CHAPTER 13. EMISSIONS IMPACT ANALYSIS

TABLE OF CONTENTS

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

13.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS ............................... 13-2

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

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

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

REFERENCES ........................................................................................................................ 13-10

LIST OF TABLES

Table 13.3.1 Power Plant Emissions Factors for Commercial Space Cooling End Use ........ 13-4

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

Table 13.5.1 Cumulative Emissions Reduction for Small, Large, and Very Large AirCooled CUAC and CUHP Trial Standard Levels .............................................. 13-6

LIST OF FIGURES

Figure 13.5.1 CO2 Total Emissions Reduction ........................................................................ 13-7

Figure 13.5.2 SO2 Total Emissions Reduction ......................................................................... 13-7

Figure 13.5.3 NOx Total Emissions Reduction ........................................................................ 13-8

Figure 13.5.4 Hg Total Emissions Reduction .......................................................................... 13-8

Figure 13.5.5 N2O Total Emissions Reduction ........................................................................ 13-9

Figure 13.5.6 CH4 Total Emissions Reduction ........................................................................ 13-9

13-i 
CHAPTER 13. EMISSIONS IMPACT 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 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 full-fuel-cycle 

(FFC), in accordance with DOE’s FFC Statement of Policy. 76 FR 51282 (Aug. 18, 2011). 

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

derived from runs of DOE’s NEMS-BT model, described in Chapter 15. DOE used the version 

of NEMS based on the Annual Energy Outlook 2013 (AEO 2013).1 Emissions factors based on 

AEO 2014, which became available too late for incorporation into this analysis, indicate that a 

significant decrease in the cumulative emission reductions from the proposed standards can be 

expected if the projections of power plant utilization assumed in AEO 2014 are realized. This is 

particularly true for CO2, SO2, and Hg. For example, the estimated amount of cumulative 

emission reductions of CO2 are expected to decrease by 36% from DOE’s current estimate (from 

1,085 Mt to 697Mt) based on the projections in AEO 2014 relative to AEO 2013. DOE plans to 

use emissions factors based on the most recent AEO available for the next phase of this 

rulemaking, which may or may not be AEO 2014, depending on the timing of the issuance of the 

next rulemaking document. 

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

regulations on emissions. AEO 2013 generally represents current Federal and State legislation 

and final implementation regulations in place as of the end of December 2012. Where applicable, 

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 (from power plants and from upstream 

combustion) 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 emissions from fuel combustion during 

extraction, processing and transportation of fuel, and “fugitive” emissions (direct leakage to the 

atmosphere) of CH4 and CO2. 

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

13-1 

 
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). 

For CH4 and N2O, DOE also presents results in terms of units of carbon dioxide 

equivalent (CO2e). Gases are converted to CO2e by multiplying by the gas' global warming 

potential (GWP) over a 100 year time horizon. Based on the Fourth Assessment Report of the 

Intergovernmental Panel on Climate Change,b DOE used GWP values of 25 for CH4 and 298 for 

N2O. 

13.2 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, 

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 2013 emissions factors used for this analysis assume that CAIR remains a 

binding regulation through 2040. 

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 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 

b Forster, P., V. Ramaswamy, P. Artaxo, T. Berntsen, R. Betts, D.W. Fahey, J. Haywood, J. Lean, D.C. Lowe, G. 

Myhre, J. Nganga, R. Prinn,G. Raga, M. Schulz and R. Van Dorland. 2007: Changes in Atmospheric Constituents 

and in Radiative Forcing. In Climate Change 2007: The Physical Science Basis. Contribution of Working Group I to 

the Fourth Assessment Report of the Intergovernmental Panel on Climate Change. S. Solomon, D. Qin, M. 

Manning, Z. Chen, M. Marquis, K.B. Averyt, M.Tignor and H.L. Miller, Editors. 2007. Cambridge University 

Press, Cambridge, United Kingdom and New York, NY, USA. p. 212.

13-2 

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

that efficiency standards will reduce SO2 emissions in 2015 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 

2013, which incorporates the MATS. 

13.3 POWER SECTOR EMISSIONS FACTORS 

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

from runs of DOE’s NEMS-BT model, using the version updated to the Annual Energy Outlook 

2013 (AEO 2013). To model the impact of a standard, DOE inputs a reduction to annual energy 

demand for the corresponding end use in the appropriate start year. The NEMS-BT model is 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 is defined by dividing the 

reduction in the total emissions of a given pollutant by the reduction in total generation (in 

billion kWh). DOE uses the site energy savings multiplied by a T&D loss factor to estimate the 

reduction in generation for each TSL. Details on the approach used may be found in Coughlin 

(2013).3

 

Table 13.3.1 presents the 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 for space cooling in commercial buildings. The average factors for each year take into 

account the projected shares of each of the sources in total electricity generation. 

