‹ Analysis & Projections

Annual Energy Outlook 2014

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

Market Trends — Emissions

Energy-related carbon dioxide emissions remain below their 2005 level through 2040


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On average, energy-related CO2 emissions in the AEO2013 Reference case decline by 0.2 percent per year from 2005 to 2040, as compared with an average increase of 0.9 percent per year from 1980 to 2005. Reasons for the decline include: an expected slow and extended recovery from the recession of 2007-2009; growing use of renewable technologies and fuels; automobile efficiency improvements; slower growth in electricity demand; and more use of natural gas, which is less carbon-intensive than other fossil fuels. In the Reference case, energy-related CO2 emissions in 2020 are 9.1 percent below their 2005 level. Energy-related CO2 emissions total 5,691 million metric tons in 2040, or 308 million metric tons (5.1 percent) below their 2005 level (Figure 108).

Petroleum remains the largest source of U.S. energy-related CO2 emissions in the projection, but its share falls to 38 percent in 2040 from 44 percent in 2005. CO2 emissions from petroleum use, mainly in the transportation sector, are 448 million metric tons below their 2005 level in 2040.

Emissions from coal, the second-largest source of energy-related CO2 emissions, are 246 million metric tons below the 2005 level in 2040 in the Reference case, and their share of total energy-related CO2 emissions declines from 36 percent in 2005 to 34 percent in 2040. The natural gas share of total CO2 emissions increases from 20 percent in 2005 to 28 percent in 2040, as the use of natural gas to fuel electricity generation and industrial applications increases. Emissions levels are sensitive to assumptions about economic growth, fuel prices, technology costs, and policies that are explored in many of the alternative cases completed for AEO2013.

Power plant emissions of sulfur dioxide are reduced by further environmental controls


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In the AEO2013 Reference case, sulfur dioxide (SO2) emissions from the U.S. electric power sector fall from 4.4 million short tons in 2011 to a range between 1.2 and 1.7 million short tons in the 2016-2040 projection period. The reduction occurs in response to the MATS [142]. Although SO2 is not directly regulated by the MATS, the reductions are achieved as a result of acid gas limits that lead to the installation of FGD units or DSI systems, which also remove SO2. AEO2013 assumes that, in order to comply with MATS, coal-fired power plants must have one of the two technologies installed by 2016. Both technologies, which are used to reduce acid gas emissions regulated under MATS, also reduce SO2 emissions.

EIA assumes a 95-percent SO2 removal efficiency for FGD units and a 70-percent SO2 removal efficiency for DSI systems paired with baghouse fabric filters. AEO2013 also assumes that a baghouse fabric filter is required for all coal-fired plants in order to comply with the nonmercury metal emissions limits set forth by MATS [143, 144].

From 2011 to 2040, approximately 43 gigawatts of coal-fired capacity is retrofitted with FGD units in the Reference case, and another 50 gigawatts is retrofitted with DSI systems. In 2016, all operating coal-fired generation units larger than 25 megawatts are assumed to have either DSI or FGD systems installed. After a 73-percent decrease from 2011 to 2016, SO2 emissions increase slowly from 2016 to 2040 (Figure 109) as total electricity generation from coal-fired power plants increases. The increase is relatively small, however, because overall growth in generation from coal is slow, and the required installations of FGD and DSI equipment limit SO2 emissions from plants in operation.

Nitrogen oxides emissions show little change from 2011 to 2040 in the Reference case


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Annual emissions of nitrogen oxides (NOX) from the electric power sector, which totaled 1.9 million short tons in 2011, range between 1.6 and 2.1 million short tons from 2011 to 2040 (Figure 110). Annual NOX emissions from electricity generation dropped by 47 percent from 2005 to 2011 as a result of the implementation of the Clean Air Interstate Rule (CAIR), which led to year-round operation of advanced pollution control equipment (that under the NOX budget program operated during the summer season only) and to additional installations of NOX pollution control equipment.

In the AEO2013 Reference case, annual NOX emissions in 2040 are 4 percent below the 2011 level, despite a 6-percent increase in annual electricity generation from coal-fired power plants over the period. The drop in emissions is primarily a result of CAIR, which established an annual cap-and-trade program for NOX emissions in 25 states and the District of Columbia. A slight rise in NOX emissions after 2020 corresponds to a projected recovery in coal-fired generation.

MATS does not have a direct effect on NOX emissions, because none of the potential technologies required to comply with MATS has a significant impact on NOX emissions. However, because MATS contributes to a reduction in coal-fired generation nationwide, it indirectly reduces NOX emissions from the power sector in states not affected by CAIR.

From 2011 to 2040, 15.4 gigawatts of coal-fired capacity is retrofitted with NOX controls in the AEO2013 Reference case. Coal-fired power plants can be retrofitted with three types of NOX control technologies: selective catalytic reduction (SCR), selective noncatalytic reduction (SNCR), or low-NOX burners, depending on the specific characteristics of the plant, including boiler configuration and the type of coal used. SCRs make up 90 percent of the NOX controls installed in the Reference case, SNCRs 5 percent, and low-NOX burners 5 percent.

Energy-related carbon dioxide emissions are sensitive to potential policy changes


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Although the AEO2013 Reference case assumes that current laws and regulations remain in effect through 2040, the potential impacts of a future fee on CO2 emissions are examined in three carbon-fee cases, starting at $10, $15, and $25 per metric ton CO2 in 2014 and rising by 5 percent per year annually thereafter. The three fee cases were combined with the Reference case and also, because of uncertainty about the growing role of natural gas in the U.S. energy landscape and how it might affect efforts to reduce GHG emissions, with the High Oil and Gas Resource case (Figure 111).

