‹ Analysis & Projections

Annual Energy Outlook 2014

Release Dates: April 7 - 30, 2014   |  Next Early Release Date: December 2014   |  See schedule

Industrial from Executive Summary

Natural gas consumption grows in industrial and electric power sectors as domestic production also serves an expanding export market


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Relatively low natural gas prices, maintained by growing shale gas production, spur increased use in the industrial and electric power sectors, particularly over the next decade. In the Reference case, natural gas use in the industrial sector increases by 16 percent, from 6.8 trillion cubic feet per year in 2011 to 7.8 trillion cubic feet per year in 2025. After 2025, the growth of natural gas consumption in the industrial sector slows, while total U.S. consumption continues to grow (Figure 7). This additional growth is mostly for use in the electric power sector. Although natural gas continues to capture a growing share of total electricity generation, natural gas consumption by power plants does not increase as sharply as generation because new plants are very efficient (needing less fuel per unit of power output). The natural gas share of generation rose from 16 percent of generation in 2000 to 24 percent in 2011 and increases to 27 percent in 2025 and 30 percent in 2040. Natural gas use in the residential and commercial sectors remains nearly constant, as increasing end-use demand is balanced by increasing end-use efficiency.

Natural gas consumption also grows in other markets in the Reference case, including heavy-duty freight transportation (trucking) and as a feedstock for GTL production of diesel and other fuels. Those uses account for 6 percent of total U.S. natural gas consumption in 2040, as compared with almost nothing in 2011.

Natural gas use in the electric power sector grows even more sharply in the High Oil and Natural Gas Resource case, as the natural gas share of electricity generation grows to 39 percent, reaching 14.8 trillion cubic feet in 2040, more than 55 percent greater than in the Reference case. Industrial sector natural gas consumption growth is also stronger in this case, with growth continuing after 2025 and reaching 13.0 trillion cubic feet in 2040 (compared to 10.5 trillion cubic feet in 2040 in the Reference case). Much of the industrial growth in the High Oil and Natural Gas Resource case is associated with natural gas use for GTL production and increased lease and plant use in natural gas production.

Industrial from Market Trends

Industrial and commercial sectors lead U.S. growth in primary energy use


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Total primary energy consumption, including fuels used for electricity generation, grows by 0.3 percent per year from 2011 to 2040, to 107.6 quadrillion Btu in 2040 in the AEO2013 Reference case (Figure 53). The largest growth, 5.1 quadrillion Btu from 2011 to 2040, is in the industrial sector, attributable to increased use of natural gas in some industries (bulk chemicals, for example) as a result of an extended period of relatively low prices coinciding with rising shipments in those industries. The industrial sector was more severely affected than the other end-use sectors by the 2007-2009 economic downturn; the increase in industrial energy consumption from 2008 through 2040 is 3.9 quadrillion Btu.

The second-largest increase in total primary energy use, at 3.1 quadrillion Btu from 2011 to 2040, is in the commercial sector, which currently accounts for the smallest share of end-use energy demand. Even as standards for building shells and energy efficiency are being tightened in the commercial sector, the growth rate for commercial energy use, at 0.5 percent per year, is the highest among the end-use sectors, propelled by 1.0-percent average annual growth in commercial floorspace.

Primary energy use in the residential sector grows by 0.2 percent per year, or about 1.6 quadrillion Btu from 2011 to 2040, but it does not increase above the 2011 level until 2029. Increased efficiency reduces energy use for space heating, lighting, and clothes washers.

In the transportation sector, light-duty vehicle (LDV) energy consumption declines as a result of the impact of fuel economy standards through 2025. Total transportation sector energy use is essentially flat from 2011 through 2040, increasing by about 140 trillion Btu.

Growth in industrial energy consumption is slower than growth in shipments


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Despite a 76-percent increase in industrial shipments, industrial delivered energy consumption increases by only 19 percent from 2011 to 2040 in the AEO2013 Reference case. The continued decline in energy intensity of the industrial sector is explained in part by a shift in the share of shipments from energy-intensive manufacturing industries (bulk chemicals, petroleum refineries, paper products, iron and steel, food products, aluminum, cement and lime, and glass) to other, less energy-intensive industries, such as plastics, computers, and transportation equipment. Also, the decline in energy intensity for the less energy-intensive industries is almost twice that for the more energy-intensive industries.

Industrial energy consumption increases by 4.7 quadrillion Btu from 2011 to 2040 in the Reference case (Figure 63), or by an average of 0.6 percent per year. Most of the growth occurs in the near term, from 2011 to 2025, with an average yearly increase of 1 percent. After 2025, the annualized rate of increase is 0.3 percent. The share of industrial delivered energy consumption used for heat and power in manufacturing increases modestly, from 63 percent in 2011 to 67 percent in 2040.

Energy consumption for heat and power in the nonmanufacturing industries (agriculture, mining, and construction) increases by about 1.1 quadrillion Btu from 2011 to 2040 in the Reference case, but its percentage of total industrial energy consumption remains at about 16 percent. Nonfuel uses of energy (feedstocks for chemical manufacturing and asphalt for construction) increase by 1.6 percent per year from 2011 to 2025 and decrease by 0.3 percent per year after 2025. The nonfuel share of energy consumption is between 18 and 20 percent over the projection period.

Reliance on natural gas, natural gas liquids, and renewables rises as industrial energy use grows


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Much of the growth in industrial energy consumption in the AEO2013 Reference case is accounted for by natural gas use, which increases by 18 percent from 2011 and 2025 and by 6 percent from 2025 to 2040 (Figure 64). With domestic natural gas production increasing sharply in the projection, natural gas prices remain relatively low. The mix of industrial fuels changes relatively slowly, however, reflecting limited capability for fuel switching in most industries.

Consumption of renewable fuels in the industrial sector grows by 22 percent from 2011 to 2025 in the Reference case and by 37 percent from 2025 to 2040. The paper industry remains the predominant consumer of renewable energy (mostly biomass) in the industrial sector. Industrial consumption of natural gas liquids (NGL) increases by 21 percent from 2011 to 2025, followed by a 9-percent decline from 2025 to 2040. NGL are consumed predominantly as feedstocks in the bulk chemicals industry and for process heat in other industries. NGL use declines starting in 2025 as shipments of bulk chemicals begin to decline in the face of increased international competition. Industrial coal use drops by less than 1 percent from 2011 to 2040, and the use of petroleum and other liquid fuels increases by 6 percent.

Low natural gas prices and increased availability of biomass contribute to growth in the use of combined heat and power (CHP). A small decline in the purchased electricity share of industrial energy consumption (less than 1 percent from 2011 to 2040) reflects growth in CHP, as well as efficiency improvements resulting from rising standards for electric motors.

Iron and steel, cement, and glass industries are most sensitive to the economic growth rate


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Total shipments from the energy-intensive industries grow by an average of 1.0 percent per year from 2011 to 2040 in the AEO2013 Reference case, as compared with 0.6 percent in the Low Economic Growth case and 1.4 percent in the High Economic Growth case. Growth in shipments is uneven among the industrial subsectors.

The iron and steel, cement, and glass industries show the greatest variability in shipments across the three cases, because they supply downstream industries that are sensitive to investment, which is more variable than GDP. Construction is a downstream user of the output for all three industries, and the metal-based durables sector is a downstream industry for the iron and steel and glass industries. The high rate of shipments growth for those industries is related largely to recovery from the recent recession. Shipments of paper products grow steadily in each of the three cases (Figure 65).

The food, bulk chemicals, and aluminum industries show less variability among the three cases. Food shipments, which tend to grow in proportion to population, are less sensitive to investment. The bulk chemicals and aluminum industries face significant international competition, but they experience significant growth, largely related to relatively inexpensive natural gas and associated declines in electricity costs for aluminum manufacturers. Shipments from the petroleum refineries industry either decline or grow relatively slowly in each of the three cases as a result of slow growth in demand for petroleum-based fuels.

Energy use reflects output and efficiency trends in energy-intensive industries


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Energy consumption growth in the energy-intensive industries from 2011 to 2040 ranges from no significant change in the Low Economic Growth case to an increase of 3.9 quadrillion Btu in the High Economic Growth case (Figure 66). Energy efficiency improvements reduce the rate of growth in energy consumption relative to shipments. In the AEO2013 Reference case, energy use in the energy-intensive industries increases by 13 percent, while shipments increase by 33 percent. In the Low Economic Growth case, energy use in the energy-intensive industries declines by 2 percent while shipments increase by 17 percent. In the High Economic Growth case, energy use grows by 27 percent and shipments by 48 percent.

Shipments from all industries grow in the Reference case, but the impact on energy consumption varies by industry because of structural changes and differences in the rate of energy efficiency improvement by industry. For example, shipments from the aluminum industry and the iron and steel industry increase in the projection, even as energy use declines. For the aluminum industry, shipments grow by 17 percent while energy use declines by 16 percent because of a rise in less energy-intensive secondary production. For the iron and steel industry, shipments grow by 18 percent while energy use declines by 10 percent because of a shift from the use of blast furnace steel production to the use of recycled products and electric arc furnaces.

Refining is the only industry subsector that shows an increase in energy intensity. Shipments from refineries fluctuate in the early years and then decline slightly after 2019, with a 4-percent decline in shipments overall from 2011 to 2040. In contrast, energy use for refining increases by 13 percent over the same period, as CTL production and the use of heavy crude feedstock, both of which are more energy-intensive to process than typical crude oil, increase after 2022.

Most of the growth in shipments from energy-intensive industries occurs before 2025


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Most of the growth in shipments from energy-intensive industries from 2011 to 2040 occurs before 2025 in the Reference case (Figure 67). The strong growth in the earlier period can be explained largely by low natural gas prices that result from increased domestic production of natural gas from tight formations, as well as continued economic recovery. After 2025 the growth in shipments is weaker, with declines in some industries as a result of growing international competition and rising natural gas prices.

In the bulk chemical industry, shipments grow by 27 percent from 2011 to 2025, then decline by 8 percent from 2025 to 2040. Aluminum shipments and iron and steel shipments both grow by about 50 percent more than shipments of bulk chemicals from 2011 to 2025. The decline in aluminum and iron and steel shipments after 2025, just over 20 percent, is also greater than the decline in bulk chemicals shipments. In addition to growing international competition, the growth in industries downstream from the primary metals sector, such as construction and transportation equipment, weakens after 2025.

