.
Renewable capacity makes up a 22-percent share of all new capacity built
in the reference case; the renewable share remains between 21 and 22 percent
in the high plant costs and frozen plant costs cases and increases to 25
percent in the falling plant costs case.
Electricity Generation and Prices
Differences among the projections for generation fuel mix in the different
cases are not as large as the differences in the projections for capacity
additions, because the construction cost assumptions do not affect the
operation of existing capacity. Coal maintains the largest share of total
generation through 2030, ranging from 44 percent to 47 percent in 2030
across the four cases (Figure 19). The renewable share in 2030 is nearly
the same in all the cases, from 14 percent to 15 percent, because all the
cases assume that the same State and regional RPS goals must be met. In
the frozen and high plant costs cases, biomass co-firing is used predominantly
to meet RPS requirements, rather than investment in new renewable capacity.
In the falling plant costs case, generation from biomass co-firing is less
than projected in the reference case, and wind generation provides more
of the renewable requirement.
Nuclear generation provides 18 percent of total generation in 2030 in the
reference case, compared with 16 percent in the frozen and high plant costs
cases and 19 percent in the falling plant costs case. Natural-gas-fired
generation, typically the source of marginal electricity supply, follows
an opposite path, increasing by 22 percent from the reference case projection
in 2030 in the high plant costs case and by 14 percent in the frozen plant
costs case, and decreasing by 11 percent in the falling plant costs case.
As a result, delivered natural gas prices vary among the different cases,
increasing by as much as 10 percent from the reference case projection
in the high plant costs case and decreasing by 6 percent in the falling
plant costs case. Electricity prices in 2030, following the trend in natural
gas prices, are 5 percent higher than the reference case projection in
the high plant costs case (where electricity prices also rise in response
to higher construction costs) and 5 percent lower than the reference case
projection in the falling plant costs case (Figure 20).
Tax Credits and Renewable Generation
Background
Tax incentives have been an important factor in the growth of renewable
generation over the past decade, and they could continue to be important
in the future. The Energy Tax Act of 1978 (Public Law 95-618) established
ITCs for wind, and EPACT92 established the Renewable Electricity Production
Credit (more commonly called the PTC) as an incentive to promote certain
kinds of renewable generation beyond wind on the basis of production levels.
Specifically, the PTC provided an inflation-adjusted tax credit of 1.5
cents per kilowatthour for generation sold from qualifying facilities during
the first 10 years of operation. The credit was available initially to
wind plants and facilities that used “closed-loop” biomass fuels [75] and
were placed in service after passage of the Act and before June 1999.
The 1992 PTC has lapsed periodically, but it has been renewed before or
shortly after each expiration date, typically for an additional 1- or 2-year
period. In addition, eligibility has been extended to generation from many
different renewable resources [76], including poultry litter, geothermal
energy [77], certain hydroelectric facilities [78], “open-loop” biomass
[79], landfill gas, and, most recently, marine energy resources. Open-loop
biomass and landfill gas currently receive one-half the PTC value (1 cent
rather than the current inflation-adjusted 2 cents available to other eligible
resources). Eligibility of new projects for the PTC was set to expire at
the end of 2008, but it was extended to December 31, 2009, for wind capacity
and to December 31, 2010, for other eligible renewable facilities [80].
As this publication was being prepared, the PTC was further extended and modified by ARRA2009, which extends eligibility for the PTC to December 31, 2012, for wind projects and to December 31, 2013, for all other eligible renewable resources. In addition, project owners may elect to receive a 30-percent ITC in lieu of the ITC. Project owners electing the grant
must commence their projects during 2009 or 2010. These recently passed
provisions are not included in AEO2009.
The PTC has contributed significantly to the expansion of the wind industry
over the past 10 years. Since 1998, wind capacity has grown by an average
of more than 25 percent per year (Figure 21). Although some of the more
recent growth may be attributable to State programs, especially the mandatory
RPS programs now in effect in 28 States and the District of Columbia, the
importance of the PTC is evidenced by the growth of wind power installations
in States without renewable mandates, either today or at the time the installations
were constructed, and by the significant drop in new wind installations
during periods when the PTC has been allowed to lapse.
