Electricity Demand
Residential and Commercial Sectors
Dominate Electricity Demand Growth
Total electricity sales increase by 29 percent in the
AEO2008 reference case, from 3,659 billion kilowatthours
in 2006 to 4,705 billion in 2030, at an average
rate of 1.1 percent per year. The relatively slow
growth follows the historical trend, with the growth
rate slowing in each succeeding decade. Electricity
sales, which are strongly affected by economic
growth, increase by 39 percent in the high growthcase, to 5,089 billion kilowatthours in 2030, but
by only 18 percent in the low growth case, to 4,319
billion kilowatthours in 2030. In the reference case,
the largest increase is in the commercial sector,
at 49 percent from 2006 to 2030 (Figure 60), as
service industries continue to drive growth. Electricity
demand grows by 27 percent in the residential
sector and by only 3 percent in the industrial sector.
Growth in population and disposable income leads to
increased demand for products, services, and floorspace.
Population shifts to warmer regions also
increase the need for cooling.
Efficiency gains offset growth in electricity demand,
as higher energy prices encourage investment in
energy-efficient equipment. In both the residential
and commercial sectors, continuing efficiency gains
in electric heat pumps, air conditioners, refrigerators,
lighting (notably LED lighting), cooking appliances,
and computer screens slow the growth of electricity
demand. The new standards set in EISA2007 for
lighting and other appliances (such as boilers,
dehumidifiers, dishwashers, and clothes washers)
further dampen electricity demand throughout the
projection. Slow growth in industrial production, particularly
in the energy-intensive industries, limits
electricity demand growth in the industrial sector.
Coal-Fired Power Plants Provide
Largest Share of Electricity Supply
Coal-fired power plants (including utilities, independent
power producers, and end-use CHP) continue to
be the dominant source of electricity generation
through 2030 (Figure 61). Although natural-gas-fired
plants with lower capital costs make up most of the
capacity additions over the next 10 years, more
coal-fired plants are built in the later years as natural
gas fuel costs increase. The natural gas share of
generation falls from 20 percent in 2006 to 14 percent
in 2030, while the coal share increases from 49 percent
to 54 percent.
Federal tax incentives, State renewable energy programs,
and rising fossil fuel prices lead to increases in
renewable and nuclear capacity and generation, as
new plants are built. The generation share from
renewable capacity increases by 32 percent from 2006
to 2030 and represents 13 percent of total electricity
supply in 2030. With capacity additions and improvements
in performance at existing nuclear facilities,
nuclear generation also increases; however, the
nuclear share of total generation falls slightly, from
19 percent in 2006 to 18 percent in 2030.
Technology choices for new plants and utilization of
existing capacity are affected by relative fuel costs
and changes in environmental policies. For example,
natural-gas-fired plants are projected to supply 21
percent of total electricity supply in 2030 in the low
price case but only 10 percent in the high price case,
but coal-fired plants supply 49 percent of the total in
the low price case and 57 percent in the high price
case. Changes in environmental policies could also
have a significant effect on the fuel shares of total
generation.
Early Capacity Additions Use Natural
Gas, Coal Plants Are Added Later
Decisions to add capacity and the choice of fuel type
depend on electricity demand growth, the need to
replace inefficient plants, the costs and operating
efficiencies of different options, fuel prices, and the
availability of Federal tax credits for some technologies.
With growing electricity demand and the retirement
of 45 gigawatts of capacity, 263 gigawatts of new
generating capacity (including end-use CHP) will be
needed by 2030.
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Natural-gas-fired plants generally have lower capacity
costs but higher fuel costs than coal-fired plants.
As a result, coal-fired plants typically are more
economical, and they account for 40 percent of total
capacity additions from 2006 to 2030, compared with
a 36-percent share for natural gas (Figure 62).
Renewable and nuclear plants tend to have high
investment costs and relatively low operating costs.
EPACT2005 and State RPS programs are expected to
stimulate generation from renewable and nuclear
plants, which represent 18 percent and 6 percent of
total additions, respectively.
The quantity and mix of capacity additions can also be
affected by different fuel price paths or growth rates
for electricity demand. Because fuel costs are a larger
share of total expenditures for new natural-gas-fired
capacity, the higher fuel costs in the high price case
lead to more coal-fired additions. In the economic
growth cases, capacity additions range from 182 gigawatts
in the low growth case to 349 gigawatts in the
high growth case, although the generation shares for
different technologies are similar in the two cases.
