CHAPTER 1 3. 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 EMISSIO NS FACTORS ................................................................ 13-3

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

13.5 EMISSIONS IMPACT RES ULTS ................................................................................ 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 S tandard Levels (EPCA Baseline) ................................................... 13-9

LIST OF FIGURES

Figure 13.5.1 Single Package Vertical Units : CO 2 Total Emissions Reduction ...................... 13-6 Figure 13.5.2 Single Package Vertical Units : SO 2 Total Emissions Reduction ....................... 13-6 Figure 13.5.3 Single Package Vertical Units : NO X 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 : N 2 O Total Emissions Reduction ...................... 13-8 Figure 13.5.6 Single Package Vertical Units : CH 4 Total Emissions Reduction ...................... 13-8

13 -iCHAPTER 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 (CO 2 ), nitrogen oxides (NO X ), sulfur dioxide (SO 2 ) and merc 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 p roduction 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) , i n accordance with DOE’s FFC Statement of Policy . 76 FR 51282 (August 18, 2011)

.

The analysis of power sector emissions for s ingle package vertical air conditioners (SPVACs) and single package vertical heat pumps (SPVHPs)

– or collectively single package

v ertical 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 a re realized. For example, the estimated change

for CO 2 emissions reductions is a decrease of 33%, while the estimated change for NO

x 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. AE O 2013 generally represents current Federal and State legislation and final implementation regulations in place as of the end of December 2012. 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 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 CH 4 and CO 2

.

The emissions intensity f actors 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 -113.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACT S

SO 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 t he District 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 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 Gen eration,

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 i s typically flexible among affected EGUs and is enforced through the use of emissions 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 emissions 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 emissions would occur

for SO 2 as a result of standards.

Beginning in 2015, however, SO 2 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 ruary 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 non- 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 3 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 SO 2 emissions. Under the MATS, NEMS shows a reduction in SO 2 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 SO 2 emissions allowances resulting from the lower electricity demand would be needed or used to permit offsetting increases in SO 2 emissions by any regulated EGU. Therefore, DOE believes that efficiency standards will reduce SO 2 emissions in 2015 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.

13 -2However, standards would be expected to reduce NO X emissions in the States not affected by

CAIR

, so DOE estimate d NO X emissi ons reductions from potential standards for th ose 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. The se 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 i nto account the projected shares of each of the sources used to

generate electricity to support commercial cooling

.

The power plant emissions factor for NO X is an average for the entire U.S. The marginal

calculation based on the NEMS -BT model accounts for the fact that NO X emissions are capped

in some States.

Table 13.3.1 Power Plant Emissions Factors

Unit* 2020 2025 2030 2035 2040

CO 2 kg/MWh 589 603 593 734 795

SO 2 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

N 2 O g/MWh 7.2 7.2 7.1 7.1 6.9

CH 4 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. E missions factors in AEO 2014 are significantly different than in AEO 2013 for

CO 2 and most other pollutants. In the next phase of this rulemaking, DOE plans to use emissions

factor s 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 -313.4 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 CO 2 occur during oil and gas production, but are small relative to combustion emissions. They comprise about 2.5 percent of total CO 2 emissions for natural gas

and 1.7 percent for petroleum fuels. Fugitive emissions of CH 4 occur during oil, gas and coal production. Combustion emissions of CH 4 are very small, while fugitive emissions (partic ularly for gas production) may be relatively large. Hence, fugitive emissions make up over 99 percent
of total CH 4 emissions 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. 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.