Although other renewable generation facilities, such as geothermal or poultry
litter plants, have been able to claim the PTC, none has grown as dramatically
as wind power. Possible explanations for their slower rate of expansion
include longer construction lead times and less favorable economics for
some facilities. In addition, some provisions of the PTC may limit its
ability to be used fully or efficiently for some projects. For example,
project owners that do not pay Federal income taxes (such as municipal
utilities and rural electric cooperatives) cannot claim the PTC, even though
they may be eligible for other Federal assistance. Also, the owners of
for-profit projects must have sufficient tax liability to claim the full
PTC, and their eligibility for PTC payments may be limited by the Federal
alternative minimum tax law.
The wind industry, in particular, has developed several alternative ownership
and finance structures to help minimize the impact of the limitations [81].
There is some evidence, however, that the restrictions reduce the value
of the PTC to project owners. In addition, the financial crisis of 2008
may exacerbate the problems for some projects [82]. As part of ARRA2009,
developers may, for a limited time, convert the PTC into a 30-percent ITC
and then into a grant. This provision may lessen the impact of the financial
crisis on the ability of wind developers to use the PTC. As noted above,
the provisions of ARRA2009 are not included in AEO2009.
Future Impacts
Because AEO2009 represents only those laws and policies in effect on or
before November 4, 2008, the renewable energy PTC is assumed to expire
at the end of 2009 for wind and at the end of 2010 for other eligible renewables;
however, the program has a long history of renewal and extension, and there
is considerable interest, both in Congress and in the renewable energy
industry, in keeping the credit available over the longer term, as seen
in the recent extension to 2013.
To examine the potential impacts of a PTC extension, AEO2009 includes a
production tax credit extension case that examines the potential impacts
of extending the current credit through 2019. Because EIA does not develop
or advocate policy, the PTC extension case is included here only to assess
the potential impacts of such an extension and should not be construed
as a proposal for, or endorsement of, any legislative action.
Aside from the expiration date, no changes in current PTC provisions are
assumed in the PTC extension case. The credit is valued at 2 cents per
kilowatthour (in 2008 dollars, adjusted for projected inflation rates)
for wind, geothermal, and hydroelectric generation and at 1 cent per kilowatthour
for biomass and landfill gas [83]. It is assumed that all eligible facilities
will receive the credit for the first 10 years of plant operation, and
that they will use the credit efficiently and completely, without further
modification of the law. The extension is assumed to be continuous over
the 10-year period and not subject to the periodic cycle of expiration
and renewal that has affected the PTC in the past.
For wind power installations, a 10-year extension of the PTC results in
significantly more capacity growth than in the reference case (Figure 22).
In the near term, capacity increases would be comparable to those seen
over the past several years, followed by a period of several years in which
the capacity expansion is slower, corresponding to a projected lull in
electricity demand growth. Significant additional growth in wind capacity
occurs thereafter, before the assumed 2019 expiration date, with total
capacity increasing to approximately 50 gigawatts in 2020, as compared
with 33 gigawatts in the reference case. Additional capacity expansion
occurs after 2020 in both cases, particularly in the reference case, where
11 gigawatts of installed capacity is added from 2020 to 2030 as compared
with 2 gigawatts in the PTC extension case.
For eligible technologies other than wind, no significant changes in capacity
installations are projected in the PTC extension case relative to the reference
case. In part, this may be a result of the shorter lead times associated
with wind technology: wind plants can be built before the projected slowdown
in electricity demand growth after 2010, potentially “crowding out” other
PTC-eligible investments. In addition, the economics for wind installations
are fundamentally more favorable than for other PTC-eligible resources,
and the resource base for wind power is more widespread.
Because eligible renewable generation still accounts for a relatively small
share of total U.S. electricity generation, the PTC extension case has
relatively minor impacts outside the markets for renewable generation.
A 10-year extension of the PTC reduces average electricity prices in 2020
by approximately 1 percent relative to the reference case. The extension
costs the Federal Government approximately $7.7 billion from 2010 to 2019
(in 2007 dollars) [84], while cumulative savings on electricity expenditures
from 2010 to 2019 total about $13 billion in comparison with the reference
case.
Total electricity generation in 2020 in the PTC extension case is less
than 0.5 percent greater than in the reference case. The increase in wind-powered
electricity generation in the PTC extension case primarily offsets the
use of natural gas in the power sector, reducing natural-gas-fired generation
by about 5 percent in 2020 compared to the reference case. Impacts on other
generation fuels generally are less than 1 percent. The maximum reduction
in CO2 emissions from the electric power sector (occurring before 2020)
is about 0.5 percent compared to the reference case.
