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CHAPTER 13. EMISSION IMPACT ANALYSIS

TABLE OF CONTENTS

13.1 Introduction.................................................................................................................... 13-1

13.2 Approach........................................................................................................................ 13-1

13.3 Air Quality Regulations and Emissions Impacts........................................................... 13-1
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CHAPTER 13. EMISSION IMPACT ANALYSIS

13.1 INTRODUCTION

The U.S. Department of Energy (DOE) conducts an emissions analysis for the notice of 

proposed rulemaking (NOPR) stage. In the emissions analysis, DOE estimates the reduction in 

power sector and site combustion emissions of carbon dioxide (CO2), nitrogen oxides (NOX), 

sulfur dioxide (SO2), mercury (Hg), methane (CH4) and nitrous oxide (N2O) from potential 

energy conservation standards for the considered equipment. In addition, DOE estimates

emissions impacts in production activities (extracting, processing, and transporting fuels) that 

provide the energy inputs to power plants and for site combustion. These are referred to as 

“upstream” emissions. Together, these emissions account for the full-fuel-cycle (FFC). In 

accordance with DOE’s FFC Statement of Policy (76 FR 51282 (August 18, 2011)), the FFC 

analysis includes impacts on emissions of methane and nitrous oxide, both of which are 

recognized as greenhouse gases.

13.2 APPROACH

DOE conducts the emissions analysis using emissions factors that are primarily derived 

from data in the latest version of the Energy Information Administration’s (EIA’s) Annual 

Energy Outlook (AEO), supplemented by data from other sources. EIA prepares the AEO using 

the National Energy Modeling System (NEMS).a Site emissions of CO2 and NOX are estimated 

using emissions intensity factors from a publication of the Environmental Protection Agency 

(EPA).

1 Combustion emissions of CH4 and N2O are estimated using emissions intensity factors 

published by the EPA GHG Emissions Factors Hub.b The FFC upstream emissions are estimated 

based on the methodology developed by Coughlin (2013).2 The upstream emissions include both 

emissions from fuel combustion during extraction, processing and transportation of fuel, and 

“fugitive” emissions (direct leakage to the atmosphere) of CH4 and CO2.

13.3 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS

Each annual version of NEMS incorporates the projected impacts of existing air quality 

regulations for emissions. The text below refers to AEO 2014, which generally represents current 

legislation and environmental regulations, including recent government actions, for which 

implementing regulations were available as of October 31, 2013. The NOPR will use emissions 

factors derived from the most current available AEO data.

 a For more information about NEMS, please refer to the U.S. Department of Energy, Energy Information 

Administration documentation. A useful summary is National Energy Modeling System: An Overview 2009, 

DOE/EIA-0581 (October 2009), available at: http://www.eia.gov/oiaf/aeo/overview/. b Available at http://www.epa.gov/climateleadership/inventory/ghg-emissions.htm.
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SO2 emissions from affected electric generating units (EGUs) are subject to nationwide 

and regional emissions cap and trading programs. Title IV of the Clean Air Act sets an annual 

emissions cap on SO2 for affected EGUs in the 48 contiguous states and the District of Columbia 

(D.C.). SO2 emissions from 28 eastern states and D.C. were also limited under the Clean Air 

Interstate Rule (CAIR), which created an allowance-based trading program that operates along 

with the Title IV program in those States and D.C. 70 FR 25162 (May 12, 2005). CAIR was 

remanded to EPA by the U.S. Court of Appeals for the District of Columbia Circuit (D.C. 

Circuit), but it remained in effect.c On July 6, 2011 EPA issued a replacement for CAIR, the 

Cross-State Air Pollution Rule (CSAPR). 76 FR 48208 (August 8, 2011). On August 21, 2012, 

the D.C. Circuit issued a decision to vacate CSAPR.d The court ordered EPA to continue 

administering CAIR. AEO 2014 assumes that CAIR remains a binding regulation through 2040.e

The attainment of emissions caps is typically flexible among EGUs and is enforced 

through the use of emissions allowances and tradable permits. Under existing EPA regulations, 

any excess SO2 emissions allowances resulting from the lower electricity demand caused by the 

adoption of an efficiency standard could be used to permit offsetting increases in SO2 emissions 

by any regulated EGU. In past rulemakings, DOE recognized that there was uncertainty about 

the effects of efficiency standards on SO2 emissions covered by the existing cap-and-trade 

system, but it concluded that no reductions in power sector emissions would occur for SO2 as a 

result of standards.

