Electricity Demand
Rate of Electricity Demand Growth Slows, Following the Historical Trend
Electricity demand fluctuates in the short term in response to business
cycles, weather conditions, and prices. Over the long term, however, electricity
demand growth has slowed progressively by decade since 1950, from 9 percent
per year in the 1950s to less than 2.5 percent per year in the 1990s. From
2000 to 2007, increases in electricity demand averaged 1.1 percent per
year. The slowdown in demand growth is projected to continue over the next
23 years (Figure 54), as a result of efficiency gains in response to rising
energy prices and new efficiency standards for lighting, heating and cooling,
and other appliances.
In the reference case, electricity demand increases by 26 percent from
2007 to 2030, or by an average of 1.0 percent per year. The largest increase
is in the commercial sector (38 percent), where service industries continue
to lead demand growth, followed by the residential sector (20 percent)
and the industrial sector (7 percent). Population growth and rising disposable
incomes increase the demand for products, services, and floorspace, and
ongoing population shifts to warmer regions increase the use of electricity
for space cooling.
From 2007 levels, electricity demand increases by 36 percent in the high
growth case, to 5,323 billion kilowatthours in 2030, compared with an increase
of 16 percent in the low growth case, to 4,518 billion kilowatthours in
2030. Plug-in electric hybrid vehicles are not expected to reverse the
trend of slowing growth in electricity demand, which increases by only
0.1 percent for every 1 million PHEV-40 vehicles in operation.
Coal-Fired Power Plants Provide Largest Share of Electricity Supply
Coal continues to provide the largest share of energy for U.S. electricity
generation in the AEO2009 reference case, with only a modest decrease from
49 percent in 2007 to 47 percent in 2030. Total electricity generation
at coal-fired power plants in 2030 is 19 percent higher than the 2007 total
(Figure 55). Growth in coal-fired generating capacity is limited by concerns
about GHG emissions and the potential for mandated limits, but existing
plants continue to be used intensively.
Concerns about GHG emissions have little effect on construction of new
capacity fueled by natural gas. The natural gas share of generation increases
to 21 percent in 2027, before dropping to 20 percent in 2030, about the
same as in 2007. Generation from nuclear power increases by 13 percent
from 2007 to 2030, as addition of new units and uprates at existing units
increase overall capacity and generation. The nuclear share of total generation
falls somewhat, however, from 19 percent in 2007 to 18 percent in 2030.
Renewable generation, supported by Federal tax incentives and State renewable
programs, increases by more than 100 percent from 2007 to 2030, when it
accounts for 14 percent of total generation.
Projected growth in demand for electricity varies with different assumptions
about future economic conditions. In 2030, total generation in the high
economic growth case is 9 percent above the reference case projection,
and in the low economic growth case it is 7 percent below the reference
case.
Most New Capacity Uses Natural Gas as Fewer Coal-Fired Plants Are Added
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 30 gigawatts of existing capacity, 259 gigawatts
of new generating capacity (including end-use CHP) will be needed between
2007 and 2030.
Natural-gas-fired plants account for 53 percent of capacity additions in
the reference case, as compared with 22 percent for renewables, 18 percent
for coal-fired plants, and 5 percent for nuclear (Figure 56). Escalating
construction costs have the largest impact on capital-intensive technologies,
including renewables, coal, and nuclear; but Federal tax incentives, State
energy programs, and rising prices for fossil fuels increase the cost-competitiveness
of renewable and nuclear capacity. In contrast, uncertainty about future
limits on GHG emissions and other possible environmental regulations (reflected
in the AEO2009 reference case by adding 3 percentage points to the cost
of capital for new coal-fired capacity) reduces the competitiveness of
coal.
Projected capacity additions also are affected by demand growth and by
fuel prices. Reflecting slower and faster growth in demand for electricity,
capacity additions from 2007 to 2030 total 184 gigawatts and 350 gigawatts
in the low and high economic growth cases, respectively. The higher fuel
costs in the AEO2009 high oil price case lead to fewer additions of natural-gas-fired
plants, because fuel costs make up a relatively large share of their total
expenditures.
Least Expensive Technology Options Are Likely Choices for New Capacity
Technology choices for new generating capacity are made to minimize costs
while meeting local and Federal emissions constraints. Capacity expansion
decisions consider capital, operating, and transmission costs. Typically,
coal-fired, nuclear, and renewable plants are capital-intensive, whereas
operating (fuel) expenditures account for most of the costs associated
with natural-gas-fired capacity (Figure 57) [96]. Capital costs depend
on such factors as interest rates and cost-recovery periods. Fuel costs
can vary according to plant operating efficiency, resource availability,
and transportation costs.