The cement and lime and glass industries show continued growth over the period from 2025 to 2040, but at relatively low levels. Cement and lime and glass have high shipping costs, which give domestic suppliers an advantage over imports and help to maintain the sector's growth after 2025. Shipments from the refinery industry show modest declines in both the 2011-2025 and 2025-2040 periods, as demand for transportation fuels is moderated by increasing vehicle efficiencies. The food and paper products industries show the least variation in shipment growth over the projection period, with growth rates declining modestly after 2025.

Metal-based durable goods show the fastest growth among non-energy-intensive industries


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In 2040, the non-energy-intensive manufacturing and nonmanufacturing industrial subsectors account for $8.5 trillion (2005 dollars) in shipments in the AEO2013 Reference case—a 92-percent increase from 2011. The growth in those shipments from 2011 to 2040 averages 1.6 percent per year in the Low Economic Growth case and 3.0 percent per year in the High Economic Growth case, compared with 2.3 percent in the Reference case (Figure 68). Non-energy-intensive manufacturing and nonmanufacturing are segments of the industrial sector that consume fuels primarily for thermal or electrical needs, not as raw materials or feedstocks.

In the three cases, the annual rate of increase in shipments from non-energy-intensive industries generally is twice the rate of increase for the energy-intensive industries, primarily as a result of growing demand for high-technology, high-value goods. Further, the growth in shipments is fastest in the medium term. From 2011 to 2025, shipments of metal-based durables grow by an average of 3.2 percent per year; from 2025 to 2040, the growth rate slows to 2.1 percent per year.

In the Reference case, shipments from the non-energy-intensive industries grow at different rates. For metal-based durables, shipments grow by 2.6 percent per year from 2011 to 2040, led by 3.0-percent average annual growth for transportation equipment. In the nonmanufacturing sector, construction grows by an average of 2.6 percent per year, agriculture grows by 1.0 percent per year, and mining grows by 0.2 percent per year.

Nonmanufacturing efficiency gains are slowed by rising energy intensity in the mining industry


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From 2011 to 2040, total energy consumption in the non-energy-intensive manufacturing and nonmanufacturing industrial subsectors increases by 18 percent (1.4 quadrillion Btu) in the Low Economic Growth case, 36 percent (2.8 quadrillion Btu) in the Reference case, and 58 percent (4.6 quadrillion Btu) in the High Economic Growth case (Figure 69).

The nonmanufacturing subsector (construction, agriculture, and mining) accounts for roughly 57 percent of the energy consumed in the non-energy-intensive industries but only 31 percent of the total shipments in 2040. The nonmanufacturing industries are more energy-intensive than the manufacturing industries, and there is no significant decline in energy intensity for the nonmanufacturing industries over the projection period. Construction and agriculture show annual declines in energy intensity from 2011 to 2040 (1.0 percent and 0.9 percent per year, respectively), whereas the energy intensity of the mining industry increased by 0.7 percent from 2011 to 2040 in the AEO2013 Reference case. Within the nonmanufacturing sector, the mining industry accounts for 17.3 percent of shipments in 2040 and roughly 43.2 percent of the energy consumed, as the energy intensity of mining activity increases with resource depletion over time.

In comparison, the non-energy-intensive manufacturing industries—such as plastics, computers, and transportation equipment—show a 33-percent decline in energy intensity from 2011 to 2040, or an average decline of about 1.4 percent per year. For the transportation equipment industry, which accounts for 19 percent of the increase in energy use but roughly 29 percent of the increase in shipments, energy intensity declines by 1.5 percent per year on average in the Reference case.

Industrial and electric power sectors lead U.S. growth in natural gas consumption


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U.S. total natural gas consumption grows from 24.4 trillion cubic feet in 2011 to 29.5 trillion cubic feet in 2040 in the AEO2013 Reference case. Natural gas use increases in all the end-use sectors except residential (Figure 85), where consumption declines as a result of improvements in appliance efficiency and falling demand for space heating, attributable in part to population shifts to warmer regions of the country.

Despite falling early in the projection period from a spike in 2012, which resulted from very low natural gas prices relative to coal, consumption of natural gas for power generation increases by an average of 0.8 percent per year, with more natural gas used for electricity production as relatively low prices make natural gas more competitive with coal. Over the projection period, the natural gas share of total power generation grows, while the coal share declines.

Natural gas consumption in the industrial sector increases by an average of 0.5 percent per year from 2011 to 2040. This includes 0.7 trillion cubic feet of natural gas used in GTL, which is largely consumed in the transportation sector. Industrial output grows as the energy-intensive industries take advantage of relatively low natural gas prices, particularly through 2025. After 2025, growth in the sector slows in response to rising prices and increased international competition.

Although vehicle uses currently account for only a small part of total U.S. natural gas consumption, the projected percentage growth in natural gas demand by vehicles is the largest percentage growth in the projection. With incentives and low natural gas prices leading to increased demand for natural gas as a fuel for HDVs, particularly after 2025, consumption in vehicles increases from about 40 billion cubic feet in 2011 to just over 1 trillion cubic feet in 2040.

Petroleum and other liquids consumption outside industrial sector is stagnant or declines


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Consumption of petroleum and other liquids peaks at 19.8 million barrels per day in 2019 in the AEO2013 Reference case and then falls to 18.9 million barrels per day in 2040 (Figure 93). The transportation sector accounts for the largest share of total consumption throughout the projection, although its share falls to 68 percent in 2040 from 72 percent in 2012 as a result of improvements in vehicle efficiency following the incorporation of CAFE standards for both LDVs and HDVs. Consumption of petroleum and other liquids increases in the industrial sector, by 0.6 million barrels per day from 2011 to 2040, but decreases in all the other end-use sectors.

Motor gasoline, ultra-low-sulfur diesel fuel, and jet fuel are the primary transportation fuels, supplemented by biofuels and natural gas. Motor gasoline consumption drops by approximately 1.6 million barrels per day from 2011 to 2040 in the Reference case, while diesel fuel consumption increases from 3.5 million barrels per day in 2011 to 4.3 million in 2040, primarily for use in heavy-duty vehicles. At the same time, natural gas use in heavy-duty vehicles displaces 0.7 million barrels per day of petroleum-based motor fuel in 2040, most of which is diesel.

An increase in consumption of biodiesel and next-generation biofuels [136], totaling about 0.4 million barrels per day from 2011 to 2040, is attributable to the EISA2007 RFS mandates. The relative competitiveness of CTL and GTL fuels improves over the projection period as petroleum prices rise. In 2040, CTL and GTL together supply 0.3 million barrels per day of nonpetroleum liquids. Both ethanol blending into gasoline and E85 consumption are essentially flat from 2011 through 2040, as a result of declining gasoline consumption and limited penetration of FFVs.

Industrial from Legislation and Regulations

4. Maximum Achievable Control Technology for industrial boilers

Section 112 of the CAA requires the regulation of air toxics through implementation of NESHAP for industrial, commercial, and institutional boilers [31]. The final regulations are also known as "Boiler MACT," where MACT is the Maximum Achievable Control Technology. Pollutants covered by the Boiler MACT regulations include control of hazardous air pollutants (HAPs), such as hydrogen chloride, mercury (Hg), and dioxin/furan, as well as carbon monoxide (CO), and particulate matter (PM) as surrogates for other HAPs. Boilers used for generating electricity are explicitly covered by the Mercury and Air Toxics Standards, also under Section 112 of the CAA, and are specifically excluded from Boiler MACT regulations.

The Final Rule for Boiler MACT was issued in March 2011; a partial Reconsideration Rule concerning limited technical corrections to the Final Rule was issued in December 2011, but it did not replace the Final Rule. The AEO2013 Reference case assumes that the Final Rule and the partial Reconsideration Rules are in force. The finalized Boiler MACT rule was announced in December 2012, after the modeling work for AEO2013 was completed. The provisions of the finalized Boiler MACT rule are less stringent than the provisions of the Final Rule and the partial Reconsideration Rule assumed in the Reference case. For AEO2013, the upgrade costs of Boiler MACT were implemented in the Macroeconomic Activity Module (MAM). Upgrade costs used are the "nonproductive costs," which are not associated with efficiency improvements. The upgrade costs are applied as an aggregated cost across all industries. Because of this aggregation of cost and the need for consistency across industries, the cost in the MAM is manifested as a reduction in shipments in the Industrial Demand Module. There is little difference in the cost of compliance for major sources between the March 2011 Final Rule and the December 2011 Reconsideration Rule, and there is no difference for area sources.

Boiler MACT has two compliance groups with different obligations: major source [32], and area source. A site that contains one or more boilers or process heaters that have the potential to emit 10 or more tons of any one HAP per year, or 25 tons or more of a combination of HAP per year, is a major source [33]. An emissions site that is not a major source is classified as an area source[34]. The characteristics of the site determine the compliance group of the boiler. Generally, compliance measures include regular maintenance and tuneups for smaller facilities and emission limits and performance tests for larger facilities. In the Reconsideration Rule, EIA calculations based on EPA estimates revealed that there were 14,111 existing major source boilers in 2011 [35]. Of those, calculations based on EPA estimates revealed that 16 percent burn fuels that potentially may subject them to specific emissions limits and annual performance tests. The existing number of affected area source boilers in 2011 was estimated at 189,450 by EIA, using data from EPA [36].

To comply with Boiler MACT, major source boilers and process heaters whose heat input is less than 10 million Btu per hour must receive tuneups every 2 years [37]. Most existing and new major source boilers or process heaters with heat inputs 10 million Btu per hour or greater that burn coal, biomass, liquid, or "other" gas are subject to emission limits on all five of the HAP listed above [38]. Larger major source boilers with heat input of 25 million Btu per hour or greater that burn coal, biomass, or residual oil must use a continuous emission monitoring system for PM [39]. Major source boilers with heat inputs of 10 million Btu per hour or more that burn natural gas or refinery gas, as well as metal process furnaces, are not subject to specific emissions limits or performance tests [40]. Existing major source boilers must comply with the Final Rule by March 21, 2014; new major source boilers must comply by May 20, 2011, or upon startup, whichever is later [41].

