Electricity

Residential and commercial sectors dominate electricity demand growth

Electricity demand growth has slowed in each decade since the 1950s. After 9.8-percent annual growth in the 1950s, demand (including retail sales and direct use) increased 2.4 percent per year in the 1990s. From 2000 to 2009 (including the 2008-2009 economic downturn) demand grew by 0.5 percent per year. In the Reference case, electricity demand growth rebounds but remains relatively slow, as growing demand for electricity services is offset by efficiency gains from new appliance standards and investments in energy-efficient equipment.

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Electricity demand grows by 31 percent in the Reference case (an average of 1.0 percent per year), from 3,745 billion kilowatthours in 2009 to 4,908 billion in 2035 (Figure 76). Residential demand grows by 18 percent over the period, spurred by population growth, rising disposable income, and continued population shifts to warmer regions with greater cooling requirements. Commercial sector electricity demand increases 43 percent, led by the service industries. Industrial electricity demand grows only 9 percent, slowed by increased competition from overseas manufacturers and a shift of U.S. manufacturing toward consumer goods that require less energy to produce.

In the Reference case, average annual electricity prices (2009 dollars) fall 6 percent from 2009 to 2035. Through 2021 prices fall in response to lower coal and natural gas prices, and the phaseout of competitive transition and system upgrade charges included in transmission and distribution costs. After 2021, rising fuel costs more than offset the lower transmission and distribution costs. Economic growth leads to more demand for electricity and the fuels used for generation, raising the prices of both. In the High and Low Economic Growth cases, electricity prices fall by 2 percent and 11 percent, respectively, over the projection period.

Coal-fired plants continue to lead electricity output

Assuming no additional constraints on carbon emissions, coal remains the dominant source of electricity generation in the AEO2011 Reference case (Figure 77). Generation from coal increases by 25 percent from 2009 to 2035, but only 10 percent from pre-recession 2007 levels, largely as a result of increased use of existing capacity. Its share of the total generation mix, however, falls from 45 percent to 43 percent as a result of more rapid increases in generation from natural gas and renewables. Growth in gas-fired generation is supported by low natural gas prices and stable capital costs for new plants. Low natural gas prices make the dispatch of existing plants and construction of new natural-gas-fired plants more competitive.

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Generation from U.S. nuclear power plants increases by 9 percent from 2009 to 2035, but its share of total generation falls from 20 percent in 2009 to 17 percent in 2035. The Reference case assumes that existing nuclear power plants will continue operating through 2035 (except for retirements already announced); that some plants will be upgraded to higher rated capacities; and that a small number of new nuclear power plants will be built as a result of various incentive programs.

Electricity generation from renewable sources grows by 72 percent in the Reference case, raising its share of total generation from 11 percent in 2009 to 14 percent in 2035. Most of the growth in renewable electricity generation in the power sector consists of generation from wind and biomass facilities. The growth in wind generation is primarily driven by State RPS and Federal tax credits. Generation from biomass comes from both dedicated biomass plants and co-firing in coal plants. Its growth is driven by State RPS, the availability of low cost feedstocks, and the RFS, which results in significant production of electricity at plants producing biofuels.

Most new capacity additions use natural gas and renewables

Decisions to add capacity and the choice of fuel depend on a number of factors [90]. With growing electricity demand and the retirement of 39 gigawatts of existing capacity, 223 gigawatts of new generating capacity (including end-use combined heat and power) will be needed between 2010 and 2035 (Figure 78).

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Natural-gas-fired plants account for 60 percent of capacity additions between 2010 and 2035 in the AEO2011 Reference case, compared with 25 percent for renewables, 11 percent for coal-fired plants, and 3 percent for nuclear. Escalating construction costs have the largest impact on capital-intensive technologies, including nuclear, coal, and renewables. However, Federal tax incentives, State energy programs, and rising prices for fossil fuels increase the competitiveness of renewable and nuclear capacity. In contrast, uncertainty about future limits on greenhouse gas emissions and other possible environmental regulations reduces the competitiveness of coal-fired plants (reflected in the AEO2011 Reference case by adding 3 percentage points to the cost of capital for new coal-fired capacity).

Capacity additions also are affected by demand growth and by fuel prices, which are uncertain. Total capacity additions from 2010 to 2035 range from 172 gigawatts in the Low Economic Growth case to 290 gigawatts in the High Economic Growth case. With higher natural gas prices, such as in the AEO2011 Low Shale EUR case, fewer natural-gas-fired plants are added than in the Reference case. In the High Shale EUR case, where delivered natural gas prices are 21 percent lower than in the Reference case by 2035, total gas-fired capacity additions increase to 154 gigawatts between 2009 and 2035 compared to 135 gigawatts in the Reference case. Total capacity additions range from 212 gigawatts in the Low Shale EUR case to 230 gigawatts in the High Shale EUR case.

