CHAPTER 13. EMISSIONS ANALYSIS

TABLE OF CONTENTS

13.1 INTRODUCTION ......................................................................................................... 13-1

13.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS............................... 13-1

13.3 POWER SECTOR AND SITE EMISSIONS FACTORS............................................. 13-3

13.4 UPSTREAM FACTORS ............................................................................................... 13-4

13.5 EMISSIONS IMPACT RESULTS................................................................................ 13-5

LIST OF TABLES

Table 13.3.1 Power Plant Emissions Factors.......................................................................... 13-3

Table 13.3.2 Natural Gas Site Combustion Emissions Factors .............................................. 13-4

Table 13.4.1 Electricity Upstream Emissions Factors............................................................ 13-5

Table 13.4.2 Natural Gas Upstream Emissions Factors.......................................................... 13-5

Table 13.5.1 Cumulative Emissions Reduction for Potential Standards for Commercial 

Clothes Washers................................................................................................. 13-6

LIST OF FIGURES

Figure 13.5.1 Commercial Clothes Washers: CO2 Total Emissions Reduction ...................... 13-7

Figure 13.5.2 Commercial Clothes Washers: SO2 Total Emissions Reduction....................... 13-7

Figure 13.5.3 Commercial Clothes Washers: NOx Total Emissions Reduction ...................... 13-8

Figure 13.5.4 Commercial Clothes Washers: Hg Total Emissions Reduction ........................ 13-8

Figure 13.5.5 Commercial Clothes Washers: N2O Total Emissions Reduction ...................... 13-9

Figure 13.5.6 Commercial Clothes Washers: CH4 Total Emissions Reduction ...................... 13-9

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CHAPTER 13. EMISSIONS ANALYSIS

13.1 INTRODUCTION

The emissions analysis consists of two components. The first component estimates the 

effect of potential energy conservation standards on power sector and site 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 

calculated by DOE. As of 2014, DOE is using a new methodology based on results published for 

the Annual Energy Outlook 2014 (AEO 2014) reference case and a set of side cases that 

implement a variety of efficiency-related policies.

1 The new methodology is described in chapter 

15 and in the report “Utility Sector Impacts of Reduced Electricity Demand” (Coughlin, 2014).4

Site emissions of CO2 and NOX are estimated using emissions intensity factors from a 

publication of the Environmental Protection Agency (EPA).

2

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

published by the EPA, GHG Emissions Factors Hub.a The FFC upstream emissions are 

estimated based on the methodology developed by Coughlin (2013).3 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 are estimated using the energy 

savings calculated in the national impact analysis (chapter 10).

13.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS

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

regulations on emissions. AEO 2014 generally represents current Federal and State legislation 

and final implementation regulations in place as of the end of October 2013.

a http://www.epa.gov/climateleadership/inventory/ghg-emissions.html

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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 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, 

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. See EME Homer City Generation, LP 

v. EPA, 696 F.3d 7, 38 (D.C. Cir. 2012). The court ordered EPA to continue administering 

CAIR. The AEO 2014 emissions factors used for the present analysis assume that CAIR remains 

a binding regulation through 2040. b

The attainment of emissions caps is typically flexible among affected Electric Generating 

Units (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 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 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. 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 established by CAIR, so it is unlikely that excess SO2 emissions allowances 

resulting from the lower electricity demand would be needed or used to permit offsetting 

b 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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increases in SO2 emissions by any regulated EGU. Therefore, DOE believes that efficiency 

standards will reduce SO2 emissions in 2016 and beyond.

CAIR 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 

CAIR, so DOE estimated 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 

emissions. DOE estimated mercury emissions reductions using the NEMS-BT based on AEO 

2014, which incorporates the MATS.

13.3 POWER SECTOR AND SITE EMISSIONS FACTORS 

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

from analysis of the AEO 2014 reference and a number of side cases incorporating enhanced 

equipment efficiencies. To model the impact of a standard, DOE calculates factors that relate a 

unit reduction to annual site electricity demand for a given end use to corresponding reductions 

to installed capacity by fuel type, fuel use for generation, and power sector emissions. Details on 

the approach used may be found in Coughlin (2014).4

Table 13.3.1 presents the average power plant emissions factors for selected years. These

power plant emissions factors are derived from the emissions factors of the plant types used to 

supply electricity to commercial sector. The average factors for each year take into account the 

projected shares of each of the sources in total electricity generation. Table 13.3.2 presents the 

natural gas site combustion emissions factors for selected years.

Table 13.3.1 Power Plant Emissions Factors

Unit* 2020 2025 2030 2035 2040

CO2 kg/MWh 710 632 571 522 478

SO2 g/MWh 688 537 452 379 338

NOx g/MWh 557 466 408 360 326

Hg g/MWh 0.00212 0.00166 0.00139 0.00117 0.00104

N2O g/MWh 7.2 7.1 6.9 6.6 6.4

CH4 g/MWh 50 49 48 46 45

* Refers to site electricity savings.

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Table 13.3.2 Natural Gas Site Combustion Emissions Factors

Unit* 2020 2025 2030 2035 2040

CO2 kg/mcf 54.2 54.2 54.2 54.2 54.2

SO2 g/ mcf 0.271 0.271 0.271 0.271 0.271

NOx g/ mcf 69.9 69.9 69.9 69.9 69.9

N2O g/ mcf 0.102 0.102 0.102 0.102 0.102

CH4 g/ mcf 1.022 1.022 1.022 1.022 1.022

* Refers to site gas savings.