 The power plant emissions factor for NOx is an average for the entire U.S. The marginal 

calculation based on the NEMS-BT model accounts for the fact that NOx emissions are capped 

in some States. 

13-3 
Table 13.3.1 Power Plant Emissions Factors for Commercial Space Cooling End Use

Unit* 2016 2020 2025 2030 2035 2040

CO2 kg/MWh 589.0 589.0 603.2 593.4 734.4 795.4

SO2 g/MWh 757.6 757.6 1064.7 1059.6 1369.8 2103.0

NOx g/MWh -582.2 -582.2 -307.5 -19.0 230.2 409.4

Hg g/MWh 0.00156 0.00156 0.00118 0.00136 0.00179 0.00254

N2O g/MWh 6.9 7.2 7.2 7.1 7.1 6.9

CH4 g/MWh 48.3 50.2 50.1 49.6 49.2 47.8

* Refers to MWh of site electricity savings.

Note: These emissions factors are based on AEO 2013, the most recent version available at the time of this analysis. 

Emissions factors in AEO 2014 are significantly lower than in AEO 2013 for CO2, SO2, and Hg. In the next phase of 

this rulemaking, DOE plans to use emissions factors based on the most recent AEO available, which may or may not 

be AEO 2014, depending on the timing of the issuance of the next rulemaking document.

13.4 UPSTREAM FACTORS 

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

accounting described in appendix 10-A. See also Coughlin (2013).3 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% of total CO2 emissions for natural gas and 

1.7% 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% of total 

methane emissions for natural gas, about 95% for coal, and 93% 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 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* 2015 2020 2025 2030 2035 2040

CO2 kg/MWh 28.5 27.3 26.9 26.8 26.9 26.3

SO2 g/MWh 4.9 5.3 5.3 5.2 5.2 5.1

NOx g/MWh 361 340 334 333 336 329

Hg g/MWh 0.00001 0.00001 0.00001 0.00001 0.00001 0.00001

N2O g/MWh 0.25 0.25 0.25 0.25 0.24 0.24

CH4 g/MWh 2142 2025 2008 2025 2057 1999

* Refers to MWh of site electricity savings.

13.5 EMISSIONS IMPACT RESULTS

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

small, large, and very large air-cooled CUAC and CUHP sold in 2019-2048 for each TSL.

13-5 
Table 13.5.1 Cumulative Emissions Reduction for Small, Large, and Very Large AirCooled CUAC and CUHP Trial Standard Levels 

 Trial Standard Level

1 2 3 4

Power Sector Emissions

CO2 (million metric tons) 262 745 1049 1514

SO2 (thousand tons) 725 2077 2927 4232

NOX (thousand tons) 129 375 528 767

Hg (tons) 0.88 2.52 3.55 5.13

N2O (thousand tons) 3.7 10.7 15.1 21.9

CH4 (thousand tons) 19 54 77 111

Upstream Emissions

CO2 (million metric tons) 9 25 36 52

SO2 (thousand tons) 2 5 8 11

NOX (thousand tons) 124 350 492 710

Hg (tons) 0.00 0.01 0.02 0.03

N2O (thousand tons) 0.1 0.3 0.4 0.5

CH4 (thousand tons) 753 2127 2996 4317

Total Emissions

CO2 (million metric tons) 271 770 1085 1565

SO2 (thousand tons) 727 2083 2934 4243

NOX (thousand tons) 252 725 1021 1477

Hg (tons) 0.89 2.53 3.57 5.16

N2O (thousand tons) 3.8 11.0 15.5 22.4

CH4 (thousand tons) 772 2181 3072 4427

Note: These results are based on emissions factors in AEO 2013, the most recent version available at the time of this 

analysis. Use of emissions factors in AEO 2014 would result in a significant decrease in cumulative emissions 

reductions for CO2, SO2, and Hg. For example, the estimated decrease for CO2 emissions reductions is 36%. In the 

next phase of this rulemaking, DOE plans to use emissions factors based on the most recent AEO available, which 

may or may not be AEO 2014, depending on the timing of the issuance of the next rulemaking document.

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 equipment 

sold in 2019-2048. 

13-6 
Figure 13.5.1 CO2 Total Emissions Reduction 

Figure 13.5.2 SO2 Total Emissions Reduction 

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Figure 13.5.3 NOx Total Emissions Reduction 

Figure 13.5.4 Hg Total Emissions Reduction 

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Figure 13.5.5 N2O Total Emissions Reduction

Figure 13.5.6 CH4 Total Emissions Reduction 

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REFERENCES

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

2040, 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. 

13-10