Annual capacity additions slow significantly after 2012

Typically, investments in electricity generation capacity have gone through "boom and bust" cycles, with periods of slower growth followed by strong growth, in response to changing expectations for future electricity demand and fuel prices, as well as changes in the industry, such as restructuring (Figure 79). A construction boom in the early 2000s saw capacity additions averaging 35 gigawatts a year, much higher than had been seen before. More recently, average annual builds have dropped to around 16 gigawatts per year.

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In the AEO2011 Reference case, capacity additions from 2010 to 2035 total 223 gigawatts, including new plants built not only in the power sector but also by end-use generators. Annual additions in 2010, 2011, and 2012 average 17 gigawatts per year, with at least 40 percent of that capacity already under construction. Of those early builds, about 46 percent are renewable capacity built to take advantage of Federal tax incentives and to meet State renewable standards.

Annual builds drop significantly after 2012 and remain below 7 gigawatts per year until 2025. During that period, existing reserves are adequate to meet growth in demand in most regions, given the earlier construction boom and relatively low demand growth following the economic recession. Between 2025 and 2035, average annual builds increase to 11 gigawatts per year, as excess reserves are depleted and total capacity growth is more consistent with demand growth. About 80 percent of the capacity added in the period is natural-gas-fired, due to higher construction costs for other capacity types and uncertain prospects for possible future limitations on GHG emissions.

Growth in generating capacity tracks rising demand for electricity

Over the long term, growth in electricity generating capacity and growth in end-use demand for electricity track one another. However, unexpected shifts in demand or dramatic changes affecting capacity investment decisions can cause imbalances for a period of time. Because long-term planning is required for large-scale investments in new capacity, such periods of imbalance can take years to work out.

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Figure 80 shows indexes summarizing relative changes in total generating capacity and demand. During the 1950s and 1960s, the capacity and demand indexes tracked very closely. The energy crises of the 1970s and 1980s, together with other factors, slowed electricity demand growth, and capacity growth outpaced demand for more than 10 years afterward, as planned units continued to come on line. Demand and capacity did not align again until the mid-1990s. Then, in the late 1990s, uncertainty about deregulation of the electricity industry caused a downturn in capacity expansion, and another period of imbalance followed, with growth in demand exceeding capacity growth.

In 2000, a boom in construction of new natural-gas-fired plants began, quickly bringing capacity back into balance with demand and, in fact, creating excess capacity. More recently, the economic recession in 2008 and 2009 caused a significant drop in electricity demand. As a result, the lower demand projected for the near term in the AEO2011 Reference case again results in excess generating capacity. Capacity that is currently under construction is completed in the Reference case, but only a limited amount of additional capacity is built through 2025. In 2025, capacity growth and demand growth are in balance again, and they grow at similar rates through 2035.

Costs and regulatory uncertainties vary across options for new capacity

Technology choices for new generating capacity are based largely on capital, operating, and transmission costs. Coal, nuclear, and renewable plants are capital-intensive (Figure 81), while operating (fuel) expenditures make up most of the costs for gas-fired capacity [91]. Capital costs depend on such factors as equipment costs, interest rates, and cost-recovery periods. Fuel costs vary with operating efficiency, fuel price, resource availability, and transportation costs.

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In addition to levelized cost considerations [92], some technologies and fuels receive subsidies, such as production tax credits (PTCs) and investment tax credits (ITCs). Also, new plants must satisfiy local and Federal emissions standards and must be compatible with the utility's load profile.

Regulatory uncertainty also affects capacity planning. New coal plants may require carbon control and sequestration equipment, resulting in higher material, labor, and operating costs. Alternatively, coal plants without carbon controls could incur higher costs for siting and permitting. Because nuclear and renewable power plants (including wind plants) do not emit greenhouse gases, their costs are not directly affected by regulatory uncertainty in this area.

Capital costs can decline over time as developers gain technology experience. In the Reference case, the capital costs of new technologies are adjusted upward initially, to reflect the optimism inherent in early estimates of project costs, then decline as project developers gain experience. The decline continues at a progressively slower rate as more units are built. Operating efficiencies also are assumed to improve over time, resulting in reduced variable costs unless increases in fuel costs exceed the savings from efficiency gains.