Greenhouse Gas Concerns and Power Sector Planning
Background
Concerns about potential climate change driven by rising atmospheric concentrations
of GHGs have grown over the past two decades, both domestically and abroad.
In the United States, potential policies to limit or reduce GHG emissions
are in various stages of development at the State, regional, and Federal
levels. In addition to ongoing uncertainty with respect to future growth
in energy demand and the costs of fuel, labor, and new plant construction,
U.S. electric power companies must consider the effects of potential policy
changes to limit or reduce GHG emissions that would significantly alter
their planning and operating decisions. The possibility of such changes
may already be affecting planning decisions for new generating capacity.
California and 10 States in the Northeast are moving forward with mandatory
emissions reduction programs. For 10 Northeastern States, 2009 is the inaugural
year of the RGGI, a cap-and-trade program for power plant emissions of
CO2 [85]. RGGI sets a cap of 188 million metric tons CO2 in 2009 for power
generating facilities with rated capacity greater than 25 megawatts and
lowers that cap annually to 169 million metric tons in 2018. Although RGGI
represents the first legally binding regulation of CO2 emissions in the
United States and will influence future decisions about investments in
generating capacity, its overall impact is expected to be modest. In 2006,
CO2 emissions from power plants covered by RGGI accounted for only 7 percent
of the CO2 emitted from all U.S. power plants, and their total 2006 emissions—at
164 million metric tons—already were below the 2018 goal of 169 million
metric tons.
Other regional initiatives also are being developed. The WCI consists of
seven Western U.S. States and four Canadian Provinces [86]. A draft rule
released in July 2008 aims at an economy-wide cap on six GHGs, including
CO2. The cap level and details of the program design still are being developed.
In November 2007, the governors of 10 Midwestern States signed the Midwestern
Greenhouse Gas Reduction Accord [87], currently in the preliminary stages
of development, with the broad goal of creating a multi-sector, interstate
cap-and-trade program for the member States.
At the State level, 37 individual States have released State-specific climate
change mitigation plans; however, the only legally binding requirements
outside the RGGI States are in California, which has passed Assembly Bill
(A.B.) 32, the Global Warming Solutions Act of 2006 [88]. A.B. 32 aims
to reduce the State’s GHG emissions to 1990 levels by 2020. Although specific
regulations associated with A.B. 32 remain to be finalized, the law requires
that policies be designed to meet the reduction targets.
At the national level, numerous bills to reduce GHGs have been introduced
in the U.S. Congress in recent years. As of July 2008, a total of 235 bills,
amendments, and resolutions addressing climate change in some form had
been introduced in the 110th Congress. Nine of the bills—three in the House
and six in the Senate—specifically proposed a cap-and-trade system for
CO2 and other GHGs. Of the nine, the Boxer-Lieberman-Warner Climate Security
Act (S. 3036) progressed the farthest, reaching the floor of the Senate
in June 2008 [89].
Even without the enactment of national emissions limits, many State utility
regulators and the banks that finance new power plants are requiring assessments
of GHG emissions for new projects. For example, many State public utility
commissions now are requiring that utilities review projected CO2 emissions
in their integrated resource plans (IRPs) [90]. The IRP process is intended
to keep public utility regulators at the State level informed of their
utilities’ strategies to meet future demand and supply. The treatment of
projected CO2 emissions has differed among utilities. Some have included
an emissions price in their base case scenarios; others have done so in
alternative scenarios. Typically, the emissions prices used have ranged
from $5 to $80 per metric ton.
Several major banks in the United States also have decided to include future
CO2 emissions as a factor in their decisionmaking processes for financing
of new power plants. In February 2008, Citibank, JPMorgan Chase, and Morgan
Stanley announced the formation of “The Carbon Principles,” which provide
climate change guidelines for advisors and lenders to power companies in
the United States [91]. Adopters of the principles would commit to:
- Encourage clients to pursue cost-effective energy efficiency, renewable
energy, and other low-carbon alternatives to conventional generation, taking
into consideration the potential value of avoided CO2 emissions
- Ascertain and evaluate the financial and operational risk to fossil fuel
generation financings posed by the prospect of domestic CO2 emissions controls
through the application of an “Enhanced Diligence Process,” and use the
results of this diligence as a contribution to the determination whether
a transaction is eligible for financing and under what terms
- Educate clients, regulators, and other industry participants regarding
the additional diligence required for fossil fuel generation financings,
and encourage regulatory and legislative changes consistent with the principles.