Area source natural gas-fired boilers are not subject to Boiler MACT. Area source coal-fired boilers whose heat input is less than 10 million Btu per hour and biomass-fired and liquid fuel-fired boilers of any size must receive a tuneup every 2 years. Existing area source boilers with heat input of 10 million Btu per hour or greater are subject to emissions limits, must receive an initial energy assessment, and must undergo performance tests every 3 years [42]. Existing and new coal-fired boilers must meet Hg and CO limits; new coal-fired boilers must also meet limits for PM. New oil-fired and biomass-fired boilers must meet emissions limits only for PM [43]. Existing area source boilers subject to an energy assessment and emissions limits must comply by March 21, 2014.

6. California Assembly Bill 32: Emissions cap-and-trade as part of the Global Warming Solutions Act of 2006

California's AB 32, the Global Warming Solutions Act of 2006, authorized the California Air Resources Board (CARB) to set California's overall GHG emissions reduction goal to its 1990 level by 2020 and establish a comprehensive, multi-year program to reduce GHG emissions in California, including a cap-and-trade program [48].In addition to the cap-and-trade program, other authorized measures include the LCFS; energy efficiency goals and programs in transportation, buildings, and industry; combined heat and power goals; and RPS [49].

The cap-and-trade program features an enforceable cap on GHG emissions that will decline over time. CARB will distribute tradable allowances equal to the emissions allowed under the cap. Enforceable compliance obligations begin in 2013 for the electric power sector, including electricity imports, and for industrial facilities. Fuel providers must comply starting in 2015. All facilities that emit 25,000 metric tons carbon dioxide equivalent (CO2e) or more are subject to cap-and-trade regulations. The only exception is that, starting in 2015, all importers of electricity from electric facilities outside of California will be subject to cap-and-trade regulations, even from facilities that emit less than 25,000 metric tons CO2e[50].

The most significant GHG covered under the program is CO2, but the cap-and-trade program covers several other GHGs [51], including methane, nitrous oxide, perfluorocarbons, chlorofluorocarbons, nitrogen trifluoride, and sulfur hexafluoride [52]. In 2007, CARB determined that 427 million metric tons carbon dioxide equivalent (MMTCO2e) was the total state-wide GHG emissions level in 1990 and, therefore, would be the 2020 emissions goal. CARB estimates that the implementation of the cap-and-trade program will reduce GHG emissions by between 18 and 27 MMTCO2e in 2020 [53].

The enforceable cap goes into effect in 2013, and there are three multi-year compliance periods:

  • Compliance period 1 (2013-2014) includes sources of GHG emissions responsible for more than one-third of state-wide emissions.
  • Compliance period 2 (2015-2017) covers sources of GHG emissions responsible for about 85 percent of state-wide emissions.
  • Compliance period 3 (2018-2020) covers the same sources as Compliance Period 2 [54].

The electric power and industrial sectors are required to comply with the cap starting in 2013. Providers of natural gas, propane, and transportation fuels are required to comply starting in 2015, when the second compliance period begins. For the first compliance period, covered entities are required to submit allowances for up to 30 percent of their annual emissions in each year; however, at the end of 2014 they are required to account for all the emissions for which they were responsible during the 2-year period. Each covered entity can also use offsets to meet up to 8 percent of its compliance obligation. Offsets used as part of the program must be approved by CARB and can be canceled later by CARB for certain reasons (a provision known as "buyer liability").

A majority (51 percent) of the allowances [55] allocated over the initial 8 years of the program will be distributed through price containment reserves and auctions, which will be held quarterly when the program commences. CARB's first allowance auction was held in November 2012 [56]. Future auctions may be linked to Québec's cap-and-trade program [57]. Twenty-five percent of the allowances are allocated directly to electric utilities that sell electricity to consumers in the state. Seventeen percent of the allowances are allocated directly to affected industrial facilities in order to mitigate the economic impact of the cap on the industrial sector [58]. Allowance allocations for the industrial sector are based on output. Starting in 2013, the number of allowances allocated annually to the industrial sector declines linearly to 50 percent of the original total in 2020. The remaining 7 percent of the allowances issued in a given year go into a price containment reserve, to be used only if allowance prices rise above a set amount in quarterly auctions.

The AB 32 cap-and-trade provisions, which were incorporated only for the electric power sector in AEO2012, are more fully implemented in AEO2013, adding industrial facilities, refineries, fuel providers, and non-CO2 GHG emissions. The allowance price, representing the incremental cost of complying with AB 32 cap-and-trade, is modeled in the NEMS Electricity Market Module via a region-specific emissions constraint. This allowance price, when added to the market fuel prices, results in higher effective fuel prices [59] in the demand sectors. Limited banking and borrowing, as well as a price containment reserve [60] and offsets, also have been modeled, providing some compliance flexibility and cost containment. NEMS macroeconomic effects are based on an energy-economy equilibrium that reacts to changes in energy prices and energy consumption; however, no macroeconomic effects are assumed explicitly from the AB 32 cap-and-trade provisions.

Industrial from Issues in Focus

1. No sunset and extended policies cases

Background

The AEO2013 Reference case is best described as a current laws and regulations case because it generally assumes that existing laws and regulations remain unchanged throughout the projection period, unless the legislation establishing them sets a sunset date or specifies how they will change. The Reference case often serves as a starting point for analysis of proposed changes in legislation or regulations. While the definition of the Reference case is relatively straightforward, there may be considerable interest in a variety of alternative cases that reflect updates or extensions of current laws and regulations. Areas of particular interest include:

  • Laws or regulations that have a history of being extended beyond their legislated sunset dates. Examples include the various tax credits for renewable fuels and technologies, which have been extended with or without modifications several times since their initial implementation.
  • Laws or regulations that call for periodic updating of initial specifications. Examples include appliance efficiency standards issued by the U.S. Department of Energy (DOE) and CAFE and greenhouse gas (GHG) emissions standards for vehicles issued by the National Highway Traffic Safety Administration (NHTSA) and the U.S. Environmental Protection Agency (EPA).
  • Laws or regulations that allow or require the appropriate regulatory agency to issue new or revised regulations under certain conditions. Examples include the numerous provisions of the Clean Air Act that require EPA to issue or revise regulations if it finds that an environmental quality target is not being met.

Two alternative cases are discussed in this section to provide some insight into the sensitivity of results to scenarios in which existing tax credits or other policies do not sunset. No attempt is made to cover the full range of possible uncertainties in these areas, and readers should not view the cases discussed as EIA projections of how laws or regulations might or should be changed. The cases examined here look only at federal laws or regulations and do not examine state laws or regulations.

Analysis cases

The two cases prepared—the No Sunset case and the Extended Policies case—incorporate all the assumptions from the AEO2013 Reference case, except as identified below. Changes from the Reference case assumptions include the following.

No Sunset case

Tax credits for renewable energy sources in the utility, industrial, and buildings sectors, or for energy-efficient equipment in the buildings sector, are assumed to be extended, including the following:

  • The PTC of 2.2 cents per kilowatthour and the 30-percent investment tax credit (ITC) available for wind, geothermal, biomass, hydroelectric, and landfill gas resources, assumed in the Reference case to expire at the end of 2012 for wind and 2013 for the other eligible resources, are extended indefinitely. On January 1, 2013, Congress passed a one-year extension of the PTC for wind and modified the qualification rules for all eligible technologies; these changes are not included in the AEO2013 Reference case, which was completed in December 2012, but they are discussed in "Effects of energy provisions in the American Taxpayer Relief Act of 2012".
  • For solar power investments, a 30-percent ITC that is scheduled to revert to a 10-percent credit in 2016 is, instead, assumed to be extended indefinitely at 30 percent.
  • In the buildings sector, personal tax credits for the purchase of renewable equipment, including photovoltaics (PV), are assumed to be extended indefinitely, as opposed to ending in 2016 as prescribed by current law. The business ITCs for commercial-sector generation technologies and geothermal heat pumps are assumed to be extended indefinitely, as opposed to expiring in 2016; and the business ITC for solar systems is assumed to remain at 30 percent instead of reverting to 10 percent. On January 1, 2013, legislation was enacted to reinstate tax credits for energy-efficient homes and selected residential appliances. The tax credits that had expired on December 31, 2011, are now extended through December 31, 2013. This change is not included in the Reference case.
  • In the industrial sector, the 10-percent ITC for combined heat and power (CHP) that ends in 2016 in the AEO2013 Reference case [65] is assumed to be preserved through 2040, the end of the projection period.

Extended Policies case

The Extended Policies case includes additional updates to federal equipment efficiency standards that were not considered in the Reference case or No Sunset case. Residential and commercial end-use technologies eligible for incentives in the No Sunset case are not subject to new standards. Other than those exceptions, the Extended Policies case adopts the same assumptions as the No Sunset case, plus the following:

  • Federal equipment efficiency standards are assumed to be updated at periodic intervals, consistent with the provisions in existing law, at levels based on ENERGY STAR specifications or on the Federal Energy Management Program purchasing guidelines for federal agencies, as applicable. Standards are also introduced for products that currently are not subject to federal efficiency standards.
  • Updated federal energy codes for residential and commercial buildings increase by 30 percent in 2020 compared to the 2006 International Energy Conservation Code in the residential sector and the American Society of Heating, Refrigerating and Air-Conditioning Engineers Building Energy Code 90.1-2004 in the commercial sector. Two subsequent rounds in 2023 and 2026 each add an assumed 5-percent incremental improvement to building energy codes. The equipment standards and building codes assumed for the Extended Policies case are meant to illustrate the potential effects of those policies on energy consumption for buildings. No cost-benefit analysis or evaluation of impacts on consumer welfare was completed in developing the assumptions. Likewise, no technical feasibility analysis was conducted, although standards were not allowed to exceed the "maximum technologically feasible" levels described in DOE's technical support documents.
  • The AEO2013 Reference, No Sunset, and Extended Policies cases include both the attribute-based CAFE standards for light-duty vehicles (LDVs) in model year (MY) 2011 and the joint attribute-based CAFE and vehicle GHG emissions standards for MY 2012 to MY 2025. The Reference and No Sunset cases assume that the CAFE standards are then held constant at MY 2025 levels in subsequent model years, although the fuel economy of new LDVs continues to rise modestly over time. The Extended Policies case modifies the assumption in the Reference and No Sunset cases, assuming continued increases in CAFE standards after MY 2025. CAFE standards for new LDVs are assumed to increase by an annual average rate of 1.4 percent.
  • In the industrial sector, the ITC for CHP is extended to cover all properties with CHP, no matter what the system size (instead of being limited to properties with systems smaller than 50 megawatts as in the Reference case [66]), which may include multiple units. Also, the ITC is modified to increase the eligible CHP unit cap to 25 megawatts from 15 megawatts. These extensions are consistent with previously proposed legislation.

