CHAPTER 1 3

. EMISSIONS ANALYSIS

TABLE OF CONTENTS

13.1 INTRODUCTION

................................ ................................ ................................ ......... 13

- 1

13.2 AIR QUALITY REGULATI ONS AND EMISSIONS IM PACTS

............................... 13

- 1

13.3 POWER SECTOR AND SIT E EMISSIONS FACTORS

................................ ............. 13

- 3

13.4 UPSTREAM FACTORS

................................ ................................ ............................... 13

- 4

13.5 EMISSIONS IMPACT RES ULTS

................................ ................................ ................ 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: CO 2 Total Emissions Reduction

...................... 13

- 7

Figure 13.5.2 Commercial Clothes Washers: SO 2 Total Emissions Reduction

....................... 13

- 7

Figure 13.5.3 Commercial Clothes Washers: NO

x 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: N 2 O Total Emissions Reduction

...................... 13

- 9

Figure 13.5.6 Commercial Clothes Washers: CH 4 Total Emissions Reduction

...................... 13

- 9

13

- iCHAPTER 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 (CO 2 ), nitrogen oxides (NO X ), sulfur dioxide (SO 2 ) and me rc ury (Hg). The

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

greenhouse gases, methane (CH 4 ) and nitrous oxide (N 2 O), 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 . T he associated

emissions are referred to as upstream emissions. Together, these emissions account for the full

fuel

- cycle ( FFC)

, i n 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 c hapter

15 and in the report “Utility Sector Impacts of Reduced Electricity De mand” ( Coughlin

, 2014). 4

Site emissions of CO 2 and NO X are estimated using emissions intensity factors from a

publication of the Environmental Protection Agency (EPA)

. 2

Combustion emissions of CH 4 and N 2 O are estimated using emissions intensity factors

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

estimated based on the methodolo gy developed by Coughlin (2013). 3 The upstream emissions

include both emissions from fuel combustion during extraction, p rocessing and transportation of

fuel, and “fugitive” emissions (direct leakage to the atmosphere) of CH 4 and CO 2

.

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 REGULATI ONS AND EMISSIONS IMPACT S

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

regulations on emissio ns. 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

13

- 1SO 2 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 SO 2 for affected EGUs in the 48 contiguous states and the Dis trict of Columbia

(D.C.). SO 2 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 Ru le (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 201 4 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 emissi ons allowances and tradable permits.

Under existing EPA regulations, any excess SO 2 emissions allowances resulting from the lower

electricity demand caused by the imposition of an efficiency standard could be used to permit

offsetting increases in SO 2 emis sions by any regulated EGU. In past rulemakings, DOE

recognized that there was uncertainty about the effects of efficiency standards on SO 2 emissions

covered by the existing cap

- and

- trade system, but it concluded that no reductions in power sector

emission s would occur for SO 2 as a result of standards.

Beginning in 201 6 , however, SO 2 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 SO 2 (a non

- HAP acid gas) as an alternative

equivalent surrogate standard for acid gas HAP. The same controls are used to reduce HAP and

n on

- HAP acid gas; thus, SO 2 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

201 4 assumes that, in order to continue operating, coal plants must hav e either flue gas

desulfurization or dry sorbent injection systems installed by 201 6 . Both technologies, which are

used to reduce acid gas emissions, also reduce SO 2 emissions. Under the MATS, e missions will

be far below the cap established by CAIR, so it is unlikely that excess SO 2 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 stat es 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 e missions 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 SO 2 emissions.

13

- 2increases in SO 2 emissions by any regulated EGU. Therefore, DOE believes that efficiency

standards will reduce SO 2 emissions in 201 6 and beyond.

CAIR established a cap on NO

x emissions in 28 eastern States and the District of

Columbia. Energy conservation standards are expected to have little effect on NO

x emissions in

those States covered by CSAPR because excess NO

x emissions allowances resulting from the

lower electricity demand could be used to permit offsetting increases in NO

x emissions.

However, standards would be expected to reduce NO

x 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 emi ssions 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 use d may be found in Coughlin ( 2014 ). 4

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

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 source s 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

CO 2 kg/MWh 710 632 571 522 478

SO 2 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

N 2 O g/MWh 7.2 7.1 6.9 6.6 6.4

CH 4 g/MWh 50 49 48 46 45

* Refers to site electricity savings.

