CHAPTER 9. EMISSIONS ANALYSIS

TABLE OF CONTENTS

9.1 INTRODUCTION ........................................................................................................... 9-1

9.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS................................. 9-2

9.3 POWER SECTOR AND SITE EMISSIONS FACTORS............................................... 9-3

9.4 UPSTREAM FACTORS ................................................................................................. 9-4

9.5 EMISSIONS IMPACT RESULTS.................................................................................. 9-5

9.5.1 Small Three-Phase Air-Cooled Air Conditioners and Heat Pumps <65,000 

Btu/h ......................................................................................................................... 9-5

9.5.2 Water-Source Heat Pumps....................................................................................... 9-10

LIST OF TABLES

Table 9.3.1 Power Plant Emissions Factors (Small Commercial Air-Cooled Air 

Conditioners and Heat Pumps) ............................................................................ 9-4

Table 9.3.2 Power Plant Emissions Factors (Water-Source Heat Pumps).............................. 9-4

Table 9.4.1 Electricity Upstream Emissions Factors.............................................................. 9-5

Table 9.5.1 Cumulative Emissions Reduction for Potential Standard for Small ThreePhase Air-Cooled Air Conditioners and Heat Pumps <65,000 Btu/h.................. 9-6

Table 9.5.2 Cumulative Emissions Reduction for Potential Standard for Water-Source 

Heat Pumps........................................................................................................ 9-10

LIST OF FIGURES

Figure 9.5.1 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: CO2

Total Emissions Reduction .................................................................................. 9-7

Figure 9.5.2 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: SO2

Total Emissions Reduction .................................................................................. 9-7

Figure 9.5.3 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: NOx

Total Emissions Reduction .................................................................................. 9-8

Figure 9.5.4 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Hg 

Total Emissions Reduction .................................................................................. 9-8

Figure 9.5.5 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: N2O 

Total Emissions Reduction .................................................................................. 9-9

Figure 9.5.6 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: CH4

Total Emissions Reduction .................................................................................. 9-9

Figure 9.5.7 Water-Source Heat Pumps: CO2 Total Emissions Reduction............................ 9-11

Figure 9.5.8 Water-Source Heat Pumps: SO2 Total Emissions Reduction............................ 9-11

Figure 9.5.9 Water-Source Heat Pumps: NOx Total Emissions Reduction ........................... 9-12

Figure 9.5.10 Water-Source Heat Pumps: Hg Total Emissions Reduction.............................. 9-12

Figure 9.5.11 Water-Source Heat Pumps: N2O Total Emissions Reduction ........................... 9-13

Figure 9.5.12 Water-Source Heat Pumps: CH4 Total Emissions Reduction............................ 9-13

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CHAPTER 9. EMISSIONS ANALYSIS

9.1 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 

11 and in the report “Utility Sector Impacts of Reduced Electricity Demand” (Coughlin, 2014).2

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

publication of the Environmental Protection Agency (EPA).

3

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).4 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 8).

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

equivalent (CO2e). Gases are converted to CO2e by multiplying the physical units by the gas

global warming potential (GWP) over a 100 year time horizon. Based on the Fifth Assessment 

Report of the Intergovernmental Panel on Climate Change,5 DOE used GWP values of 28 for 

CH4 and 265 for N2O.b

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

b The values are without inclusion of climate-carbon feedbacks in response to emissions of the indicated non-CO2 

gases.

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9.2 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.

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. c

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

c 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 2014, 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.

9-2

 
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 

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 emissions factors based on AEO 

2014, which incorporates the MATS.

9.3 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).

Table 9.3.1 and Table 9.3.2 present 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 buildings for space cooling and space 

heating. The average factors for each year take into account the projected shares of each of the 

sources in total electricity generation. For mall commercial air-cooled air-conditioning and 

heating equipment, the emissions factors refer to the power plants that supply electricity for 

space cooling. For water-source heat pumps, the factors are calculated as the weighted average of 

emissions factors of plants that supply electricity for space cooling (80%) and space heating 

(20%).

9-3
Table 9.3.1 Power Plant Emissions Factors (Small Commercial Air-Cooled Air 

Conditioners and Heat Pumps)

Unit* 2020 2025 2030 2035 2040

CO2 kg/MWh 695 620 560 514 472

SO2 g/MWh 649 507 426 357 319

NOx g/MWh 536 450 394 348 316

Hg g/MWh 0.00200 0.00156 0.00132 0.00110 0.00098

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.