Least Expensive Technology Options
Are Likely Choices for New Capacity
Technology choices for new generating capacity
are made to minimize cost while meeting local and
Federal emissions constraints. The choice of technology
for capacity additions is based on the
least expensive option available (Figure 63) [83].
The AEO2008 reference case assumes a capital recovery
period of 20 years, with the cost of capital based
on competitive market rates.
Real capital costs decline over time (Table 6) at rates
that depend on the current stage of development for
each technology. For the newest technologies, capital
costs are initially adjusted upward to reflect the optimism
inherent in early estimates of project costs.
As project developers gain experience, the costs are
assumed to decline. The decline continues at a progressively
slower rate as more units are built. The
efficiency of new plants is also assumed to improve
through 2025, with heat rates for advanced combined
cycle and coal gasification units declining from 6,752
and 8,765 Btu per kilowatthour in 2006 to 6,333 and
7,450 Btu per kilowatthour, respectively, in 2025.
Largest Capacity Additions Expected
in the Southeast and the West
Most areas of the United States currently have excess
generation capacity, but all electricity demand regions
(see Appendix F for definitions) are expected to
need additional, currently unplanned, capacity by
2030. The largest amount of new capacity is expected
in the Southeast (FL and SERC), which represents a
relatively large and growing share of total U.S.
electricity sales and thus requires more capacity than
other regions (Figure 64). The growth in demand for
electricity in the Southeast is well above the national
average.
With natural gas prices rising in the reference case,
coal-fired plants account for the largest share of
capacity additions through 2030, given the assumption
that current environmental policies are maintained
indefinitely. The largest concentration of new
coal-fired capacity is in the Southeast, where new
coal-fired plants are built to accommodate growth in
the electricity market and the corresponding need for
additional capacity.
Natural gas, renewable, and nuclear plants represent
the remaining capacity additions. Natural-gas-fired
plants are built to maintain a diverse capacity mix, to
serve as reserve capacity, or to meet environmental
regulations. About three-fourths of the additions are
located in the Southeast, the West (NWP, RA, and
CA), and the Midwest (ECAR, MAIN, and MAPP).
Renewable capacity is also needed because of State
and Federal renewable energy policies, and the Midwest
accounts for the largest share of renewable
capacity additions. Most nuclear additions are
expected in the Southeast, where suppliers have
expressed interest in building new nuclear plants.
EPACT2005 Tax Credits Are Expected
To Stimulate New Nuclear Builds
In the AEO2008 reference case, nuclear capacity
grows from 100.2 gigawatts in 2006 to 114.9 gigawatts
in 2030, including 2.7 gigawatts of expansion at
existing plants, 16.6 gigawatts of new capacity, and
4.5 gigawatts of retirements. EPACT2005 provides
an 8-year PTC of 1.8 cents per kilowatthour for up to
6 gigawatts of new nuclear capacity built before 2021.
The credit also can be shared for additional capacity
but at a lower credit value. The reference case projects
8.0 gigawatts of new nuclear capacity (which will
receive the tax credits) by 2020. Early builds are
expected to bring down the cost of nuclear capacity
and, when combined with rising fossil fuel costs, to
result in additional nuclear builds after 2020. All
uprates approved, pending, or expected by the NRC at
existing units are assumed to be carried out. Most
existing nuclear units are expected to continue operating
through 2030, based on the assumption that
they will apply for and receive license renewals. Seven
units, totaling 4.5 gigawatts, are projected to be
retired after 2028, when the end date of their original
licenses plus a 20-year renewal is reached.
Projected nuclear capacity additions vary, depending
on overall demand for electricity and the prices of
other fuels. In the five main AEO2008 cases, nuclear
generation grows from 787 billion kilowatthours in
2006 to between 837 and 1,047 billion kilowatthours
in 2030 (Figure 65). In the low price case, the delivered
price of natural gas in 2030 is 15 percent lower
than in the reference case, and new nuclear plants
become less economical. In the high price and high
growth cases, respectively, 30 and 33 gigawatts of
new nuclear capacity are projected, because more capacity
is needed and the cost of alternatives is higher.