Analysis results

The changes made to the Reference case assumptions in the No Sunset and Extended Policies cases generally lead to lower estimates for overall energy consumption, increased use of renewable fuels particularly for electricity generation and reduced energy-related carbon dioxide (CO2) emissions. Because the Extended Policies case includes most of the assumptions in the No Sunset case but adds others, the effects of the Extended Policies case tend to be greater than those in the No Sunset case—but not in all cases, as discussed below. Although these cases show lower energy prices, because the tax credits and end-use efficiency standards lead to lower energy demand and reduce the costs of renewable technologies, appliance purchase costs are also affected. In addition, the government receives lower tax revenues as consumers and businesses take advantage of the tax credits.

Energy consumption


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Total energy consumption in the No Sunset case is close to the level in the Reference case (Figure 13). Improvements in energy efficiency lead to reduced consumption in this case, but somewhat lower energy prices lead to relatively higher levels of consumption, partially offsetting the impact of improved efficiency. In 2040, total energy consumption in the Extended Policies case is 3.8 percent below the Reference case projection.

Buildings energy consumption

Renewable distributed generation (DG) technologies (PV systems and small wind turbines) provide much of the buildings-related energy savings in the No Sunset case. Extended tax credits in the No Sunset case spur increased adoption of renewable DG, leading to 61 billion kilowatthours of onsite electricity generation from DG systems in 2025, compared with 28 billion kilowatthours in the Reference case. Continued availability of the tax credits results in 137 billion kilowatthours of onsite electricity generation in 2040 in the No Sunset case—more than three times the amount of onsite electricity generated in 2040 in the Reference case. Similar adoption of renewable DG occurs in the Extended Policies case. With the additional efficiency gains from assumed future standards and more stringent building codes, delivered energy consumption for buildings is 3.9 percent (0.8 quadrillion British thermal units [Btu]) lower in 2025 and 8.0 percent (1.7 quadrillion Btu) lower in 2040 in the Extended Policies case than in the Reference case. The reduction in 2040 is more than seven times as large as the 1.1-percent (0.2 quadrillion Btu) reduction in the No Sunset case.

Electricity use shows the largest reduction in the two alternative cases compared to the Reference case. Building electricity consumption is 1.3 percent and 5.8 percent lower, respectively, in the No Sunset and Extended Policies cases in 2025 and 2.1 percent and 8.7 percent lower, respectively, in 2040 than in the Reference case, as onsite generation continues to increase and updated standards affect a greater share of the equipment stock in the Extended Policies case. Space heating and cooling are affected by the assumed standards and building codes, leading to significant savings in energy consumption for heating and cooling in the Extended Policies case. In 2040, delivered energy use for space heating in buildings is 9.6 percent lower, and energy use for space cooling is 20.3 percent lower, in the Extended Policies case than in the Reference case. In addition to improved standards and codes, extended tax credits for PV prompt increased adoption, offsetting some of the costs for purchased electricity for cooling. New standards for televisions and for personal computers and related equipment in the Extended Policies case lead to savings of 28.3 percent and 31.8 percent, respectively, in residential electricity use for this equipment in 2040 relative to the Reference case. Residential and commercial natural gas use declines from 8.1 quadrillion Btu in 2011 to 7.8 quadrillion Btu in 2025 and 7.2 quadrillion Btu in 2040 in the Extended Policies case, representing a 2.2-percent reduction in 2025 and a 8.5-percent reduction in 2040 relative to the Reference case.

Industrial energy consumption

The No Sunset case modifies the Reference case assumptions by extending the existing ITC for industrial CHP through 2040. The Extended Policies case starts from the No Sunset case and expands the credit to include industrial CHP systems of all sizes and raises the maximum credit that can be claimed from 15 megawatts of installed capacity to 25 megawatts. The changes result in 1.6 gigawatts of additional industrial CHP capacity in the No Sunset case compared with the Reference case in 2025 and 3.5 gigawatts of additional capacity in 2040. From 2025 through 2040, more CHP capacity is installed in the No Sunset case than in the Extended Policy case. CHP capacity is 0.3 gigawatts higher in the No Sunset Case than in the Extended Policies Case in 2025 and 1.2 gigawatts higher in 2040. Although the Extended Policies case includes a higher tax benefit for CHP than the No Sunset case, which by itself provides greater incentive to build CHP capacity, electricity prices are lower in the Extended Policies case than in the No Sunset case starting around 2020, and the difference increases over time. Lower electricity prices, all else equal, reduce the economic attractiveness of CHP. Also, the median size of industrial CHP units size is 10 megawatts [67], and many CHP systems are well within the 50-megawatt total system size, which means that relaxing the size constraint is not as strong an incentive for investment as is allowing the current tax credit for new CHP investments to continue after 2016.

Natural gas consumption averages 9.7 quadrillion Btu per year in the industrial sector from 2011 to 2040 in the No Sunset case—about 0.1 quadrillion Btu, or 0.9 percent, above the level in the Reference case. Over the course of the projection, the difference in natural gas consumption between the No Sunset case and the Reference case is small but increases steadily. In 2025, natural gas consumption in the No Sunset case is approximately 0.1 quadrillion Btu higher than in the Reference Case, and in 2040 it is 0.2 quadrillion Btu higher. Natural gas consumption in the Extended Policies case is virtually the same as in the No Sunset case through 2030. After 2030, refinery use of natural gas stabilizes in the Extended Policies case as continued increases in CAFE standards reduce demand for petroleum products.

Transportation energy consumption

The Extended Policies case differs from the Reference and No Sunset cases in assuming that the CAFE standards recently finalized by EPA and NHTSA for MY 2017 through 2025 (which call for a 4.1-percent annual average increase in fuel economy for new LDVs) are extended through 2040 with an assumed average annual increase of 1.4 percent. Sales of vehicles that do not rely solely on a gasoline internal combustion engines for both motive and accessory power (including those that use diesel, alternative fuels, or hybrid electric systems) play a substantial role in meeting the higher fuel economy standards after 2025, growing to almost 72 percent of new LDV sales in 2040, compared with about 49 percent in the Reference case.


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LDV energy consumption declines in the Reference case from 16.1 quadrillion Btu (8.7 million barrels per day) in 2011 to 14.0 quadrillion Btu (7.7 million barrels per day) in 2025 as a result of the increase in CAFE standards. Extension of the increases in CAFE standards in the Extended Policies case further reduces LDV energy consumption to 11.9 quadrillion Btu (6.5 million barrels per day) in 2040, or about 8 percent lower than in the Reference case. Petroleum and other liquid fuels consumption in the transportation sector is virtually identical through 2025 in the Reference and Extended Policies cases but declines in the Extended Policies case from 13.3 million barrels per day in 2025 to 12.3 million barrels per day in 2040, as compared with 13.0 million barrels per day in 2040 in the Reference case (Figure 14).

Renewable electricity generation

The extension of tax credits for renewables through 2040 would, over the long run, lead to more rapid growth in renewable generation than in the Reference case. When the renewable tax credits are extended without extending energy efficiency standards, as assumed in the No Sunset case, there is a significant increase in renewable generation in 2040 compared to the Reference case (Figure 15). Extending both renewable tax credits and energy efficiency standards in the Extended Policies case results in more modest growth in renewable generation, because renewable generation is a significant source of new generation to meet load growth, and enhanced energy efficiency standards tend to reduce overall electricity consumption and the need for new generation resources.


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The AEO2013 Reference case does not reflect the provisions of the American Taxpayer Relief Act of 2012 (P.L. 112-240) passed on January 1, 2013 [68], which extends the PTCs for renewable generation beyond what is included in the AEO2013 Reference case. While this legislation was completed too late for inclusion in the Reference case, EIA did complete an alternative case that examined key energy-related provisions of that legislation, the most important of which is the extension of the PTC for renewable generation. A brief summary of those results is presented in the box, "Effects of energy provisions in the American Taxpayer Relief Act of 2012."

Effects of energy provisions in the American Taxpayer Relief Act of 2012

On January 1, 2013, Congress passed the American Taxpayer Relief Act of 2012 (ATRA). The law, among other things, extended several provisions for tax credits to the energy sector. Although the law was passed too late to be incorporated in the Annual Energy Outlook 2013 (AEO2013) Reference case, a special case was prepared to analyze some of its key provisions, including the extension of tax credits for utility-scale renewables, residential energy efficiency improvements, and biofuels [69]. The analysis found that the most significant impact on energy markets came from extending the production tax credits (PTCs) for utility-scale wind, and from changing the PTC qualification criteria from being in service on December 31, 2013, to being under construction by December 31, 2013, for all eligible utility-scale technologies. Although there is some uncertainty about what criteria will be used to define "under construction," this analysis assumes that the effective length of the extension is equal to the typical project development time for a qualifying project. For wind, the effective extension is 3 years.

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Compared with the AEO2013 Reference case, ATRA increases renewable generation, primarily from wind (Figure 16). Renewable generation in 2040 is about 2 percent higher in the ATRA case than in the Reference case, with the greatest growth occurring in the near term. In 2016, renewable generation in the ATRA case exceeds that in the Reference case by nearly 9 percent. Almost all the increase comes from wind generation, which in 2016 is about 34 percent higher in the ATRA case than in the Reference case. In 2040, however, wind generation is only 17 percent higher than projected in the Reference case. These results indicate that, while the short-term extension does result in additional wind generation capacity, some builds that otherwise would occur later in the projection period are moved up in time to take advantage of the extended tax credit. The increase in wind generation partially displaces other forms of generation in the Reference case, both renewable and nonrenewable—particularly solar, biomass, coal, and natural gas.

