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CHAPTER 13. EMISSIONS 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. EMISSIONS ANALYSIS

13.1 INTRODUCTION

DOE will conduct an emissions analysis for the notice of proposed rulemaking. In the 

emissions analysis, DOE will estimate the reduction in power sector emissions of carbon dioxide 

(CO2), nitrogen oxides (NOX), sulfur dioxide (SO2) and mercury (Hg) from potential energy 

conservation standards for the considered products. In addition, DOE will estimate emissions 

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

energy inputs to power plants. 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 (Aug. 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

The analysis of power sector emissions uses marginal emissions intensity factors derived 

from runs of the NEMS model. DOE uses the version of NEMS based on the most recent Annual 

Energy Outlook (AEO). Site emissions of CO2 and NOX are estimated using emissions intensity 

factors from a publication of the EPA.

1 Combustion emissions of CH4 and N2O are estimated 

using emissions intensity factors published by the Environmental Protection Agency (EPA)

GHG Emissions Factors Hub.a 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 on emissions. The text below refers to the Annual Energy Outlook 2013 (AEO 2013).

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 remains in effect. 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). On July 6, 2011 EPA issued a 

replacement for CAIR, the Cross-State Air Pollution Rule (CSAPR; also known as the Transport 

Rule). 76 FR 48208 (August 8, 2011). 

 a http://www.epa.gov/climateleadership/guidance/ghg-emissions.html
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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 2015, however, SO2 emissions will fall as a result of the Mercury and Air 

Toxics Standards (MATS) for power plants, which were announced by EPA on December 21, 

2011. 77 FR 9304 (Feb. 16, 2012)b 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 2013 assumes that, in order to continue 

operating, coal plants must have either flue gas desulfurization or dry sorbent injection systems 

installed by 2015. Both technologies, which are used to reduce acid gas emissions, also reduce 

SO2 emissions. Under the MATS, NEMS shows a reduction in SO2 emissions when electricity 

demand decreases (e.g., as a result of energy efficiency standards). 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 2015 and beyond.

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 2013, 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 

 b On July 20, 2012, EPA announced a partial stay, for a limited duration, of the effectiveness of national new source 

emission standards for hazardous air pollutants from coal- and oil-fired electric utility steam generating units. More 

at: www.epa.gov/airquality/powerplanttoxics/pdfs/20120727staynotice.pdf
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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.