Reflecting Concerns Over Greenhouse Gas Emissions in AEO2009
Key questions in the development of the AEO2009 projections included the
degree to which ongoing debate about potential climate change policies,
together with the actions taken by State regulators and the financial community,
already are affecting planning and operating decisions in the electric
power sector, and how best to capture those impacts in the analysis. Although
existing plants continue to be operated on a least-cost basis without adjustments
for GHG emissions levels, concerns about GHG emissions do appear to be
having an impact on decisions about new plants.
When regulators and banks are reviewing the projected GHG emissions of
new plants in their investment evaluation process, they are implicitly
adding a cost to some plants, particularly those that involve GHG-intensive
technologies. The implicit cost could be represented by adding an amount
to the operating costs of plants that emit CO2 to reflect the value of
emissions; however, doing so would affect not only planning decisions for
new capacity but also future utilization decisions for all plants—something
that does not appear to be occurring on a widespread basis in markets today.
Alternatively, the costs of building and financing new GHG-intensive capacity
could be adjusted to reflect the implicit costs being added by utilities,
their regulators, and the financial community. This option better reflects
current market behavior, which is focused on discouraging power companies
from investing in high-emission technologies. As a result, in the AEO2009 reference case, a 3-percentage-point increase is added to the cost of capital
for investments in GHG-intensive technologies, such as coal-fired power
plants without CCS and CTL plants.
Although the 3-percentage-point adjustment is somewhat arbitrary, its impact
in levelized cost terms is similar to that of a $15 fee per metric ton
of CO2 for investments in new coal-fired power plants without CCS—well
within the range of the results of simulations that utilities and regulators
have prepared. The adjustment should be seen not as an increase in the
actual cost of financing but rather as representing the implicit costs
being added to GHG-intensive projects to account for the possibility that,
eventually, they may have to purchase allowances or invest in other projects
that offset their emissions.
Two alternative cases were prepared to show how the representation of investment
behavior in the electric power sector affects the AEO2009 reference case
projections, given uncertainty about the evolution of potential GHG policies.
In the no GHG concern case, the cost-of-capital adjustment for GHG-intensive
technologies is removed to represent a future in which concern about GHG
emissions wanes or efforts to implement GHG reduction regulations subside.
This case reflects an approach similar to that used for the reference case
in past AEOs. In the LW110 case, the GHG emissions reduction policy called
for in S. 2191, the Lieberman-Warner Climate Security Act of 2007 introduced
in the 110th Congress, is analyzed [92]. This case illustrates a future
in which an explicit Federal policy limiting GHG emissions is enacted,
affecting both planning and operating decisions.
Because the projected impact of any policy to reduce GHG emissions will
depend on its detailed specifications—which may differ significantly from
those in the LW110 case—results from the LW110 case do not apply to other
past or future policy proposals. Rather, projections in the two alternative
cases illustrate the potential importance to the electric power industry
of GHG policy changes, and why uncertainty about such changes weighs heavily
on planning and investment decisions.
Findings
The imposition of a GHG reduction policy would affect all aspects of the
electric power industry, including decisions about the types of plants
built to meet growing electricity demand, the fuels used to generate electricity,
the prices consumers will pay in the future, and GHG emissions from electric
power plants.
Capacity
Generating capacity investment decisions in the two sensitivity cases differ
from those in the AEO2009 reference case (Figure 23). The overall amounts
of new capacity added in the reference case and the no GHG concern case
are similar, but there are differences in the mix of plant types built.
New coal builds without CCS are higher in the no GHG concern case than
in the reference case, as the concern that new regulations might be coming
dampens investment in new coal-fired plants in the reference case. On the
other hand, new natural-gas-fired plants, which are not as GHG-intensive,
are more attractive economically in the reference case. In an environment
of uncertainty about future regulation of CO2 emissions, natural gas becomes
the primary choice for new capacity additions; without such uncertainty,
coal remains the primary choice. Concern about possible new regulations
plays a role in the construction of a modest amount of nuclear power and
renewable energy capacity in the reference case, but other incentives also
influence their selection. It is unclear whether utilities would be willing
to incur the high costs of building new nuclear plants in the absence of
concerns about potential GHG regulations.