ATRA does not have significant effects on electricity or delivered natural gas prices and generally does not result in a difference of more than 1 percent either above or below Reference case prices. In the longer term (beyond 2020), electricity and natural gas prices generally both are slightly lower in the ATRA case, as increased wind capacity reduces variable fuel costs in the power sector and reduces the demand for natural gas.

Other ATRA provisions analyzed had minimal impact on all energy measures, primarily limited to short-term reductions in renewable fuel prices and a one-year window for residential customers to get tax credits for certain efficiency expenditures. Provisions of the act not addressed in this analysis are likely to have only modest impacts because of their limited scale, scope, and timing.

In the No Sunset and Extended Policies cases, renewable generation more than doubles from 2011 to 2040, as compared with a 64-percent increase in the Reference case. In 2040, the share of total electricity generation accounted for by renewables is between 22 and 23 percent in both the No Sunset and Extended Policies cases, as compared with 16 percent in the Reference case.

Construction of wind-generation units slows considerably in the Reference case from recent construction rates, following the assumed expiration of the tax credit for wind power in 2012. The combination of slow growth in electricity demand, little impact from state-level renewable generation requirements, and low prices for competing fuels like natural gas keeps growth relatively low until around 2025, when load growth finally catches up with installed capacity, and natural gas prices increase to a level at which wind is a cost-competitive option in some regions. Extending the PTC for wind spurs a brief surge in near-term development by 2014, but the factors that limit development through 2025 in the Reference case still largely apply, and growth from 2015 to about 2025 is slow, in spite of the availability of tax credits during the 10-year period. When the market picks up again after 2025, availability of the tax credits spurs additional wind development over Reference case levels. Wind generation in the No Sunset case is about 27 percent higher than in the Reference case in 2025 and 86 percent higher in 2040.

In the near term, the continuation of tax credits for solar generation results in a continuation of recent growth trends for this resource. The solar tax credits are assumed to expire in 2016 in the Reference case, after which the growth of solar generation slows significantly. Eventually, economic conditions become favorable for utility-scale solar without the federal tax credits, and the growth rate picks up substantially after 2025. With the extension of the ITC, growth continues throughout the projection period. Solar generation in the No Sunset case in 2040 is more than 30 times the 2011 level and more than twice the level in 2040 in the Reference case.

The impacts of the tax credit extensions on geothermal and biomass generation are mixed. Although the tax credits do apply to both geothermal and biomass resources, the structure of the tax credits, along with other market dynamics, makes wind and solar projects relatively more attractive. Over most of the projection period, geothermal and biomass generation are lower with the tax credits available than in the Reference case. In 2040, generation from both resources in the No Sunset and Extended Policies cases is less than 10 percent below the Reference case levels. However, generation growth lags significantly through 2020 with the tax credit extensions, and generation in 2020 from both resources is about 20 percent lower in the No Sunset and Extended Policy cases than in the Reference case.

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After 2025, renewable generation in the No Sunset and Extended Policies cases starts to increase more rapidly than in the Reference case. As a result, generation from nuclear and fossil fuels is below Reference case levels. Natural gas represents the largest source of displaced generation. In 2040, electricity generation from natural gas is 13 percent lower in the No Sunset case and 16 percent lower in the Extended Policies case than in the Reference case (Figure 17).

Energy-related CO2 emissions

In the No Sunset and Extended Policies cases, lower overall fossil energy use leads to lower levels of energy-related CO2 emissions than in the Reference case. In the Extended Policies case, the emissions reduction is larger than in the No Sunset case. From 2011 to 2040, energy-related CO2 emissions are reduced by a cumulative total of 4.6 billion metric tons (a 2.8-percent reduction over the period) in the Extended Policies case relative to the Reference case projection, as compared with 1.7 billion metric tons (a 1.0-percent reduction over the period) in the No Sunset case (Figure 18). The increase in fuel economy standards assumed for new LDVs in the Extended Policies case is responsible for 11.4 percent of the total cumulative reduction in CO2 emissions from 2011 to 2040 in comparison with the Reference case. The balance of the reduction in CO2 emissions is a result of greater improvement in appliance efficiencies and increased penetration of renewable electricity generation.

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Most of the emissions reductions in the No Sunset case result from increases in renewable electricity generation. Consistent with current EIA conventions and EPA practice, emissions associated with the combustion of biomass for electricity generation are not counted, because they are assumed to be balanced by carbon absorption when the plant feedstock is grown. Relatively small incremental reductions in emissions are attributable to renewables in the Extended Policies case, mainly because electricity demand is lower than in the Reference case, reducing the consumption of all fuels used for generation, including biomass.

In both the No Sunset and Extended Policies cases, water heating, space cooling, and space heating together account for most of the emissions reductions from Reference case levels in the buildings sector. In the industrial sector, the Extended Policies case projects reduced emissions as a result of decreases in electricity purchases and petroleum use.

Energy prices and tax credit payments

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With lower levels of fossil energy use and more consumption of renewable fuels stimulated by tax credits in the No Sunset and Extended Policies cases, energy prices are lower than in the Reference case. In 2040, average delivered natural gas prices (2011 dollars) are $0.29 per million Btu (2.7 percent) and $0.59 per million Btu (5.4 percent) lower in the No Sunset and Extended Policies cases, respectively, than in the Reference case (Figure 19), and electricity prices are 3.9 percent and 6.3 percent lower than in the Reference case (Figure 20).


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The reductions in energy consumption and CO2 emissions in the Extended Policies case are accompanied by higher equipment costs for consumers and revenue reductions for the U.S. government. From 2013 to 2040, residential and commercial consumers spend, on average, an additional $20 billion per year (2011 dollars) for newly purchased end-use equipment, DG systems, and residential building shell improvements in the Extended Policies case as compared with the Reference case. On the other hand, residential and commercial customers save an average of $30 billion per year on energy purchases.

Tax credits paid to consumers in the buildings sector (or, from the government's perspective, reduced revenue) in the No Sunset case average $4 billion (2011 dollars) more per year than in the Reference case, which assumes that existing tax credits expire as currently scheduled, mostly by 2016.

The largest response to federal tax incentives for new renewable generation is seen in the No Sunset case, with extension of the PTC and the 30-percent ITC resulting in annual average reductions in government tax revenues of approximately $2.3 billion from 2011 to 2040, as compared with $650 million per year in the Reference case.

Industrial from Comparison with other projections

4. Electricity

Table 11 compares summary results from the AEO2013 Reference case with projections from EVA, IHSGI, INFORUM, ICF, and the National Renewable Energy Laboratory (NREL). In 2025, total electricity sales range from a low of 4,095 billion kilowatthours (INFORUM) to a high of 4,712 billion kilowatthours (IHSGI) [145]. The AEO2013 Reference case projects 4,140 billion kilowatthours of total electricity sales in 2025, EVA projects 4,311 billion kilowatthours in 2025, and NREL projects 4,487 billion kilowatthours in 2026. In comparison with the other projections, IHSGI shows higher sales across all sectors in 2025, with the exception of the commercial sector (1,709 billion kilowatthours), where the EVA projection of 1,824 billion kilowatthours is 115 billion kilowatthours higher. The higher total in the commercial sector counterbalances EVA's lower projection of 736 billion kilowatthours for the industrial sector, compared with 1,186 billion kilowatthours in the AEO2013 Reference case, 1,246 billion kilowatthours in the IHSGI projection, and 1,033 billion kilowatthours in the INFORUM projection.

Total electricity sales in 2035 in the IHSGI projection (5,316 billion kilowatthours) are higher than in the others: 4,406 billion kilowatthours in the INFORUM projection, 4,421 billion kilowatthours in the AEO2013 Reference case, 4,824 billion kilowatthours (in 2036) in the NREL projection, and 4,923 billion kilowatthours in the EVA projection. EVA projects the highest level of electricity sales in both the residential and commercial sectors in 2035 but a lower level of industrial sales in comparison with the other projections. Electricity sales in the industrial sector in the IHSGI projection are 1,332 billion kilowatthours in 2035, as compared with 1,142 billion kilowatthours in the AEO2013 Reference case, 978 billion kilowatthours in the INFORUM projection, and only 515 billion kilowatthours in the EVA projection. Total electricity sales in 2040 are again led by the IHSGI projection, with 5,602 billion kilowatthours, followed by 5,238 billion kilowatthours in the EVA projection, 4,608 billion kilowatthours in the AEO2013 Reference case, and 4,940 billion kilowatthours in the NREL projection.

IHSGI, INFORUM, and the AEO2013 Reference case provide projections for average electricity prices by sector for 2025 and 2035. NREL provides a U.S. average electricity price projection for 2026 and 2036, but not by sector. IHSGI, NREL, and the AEO2013 Reference case provide projections for average electricity prices in 2040. Average electricity prices in the AEO2013 Reference case are 9.5 cents per kilowatthour in 2025, 10.1 cents per kilowatthour in 2035, and 10.8 cents per kilowatthour in 2040. Average electricity prices in the INFORUM projection are 10.0 cents per kilowatthour in 2025 and 10.5 cents per kilowatthour in 2035 [146]. IHSGI projects considerably higher average electricity prices than either the AEO2013 Reference case or INFORUM, at 11.2 cents per kilowatthour in 2025, 11.9 cents per kilowatthour in 2035, and 12.2 cents per kilowatthour in 2040. NREL projects overall average electricity prices of 10.4 cents per kilowatthour in 2026, 11.7 cents per kilowatthour in 2036, and 12.0 cents per kilowatthour in 2040 (the NREL prices were provided in 2009 dollars).

In all the projections, average electricity prices by sector follow patterns similar to changes in the weighted average electricity price across all sectors (including transportation services). The lowest prices by sector in 2025 are in the AEO2013 Reference case (11.6 cents per kilowatthour for the residential sector, 9.7 cents per kilowatthour for the commercial sector, and 6.5 cents per kilowatthour for the industrial sector). The highest average electricity prices by sector in 2025 are in the IHSGI projection (13.3 cents per kilowatthour for the residential sector, 11.6 cents per kilowatthour for the commercial sector, and 7.6 cents per kilowatthour for the industrial sector). The AEO2013 Reference case, IHSGI, and NREL reflect similar price patterns for 2035 (or 2036 for NREL) and 2040.

