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 ................................................................................ 13-4

LIST OF TABLES

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

Table 13.4.1 Electricity Upstream Emissions Factors ............................................................ 13-4

Table 13.5.1 Cumulative Emissions Reduction Estimated for Single Package Vertical 

Units Trial Standard Levels ............................................................................... 13-5

Table 13.5.2 Cumulative Emissions Reduction Estimated for Single Package Vertical 

Units Trial Standard Levels (EPCA Baseline)................................................... 13-9

LIST OF FIGURES

Figure 13.5.1 Single Package Vertical Units: CO2 Total Emissions Reduction ...................... 13-6

Figure 13.5.2 Single Package Vertical Units: SO2 Total Emissions Reduction....................... 13-6

Figure 13.5.3 Single Package Vertical Units: NOX Total Emissions Reduction ..................... 13-7

Figure 13.5.4 Single Package Vertical Units: Hg Total Emissions Reduction ........................ 13-7

Figure 13.5.5 Single Package Vertical Units: N2O Total Emissions Reduction ...................... 13-8

Figure 13.5.6 Single Package Vertical Units: CH4 Total Emissions Reduction ...................... 13-8

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 

extracting, 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 (August 18, 2011). 

The analysis of power sector emissions for single package vertical air conditioners 

(SPVACs) and single package vertical heat pumps (SPVHPs) – or collectively single package 

vertical units (SPVUs) – 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 change 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. For example, the estimated change 

for CO2 emissions reductions is a decrease of 33%, while the estimated change for NOx

emissions reductions is an increase of 13%. 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. 

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. 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). 

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

13-1 

 
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 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 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 (February 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 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.

13-2 
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 transmission-and-distribution 

(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 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 commercial cooling. The factors presented in Table 13.3.1 for each year are 

weighted averages that take into account the projected shares of each of the sources used to 

generate electricity to support commercial cooling. 

 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. 

Table 13.3.1 Power Plant Emissions Factors 

Unit* 2020 2025 2030 2035 2040

CO2 kg/MWh 589 603 593 734 795

SO2 g/MWh 758 1065 1060 1370 2103

NOx g/MWh -582 -308 -19 230 409

Hg g/MWh 0.00156 0.00118 0.00136 0.00179 0.00254

N2O g/MWh 7.2 7.2 7.1 7.1 6.9

CH4 g/MWh 50 50 50 49 48

* Refers to 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 different than in AEO 2013 for 

CO2 and most other pollutants. 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.

13-3 
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

 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 CH4 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 CH4 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 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. 

Table 13.4.1 Electricity Upstream Emissions Factors

Unit* 2020 2025 2030 2035 2040

CO2 kg/MWh 27.9 27.3 26.9 26.8 26.9

SO2 g/MWh 5.0 5.3 5.3 5.2 5.2

NOx g/MWh 353 340 334 333 336

Hg g/MWh 0.000013 0.000014 0.000014 0.000013 0.000013

N2O g/MWh 0.249 0.254 0.252 0.249 0.244

CH4 g/MWh 2084 2025 2008 2025 2057

* Refers to site electricity savings.

13.5 EMISSIONS IMPACT RESULTS

Table 13.5.1 presents the estimated, for each TSL, cumulative emissions reductions for 

the lifetime of equipment sold over the 30-year analysis period. 

13-4 
Table 13.5.1 Cumulative Emissions Reduction Estimated for Single Package Vertical 

Units Trial Standard Levels 

Trial Standard Level

1 2 3 4 

Primary Emissions

CO2 (million metric tons) 8.0 20 32 34 

SO2 (thousand tons) 22 53 86 90

NOX (thousand tons) 3.6 8.9 14 14 

Hg (tons) 0.03 0.06 0.10 0.11

N2O (thousand tons) 0.11 0.27 0.44 0.46 

CH4 (thousand tons) 0.60 1.4 2.4 2.5

Upstream Emissions

CO2 (million metric tons) 0.28 0.68 1.1 1.2

SO2 (thousand tons) 0.06 0.15 0.24 0.26 

NOX (thousand tons) 3.9 9.4 16 17

Hg (tons) 0.0002 0.0004 0.0006 0.0006 

N2O (thousand tons) 0.003 0.007 0.011 0.012

CH4 (thousand tons) 24 57 94 101 

Full Fuel Cycle Emissions

CO2 (million metric tons) 8.3 20 33 35 

SO2 (thousand tons) 22 53 86 91

NOX (thousand tons) 7.4 18 30 31 

Hg (tons) 0.03 0.06 0.11 0.11

N2O (thousand tons) 0.11 0.28 0.45 0.47 

CH4 (thousand tons) 24 59 97 103

Note: These results are based on emissions factors in AEO 2013, the most recent version 

available at the time of this analysis. Emissions factors in AEO 2014 are significantly 

different than in AEO 2013 for CO2 and most other pollutants. 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 total annual emissions reductions for each 

pollutant and TSL. The reductions reflect the lifetime impacts of equipment sold over the 30-

year analysis period. 

13-5 
Figure 13.5.1 Single Package Vertical Units: CO2 Total Emissions 

Reduction

Figure 13.5.2 Single Package Vertical Units: SO2 Total Emissions 

Reduction

0.0

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Figure 13.5.3 Single Package Vertical Units: NOX Total Emissions 

Reduction

Figure 13.5.4 Single Package Vertical Units: Hg Total Emissions 

Reduction

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TSL 1 TSL 2 TSL 3 TSL 4

13-7 
Figure 13.5.5 Single Package Vertical Units: N2O Total Emissions 

Reduction

Figure 13.5.6 Single Package Vertical Units: CH4 Total Emissions 

Reduction

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13-8 
Although DOE is statutorily required to evaluate impacts of this rulemaking relative to 

the ASHRAE baseline, for informational purposes only, Table 13.5.2 shows the cumulative 

emissions reductions for the lifetime of equipment sold over the 30-year analysis period

compared to a base case including the current federal minimum standards (i.e., EPCA baseline). 

Table 13.5.2 Cumulative Emissions Reduction Estimated for Single Package Vertical 

Units Trial Standard Levels (EPCA Baseline) 

Trial Standard Level

1 2 3 4 

Primary Emissions

CO2 (million metric tons) 28 40 52 54 

SO2 (thousand tons) 76 107 140 145

NOX (thousand tons) 12 18 23 23 

Hg (tons) 0.09 0.13 0.17 0.18

N2O (thousand tons) 0.39 0.55 0.71 0.73 

CH4 (thousand tons) 2.1 3.0 3.9 4.0

Upstream Emissions

CO2 (million metric tons) 1.0 1.4 1.8 1.9

SO2 (thousand tons) 0.21 0.30 0.39 0.41 

NOX (thousand tons) 14 19 25 26

Hg (tons) 0.0005 0.0007 0.0010 0.0010 

N2O (thousand tons) 0.010 0.014 0.018 0.019

CH4 (thousand tons) 83 116 154 160 

Full Fuel Cycle Emissions

CO2 (million metric tons) 29 41 54 56 

SO2 (thousand tons) 76 108 141 145

NOX (thousand tons) 26 37 48 50 

Hg (tons) 0.09 0.13 0.17 0.18

N2O (thousand tons) 0.40 0.56 0.73 0.75 

CH4 (thousand tons) 85 119 157 164

13-9 
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