The cap-and-trade policy adopted in the LW110 case changes the mix of capacity
additions significantly relative to the other cases. The adjusted cost
of capital in the reference case increases the cost of building new GHG-intensive
facilities but does not change the cost of operating those plants already
in service or new plants once they are built. The introduction of an explicit
cap on GHG emissions adds a cost to the emissions generated from existing
and new facilities, making carbon-intensive coal-fired plants more expensive
to build and operate. As a result, approximately 35 percent of the existing
fleet of coal-fired plants is retired by 2030 in the LW110 case, and 33
percent more new capacity is added than in the reference case, replacing
the retired capacity. The explicit GHG emission constraint results in the
construction of a different mix of new capacity additions, with new nuclear
power, renewables, and coal with CCS making up a majority of the capacity
added. The new capacity additions lead to a significantly different portfolio
of generation assets and generation by fuel in 2030.
The results show that implementation of the LW110 case would lead to greater
use of coal with CCS, nuclear, and renewable capacity; however, there is
significant uncertainty around the projections. New coal-fired plants with
CCS equipment have not been fully commercialized, and it is unclear when
they might be and what they would cost. Similarly, a rapid expansion of
nuclear capacity also would present challenges, including uncertainty both
about the cost of the plants and about public acceptance of them. There
also may be limits to a rapid expansion of renewable generation, because
many of the best resources are located far from electricity load centers.
Previous EIA analysis has found that, if the expansion is limited, the
electricity industry may rely more heavily on new natural-gas-fired plants
to reduce GHG emissions, leading to higher allowance costs and higher electricity
prices [93].
Generation by Fuel
Among the three cases examined, total electricity generation in 2030 is
lowest in the LW110 case (Figure 24 and Table 14). The explicit cap raises
the price of electricity, which over time slows the growth in demand for
electricity, lowering generation requirements. The opposite is true in
the no GHG concern case, where lower electricity prices stimulate higher
demand for electricity and increase generation requirements. Generation
from coal drops the most in the LW110 case. Relative to the AEO2009 reference
case, the explicit GHG emission cap reduces the total amount of electricity
generated from all coal-fired plants by 33 percent and the amount from
coal-fired plants without CCS by 68 percent in 2030, as older coal plants
are retired and the marginal costs of units still operating, which must
hold allowances, are higher. Despite their high initial capital costs,
new coal-fired units with CCS are less expensive to operate than traditional
coal-fired plants without CCS, given a tight constraint on CO2 emissions.
The shares of renewables and nuclear power in the generation mix also increase
significantly in the LW110 case, as low-emissions technologies are added
to meet the growing demand for electricity.
Electricity Prices
Projected electricity prices are lowest in the no GHG concern case, where
there is no cap on emissions, and coal-fired plants with relatively low
fuel costs continue to dominate the mix of generation (Figure 25). Greater
reliance on natural gas in the reference case leads to higher electricity
prices when construction of carbon-intensive facilities, including coal-fired
plants, is dampened because of uncertainty about possible GHG regulations.
An explicit cap on GHG emissions adds an additional cost to the generation
of electricity from CO2-emitting sources. To lower emissions in the LW110
case, the industry turns to more expensive resources and allowance purchases
to cover remaining emissions. Therefore, electricity generated from fossil
fuels becomes more expensive, while higher priced low-emitting sources,
such as nuclear, renewables, and coal with CCS, become more cost-competitive.
As a result, the cost of generating electricity increases. In 2030, the
price of electricity is 22 percent higher in the LW110 case than in the
reference case and 26 percent higher than in the no GHG concern case.
Emissions
The electric power sector is expected to play a major role in any effort
to reduce GHG emissions in the United States (Figure 26). The sector accounted
for 41 percent of energy-related CO2 emissions in 2007, and its emissions
are projected to grow. On the other hand, a wide array of fuels and technologies
with various emission levels are used in the electric power sector, providing
some flexibility for altering emissions levels without turning to wholly
unknown technologies or requiring end-use consumers to purchase any new
equipment. Increases in CO2 emissions from
the electric power sector are projected to continue through 2030 in the
no GHG concern case and the AEO2009 reference case. In the no GHG concern
case, emissions are expected to rise as demand for electricity increases
and coal’s share of the national generation mix grows to 53 percent in
2030. Emissions also continue to increase through 2030 in the reference
case but at a slower rate because of the reduced reliance on coal for generation.
In the LW110 case, in contrast, CO2 emissions from the electric power sector
are projected to fall significantly over time. In this case, CO2 emissions
from the electric power sector in 2030 are projected to be 52 percent below
their 2007 level and 57 percent below the level in the reference case.
Issues In Focus End Notes |