13.4 UPSTREAM FACTORS 

The upstream emissions accounting uses the same approach as the upstream energy 

accounting described in appendix 10-B. See also Coughlin (2013)

3 and Coughlin (2014).4 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. Fugitive emissions factors for 

methane from coal mining and natural gas production were estimated based on a review of recent 

studies compiled by Burnham (2011).5 This review includes estimates of the difference between 

fugitive emissions factors for conventional production of natural vs. unconventional (shale or 

tight gas). These estimates rely in turn on data gathered by EPA under new GHG reporting 

requirements for the petroleum and natural gas industries.6,7 As more data are made available, 

DOE will continue to update these estimated emissions factors.

For ease of application in its analysis, DOE developed all of the emissions factors using 

site (point of use) energy savings in the denominator. Table 13.4.1 presents the electricity 

upstream emissions factors for selected years. The caps that apply to power sector NOX

emissions do not apply to upstream combustion sources.

13-4
Table 13.4.1 Electricity Upstream Emissions Factors

Unit 2020 2025 2030 2035 2040

CO2 kg/MWh 29.1 29.4 29.7 29.9 29.8

SO2 g/MWh 5.0 5.1 4.9 4.7 4.6

NOx g/MWh 368 375 382 387 387

Hg g/MWh 0.00001 0.00001 0.00001 0.00001 0.00001

N2O g/MWh 0.25 0.25 0.24 0.23 0.23

CH4 g/MWh 2,149 2,195 2,216 2,248 2,255

Table 13.4.2 illustrates the natural gas upstream emissions factors for selected years. 

These were used to estimate the emissions associated with the increased gas use at some of the 

considered efficiency levels.

Table 13.4.2 Natural Gas Upstream Emissions Factors

Unit 2020 2025 2030 2035 2040

CO2 kg/ mcf 7.1 7.2 7.3 7.4 7.4

SO2 g/ mcf 0.030 0.031 0.031 0.032 0.032

NOx g/ mcf 101 103 105 105 105

N2O g/ mcf 0.011 0.011 0.012 0.012 0.012

CH4 g/ mcf 659 665 666 670 670

13.5 EMISSIONS IMPACT RESULTS

Table 13.5.1 presents the estimated cumulative emissions reductions for the lifetime of 

products sold in 2018-2047 for each TSL. Negative values indicate that emissions increase.

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Table 13.5.1 Cumulative Emissions Reduction for Potential Standards for Commercial 

Clothes Washers

TSL

1 2 3 4

Power Sector and Site Emissions

CO2 (million metric tons) 3.4 3.8 7.5 6.9

SO2 (thousand tons) 1.782 1.861 4.241 4.211

NOX (thousand tons) 3.5 4.0 7.4 6.5

Hg (tons) 0.00548 0.00571 0.01304 0.01296

CH4 (thousand tons) 0.2 0.2 0.5 0.5

N2O (thousand tons) 0.032 0.034 0.075 0.073

Upstream Emissions

CO2 (million metric tons) 0.3 0.3 0.6 0.5

SO2 (thousand tons) 0.022 0.023 0.051 0.051

NOX (thousand tons) 4.5 5.1 9.2 8.0

Hg (tons) 0.00005 0.00005 0.00011 0.00011

CH4 (thousand tons) 27.7 31.8 56.6 48.8

N2O (thousand tons) 0.001 0.001 0.003 0.003

Total Emissions

CO2 (million metric tons) 3.7 4.1 8.1 7.4

SO2 (thousand tons) 1.804 1.884 4.293 4.262

NOX (thousand tons) 8.0 9.1 16.6 14.5

Hg (tons) 0.00552 0.00576 0.01315 0.01307

CH4 (thousand tons) 28.0 32.0 57.2 49.3

N2O (thousand tons) 0.033 0.035 0.078 0.076

Figure 13.5.1 through Figure 13.5.6 show the annual reductions for total emissions for 

each type of emission from each TSL. The reductions reflect the lifetime impacts of products 

sold in 2018-2047.

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Figure 13.5.1 Commercial Clothes Washers: CO2 Total Emissions 

Reduction

Figure 13.5.2 Commercial Clothes Washers: SO2 Total Emissions 

Reduction

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Figure 13.5.3 Commercial Clothes Washers: NOx Total Emissions 

Reduction

Figure 13.5.4 Commercial Clothes Washers: Hg Total Emissions 

Reduction

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Figure 13.5.5 Commercial Clothes Washers: N2O Total Emissions 

Reduction

Figure 13.5.6 Commercial Clothes Washers: CH4 Total Emissions 

Reduction

0.0

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REFERENCES

1. Energy Information Administration, Annual Energy Outlook 2013 with Projections to 

2040, June 2013. Washington, DC. 

<http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf>

2. 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/index.html

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

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

4. Coughlin, K., Utility Sector Impacts of Reduced Electricity Demand, 2014. Lawrence 

Berkeley National Laboratory. Report No. LBNL-xxxx. 

5. Burnham, A., J. Han, C. E. Clark, M. Wang, J. B. Dunn, I. Palou-Rivera,, Life-Cycle 

Greenhouse Gas Emissions of Shale Gas, Natural Gas, Coal, and Petroleum.

Environmental Science & Technology, 2011. 46(2): pp. 619-627 

6. U.S. Environmental Protection Agency, Fugitive Emissions Reporting from the 

Petroleum and Natural Gas Industry, 2009. U.S. Environmental Protection Agency. 

Washington, DC. 

7. U.S. Environmental Protection Agency, Oil and Natural Gas Sector: Standards of 

Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution, 

Background Supplemental Technical Support Document for the Final New Source 

Performance Standards, 2012. U.S. Environmental Protection Agency. Washington, DC.

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