Table 13.4.1 Electricity Upstream Emissions Factors

Unit* 2020 2025 2030 2035 2040

CO 2 kg/MWh 27.9 27.3 26.9 26.8 26.9

SO 2 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

N 2 O g/MWh 0.249 0.254 0.252 0.249 0.244

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

Units Trial Standard Levels

Trial Standard Level

1 2 3 4

Primary Emissions

CO 2 (million metric tons) 8.0 20 32 34

SO 2 (thousand tons) 22 53 86 90

NO X (thousand tons) 3.6 8.9 14 14

Hg (tons) 0.03 0.06 0.10 0.11

N 2 O (thousand tons) 0.11 0.27 0.44 0.46

CH 4 (thousand tons) 0.60 1.4 2.4 2.5

Upstream Emissions

CO 2 (million metric tons) 0.28 0.68 1.1 1.2

SO 2 (thousand tons) 0.06 0.15 0.24 0.26

NO X (thousand tons) 3.9 9.4 16 17

Hg (tons) 0.0002 0.0004 0.0006 0.0006

N 2 O (thousand tons) 0.003 0.007 0.011 0.012

CH 4 (thousand tons) 24 57 94 101

Full Fuel Cycle Emissions

CO 2 (million metric tons) 8.3 20 33 35

SO 2 (thousand tons) 22 53 86 91

NO X (thousand tons) 7.4 18 30 31

Hg (tons) 0.03 0.06 0.11 0.11

N 2 O (thousand tons) 0.11 0.28 0.45 0.47

CH 4 (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. E missions factors in AEO 2014 are significantly

different than in AEO 2013 for CO 2 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 do cument.

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 -5Figure 13.5.1 Single Package Vertical Units : CO 2 Total Emissions

Reduction

Figure 13.5.2 Single Package Vertical Units : SO 2 Total Emissions

Reduction 0.0 200.0 400.0 600.0 800.0 1000.0 1200.0 1400.02015202020252030203520402045205020552060206520702075208020852090kt CO 2 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

0.0 500.0 1000.0 1500.0 2000.0 2500.0 3000.0 3500.0 4000.02015202020252030203520402045205020552060206520702075208020852090ton SO 2 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

13 -6Figure 13.5.3 Single Package Vertical Units : NO X Total Emissions

Reduction

Figure 13.5.4 Single Package Vertical Units : Hg Total Emissions

Reduction -200.0 0.0 200.0 400.0 600.0 800.0 1000.0 1200.0 1400.02015202020252030203520402045205020552060206520702075208020852090ton NO

x Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

0.0000 0.0005 0.0010 0.0015 0.0020 0.0025 0.0030 0.0035 0.0040 0.00452015202020252030203520402045205020552060206520702075208020852090ton Hg Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

13 -7Figure 13.5.5 Single Package Vertical Units : N 2 O Total Emissions

Reduction

Figure 13.5.6 Single Package Vertical Units : CH 4 Total Emissions

Reduction 0.0 5.0 10.0 15.0 20.0 25.02015202020252030203520402045205020552060206520702075208020852090ton 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 3000.0 3500.0 4000.02015202020252030203520402045205020552060206520702075208020852090ton CH 4 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

13 -8Although 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., EP CA 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

CO 2 (million metric tons) 28 40 52 54

SO 2 (thousand tons) 76 107 140 14 5

NO X (thousand tons) 12 18 23 23

Hg (tons) 0.09 0.13 0.17 0.1 8

N 2 O (thousand tons) 0.39 0.55 0.71 0.73

CH 4 (thousand tons) 2.1 3.0 3.9 4.0

Upstream Emissions

CO 2 (million metric tons) 1.0 1.4 1.8 1.9

SO 2 (thousand tons) 0.21 0.30 0.39 0.41

NO X (thousand tons) 14 19 25 26

Hg (tons) 0.0005 0.0007 0.0010 0.0010

N 2 O (thousand tons) 0.01 0 0.01 4 0.0 18 0.0 19

CH 4 (thousand tons) 83 116 154 160

Full Fuel Cycle Emissions

CO 2 (million metric tons) 29 41 54 56

SO 2 (thousand tons) 76 10 8 141 145

NO X (thousand tons) 26 37 48 50

Hg (tons) 0.09 0.13 0.17 0.1 8

N 2 O (thousand tons) 0.40 0.56 0.73 0.75

CH 4 (thousand tons) 85 1 19 157 16 4

13 -9REFERENCES

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.

Lawren ce Berkeley National Laboratory. Report No. LBNL -6025E.

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