Home > Forecasts & Analysis > Annual Energy Outlook 2008 > Electricity Demand

Annual Energy Outlook2008with Projections to 2030

Report #:DOE/EIA-0383(2008)

Release date full report:June 2008

Next release date full report:February 2009

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

2006to 14percent in 2030,while the coal share increases from 49percent to 54percent.

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 21percent of total electricity supply in 2030in 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.

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

2006to 2030,compared with a 36-percent share for natural gas (Figure 62).

figure data

figure data

EIA - Annual EnergyOutlook2008- ElectricityDemand Page 1 of 5

http://www.eia.gov/oiaf/archive/aeo08/electricity.html 5/6/2014
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 18percent and 6percent 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.

EPACT2005Tax 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.

figure data

figure data

figure data

EIA - Annual EnergyOutlook2008- ElectricityDemand Page 2 of 5

http://www.eia.gov/oiaf/archive/aeo08/electricity.html 5/6/2014
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

837and 1,047billion 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 0.6percent of total generation in 2006to 2.4percent 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 656billion kilowatthours or 12.5percent 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 2006to 6.8percent 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

figure data

figure data

figure data

figure data

EIA - Annual EnergyOutlook2008- ElectricityDemand Page 3 of 5

http://www.eia.gov/oiaf/archive/aeo08/electricity.html 5/6/2014
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 220megawatts 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 37billion kilowatthours of generation annually.Most of the

new biomass capacity is projected to come on line in the Mid-Atlantic region

from 2006to 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 AEO2008reference 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 2016on,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 8.8cents 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-gasfired 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 8.5to 9.1cents per kilowatthour in 2030.

Electricity distribution costs decline by 5percent from 2006to 2030,as technology improvements and a growing customer base lower the

cost of the distribution infrastructure.Transmission costs increase by 30percent,as additional investments are made in the grid to alleviate

current constraints,facilitate competitive markets,and meet growing consumer demand for electricity.

figure data

figure data

figure data

EIA - Annual EnergyOutlook2008- ElectricityDemand Page 4 of 5

http://www.eia.gov/oiaf/archive/aeo08/electricity.html 5/6/2014
Market Trends Notes

EIA - Annual EnergyOutlook2008- ElectricityDemand Page 5 of 5

http://www.eia.gov/oiaf/archive/aeo08/electricity.html 5/6/2014