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CHAPTER 16. EMISSIONS IMPACT ANALYSIS

TABLE OF CONTENTS

16.1 INTRODUCTION ......................................................................................................... 16-1

16.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS ............................... 16-1

16.3 POWER SECTOR EMISSIONS FACTORS ................................................................ 16-3

16.4 UPSTREAM AND GHG EMISSIONS FACTORS ...................................................... 16-3

REFERENCES .......................................................................................................................... 16-4
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CHAPTER 16. EMISSIONS IMPACT ANALYSIS

16.1 INTRODUCTION

As part of its notice of proposed rulemaking, the U.S. Department of Energy (DOE) will 

conduct an emissions analysis consisting of two components. The first component estimates the 

effect of potential energy conservation standards on power sector combustion emissions of 

carbon dioxide (CO2), nitrogen oxides (NOX), sulfur dioxide (SO2), and mercury (Hg). The 

second component estimates the impacts of a potential standard on emissions of two additional 

greenhouse gases, methane (CH4) and nitrous oxide (N2O), as well as the reductions to emissions 

of all species due to “upstream” activities in the fuel production chain. These upstream activities 

comprise extraction, processing, and transporting fuels to the site of combustion. The associated 

emissions are referred to as upstream emissions. Together, these emissions account for the fullfuel-cycle (FFC), in accordance with DOE’s FFC Statement of Policy. 76 FR 51282 (Aug. 18, 

2011). 

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

from runs of DOE’s NEMS-BT model, described in chapter 15 of the interim technical support 

document (TSD). DOE will use the latest version of NEMS based on the Annual Energy Outlook 

(AEO).

1

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

regulations on emissions. For example, AEO2012 generally represented current Federal and State 

legislation and final implementation regulations in place as of the end of December 2011. 

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

published by the U.S. Environmental Protection Agency (EPA), GHG Emissions Factors Hub.a

The FFC upstream emissions are estimated based on the methodology developed by Coughlin 

(2012).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. 

The emissions intensity factors are expressed in terms of physical units per MWh or 

MMBtu of site energy savings. Total emissions reductions will be estimated using the energy 

savings calculated in the national impact analysis (chapter 11 of the interim TSD).

16.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS 

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 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 parts of it remained in effect. On July 6, 2011 EPA issued a replacement for CAIR, 

 

a www.epa.gov/climateleadership/guidance/ghg-emissions.html
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the Cross-State Air Pollution Rule (CSAPR). 76 FR 48208 (August 8, 2011). The AEO2012 

NEMS assumed the implementation of CSAPR.b

The attainment of emissions caps is typically flexible among affected 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 imposition 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). In the final MATS rule, EPA established a standard for 

hydrogen chloride 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. AEO2012 assumed 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 28 eastern States and the District of 

Columbia. Energy conservation standards are expected to have little effect on NOx 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, so DOE will estimate NOX emissions reductions from potential standards for those 

States. 

 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 

 

b On December 30, 2011, the D.C. Circuit stayed the new rules while a panel of judges reviews them, and told EPA 

to continue enforcing CAIR. See EME Homer City Generation, LP v. EPA, Order, No. 11-1302, Slip Op. at *2 (D.C. 

Cir. Dec. 30, 2011). On August 21, 2012, the D.C. Circuit vacated CSAPR. See EME Homer City Generation, LP v. 

EPA, No. 11-1302, 2012 WL 3570721 at *24 (D.C. Cir. Aug. 21, 2012). The court required EPA to continue 

administering CAIR. AEO2012 had been finalized prior to both these decisions, however. DOE understands that 

CAIR and CSAPR are similar with respect to their effect on emissions impacts of energy efficiency standards.
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emissions. DOE will estimate mercury emissions reductions using the NEMS-BT based on an

AEO version that incorporates the MATS, if applicable. 

16.3 POWER SECTOR EMISSIONS FACTORS 

The analysis of power sector emissions will use marginal emissions intensity factors 

derived from runs of DOE’s latest NEMS-BT model. To model the impact of a standard, DOE 

will input a reduction to annual energy demand for the corresponding end use in the appropriate 

start year. The NEMS-BT model will be run with the decremented energy demand to determine 

the modified build-out of capacity, fuel use, and power sector emissions. A marginal emissions 

intensity factor will be defined by dividing the reduction in the total emissions of a given 

pollutant by the reduction in total generation (in billion kWh). DOE will use the site energy 

savings multiplied by a T&D loss factor to estimate the reduction in generation for each TSL. 

Details on this approach may be found in Coughlin (2012).2 

16.4 UPSTREAM AND GHG EMISSIONS FACTORS 

The upstream emissions accounting will use the same approach as the upstream energy 

accounting. See also Coughlin (2012).2

 When demand for a particular fuel is reduced, there is a 

corresponding reduction in the emissions from combustion of that fuel at either the building site 

or the power plant. The associated reduction in energy use for upstream activities leads to further 

reductions in emissions. These upstream emissions are defined to include the combustion 

emissions from the fuel used upstream, the fugitive emissions associated with the fuel used 

upstream, and the fugitive emissions associated with the fuel used on site. 

Fugitive emissions of CO2 occur during oil and gas production, but are small relative to 

combustion emissions. They comprise about 2.5 percent of total CO2 emissions for natural gas 

and 1.7 percent for petroleum fuels. Fugitive emissions of methane occur during oil, gas, and 

coal production. Combustion emissions of CH4 are very small, while fugitive emissions 

(particularly for gas production) may be relatively large. Hence, fugitive emissions make up over 

99 percent of total methane emissions for natural gas, about 95 percent for coal, and 93 percent

for petroleum fuels. 

Upstream emissions factors account for both fugitive emissions and combustion 

emissions in extraction, processing, and transport of primary fuels. For ease of application in its 

analysis, DOE will develop all of the emissions factors using site (point of use) energy savings in 

the denominator. 
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REFERENCES

1. U.S. Department of Energy–Energy Information Administration. Annual Energy Outlook 

2012 with Projections to 2035. 2012. (Last accessed February 19, 2013.) 

<www.eia.gov/forecasts/archive/aeo12/index.cfm>

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

Berkeley National Laboratory, Report Number LBNL-6025E.