13

- 3Table 13.3.2 Natural Gas Site Combustion Emissions Factors

Unit* 2020 2025 2030 2035 2040

CO 2 kg/mcf 54.2 54.2 54.2 54.2 54.2

SO 2 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

N 2 O g/ mcf 0.102 0.102 0.102 0.102 0.102

CH 4 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 (201 3 ) 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 CO 2 occur during oil and gas production, but are small relative to

combustion emi ssions. They comprise about 2.5 percent of total CO 2 em issions for natural gas

and 1.7 percent for petroleum fuels. Fugitive emissions of met hane occur during oil, gas and coal

production. Combustion emissions of CH 4 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 emis sions for natural gas, about 95 percent for coal, and 93 percent for

petroleum fuels.

U pstream emissions factors account for both fugitive emissions and combustion

emissions in extraction, processing, and transport of primary fuels. Fugitive emissions factors fo r

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 emi ssions 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 NO X emissions do not apply to upstream combustion sources.

13

- 4Table 13.4.1 Electricity Upstream Emissions Factors

Unit 2020 2025 2030 2035 2040

CO 2 kg/MWh 29.1 29.4 29.7 29.9 29.8

SO 2 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

N 2 O g/MWh 0.25 0.25 0.24 0.23 0.23

CH 4 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

CO 2 kg/ mcf 7.1 7.2 7.3 7.4 7.4

SO 2 g/ mcf 0.030 0.031 0.031 0.032 0.032

NOx g/ mcf 101 103 105 105 105

N 2 O g/ mcf 0.011 0.011 0.012 0.012 0.012

CH 4 g/ mcf 659 665 666 670 670

13.5 EMISSIONS IMPACT RES ULTS

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.

13

- 5Table 13.5.1 Cumulative Emissions Red uction for Potential Standards for Commercial

Clothes Washers

TSL

1 2 3 4

Power Sector and Site Emissions

CO 2 (million metric tons) 3.4 3.8 7.5 6.9

SO 2 (thousand tons) 1.782 1.861 4.241 4.211

NO X (thousand tons) 3.5 4.0 7.4 6.5

Hg (tons) 0.00548 0.00571 0.01304 0.01296

CH 4 (thousand tons) 0.2 0.2 0.5 0.5

N 2 O (thousand tons) 0.032 0.034 0.075 0.073

Upstream Emissions

CO 2 (million metric tons) 0.3 0.3 0.6 0.5

SO 2 (thousand tons) 0.022 0.023 0.051 0.051

NO X (thousand tons) 4.5 5.1 9.2 8.0

Hg (tons) 0.00005 0.00005 0.00011 0.00011

CH 4 (thousand tons) 27.7 31.8 56.6 48.8

N 2 O (thousand tons) 0.001 0.001 0.003 0.003

Total Emissions

CO 2 (million metric tons) 3.7 4.1 8.1 7.4

SO 2 (thousand tons) 1.804 1.884 4.293 4.262

NO X (thousand tons) 8.0 9.1 16.6 14.5

Hg (tons) 0.00552 0.00576 0.01315 0.01307

CH 4 (thousand tons) 28.0 32.0 57.2 49.3

N 2 O (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

.

13

- 6Figure 13.5.1 Commercial Clothes Washers : CO 2 Total Emissions

Reduction

Figure 13.5.2 Commercial Clothes Washers : SO 2 Total Emissions

Reduction 0.0 50.0 100.0 150.0 200.0 250.0 300.0 350.0 400.0201820232028203320382043204820532058206320682073kt CO

2 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

0.0 20.0 40.0 60.0 80.0 100.0 120.0 140.0 160.0 180.0 200.0201820232028203320382043204820532058206320682073ton SO

2 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

13

- 7Figure 13.5.3 Commercial Clothes Washers : NO

x Total Emissions

Reduction

Figure 13.5.4 Commercial Clothes Washers : Hg Total Emissions

Reduction 0.0 100.0 200.0 300.0 400.0 500.0 600.0 700.0 800.0201820232028203320382043204820532058206320682073ton NO

x Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

0.00000 0.00005 0.00010 0.00015 0.00020 0.00025 0.00030 0.00035 0.00040 0.00045 0.00050201820232028203320382043204820532058206320682073ton Hg Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

13

- 8Figure 13.5.5 Commercial Clothes Washers : N 2 O Total Emissions

Reduction

Figure 13.5.6 Commercial Clothes Washers : CH 4 Total Emissions

Reduction 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0201820232028203320382043204820532058206320682073ton N

2 O Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

0.0 500.0 1000.0 1500.0 2000.0 2500.0 3000.0201820232028203320382043204820532058206320682073ton CH

4 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

13

- 9REFERENCES

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. Environmen tal 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 Labora tory. 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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