Beginning in 2016, however, SO2 emissions will fall as a result of the Mercury and Air 

Toxics Standards (MATS) for power plants. 77 FR 9304 (Feb. 16, 2012) In the final MATS rule, 

EPA established a standard for HCl as a surrogate for acid gas hazardous air pollutants (HAP), 

and also established a standard for SO2 (a non-HAP acid gas) as an alternative equivalent 

surrogate standard for acid gas HAP. The same controls are used to reduce HAP and non-HAP 

acid gas; thus, SO2 emissions will be reduced as a result of the control technologies installed on 

coal-fired power plants to comply with the MATS requirements for acid gas. AEO 2014 assumes 

that, in order to continue operating, coal plants must have either flue gas desulfurization or dry 

sorbent injection systems installed by 2016. Both technologies, which are used to reduce acid gas 

emissions, also reduce SO2 emissions. Under the MATS, emissions will be far below the cap that 

would be established by CSAPR, so it is unlikely that excess SO2 emissions allowances resulting 

from the lower electricity demand would be needed or used to permit offsetting increases in SO2

emissions by any regulated EGU. Therefore, DOE believes that efficiency standards will reduce 

SO2 emissions in 2016 and beyond.

 c See North Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 2008); North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 

2008).

d See EME Homer City Generation, LP v. EPA, 696 F.3d 7, 38 (D.C. Cir. 2012). e On April 29, 2014, the U.S. Supreme Court reversed the judgment of the D.C. Circuit and remanded the case for 

further proceedings consistent with the Supreme Court's opinion. The Supreme Court held in part that EPA's 

methodology for quantifying emissions that must be eliminated in certain states due to their impacts in other 

downwind states was based on a permissible, workable, and equitable interpretation of the Clean Air Act provision 

that provides statutory authority for CSAPR. See EPA v. EME Homer City Generation, No 12-1182, slip op. at 32 

(U.S. April 29, 2014). Because DOE is using emissions factors based on AEO 2013, the analysis assumes that 

CAIR, not CSAPR, is the regulation in force. The difference between CAIR and CSAPR is not relevant for the 

purpose of DOE's analysis of SO2 emissions.
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CSAPR established a cap on NOX emissions in eastern States and the District of 

Columbia. Energy conservation standards are expected to have little or no physical effect on 

these emissions in those States covered by CSAPR because excess NOX emissions allowances 

resulting from the lower electricity demand could be used to permit offsetting increases in NOX

emissions. However, standards would be expected to reduce NOX emissions in the States not 

affected by CSAPR. Therefore, DOE estimates NOX emissions reductions from potential 

standards in the States where emissions are not capped.

The MATS limit mercury emissions from power plants, but they do not include emissions 

caps and, as such, DOE’s energy conservation standards would likely reduce Hg emissions. For 

this rulemaking, DOE plans to estimate mercury emissions reductions using emissions factors 

based on AEO 2014, which incorporates the MATS.

Power plants may emit particulates from the smoke stack, which are known as direct 

particulate matter (PM) emissions. NEMS does not account for direct PM emissions from power 

plants. DOE is investigating the possibility of using other methods to estimate reduction in PM 

emissions due to standards. The great majority of ambient PM associated with power plants is in 

the form of secondary sulfates and nitrates, which are produced at a significant distance from 

power plants by complex atmospheric chemical reactions that often involve the gaseous 

emissions of power plants, mainly SO2 and NOX. The monetary benefits that DOE estimates for 

reductions in SO2 and NOX emissions resulting from standards are in fact primarily related to the 

health benefits of reduced ambient PM. 
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REFERENCES

1. U.S. Environmental Protection Agency, Compilation of Air Pollutant Emission Factors, 

AP-42, Fifth Edition, Volume I: Stationary Point and Area Sources.

1998<http://www.epa.gov/ttn/chief/ap42/>

2. Coughlin, K., Projections of Full-Fuel-Cycle Energy and Emissions Metrics, 2013. 

Lawrence Berkeley National Laboratory. Report No. LBNL-6025E.