Regulatory uncertainty affects capacity planning decisions. Unless they
are equipped with CCS equipment, new coal-fired plants could incur higher
costs as a result of higher expenses for siting and permitting. Because
nuclear and renewable power plants (including wind plants) do not emit
GHGs, however, their costs are not directly affected by regulatory uncertainty.
Capital costs can decline over time as developers gain experience with
a given technology. In the AEO2009 reference case, capital costs are adjusted
upward initially, to reflect the optimism inherent in early public estimates
of project costs. The costs decline as project developers gain experience,
and the decline continues at a progressively slower rate as more units
are built. Operating efficiencies also are assumed to improve over time,
and variable costs could therefore be reduced unless increases in fuel
costs exceed the savings from efficiency gains.
Electricity Prices Moderate in the Near Term, Then Rise Gradually
In recent years, real electricity prices (in 2007 dollars) have increased
sharply, as fuel costs and capital costs have risen rapidly and restructuring
initiatives that constrained price increases have ended. In the AEO2009 reference case, real electricity prices fall in the near term when fuel
prices decline during the economic slowdown. With economic recovery, real
electricity prices stabilize at 9.0 cents per kilowatthour in 2010, then
remain at that level for several years, while fuel prices remain relatively
low and new coal- and natural-gas-fired capacity comes on line. Real electricity
prices begin to rise steadily after 2015, as fuel prices increase more
rapidly and the need for new capacity grows. Much of the new renewable
capacity is required by State renewable mandates.
Real retail electricity prices increase to 10.4 cents per kilowatthour
in 2030 in the reference case (Figure 58). They are higher in the high
economic growth case, reaching 10.8 cents per kilowatthour in 2030 as stronger
economic growth leads to more rapid growth in electricity demand. Electricity
prices are lower in the low economic growth case, at 9.7 cents per kilowatthour
in 2030.
Transmission costs, while remaining a relatively small component of delivered
electricity prices, increase by 35 percent from 2007 to 2030 because of
the additional investment needed to meet electricity demand growth, alleviate
existing transmission constraints and bottlenecks, facilitate the operation
of competitive wholesale energy markets, and link new generation from remote
wind facilities with demand centers.
EPACT2005 Tax Credits Are Expected To Stimulate Some Nuclear Builds
In the AEO2009 reference case, nuclear power capacity increases from 100.5
gigawatts in 2007 to 112.6 gigawatts in 2030, including 3.4 gigawatts of
expansion at existing plants, 13.1 gigawatts of new capacity, and 4.4 gigawatts
of retirements. The reference case includes a second unit in 2014 at the
Watts Bar site, where construction was halted in 1988 after being partially
completed. Rising costs for construction materials have greatly increased
the estimated cost of new nuclear plants, which when combined with the
current instability of financial markets makes new investments in nuclear
power uncertain. In the reference case, some 10 new nuclear power plants
are completed through 2030. The first few are eligible for the EPACT2005
PTC. Most existing nuclear units continue to operate through 2030, based
on the assumption that they will apply for and receive operating license
renewals. Seven units, totaling 4.4 gigawatts, are retired after 2028,
when they reach the end date of their original licenses plus a 20-year
renewal.
In the AEO2009 projections, nuclear capacity additions vary with assumptions
about overall demand for electricity and the prices of other fuels (Figure
59). The amount of nuclear capacity added also is sensitive to assumptions
about future plans and policies for limiting or reducing GHG emissions.
Across the oil price and economic growth cases, nuclear capacity additions
from 2007 to 2030 range from 1 to 28 gigawatts. In the low economic growth
case, with falling electricity demand and rising interest rates, new nuclear
plants are not economical. More new nuclear capacity is built in the high
growth and high oil price cases, because overall capacity requirements
are higher and/or alternatives are more expensive.
Biomass and Wind Lead Projected Growth in Renewable Generation
The potential for growth in electricity generation from wind power 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 for wind, which is scheduled to expire at the end of 2009. Other renewable
technologies are guaranteed a tax credit for an additional year. In the AEO2009 reference case, generation from wind power increases from 0.8 percent
of total generation in 2007 to 2.5 percent in 2030 (Figure 60). Generation
from biomass, both dedicated and co-firing, grows from 39 billion kilowatthours
in 2007 (0.9 percent of the total) to 231 billion kilowatthours (4.5 percent)
in 2030. Generation from geothermal facilities also increases but at such
a slow rate that it does not gain market share. Current assessments show
limited potential for expansion at conventional geothermal sites. Enhanced
geothermal development remains economically infeasible.