Total U.S. electricity generation plus imports in 2025 range from a low of 4,296 billion kilowatthours in the INFORUM projection to a high of 5,207 billion kilowatthours in the IHSGI projection. Within that range, the AEO2013 Reference case projects total generation of 4,612 billion kilowatthours. Coal continues to represent the largest share of generation in 2025 in the AEO2013 Reference case, which reports 1,727 billion kilowatthours from coal versus 1,252 billion kilowatthours from natural gas. By comparison, the natural gas share of total generation in the IHSGI projection in 2025 surpasses generation from coal by 126 billion kilowatthours, with 1,732 billion kilowatthours of generation from natural gas and 1,605 billion kilowatthours from coal. IHSGI projects 1,646 billion kilowatthours of electricity generation from both coal and natural gas in 2023, with the natural gas total exceeding that for coal in 2024 and beyond as a result of the assumed implementation of a carbon tax in the IHSGI projection. Conversely, coal continues to represent the largest share of generation in the AEO2013 Reference case in 2035—1,807 billion kilowatthours as compared with 1,519 billion kilowatthours from natural gas. The AEO2013 Reference case is based on current regulations and policies and does not assume a carbon tax. In 2035, the natural gas share of total generation in the IHSGI projection exceeds generation from coal by 808 billion kilowatthours. In the AEO2013 Reference case, coal continues to represent the largest share of generation in 2040 at 1,829 billion kilowatthours, compared with 1,582 billion kilowatthours from natural gas. In comparison, the natural gas share of total generation in 2040 in the IHSGI projection widens its lead over coal by 1,088 billion kilowatthours. In the EVA projection, coal is outpaced by natural gas as a share of total generation in 2040, with 2,330 billion kilowatthours from natural gas and 1,740 billion kilowatthours from coal [147].

Projections for electricity generation from U.S. nuclear power plants in 2025 range from a low of 794 billion kilowatthours (NREL, in 2026) to a high of 923 billion kilowatthours in the IHSGI projection. NREL projects a steady decline in nuclear generation, from 794 billion kilowatthours in 2025 to 510 billion kilowatthours in 2036 and 442 billion kilowatthours in 2040, due to significant plant retirements. For 2035, the AEO2013 Reference case projects a drop in nuclear generation from the 2025 level, to 875 billion kilowatthours, as a result of capacity retirements. In contrast, nuclear generation increases to 953 billion kilowatthours in 2035 in the IHSGI projection. The AEO2013 Reference case shows nuclear generation rebounding to 903 billion kilowatthours in 2040, as compared with 991 billion kilowatthours in the IHSGI projection.

Total generating capacity by fuel in 2025 (including combined heat and power [CHP]) is fairly similar across the projections, ranging from a low of 1,098 gigawatts in the AEO2013 Reference case to a high of 1,237 gigawatts in the IHSGI projection. IHSGI projects slightly more growth in total generating capacity due to what appears to be a much higher demand projection. Natural gas- and oil-fired capacity combined is projected to total 555 gigawatts in 2025 in the IHSGI projection, compared with 500 gigawatts in the AEO2013 Reference case and a maximum of 568 gigawatts in the EVA projection. In all the projections, the hydroelectric/other category includes generation from both hydroelectric and nonhydroelectric renewable resources. In all the projections, hydroelectric capacity remains essentially unchanged, with almost all growth attributable to nonhydroelectric renewable resources. Hydroelectric/other capacity is the highest in 2025 in the IHSGI outlook at 289 gigawatts, compared with 257 gigawatts in the NREL projection (for 2026), 234 gigawatts in the ICF projection, 210 gigawatts in the EVA projection, and 208 gigawatts in the AEO2013 Reference case.

Both the IHSGI and NREL projections reflect lower levels of coal-fired generating capacity in 2040, with 251 gigawatts projected by IHSGI and 224 gigawatts by NREL. In comparison, natural gas- and oil-fired capacity (again dominated by natural gas-fired generating capacity) and hydroelectric/other capacity (dominated by nonhydroeletric renewable capacity) are projected to increase from 2025 levels. IHSGI projects 722 gigawatts of natural gas- and oil-fired capacity and 396 gigawatts of hydroelectric/other capacity in 2040. NREL projects 691 gigawatts of natural gas- and oil-fired capacity and 322 gigawatts of hydroelectric/other capacity in 2040. The AEO2013 Reference case projects 632 gigawatts of natural gas- and oil-fired capacity and 270 gigawatts of hydroelectric/other capacity in 2040.

Cumulative capacity retirements from 2011 through 2025 range from 151 gigawatts in the EVA projection to 82 gigawatts in the AEO2013 Reference case. The majority of the retirements in the IHSGI, ICF, and AEO2013 Reference case projections from 2011 to 2025 are attributed to coal-fired capacity. In the EVA and ICF outlooks, 73 gigawatts of coal-fired capacity is retired from 2011 to 2025. Over the same period, 46 gigawatts of coal-fired capacity is retired in the IHSGI outlook and 49 gigawatts in the AEO2013 Reference case. The NREL projection assumes 33 gigawatts of coal-fired capacity retirements from 2011 to 2026. EVA projects 73 gigawatts of oil- and natural gas-fired capacity retirements between 2011 and 2025, as compared with the ICF, AEO2013 Reference case, and IHSGI projections, which range between 29 gigawatts and 36 gigawatts over the same period. NREL projects 69 gigawatts of oil- and natural gas-fired retirements through 2026. With the exception of EVA and ICF, all the capacity retirements greater than 1 gigawatt between 2011 and 2025 in the outlooks are attributed to coal, oil, and natural gas capacity. EVA and ICF both project 3 gigawatts of nuclear retirements by 2025, while EVA projects 2 gigawatts of hydroelectric/other capacity retirements for the same period.

Cumulative capacity retirements through 2035 range from a high of 161 gigawatts in the EVA projection to a low of 100 gigawatts in the AEO2013 Reference case. Coal-fired capacity represents a large portion of the cumulative retirements from 2011 to 2035, with ICF projecting 82 gigawatts, EVA 77 gigawatts, IHSGI 68 gigawatts, and the AEO2013 Reference case 49 gigawatts. The AEO2013 Reference case projects no retirements of coal-fired capacity from 2025 to 2035. Over the same period, EVA projects only 4 gigawatts, ICF 9 gigawatts, and IHSGI 22 gigawatts. Cumulative retirements of oil- and natural gas-fired capacity from 2011 to 2035 total 44 gigawatts in the AEO2013 Reference case and 74 gigawatts in the EVA projection. NREL projects cumulative totals of 70 gigawatts and 138 gigawatts of retirements for coal-fired capacity and for oil- and natural gas-fired capacity, respectively, from 2011 to 2036. EVA and the AEO2013 Reference case project cumulative nuclear capacity retirements of 9 gigawatts and 6 gigawatts, respectively, from 2011 to 2035, and IHSGI projects 21 gigawatts of cumulative nuclear retirements over the same period. NREL projects 35 gigawatts of cumulative nuclear retirements from 2011 to 2036.

5. Natural gas

Projections for natural gas consumption, production, imports, and prices differ significantly among the outlooks compared in Table 12. The variations result, in large part, from differences in underlying assumptions. For example, the AEO2013 Reference case assumes that current laws and regulations are unchanged through the projection period, whereas some of the other projections include assumptions about anticipated policy developments over the next 25 years. In particular, the AEO2013 Reference case does not incorporate any future changes in policy directed at carbon emissions or other environmental issues, whereas ExxonMobil and some of the other outlooks include explicit assumptions about policies aimed at reducing carbon emissions.

IHSGI and ICF project large increases in natural gas production and consumption over the projection period. IHSGI projects that, as production increases, prices will remain low and U.S. consumers, particularly in the electric power sector, will continue to benefit from an abundance of relatively inexpensive natural gas. In contrast, ICF projects that prices will rise at a more rapid rate than in the IHSGI projection. EVA projects growth in natural gas production, but at lower rates than IHSGI and ICF. Both EVA and ExxonMobil also project strong growth in natural gas consumption in the electric power sector through 2035. EVA differs from the others, however, by projecting strong growth in natural gas consumption despite a rise in natural gas prices to $8.00 per million Btu in 2035. Timing of the growth in consumption is somewhat different between the ExxonMobil projection and the other outlooks. ExxonMobil expects consumption to increase only through 2025, after which it remains relatively flat. The AEO2013 Reference case projects a smaller increase in natural gas consumption for electric power generation than in the other outlooks, with additional natural gas production allowing for a sharp increase in net exports, particularly as liquefied natural gas (LNG). The INFORUM projection shows a smaller rise in production and consumption of natural gas than in any of the other projections.

Production

All the outlooks shown in Table 12 project increases in natural gas production from the 2011 production level of 23.0 trillion cubic feet. IHSGI projects the largest increase, to 36.1 trillion cubic feet in 2035—13.1 trillion cubic feet or 57 percent more than the 2011 levels—with most of the increase coming in the near term (9.3 trillion cubic feet from 2011 to 2025). An additional 1.5 trillion cubic feet of natural gas production is added from 2035 to 2040. In the ICF projection, natural gas production grows by 12.5 trillion cubic feet over the period from 2011, to 35.5 trillion cubic feet in 2035. More than one-half of the increase (6.5 trillion cubic feet) occurs before 2020. INFORUM projects the smallest increase in natural gas production, at only 4.9 trillion cubic feet from 2011 to the 2035 total of 27.9 trillion cubic feet.

The AEO2013 Reference case and EVA project more modest growth in natural gas production. In the AEO2013 Reference case and EVA projections, natural gas production grows to 31.4 trillion cubic feet in 2035, an increase of 8.4 trillion cubic feet from 2011 levels. The AEO2013 Reference case and EVA projections show slower growth in natural gas production from 2011 to 2025, at 5.6 trillion cubic feet and 6.9 trillion cubic feet, respectively. Although the AEO2013 Reference case shows the least aggressive near-term growth in natural gas production, it shows the strongest growth from 2025 to 2035 among the projections, with another increase of 1.8 trillion cubic feet from 2035 to 2040.