EPACT2005 tax credits stimulate some nuclear builds

In the AEO2011 Reference case, nuclear power capacity increases from 101.0 gigawatts in 2009 to 110.5 gigawatts in 2035 (Figure 82), including 3.8 gigawatts of expansion at existing plants and 6.3 gigawatts of new capacity. The new capacity includes completion of a second unit at the Watts Bar site, where construction on a partially completed plant has resumed. Increases in the estimated costs for new nuclear plants make new investments in nuclear power uncertain. Four new nuclear power plants are completed in the Reference case, all of which are brought on line by 2020 to take advantage of Federal financial incentives. High construction costs for nuclear plants, especially relative to natural-gas-fired plants, make other options for new nuclear capacity uneconomical even in the alternative electricity demand and fuel price cases. In the GHG Price Economywide case, which attaches a price to reductions in carbon dioxide, total nuclear capacity additions from 2010 to 2035 increase to 29 gigawatts as a consequence of the higher costs for operating fossil-fueled capacity.

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One nuclear unit, Oyster Creek, is expected to be retired at the end of 2019, as announced by Exelon in December 2010. All other existing nuclear units continue to operate through 2035 in the Reference case, which assumes that they will apply for, and receive, operating license renewals, including in some cases a second 20-year extension after they reach 60 years of operation. As discussed in last year's "Issues in focus" section, it will likely be a decade or more before significant insight can be gained regarding what will happen beyond 60 years. With costs for natural-gas-fired generation rising and future regulation of GHG emissions uncertain, the economics of keeping existing nuclear power plants in operation are favorable.

Biomass and wind lead growth in renewable generation

Renewable electricity generation, excluding hydropower, accounts for nearly one-quarter of the growth in electricity generation from 2009 to 2035 in the AEO2011 Reference case (Figure 83). The increase is supported by RFS, State-level renewable electricity standards, and Federal tax credits. In the Reference case, generation from wind power nearly doubles its share of total generation, while generation from geothermal resources triples as a result of technology advances that make previously marginal sites attractive for development, as well as increasing the resources available at existing geothermal sites.

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Renewable electricity generation in the end-use sectors also continues to grow. As a result of the Federal RFS that requires increased use of biofuels, there is an attractive opportunity to use waste heat from biofuel production to generate electricity. Consequently, generation from biomass more than triples from 2009 to 2035, when it accounts for 39 percent of total nonhydroelectric renewable electricity generation. Generation from solar resources increases from 2 percent of nonhydroelectric renewable generation in 2009 to more than 5 percent in 2035, as capital costs, especially for PV technologies in the end-use sectors, decrease over time. End-use solar generation grows from 2.3 billion kilowatthours in 2009 to 16.8 billion kilowatthours in 2035, and additional growth in solar generation comes from utility-scale PV plants, which begin to become competitive in the later years of the projection.

Renewable capacity growth spurred by end-use increases

Supported in part by Federal tax credits in the early part of the projection period, the Federal renewable fuels standard, and State renewable portfolio standards, nonhydropower renewable generating capacity grows at a faster rate than fossil fuel capacity in the AEO2011 Reference case. Total nonhydropower renewable capacity increases from 47 gigawatts in 2009 to 100 gigawatts in 2035 (Figure 84). The largest increase is in wind-powered generating capacity. Because the Federal PTC expires at the end of 2012, however, 73 percent of the overall increase in wind capacity (18.2 gigawatts) occurs between 2009 and 2012. From 2012 through 2035, only an additional 6.9 gigawatts of wind capacity is added.

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Biomass generating capacity grows from 7 gigawatts in 2009 (15 percent of total nonhydropower renewable capacity) to 20.2 gigawatts in 2035 (20 percent). All the growth in biomass capacity occurs in the end-use sectors, mainly at biorefineries, where electricity generation capacity increases as a result of mandates in the Federal RFS that require increased use of biofuels. No growth occurs in dedicated biomass generating capacity, because dedicated open-loop biomass plants remain too expensive to compete successfully with renewable capacity.

Solar generating capacity increases five-fold, with most capacity additions coming in the end-use sectors. The additions are based on a decline in the cost of photovoltaic systems over the projection period and the availability of Federal tax credits through 2016. Geothermal capacity also grows as a result of increased site availability, more favorable resource estimates, and lower costs for construction of geothermal facilities.

State portfolio standards increase renewable electricity generation

Regional growth in renewable generation is based largely on two factors: availability of renewable energy resources and the existence of State RPS programs. After a period of robust RPS enactments in several States, 2010 was a relatively quiet year for RPS expansions. The most prominent change was California's RPS modification, which now requires renewable energy (including hydroelectric plants smaller than 30 megawatts capacity) to make up 33 percent of electricity generation, strengthening the prior 20-percent requirement that was supported by a limited fund.

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The WECC California region (CAMX), whose area approximates the California State boundaries (for a map of the electricity regions modeled, see Appendix F) has the largest projected nonhydroelectric renewable capacity, at 13.8 gigawatts in 2035 (Figure 85). The vast majority of California's renewable generating plants in 2035 consist of wind and geothermal capacity, each totaling more than 4.5 gigawatts in 2035. The Texas Regional Entity (ERCT) has more wind capacity in 2035 than any other region, at 10.1 gigawatts in 2035, and the second-largest nonhydro renewable capacity overall.