Table 9.3.2 Power Plant Emissions Factors (Water-Source Heat Pumps)

Unit* 2020 2025 2030 2035 2040

CO2 kg/MWh 705 628 567 519 477

SO2 g/MWh 671 524 441 369 330

NOx g/MWh 549 460 402 355 322

Hg g/MWh 0.00207 0.00162 0.00136 0.00114 0.00102

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.

9.4 UPSTREAM FACTORS 

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

accounting described in appendix 8A. See also Coughlin (2013) and Coughlin (2014). 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).6 This review includes estimates of the difference between 

9-4
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.7, 8 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 9.4.1 presents the electricity 

upstream emissions factors for selected years. These were used to estimate the emissions 

associated with the decreased electricity use. The caps that apply to power sector NOX emissions 

do not apply to upstream combustion sources.

Table 9.4.1 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 0.000012 0.000011 0.000011 0.000010 0.000010

N2O g/MWh 0.252 0.247 0.241 0.234 0.228

CH4 g/MWh 2149 2195 2216 2248 2255

* Refers to site electricity savings.

9.5 EMISSIONS IMPACT RESULTS

9.5.1 Small Three-Phase Air-Cooled Air Conditioners and Heat Pumps <65,000 Btu/h

Table 9.5.1 presents the estimated cumulative emissions reductions for the lifetime of 

equipment sold in 2017-2046 for the ASHRAE level and 2020-2046 for each additional 

efficiency level for the equipment classes triggered by ASHRAE, and 2019-2048 for split system 

air conditioners. Negative values indicate that emissions increase.

9-5
Table 9.5.1 Cumulative Emissions Reduction for Potential Standard for Small ThreePhase Air-Cooled Air Conditioners and Heat Pumps <65,000 Btu/h

Efficiency Level

ASHRAE/0 1 2 3 4 5

Power Sector Emissions

 CO2 (million metric tons) 3.7 8.9 16.8 20.8 24.3 25.9

 SO2 (thousand tons) 2.9 6.9 13.0 16.1 18.8 20.1

 NOX (thousand tons) 2.8 6.7 12.6 15.6 18.2 19.4

 Hg (tons) 0.01 0.02 0.04 0.05 0.06 0.06

 N2O (thousand tons) 0.05 0.13 0.24 0.30 0.35 0.37

 CH4 (thousand tons) 0.38 0.90 1.69 2.10 2.45 2.61

Upstream Emissions

 CO2 (million metric tons) 0.22 0.54 1.00 1.24 1.45 1.54

 SO2 (thousand tons) 0.04 0.09 0.17 0.22 0.25 0.27

 NOX (thousand tons) 3.2 7.6 14.3 17.7 20.7 22.0

 Hg (tons) 0.0001 0.0002 0.0004 0.0005 0.0006 0.0006

 N2O (thousand tons) 0.002 0.005 0.009 0.011 0.012 0.013

 CH4 (thousand tons) 19 45 83 103 121 128

Total FFC Emissions

 CO2 (million metric tons) 4.0 9.5 17.8 22.1 25.8 27.4

 SO2 (thousand tons) 2.9 7.0 13.2 16.4 19.1 20.3

 NOX (thousand tons) 6.0 14.3 26.8 33.4 38.9 41.4

 Hg (tons) 0.01 0.02 0.04 0.05 0.06 0.06

 N2O (thousand tons) 0.06 0.13 0.25 0.31 0.36 0.39

 CH4 (thousand tons) 19 45 85 105 123 131

Note: The potential emissions reduction for efficiency levels more stringent than those specified by ASHRAE 

Standard 90.1-2013 were calculated relative to the efficiency levels that would result if ASHRAE Standard 90.1-

2013 standards were adopted.

Figure 9.5.1 through Figure 9.5.6 show the annual reductions for total emissions for each 

type of emission from each efficiency level. The reductions reflect the lifetime impacts of 

equipment sold in 2017-2046 for the ASHRAE level and 2020-2046 for each additional 

efficiency level for the equipment classes triggered by ASHRAE, and 2019-2048 for split system 

air conditioners.

