U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Annual Energy Outlook 2015
Release Date: April 14, 2015 | Next Release Date: March 2016 | full report
Market Trends: Emissions
The cost of capital for investments in GHG-intensive technologies, such as new coal-fired and coal-to-liquids (CTL) plants without carbon capture and storage (CCS), is increased by 3 percentage points in the AEO2014 Reference case. This increase addresses the higher risk associated with those investments, given the potential for future restrictions on GHG emissions. The higher cost of capital is also applied to capital projects at existing coal-fired power plants (excluding CCS), such as retrofits to control emissions of mercury, acid gases, and particulates for compliance with MATS. The 3 percentage point adjustment is roughly equivalent in levelized cost terms to an emissions fee of $15/metric ton of CO2 when investing in a new coal plant without CCS, and it increases the capital cost component for a new coal unit by approximately 1.5 cents/kWh. The No GHG Concern case assumes that the costs of capital for GHG-intensive technologies do not reflect the risk premium described above.
In the No GHG Concern case, estimated levelized costs for new coal- and natural gas-fired capacity begin to converge in the mid- to late-2020s (Figure MT-63) , leading to new coalfired capacity builds in a number of regions. In comparison, virtually no new unplanned coal-fired capacity is added in the Reference case until nearly 2040. In the No GHG Concern case, 13 GW of new coal-fired capacity is added (including plants currently under construction), compared with fewer than 3 GW in the Reference case. As a consequence, additions of natural gas, nuclear, and renewable generating capacity all are slightly lower in the No GHG Concern case than in the Reference case, and total energy-related CO2 emissions in 2040 are 54 million metric tons (1%) higher than in the Reference case. In the No GHG Concern case, the cost estimates for new coal-fired plants by region in 2030 range from 9% below to 11% above the national average—not including New England, where the cost estimate is 23% above the national average .
Energy-related CO2 emissions in the AEO2014 Reference case decline by 0.2%/year on average from 2005 to 2040, as compared with an average increase of 0.9%/year from 1980 to 2005. Reasons for the decline include lower economic growth, increasing 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 when combusted. Energy-related CO2 emissions in 2020 are 8.7% below their 2005 level in the Reference case, and in 2040 they total 5,599 million metric tons (MMmt) and 400 MMmt (6.7%) below their 2005 level (Figure MT-64).
In the Reference case, petroleum remains the largest source of U.S. energy-related CO2 emissions. However, its share of the total falls to 38% in 2040 from 44% in 2005. In 2040, CO2 emissions from petroleum use, mainly in the transportation sector, are 509 MMmt below the 2005 level.
Emissions from coal, the second-largest source of energyrelated CO2 emissions, are 402 MMmt below the 2005 level in 2040 in the Reference case, and their share of total energyrelated CO2 emissions declines from 36% in 2005 to 32% in 2040. The natural gas share of energy-related CO2 emissions increases from 20% in 2005 to 30% 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 AEO2014.
In the AEO2014 Reference case, sulfur dioxide (SO2) emissions from the electric power sector increase slightly in the early years of the projection but fall rapidly in 2016, when the Mercury and Air Toxics Standards (MATS)  are fully implemented. The Reference case assumes that all coal-fired power plants operating in the United States will be equipped with either flue gas desulfurization units (scrubbers) or dry sorbent injection (DSI) systems by 2016 to comply with the specific requirements of MATS. The emissions controls have the ancillary benefit of removing significant amounts of SO2. For example, scrubbers remove more than 90% of SO2 emissions from flue gas. DSI systems, when combined with fabric filters, remove approximately 70% of SO2 emissions.
At the end of 2012, 64% of electric power sector coal-fired generating capacity in the United States already had either scrubbers or DSI systems installed. The Reference case assumes that by 2016, every operating coal plant in the United States larger than 25 megawatts has some type of control equipment, including approximately 31 GW of coal-fired capacity retrofitted with scrubbers and another 45 GW retrofitted with DSI systems. After a 61% decrease from 2012 to 2016 (Figure MT-65), annual SO2 emissions increase by 0.9%/year from 2016 to 2040, as total electricity generation from coal-fired power plants increases by 0.3%/year, and scrubbers and DSI equipment remove most (but not all) SO2 from flue gas. As a result of MATS compliance, SO2 emissions are reduced to a level below the cap specified in the Clean Air Interstate Rule (CAIR).
Although the AEO2014 Reference case assumes that current laws and regulations remain in effect through 2040, the potential impacts of future policies that would place an implicit or explicit value on CO2 emissions are examined in two cases, starting at $10 (GHG10) and $25 (GHG25) per metric ton CO2 in 2015 and rising by 5% per year thereafter. 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, the $10 fee case was run both with the Reference case and combined with the High Oil and Gas Resource case (GHG10 and Low Gas Prices) (Figure MT-66).
Emissions fees or other policies that place an explicit or implicit value on CO2 emissions 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 15% and 28% lower in 2025 in the GHG10 and GHG25 cases using Reference case resources, respectively, and 22% and 40% lower in 2040. When combined with High Oil and Gas Resource assumptions, the CO2 fees in the GHG10 case 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 the GHG10 and Low Gas Prices case. 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. Shortly after 2020, 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.
The role of natural gas in the CO2 fee cases varies widely over time and also varies over the range of assumptions about natural gas resources. When CO2 fees are assumed to be introduced in 2015 in both the GHG10 and GHG25 cases, natural gas-fired generation increases sharply during the first few years, and it continues to increase modestly over the next several years (Figure MT-67). Subsequently, the increases no longer occur, as more new nuclear and renewable plants are added. In the GHG10 case, natural gas-fired generation levels off around 2030. In the GHG25 case, the role of natural gas begins to decline after 2025.
After accounting for about 50% of all U.S. electricity generation for many years, coal's share has declined in recent years as a result of growing competition from efficient natural gasfired plants with access to relatively low-cost natural gas. In the Reference case, the share of generation fueled by coal falls from 37% in 2012 to 32% in 2040. Coal's share falls even further in the GHG cases, to a range between 10% and 28% in 2025 and between 1% and 19% in 2040.
As the fee for CO2 emissions increases over time, power companies reduce their use of coal and increase their use of natural gas, renewables, and nuclear. The nuclear and renewable shares of total generation increase in most of the GHG cases, particularly in the later years of the projections. In the Reference case, nuclear generation accounts for 17% of the total in 2025 and 16% in 2040. In the GHG cases, the nuclear share varies from 17% to 21% in 2025 and from 17% to 37% in 2040. In the Reference case, the renewable share of total generation increases from 15% in 2025 to 16% in 2040. The renewable share is generally higher in the GHG cases—between 17% and 20% in 2025 and between 18% and 27% in 2040.
- For detailed discussion of levelized costs, see U.S. Energy Information Administration, "Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2014," http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
- The levelized cost estimates shown in Figure MT-63 represent national averages.
- U.S. Environmental Protection Agency, "Mercury and Air Toxics Standards," http://www.epa.gov/mats.
In This Section
- Concerns about future GHG policies affectbuilds of new coal-fired generating capacity
- Energy-related carbon dioxide emissions remain below their 2005 level through 2040
- Power plant emissions of sulfur dioxide are reduced by further environmental controls
- Nitrogen oxides emissions show little change from 2011 to 2040 in the Reference case
- Energy-related carbon dioxide emissions are sensitive to potential policy changes
- Carbon dioxide fees first favor, then discourage, natural gas-fired generation