CAMX leads in solar installations, although State RPS programs heavily influence solar growth beyond the Southwest as both the Reliability First Corporation/East (RFCE) and the Reliability First Corporation/West (RFCW) regions have about 1 gigawatt of end-use solar capacity in 2035. Those two regions are not known for a strong solar resource base, and the installations are in response to the ITC in the early years of the projection period and high electricity prices during the later years. Most biomass capacity—confined largely to the end-use sectors—is built at cellulosic ethanol plant sites, most of which are in the Southeast.

Electricity use increases despite improved efficiency of electric devices

Electricity use grows 0.7 percent per year, from 42 percent of total residential delivered energy consumption in 2009 to 47 percent in 2035 in the AEO2011 Reference case. Growing service demand is only partially offset by technological improvements that lead to increased efficiency of electric devices and appliances.

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Despite increases in market penetration by ENERGY STAR qualified computers, as well as a general shift from desktop computers to laptops and other portable computing devices, energy use for personal computers (PCs) and related equipment continues to grow slowly, as the number of computers and peripherals per household increases (although at a slower rate than in the past). Contributing to the growth are related electronic devices, such as high-speed internet modems and network routers, which typically lack automatic standby modes and consume full power 24 hours a day.

Increased market penetration is also expected for ENERGY STAR televisions and computer monitors. Flat panel displays capture a growing share of the market and overall stock efficiency improves as light-emitting diodes (LEDs) displace cold cathode fluorescent lamps as a major backlighting technology for liquid crystal displays. Improvements in efficiency are offset to some degree, however, by a trend toward larger screen sizes.

The EISA2007 Federal lighting standards will lead to a decline in energy use for lighting, as low-efficacy incandescent lamps are replaced by compact fluorescent, LED, and high-efficiency incandescent lamps (Figure 59). In 2020, delivered energy use for lighting per household in the Reference case is 33 percent below the 2009 level.

Growth in electricity use dominates the outlook for commercial energy demand

Electricity use increases 1.4 percent per year, from 53 percent of total commercial delivered energy consumption in 2009 to 58 percent in 2035, in the AEO2011 Reference case. Growth in electricity demand for new electronic equipment more than offsets improvements in equipment and building shell efficiency and growth in CHP.

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Average annual growth in commercial sector electricity use for PCs and related devices slows between 2009 and 2035, as the market penetration of ENERGY STAR qualified products increases, and laptops gain market share relative to desktop PCs, which use more energy than laptops.

Electricity use for "other" office equipment—including servers and mainframe computers—increases by 2.5 percent per year as demand for high-speed networks and internet connectivity grows, surpassing electricity demand for commercial refrigeration by 2019.

End uses such as space heating and cooling, water heating, and lighting are covered by Federal and State efficiency standards, which have the effect of limiting growth in energy consumption to less than the average of 1.2 percent per year for growth in commercial floorspace (Figure 63). "Other" electric end uses, some of which are not subject to Federal standards, account for much of the growth in commercial electricity consumption. Electricity demand for those other end uses, which include distribution transformers, vertical transport, and medical imaging equipment, increases by an average of 2.4 percent per year and accounts for 39 percent of total commercial electricity consumption in 2035.

Improved interconnection supports growth in distributed generation

More than 40 States have some form of interconnection standard or guideline that governs the installation of DG capacity and its incorporation into the electricity grid. Current limits on the maximum capacity that can be interconnected are expected to decrease with improvements in technology and the spread of RPS policies and goals over time.

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In addition to declining limits on DG interconnection, ITCs for various renewable and nonrenewable DG technologies continue through 2016. With the exception of a permanent 10-percent credit following the expiration of the current 30-percent credit for solar PVs, the AEO2011 Reference case assumes no ITCs for DG after 2016. The Extended Policies case, on the other hand, assumes that current tax credits continue through 2035.

Total commercial DG capacity in the Reference case increases from 1.9 gigawatts in 2009 to more than 6.8 gigawatts in 2035. In the Extended Policies case, capacity increases to 9.8 gigawatts in 2035. Microturbines show the fastest capacity growth among the DG technologies in the Reference case, averaging 16 percent per year. Commercial sector wind capacity grows by 11 percent per year in the Extended Policies case, more than double the annual growth in the Reference case, as a result of continued tax credits. In 2035, renewable energy accounts for 50 percent of all commercial DG capacity in the Extended Policies case, as compared with less than 35 percent in the Reference case (Figure 65).