9-6
Figure 9.5.1 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: CO2 Total Emissions Reduction

Figure 9.5.2 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: SO2 Total Emissions Reduction

9-7
Figure 9.5.3 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: NOx Total Emissions Reduction

Figure 9.5.4 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Hg Total Emissions Reduction

9-8
Figure 9.5.5 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: N2O Total Emissions Reduction

Figure 9.5.6 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: CH4 Total Emissions Reduction

9-9
9.5.2 Water-Source Heat Pumps

Table 9.5.2 presents the estimated cumulative emissions reductions for the lifetime of 

equipment sold in 2016-2045 for the ASHRAE level and 2020-2045 for each additional 

efficiency level. Negative values indicate that emissions increase.

Table 9.5.2 Cumulative Emissions Reduction for Potential Standard for WaterSource Heat Pumps

Efficiency Level

ASHRAE/0* 1 2 3 4 5

Power Sector Emissions

 CO2 (million metric tons) - 1.4 16.3 30.5 41.6 56.8

 SO2 (thousand tons) - 1.1 12.9 24.2 32.9 44.9

 NOX (thousand tons) - 1.1 12.3 23.1 31.4 42.9

 Hg (tons) - 0.003 0.040 0.075 0.101 0.139

 N2O (thousand tons) - 0.02 0.23 0.44 0.60 0.81

 CH4 (thousand tons) - 0.14 1.63 3.06 4.17 5.69

Upstream Emissions

 CO2 (million metric tons) - 0.08 0.97 1.81 2.47 3.37

 SO2 (thousand tons) - 0.01 0.17 0.32 0.43 0.59

 NOX (thousand tons) - 1.2 13.8 25.9 35.2 48.0

 Hg (tons) - 0.00003 0.00037 0.00070 0.00095 0.00130

 N2O (thousand tons) - 0.001 0.008 0.016 0.021 0.029

 CH4 (thousand tons) - 7.0 80.5 150.8 205.2 279.9

Total FFC Emissions

 CO2 (million metric tons) - 1.5 17.3 32.4 44.0 60.1

 SO2 (thousand tons) - 1.1 13.1 24.5 33.3 45.5

 NOX (thousand tons) - 2.3 26.1 49.0 66.7 91.0

 Hg (tons) - 0.004 0.040 0.075 0.102 0.140

 N2O (thousand tons) - 0.02 0.24 0.45 0.62 0.84

 CH4 (thousand tons) - 7.2 82.1 153.9 209.4 285.6

Note: The potential emissions reduction for efficiency levels more stringent than those specified by ASHRAE 

Standard 90.1-2013 were calculated relative to the efficiency levels that would result if ASHRAE Standard 90.1-

2013 standards were adopted. *

There are no reductions for the ASHRAE level because there is no market share projected at the federal baseline in 

the base case.

Figure 9.5.7 through Figure 9.5.12 show the annual reductions for total emissions for 

each type of emission from each efficiency level. The reductions reflect the lifetime impacts of 

equipment sold in 2016-2045 for the ASHRAE level and 2020-2045 for each additional 

efficiency level.

9-10
Figure 9.5.7 Water-Source Heat Pumps: CO2 Total Emissions Reduction

Figure 9.5.8 Water-Source Heat Pumps: SO2 Total Emissions Reduction

0.0

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ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

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Figure 9.5.9 Water-Source Heat Pumps: NOx Total Emissions Reduction

Figure 9.5.10 Water-Source Heat Pumps: Hg Total Emissions Reduction

0.0

500.0

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ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

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0.0005

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ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

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Figure 9.5.11 Water-Source Heat Pumps: N2O Total Emissions Reduction

Figure 9.5.12 Water-Source Heat Pumps: CH4 Total Emissions Reduction

0.0

5.0

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15.0

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30.0

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ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

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1. Energy Information Administration, Annual Energy Outlook 2014 with Projections to 

2040, 2014 Washington, DC. <http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf>

2. Coughlin, K., Utility Sector Imacts of Reduced Electricity Demand, 2014. Lawrence 

Berkeley National Laboratory. Report No. LBNL-6864E. 

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AP-42, Fifth Edition, Volume I: Stationary Point and Area Sources. 1998. 

www.epa.gov/ttn/chief/ap42/index.html

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

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Editor. 2013. Cambridge University Press: Cambridge, United Kingdom and New York, 

NY, USA

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

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

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

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

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