Biomass and Wind Lead Projected
Growth in Renewable Generation
There is considerable uncertainty about the growth
potential of wind power, which depends on a variety
of factors, including fossil fuel costs, State renewable
energy programs, technology improvements, access
to transmission grids, public concerns about environmental
and other impacts, and the future of the
Federal PTC, which is expected to expire at the end of
2008. In the AEO2008 reference case, generation
from wind power increases from 0.6 percent of total
generation in 2006 to 2.4 percent in 2030 (Figure 66).
Biomass, both dedicated and co-firing, grows from 39
billion kilowatthours in 2006 (1.0 percent of the total)
to 170 billion kilowatthours (3.2 percent). Generation
from geothermal facilities also grows, but at a slower
rate, increasing from 0.4 percent of total generation
in 2006 to 0.6 percent in 2030. Current assessments
show limited potential for expansion at conventional
geothermal sites.
For consistency in reporting, nonbiogenic municipal
solid waste (MSW) is separated from renewable generation.
Nonrenewable materials, such as plastics,
have made up an increasing proportion of MSW, and
44 percent of the energy value of MSW in 2005 was
from nonbiogenic sources; in the AEO2008 reference
case, that share is held constant over the projection
period. (All growth in generation from MSW and
landfill gas facilities is attributed to landfill gas
only.) Solar technologies in general remain too costly
for grid-connected applications, but demonstration
programs and State policies support some growth in
central-station solar PV, and small-scale customersited
PV applications grow rapidly [84].
Technology Advances, Tax Provisions
Increase Renewable Generation
With State RPS programs included in the reference
case, renewable electricity generation grows by more
than 270 billion kilowatthours. In 2030, total renewable
generation is 656 billion kilowatthours or 12.5
percent of total domestic power production. Although
conventional hydropower remains the largest source
of renewable generation through 2030 (Figure 67),
environmental concerns and the scarcity of untapped
large-scale sites limit its growth, and its share of total
generation falls from 7.1 percent in 2006 to 5.8 percent
in 2030. Electricity generation from nonhydroelectric
alternative fuels increases, bolstered by
legislatively mandated State RPS programs, technology
advances and State and Federal supports, although
the Federal PTC is assumed to expire at the
end of 2008 per existing law. The share of nonhydropower
renewable generation increases from 2.4 percent
of total generation in 2006 to 6.8 percent in 2030.
Wind is the largest source of renewable generation
among the nonhydropower renewable fuels, with 124
billion kilowatthours of generation in 2030, up from
26 billion kilowatthours in 2006. Initially helped by
the Federal PTC, its growth continues as States
meet their RPS requirements. Biomass also grows
strongly, as generation from both dedicated facilities
and co-firing applications increases to 83 billion
kilowatthours in 2030, with an additional 87 billion
kilowatthours generated in end-use systems. In the
near term, market penetration by the unproven biomass
gasification technology is slow, while co-firing
expands more rapidly. The strong growth in end-use
generation is led by the renewable fuels mandate.
Facilities producing BTL fuels also use the feedstocks
for electricity production.
Renewables Are Expected To Become
More Competitive Over Time
The projected cost of renewable generation in
AEO2008 is significantly higher than projected in
previous AEOs, primarily as a result of increases in
the installation cost of new generating capacity
observed throughout the electric power industry.
Broad indexes of utility construction costs suggest
increases of approximately 15 percent over previous
EIA estimates. Available data for specific renewable
capacity markets, such as wind power, confirm both
the direction and general magnitude of the cost increases
when applied more narrowly to renewable
generation. For AEO2008, the cost increases are
applied to all power-sector installations, and they are
expected to be persistent rather than short-term cost
spikes. In general, renewable generation is expected
to remain more expensive than the generation it
would displace, that is, its avoided cost (Figure 68).
In addition to the increase in capital costs, EIA reassessed
the cost and performance of dedicated biomass
generation technology. According to an independent
expert review, previous EIA estimates for biomass
gasification technology understated its cost even
before the industry-wide increase in capital costs.
Although higher installation costs make biomass
more expensive, significant growth in dedicated biomass
capacity is expected in regions with stringent
RPS requirements and limited supplies of lower cost
resources, such as wind. In the near term, growth in
renewable generation in those regions is met largely
by biomass co-firing in existing coal plants—an
option with relatively low capital costs. The higher
efficiency of dedicated plants makes them increasingly
attractive, however, as biomass fuels with higher
energy value are used to meet RPS mandates.