The principal reason for the robust growth of renewable electricity generation
in the end-use sectors, which is included in the totals above, is the EISA2007
renewable fuels mandate. Biorefineries producing cellulosic ethanol use
residues from the biomass feedstock for electricity production. Generation
from biomass comprises nearly 80 percent, or 91 billion kilowatthours,
of end-use renewable electricity in 2030. 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, customer-sited PV applications grow rapidly [97].
Technology Advances, Tax Provisions Increase Renewable Generation
The AEO2009 reference case includes both State RPS requirements and a risk
premium on high-carbon generating technologies. As a result, total renewable
electricity generation grows by nearly 380 billion kilowatthours, to 730
billion kilowatthours (14.2 percent of total domestic power production)
in 2030. Environmental concerns and a scarcity of new large-scale sites
limit the growth of conventional hydropower, and from 2007 to 2030 its
share of total generation remains between 6 percent and 7 percent. Generation
from nonhydroelectric alternatives increases, bolstered by legislatively
mandated State RPS programs, technology advances, and State and Federal
supports (Figure 61). Although the Federal PTC is assumed to expire after
2009 for wind and after 2010 for other renewables, nonhydropower renewable
generation increases from 2.5 percent of total generation in 2007 to 8.3
percent in 2030.
Wind and biomass are the largest sources of electricity among the nonhydropower
renewables. Initially helped by the Federal PTC, their growth continues
as States meet their RPS requirements and more States enact RPS programs
each year. Central-station solar is also growing rapidly in California.
Although the technology remains costly, several credible project announcements
have been made that would lead to capacity expansion in the hundreds of
megawatts. Moreover, as States continue to organize regional climate pacts,
renewable generation will become more prominent in carbon-constrained regions.
The Northeast RGGI is the only such program included in the AEO2009 reference
case, but western States are moving forward quickly with their own programs.
Higher or Lower Costs Affect Trends in Renewable Generation Capacity
If the costs of renewable generation technologies decline significantly
faster than projected in the AEO2009 reference case, there may be more
new renewable capacity than is needed to meet State renewable generation
mandates. The low renewable technology cost case assumes costs 25 percent
lower than in the reference case in 2030, resulting in 38 percent more
new wind capacity and 200 percent more new dedicated biomass capacity.
New end-use solar capacity in 2030 is 49 percent above the reference case
level, although the technology remains too expensive for widespread use
in bulk power markets; geothermal, hydroelectric, and municipal solid waste
capacity shows little change, because economical resources are limited.
A significant increase in dedicated biomass capacity in the low cost case
draws biomass away from less efficient co-firing operations and helps producers
meet State RPS requirements.
In the high renewable technology cost case, the costs for renewable capacity
remain at the reference case levels and “dedicated energy crops” are not
developed, resulting in slightly less new renewable capacity in 2030 than
in the reference case (Figure 62). State mandates still are expected to
guarantee a significant amount of growth in renewable capacity, however,
even with the higher costs. In the high cost case, biomass co-firing operations
make a larger contribution to RPS compliance than in the reference case.
Although many State RPS laws include cost containment measures that may
limit overall compliance if renewable generation is more expensive than
projected in the reference case, many of those provisions either are discretionary
or cannot be analyzed fully in the high cost case.
State Portfolio Standards Increase Generation from Renewable Fuels
As of early November 2008, 28 States and the District of Columbia had legislatively
mandated RPS programs. The mandatory programs are included in the reference
case, but States’ voluntary goals are not. Because NEMS does not provide
projections at the State level, the reference case assumes that most 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 on the authorized funding for its RPS program.
By region, the fastest growth in nonhydroelectric renewable generation
is projected for MAIN (Figure 63). The largest share of wind power is in
the MAIN region, which includes Illinois, Wisconsin, and parts of Michigan
and Missouri. In Texas, generation from wind power grows until the Federal
PTC expires on December 31, 2010, and resumes growth after 2020, when natural
gas prices begin to rise more rapidly. Solar and geothermal energy are
used in the Southwest. Biomass generates most of the required renewable
energy in the Mid-Atlantic region, which in 2030 contains nearly 53 percent
of the Nation’s dedicated biomass capacity.
Most NEMS regions include at least one State with an RPS program (see Figure
F2 in Appendix F for a map of the regions). The only area without widespread
RPS programs is the Southeast, where North Carolina is the only State with
an enforceable RPS.
Market Trends End Notes |