Net imports/exports

Differences among the projections for natural gas production generally coincide with differences in total natural gas consumption or net imports/exports. EVA projects positive growth in net imports throughout the projection period, driven by strong growth in natural gas consumption. Although the EVA projection shows significant growth in pipeline imports, it shows no growth in net LNG exports. In contrast, the IHSGI, ICF, and AEO2013 Reference case projections show net exports of natural gas starting on or before 2020. The AEO2013 Reference case projects the largest increase in net exports of natural gas, with net pipeline exports increasing alongside steady growth in net LNG exports. In the ICF projection, the United States becomes a net exporter of natural gas by 2020 but remains a net importer of pipeline through 2035. Combined net exports of natural gas grow to 0.7 trillion cubic feet in 2035 in the ICF projection, with all the growth accounted for by LNG exports, which increase by 1.5 trillion cubic feet from 2011 to 2035. IHSGI projects a U.S. shift from net importer to net exporter of natural gas after 2017, with net exports declining after 2024.

Consumption

All the projections show total natural gas consumption growing throughout the projection periods, and most of them expect the largest increases in the electric power sector. IHSGI projects the greatest growth in natural gas consumption for electric power generation, driven by relatively low natural gas prices, followed by ExxonMobil and EVA, with somewhat higher projections for natural gas prices. The ICF projection shows less growth in natural gas consumption for electric power generation, despite lower natural gas prices, than in the EVA projection. In the AEO2013 Reference case and INFORUM projections, natural gas consumption for electric power generation is somewhat less than in the other outlooks. Some of that variation may be the result of differences in assumptions about potential fees on carbon emissions. For example, the ExxonMobil outlook assumes a tax on carbon emissions, whereas the AEO2013 Reference case does not.

Projections for natural gas consumption in the residential and commercial sectors are similar in the outlooks, with expected levels of natural gas use remaining relatively stable over time. The AEO2013 Reference case projects the lowest level of residential and commercial natural gas consumption, largely as a result of increases in equipment efficiencies, with projected consumption in those sectors falling by 0.1 trillion cubic feet from 2011 to 2040, to a level slightly below those projected by IHSGI and ICF. ExxonMobil projects a significant one-time decrease of 1.0 trillion cubic feet from 2020 to 2025.

The largest difference among the outlooks for natural gas consumption is in the industrial sector, where definitional differences can make accurate comparisons difficult. ExxonMobil and the AEO2013 Reference case both project increases in natural gas consumption in the industrial sector from 2011 to 2040 that are greater than 1.0 trillion cubic feet, with most of the growth in the AEO2013 Reference case occurring from 2015 to 2020. ICF projects the largest increase in industrial natural gas consumption, at 2.2 trillion cubic feet from 2011 to 2035, followed by EVA's projection of 1.8 trillion cubic feet over the same period. Although ExxonMobil projects a significant one-time decrease in industrial natural gas consumption—1.0 trillion cubic feet from 2025 to 2030—its projected level of industrial consumption in 2025, at 9.0 trillion cubic feet, is higher than in any of the other projections. Despite ExxonMobil's projected decrease in industrial natural gas consumption from 2025 to 2030, its projection for 2030 (8.0 trillion cubic feet) is second only to EVA's projection of 8.4 trillion cubic feet. IHSGI and INFORUM show modest increases in industrial natural gas consumption from their 2011 levels, to 6.9 trillion cubic feet in 2035 in both outlooks. Projected industrial natural gas consumption declines in the IHSGI projection after 2035, to 6.7 trillion cubic feet in 2040.

Prices

Only four of the outlooks included in Table 12 provide projections for Henry Hub natural gas spot prices. EVA shows the highest Henry Hub prices in 2035 and IHSGI the lowest. In the IHSGI projection, Henry Hub prices remain low through 2035, when they reach $4.98 per million Btu, compared with $3.98 per million Btu in 2011. Natural gas prices to the electric power sector rise from $4.87 per thousand cubic feet in 2011 to $5.47 per thousand cubic feet in 2035 in the IHSGI projection. The low Henry Hub prices in the IHSGI projection are supported by an abundant supply of relatively inexpensive natural gas, with only a small increase in net exports in comparison with the increase in the AEO2013 Reference case. EVA, in contrast, shows the Henry Hub price rising to a much higher level of $8.00 per million Btu in 2035, apparently as a result of stronger growth in natural gas consumption, particularly for electric power generation, and a lower level of natural gas exports. Indeed, the EVA outlook shows the U.S. remaining a net importer of natural gas through 2035.

Henry Hub natural gas prices in the ICF and AEO2013 Reference case projections for 2035—at $6.21 per million Btu and $6.32 per million Btu, respectively—fall within the price range bounded by IHSGI and EVA. In the AEO2013 Reference case, commercial, electric power, and industrial natural gas prices all rise by between $2 and $3 per thousand cubic feet from 2011 to 2035, while residential prices rise by $3.88 per thousand cubic feet over the same period. The residential sector is also the only sector for which the AEO2013 Reference case projects a decline in natural gas consumption to below 2011 levels in 2035. ICF projects a much smaller increase in delivered natural gas prices for the commercial, industrial, and electric power sectors, with prices rising to more than $2 per thousand cubic feet above 2011 levels by 2035 only in the electric power sector. With smaller price increases, ICF projects a much larger increase for natural gas consumption in the electric power and industrial sectors from 2011 to 2035 than in the AEO2013 Reference case.

7. Coal

The AEO2013 Reference case projects the highest levels of total coal production and prices in comparison with other coal outlooks available from EVA, ICF, IHSGI, INFORUM, the IEA’s World Energy Outlook, and ExxonMobil. Total consumption in AEO2013 is also higher than in the other outlooks, except for INFORUM and ICF, whose consumption projections for 2035 are 2 percent and 5 percent higher, respectively, than projected in the AEO2013 Reference case (Table 14).

The detailed assumptions that underlie the various projections are not generally available, although there are some important known differences that contribute to the differences among the outlooks. For instance, EVA and ICF assume the implementation of new regulations for cooling water intake and coal combustion residuals; ExxonMobil, which has the lowest projection of coal consumption, assumes a carbon tax; and ICF also includes a carbon cap-and-trade program beginning in 2023. Because those policies are not current law, the AEO2013 Reference case excludes them, which contributes to the lower coal consumption projections in many of the other outlooks relative to AEO2013. Variation among the assumptions about growth in energy demand and other fuel prices, particularly for natural gas, also contribute to the differences.

Although the AEO2013 projections for total coal consumption are actually somewhat lower than the ICF and INFORUM projections, the other outlooks offer more pessimistic projections. ExxonMobil is the most pessimistic, with coal consumption 33 percent and 55 percent lower in 2025 and 2030, respectively, than in the AEO2013 Reference case. Coal consumption in 2025 is 17 percent (174 million tons) less in the EVA outlook than in the AEO2013 Reference case and 8 percent less in the IHSGI outlook. The INFORUM and ICF outlooks for total coal consumption in 2035 are between 21 million tons (2 percent) and 55 million tons (5 percent) higher, respectively, than in the AEO2013 Reference case.

The electricity sector is the predominant consumer of coal and the primary source of differences among the projections, due to their differing assumptions about regulations and the economics of coal versus other fuel choices over time. Although EVA shows a greater reduction in coal use for electricity generation in 2025 than does IHSGI, for 2035 the two projections are similar. After 2035, EVA shows a continued small increase in coal use for electricity generation, whereas it continues to fall in the IHSGI projection and in 2040 is 37 million tons less than projected by EVA. The ICF outlook for coal consumption in electricity generation is similar to the AEO2013 projection through 2025 but then declines gradually through 2035. IEA projects a level of coal use for electricity generation in 2035 that is most similar to the AEO2013 Reference case.

In all the projections, coal consumption in the end-use sectors is low in comparison with the electric power sector; however, there are several notable differences among the outlooks. Most notably, the ICF outlook shows increasing coal use in the other sectors that offsets declining consumption for electric power. ICF is the only projection that shows an increase in coal use in the industrial and buildings sectors. AEO2013 shows the next highest level of coal consumption in the industrial and buildings sectors, but it is still less than half of ICF's projection for industrial and buildings consumption in 2035. Both IHSGI and EVA show significant declines in coal use in those sectors over the projection period. In 2040, coal use in the buildings and industrial sectors in the IHSGI and EVA projections is equal to only 39 percent and 60 percent, respectively, of the coal use in those sectors in AEO2013. In addition, only AEO2013 and ICF project coal use for liquids production. Some of the gains in the two sectors are offset in the ICF outlook by lower consumption of coal at coke plants, which falls from 21 million tons in 2011 to 12 million tons in 2035. In the other outlooks, coal use at coke plants is similar to the levels in the AEO2013 Reference case, with modest declines through the end of their projections.

Differences among the projections for U.S. domestic coal production fall within a smaller range than the projections for coal consumption, depending in part on each outlook's projections for net exports. For example, coal production in the EVA and IHSGI projections is buoyed by relatively high export levels after 2011, with total coal production falling by 13 percent and 5 percent, respectively, from 2011 to 2035, compared with a 16-percent decline in total coal consumption in both projections. The ICF and INFORUM outlooks, which project 11-percent and 8-percent increases in total coal consumption through 2035, respectively, show changes in total coal production of 4 percent and no growth, respectively, as a result of significantly lower net export levels.

The projections for coal exports in the AEO2013 Reference case generally fall between the EVA and IHSGI projections. INFORUM's projection for coal exports is the lowest among the outlooks but similar to ICF's projection for 2035. The composition of EVA's exports also differs from that in AEO2013, in that EVA expects most exports to be thermal coal, whereas most exports in the early years of the AEO2013 Reference case are coking coal. In 2025, coking coal accounts for 57 percent of total coal exports in the AEO2013 Reference case, compared with 34 percent in the EVA projection. In 2040, however, the coking coal share of exports in the AEO2013 projection declines to 44 percent, compared with 32 percent in the EVA projection. In comparison, coking coal accounts for 74 percent of total coal exports in 2035 in the ICF projection.