State Portfolio Standards Increase
Generation from Renewable Fuels
In October 2007, 25 States and the District of Columbia
had legislatively mandated RPS programs. The
mandatory programs were modeled in the AEO2008
reference case [85], but States with voluntary goals
were assumed not to have any impact on the national
energy mix. Because NEMS does not provide projections
at the State level, the reference case assumes
that all States will reach their goals within each program’s
legislative framework, and the results are
aggregated at the regional level. In some States,
however, compliance could be limited by authorized
funding levels for the programs. For example, California
is not expected to meet its renewable energy
targets because of limits to authorized funding for its
RPS program.
In the reference case, wind capacity grows much
more rapidly than projected in previous AEOs, to
40 gigawatts in 2030 [86]. Much of the qualifying
capacity in the Midwest, Northeast, Southwest, and
Pacific Northwest is expected to consist of wind
farms. In one midwestern region (MAIN), 11 gigawatts
of wind turbine capacity is projected to be on
line in 2030, as compared with 220 megawatts in
2006. In the Mid-Atlantic region, State RPS programs
are the driving force behind additional dedicated biomass
gasification plants. Approximately 3 gigawatts
of new capacity, along with co-firing, provides 37 billion
kilowatthours of generation annually. Most of
the new biomass capacity is projected to come on line
in the Mid-Atlantic region from 2006 to 2030 (Figure
69). While the growth in wind capacity is the most
dramatic, biomass co-firing and geothermal power
plants also contribute to the baseload generation
needed to satisfy State RPS requirements.
Fuel Costs Drop from Recent Highs,
Then Increase Gradually
Fuel costs account for about two-thirds of the generating
costs of new natural-gas-fired plants, less than
one-third for new coal-fired plants, and less than
one-tenth for new nuclear power plants in 2030.
For many renewable fuels, such as wind and solar,
fuel is free. Capital and operations and maintenance
expenses make up the balance of the costs. As a result,
natural-gas-fired generation tends to be the most
sensitive—and wind and solar the least sensitive—to
changes in fuel costs.
In the reference case, prices for fossil fuels delivered
to electricity generators peak between 2005 and 2010,
as the result of a boom in U.S. and foreign demand,
combined with constraints on supply growth and
political instability in oil- and gas-producing nations.
Fossil fuel prices fall in the middle years of the projection,
however, as new supplies come on line to meet
growing demand. Prices then increase steadily as
demand once again starts to outpace supply (Figure
70). Nuclear and biomass fuel prices rise gradually
throughout the projection, as a result of worldwide
growth in the demand for nuclear fuel and depletion
of local biomass stocks.
Electricity generation from relatively low-cost, lowpolluting,
natural-gas-fired plants increased significantly
in the early years of this decade. More recently,
higher costs and increasing volatility of supply and
prices have characterized natural gas markets.
Consequently, in the reference case, the natural
gas share of total electricity generation drops after
2016, and both coal-fired and renewable generation increase.
Electricity Prices Moderate in the
Near Term, Then Rise Gradually
In the AEO2008 reference case, continuing high fuel
prices and escalating capital costs for new generating
capacity lead to a jump in real electricity prices, peaking
in 2009 at an annual average of 9.3 cents per kilowatthour
(2006 dollars). Electricity prices fall to 8.5
cents per kilowatthour in 2015, as new sources of natural
gas and coal are brought on line. From 2016 on,
generally rising prices for natural gas and petroleum
(in addition to the impact of State renewable fuel
mandates) encourage power producers to increase
their use of less expensive coal and renewable fuels.
Retail electricity prices rise gradually after 2016, to
8.8 cents per kilowatthour in 2030 (Figure 71).
Customers in States with competitive retail markets
for electricity experience the effects of changes in
natural gas prices more rapidly than customers in
States with regulated markets, because competitive
prices are determined by the marginal cost of energy,
and natural-gas-fired plants, with their higher operating
costs, often set hourly marginal prices. After
2016, as other plant types set hourly prices more
often, the price of natural gas has less influence on
competitive retail markets. In the low and high oil
and natural gas price cases, electricity prices range
from 8.5 to 9.1 cents per kilowatthour in 2030.
Electricity distribution costs decline by 5 percent
from 2006 to 2030, as technology improvements and a
growing customer base lower the cost of the distribution
infrastructure. Transmission costs increase by
30 percent, as additional investments are made in
the grid to alleviate current constraints, facilitate
competitive markets, and meet growing consumer
demand for electricity.
Market Trends Notes |