Emissions fees would have a significant impact on U.S. energy-related CO2 emissions. They would encourage all energy producers and consumers to shift to lower-carbon or zero-carbon energy sources. Relative to 2005 emissions levels, energy-related CO2 emissions are 14 percent, 19 percent, and 28 percent lower in 2025 in the $10, $15, and $25 fee cases using Reference case resources, respectively, and 17 percent, 28 percent, and 40 percent lower in 2040. When combined with High Oil and Gas Resource assumptions, the CO2 fees tend to lead to slightly greater emissions reductions in the near term and smaller reductions in the long term.

The alternative assumptions about natural gas resources have only small impacts on energy-related CO2 emissions in all the cases except the $25 fee cases. Although more abundant and less expensive natural gas in the High Oil and Gas Resource cases does lead to less coal use and more natural gas use, it also reduces the use of renewable and nuclear fuels and increases energy consumption overall. In the long run, the emissions reductions achieved by shifting from coal to natural gas are offset by the impacts of reduced use of renewables and nuclear power for electricity generation, and by higher overall levels of energy consumption.

Carbon dioxide fee cases generally increase the use of natural gas for electricity generation


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The role of natural gas in the CO2 fee cases varies widely over time and, in addition, over the range of assumptions about natural gas resources. When CO2 fees are assumed to be introduced in 2014, natural gas-fired generation increases sharply. The role of natural gas in the CO2 fee cases begins declining between 2025 and 2030, however, as power companies bring more new nuclear and renewable plants on line (Figure 112).

After accounting for about 50 percent of all U.S. electricity generation for many years, coal's share has declined over the past few years because of growing competition from efficient natural gas-fired plants with access to low-cost natural gas. In the Reference case, the share of generation accounted for by coal falls from 42 percent in 2011 to 38 percent in 2025 and 35 percent in 2040. Coal's share falls even further in the CO2 fee cases, to a range between 6 percent and 31 percent in 2025 and between 1 percent and 24 percent in 2040.

As the fee for CO2 emissions increases over time, power companies reduce their use of coal and increase their use of nuclear power, renewables, and natural gas. The nuclear and renewable shares of total generation increase in most of the CO2 fee cases, particularly in the later years of the projections. In the Reference case, nuclear generation accounts for 20 percent of the total in 2025 and 17 percent in 2040. In the CO2 fee cases, the nuclear share varies from 20 to 24 percent in 2025 and 18 to 37 percent in 2040. The renewable share of total generation in 2025 is 14 percent in the Reference case, increasing to 16 percent in 2040. In the CO2 fee cases the renewable share is generally higher, between 15 percent and 21 percent in 2025 and between 17 percent and 31 percent in 2040.

Endnotes for Market Trends: Emissions

142. U.S. Environmental Protection Agency, "Mercury and Air Toxics Standards," http://www.epa.gov/mats.
143. Recent analysis performed by the EPA indicates that upgraded electrostatic precipitators may also enable coal-fired power plants to meet the nonmercury metal emissions control requirement for MATS. This assumption was not included in AEO2013 but will be revisited in future AEOs.
144. U.S. Energy Information Administration, "Dry sorbent injection may serve as a key pollution control technology at power plants," Today in Energy (March 16, 2012), http://www.eia.gov/todayinenergy/detail.cfm?id=5430.

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 8. Electricity Supply, Disposition, Prices, and Emissions 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 55. Electric Power Projections for EMM Region - United States XLS
Table 55.1. Electric Power Projections for EMM Region - Texas Regional Entity XLS
Table 55.1. Electric Power Projections for EMM Region - Reliability First Corporation / Michigan XLS
Table 55.11. Electric Power Projections for EMM Region - Reliability First Corporation / West XLS
Table 55.12. Electric Power Projections for EMM Region - SERC Reliability Corporation / Delta XLS
Table 55.13. Electric Power Projections for EMM Region - SERC Reliability Corporation / Gateway XLS
Table 55.14. Electric Power Projections for EMM Region - SERC Reliability Corporation / Southeastern XLS
Table 55.15. Electric Power Projections for EMM Region - SERC Reliability Corporation / Central XLS
Table 55.16. Electric Power Projections for EMM Region - SERC Reliability Corporation / Virginia-Carolina XLS
Table 55.17. Electric Power Projections for EMM Region - Southwest Power Pool / North XLS
Table 55.18. Electric Power Projections for EMM Region - Southwest Power Pool / South XLS
Table 55.19. Electric Power Projections for EMM Region - Western Electricity Coordinating Council / Southwest XLS
Table 55.2. Electric Power Projections for EMM Region - Western Electricity Coordinating Council / California XLS
Table 55.2. Electric Power Projections for EMM Region - Florida Reliability Coordinating Council XLS
Table 55.21. Electric Power Projections for EMM Region - Western Electricity Coordinating Council / Northwest Power Pool Area XLS
Table 55.22. Electric Power Projections for EMM Region - Western Electricity Coordinating Council / Rockies XLS
Table 55.3. Electric Power Projections for EMM Region - Midwest Reliability Council / East XLS
Table 55.4. Electric Power Projections for EMM Region - Midwest Reliability Council / West XLS
Table 55.5. Electric Power Projections for EMM Region - Northeast Power Coordinating Council / Northeast XLS
Table 55.6. Electric Power Projections for EMM Region - Northeast Power Coordinating Council / NYC-Westchester XLS
Table 55.7. Electric Power Projections for EMM Region - Northeast Power Coordinating Council / Long Island XLS
Table 55.8. Electric Power Projections for EMM Region - Northeast Power Coordinating Council / Upstate New York XLS
Table 55.9. Electric Power Projections for EMM Region - Reliability First Corporation / East XLS