In the EVA and IHSGI projections, coal imports remain low and relatively flat. AEO2013 also shows low levels of imports initially, but they grow to 36 million tons in 2040 from 5 million tons in 2025. For 2035, the ICF outlook implies 136 million tons of coal imports (calculated by subtracting production from the sum of consumption and exports), which is higher than all the others shown in the comparison table. Coal imports remain above 20 million tons in the INFORUM projections, and as in the ICF and AEO2013 projections, they increase over time, doubling in 2035 from the 2025 level.

Only AEO2013, ICF, and INFORUM provide projections of minemouth coal prices. In the ICF projections, minemouth prices in 2025 are 20 percent below those in 2011 (on a dollar-per-ton basis), and they decline only slightly through 2035. INFORUM projects coal minemouth prices that are very similar to the AEO2013 prices (on a dollar-per-million Btu basis).

The ICF outlook shows the lowest price for coal delivered to the electricity sector in both 2025 and 2035, with the real coal price lower than in 2011. INFORUM's prices for coal delivered to electricity generators (on a dollar-per-ton basis) are similar. IHSGI's delivered coal prices to electricity generators are significantly lower than those in the AEO2013 Reference case and remain close to the 2011 price over the entire projection period. As a result, the IHSGI delivered coal price to electricity generators is 9 percent lower in 2025 and 22 percent lower in 2040, on a dollar-per-ton basis, than projected in the AEO2013 Reference case.

Endnotes

31. Clean Air Act, 42 U.S.C. 7412 (2011), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title42/pdf/USCODE-2011-title42-chap85-subchapI-partA.pdf.
32. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011) pp. 15,608-15,702, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
33. U.S. Environmental Protection Agency, "Definitions," Code of Federal Regulations, 40 CFR §63.2 (July 1, 2012), http://www.gpo.gov/fdsys/pkg/CFR-2012-title40-vol10/pdf/CFR-2012-title40-vol10-part63-subpartA.pdf, p. 16.
34. U.S. Environmental Protection Agency, "Definitions," Code of Federal Regulations, 40 CFR §63.2 (July 1, 2012), http://www.gpo.gov/fdsys/pkg/CFR-2012-title40-vol10/pdf/CFR-2012-title40-vol10-part63-subpartA.pdf, pp. 13-14.
35. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Proposed Rule," Federal Register, Vol. 76, No. 247 (Washington, DC: December 23, 2011), p. 80,622, http://www.gpo.gov/fdsys/pkg/FR-2011-12-23/pdf/2011-31667.pdf.
36. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,579, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
37. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,695, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
38. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), pp. 15,689-15,691, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
39. CU.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,615, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
40. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,696, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
41. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,665, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
42. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,594, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
43. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers, Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), pp. 15,601-15,602, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
48. California Legislative Information, "Assembly Bill No. 32: California Global Warming Solutions Act of 2006" (Sacramento, CA: September 27, 2006), http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=200520060AB32.
49. California Air Resources Board, "AB 32 Scoping Plan Functional Equivalent Document (FED)" (Sacramento, CA: May 16, 2012), http://www.arb.ca.gov/cc/scopingplan/fed.htm.
50. State of California, "Final Regulation Order, Subchapter 10 Climate Change, Article 5, Sections 95800 to 96023, Title 17, Article 5: California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms" (Sacramento, CA: December 22, 2011), pp. 47-49, http://www.arb.ca.gov/regact/2010/capandtrade10/finalrevfro.pdf.
51. State of California, "Final Regulation Order, Subchapter 10 Climate Change, Article 5, Sections 95800 to 96023, Title 17, Article 5: California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms" (Sacramento, CA: December 22, 2011), http://www.arb.ca.gov/regact/2010/capandtrade10/finalrevfro.pdf.
52. California Air Resources Board, "California Greenhouse Gas Emissions Inventory: 2000-2009" (Sacramento, CA: December 2011), p. 10, http://www.arb.ca.gov/cc/inventory/pubs/reports/ghg_inventory_00-09_report.pdf.
53. California Air Resources Board, "Updated Information Digest, Regulation to Implement the California Cap-and-Trade Program" (Sacramento, CA: December 14, 2011), p. 6, http://www.arb.ca.gov/regact/2010/capandtrade10/finuid.pdf.
54. For years 2021-2040 held constant in AEO2013 at 2020 levels.
55. California Air Resources Board, "Appendix J, Allowance Allocation" (Sacramento, CA: October 18, 2010), p. J-12, http://www.arb.ca.gov/regact/2010/capandtrade10/capv4appj.pdf.
56. California Air Resources Board, "California Air Resources Board Quarterly Auction 1" (Sacramento, CA: November 19, 2012), http://www.arb.ca.gov/cc/capandtrade/auction/november_2012/auction1_results_2012q4nov.pdf.
57. California Environmental Protection Agency, "Press Release: California Applauds Québec on Adoption of Amended Cap-and-Trade Program" (Sacramento, CA: December 13, 2012), http://www.calepa.ca.gov/PressRoom/Releases/2012/Quebec.pdf.
58. See Assembly Bill 32, Section 38562(B)(8), http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf. The evaluation of "leakage risk" and the amount allocated to prevent leakage will be revisited by CARB during each of the periodic reviews of the cap-and-trade program, which will occur at least once every three-year compliance cycle.
59. CA price that has been adjusted for allowance costs.
60. State of California, "Final Regulation Order, Subchapter 10 Climate Change, Article 5, Sections 95800 to 96023, Title 17, California Code of Regulations: California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms" (Sacramento, CA: December 22, 2011), http://www.arb.ca.gov/regact/2010/capandtrade10/finalrevfro.pdf. Note: The final regulation states that reserves are held at 1 percent in compliance period 1, 4 percent in compliance period 2, and 7 percent in compliance period 3. For modeling purposes, post-2020 reserves are set to 0 percent.
65. United States Internal Revenue Code, Title 26, Subtitle A—Income Taxes, §48(a)(2)(A)(ii), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title26/pdf/USCODE-2011-title26-subtitleA-chap1-subchapA.pdf.
66. United States Internal Revenue Code, Title 26, Subtitle A—Income Taxes, §48(c)(3)(B)(iii), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title26/pdf/USCODE-2011-title26-subtitleA-chap1-subchapA.pdf.
67. Calculations based on U.S. Energy Information Administration, Form EIA-860, Schedule 3, 2011 data (Washington, DC: January 9, 2013), http://www.eia.gov/electricity/data/eia860/index.html.
68. U.S. Congress, "American Taxpayer Relief Act of 2012," P.L. 112-240, Sections 401 through 412, http://www.gpo.gov/fdsys/pkg/PLAW-112publ240/pdf/PLAW-112publ240.pdf.
69. Modeled provisions based on U.S. Congress, "American Taxpayer Relief Act of 2012," P.L. 112-240, Sections 401, 404, 405, 407, 408, 409, and 412, http://www.gpo.gov/fdsys/pkg/PLAW-112publ240/pdf/PLAW-112publ240.pdf.
136.Next-generation biofuels include pyrolysis oils, biomass-derived Fisher-Tropsch liquids, and renewable feedstocks used for on-site production of diesel and gasoline.
145. EIA summed the sector-level sales from the INFORUM and EVA projections to develop a total electricity sales value for comparison purposes.
146. EIA estimated a weighted-average electricity price for INFORUM based on the sector-level prices and sales.
147. For purposes of comparison, generation from natural gas, turbine, and oil/gas steam capacity from EVA was combined, resulting in a total of 2,330 billion kilowatthours of generation from natural gas for 2040, as shown in Table 25.

Reference Case Tables
Table 2. Energy Consumption by Sector and Source - United States XLS
Table 2.1. Energy Consumption by Sector and Source - New England XLS
Table 2.2. Energy Consumption by Sector and Source - Middle Atlantic XLS
Table 2.3. Energy Consumption by Sector and Source - East North Central XLS
Table 2.4. Energy Consumption by Sector and Source - West North Central XLS
Table 2.5. Energy Consumption by Sector and Source - South Atlantic XLS
Table 2.6. Energy Consumption by Sector and Source - East South Central XLS
Table 2.7. Energy Consumption by Sector and Source - West South Central XLS
Table 2.8. Energy Consumption by Sector and Source - Mountain XLS
Table 2.9. Energy Consumption by Sector and Source - Pacific XLS
Table 6. Industrial Sector Key Indicators and Consumption XLS
Table 17. Renewable Energy Consumption by Sector and Source XLS
Table 18. Energy-Related Carbon Dioxide Emissions by Sector and Source - United States XLS
Table 18.1. Energy-Related Carbon Dioxide Emissions by Sector and Source - New England XLS
Table 18.2. Energy-Related Carbon Dioxide Emissions by Sector and Source - Middle Atlantic XLS
Table 18.3. Energy-Related Carbon Dioxide Emissions by Sector and Source - East North Central XLS
Table 18.4. Energy-Related Carbon Dioxide Emissions by Sector and Source - West North Central XLS
Table 18.5. Energy-Related Carbon Dioxide Emissions by Sector and Source - South Atlantic XLS
Table 18.6. Energy-Related Carbon Dioxide Emissions by Sector and Source - East South Central XLS
Table 18.7. Energy-Related Carbon Dioxide Emissions by Sector and Source - West South Central XLS
Table 18.8. Energy-Related Carbon Dioxide Emissions by Sector and Source - Mountain XLS
Table 18.9. Energy-Related Carbon Dioxide Emissions by Sector and Source - Pacific XLS
Table 19. Energy-Related Carbon Dioxide Emissions by End Use XLS
Table 24. Industrial Sector Macroeconomic Indicators XLS
Table 25. Refining Industry Energy Consumption XLS
Table 26. Food Industry Energy Consumption XLS
Table 27. Paper Industry Energy Consumption XLS
Table 28. Bulk Chemical Industry Energy Consumption XLS
Table 29. Glass Industry Energy Consumption XLS
Table 30. Cement and Lime Industry Energy Consumption XLS
Table 31. Iron and Steel Industries Energy Consumption XLS
Table 32. Aluminum Industry Energy Consumption XLS
Table 33. Metal Based Durables Energy Consumption XLS
Table 34. Other Manufacturing Sector Energy Consumption XLS
Table 35. Nonmanufacturing Sector Energy Consumption XLS
Table 73. Employment and Shipments by Industry, and Income and Employment by Region XLS