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 IMPA CT 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 CO 2 Total Emissions Reduction ........................................................................ 13-7 Figure 13.5.2 SO 2 Total Emissions Reduction ......................................................................... 13-7 Figure 13.5.3 NO

x Total Emissions Reduction ........................................................................ 13-8 Figure 13.5.4 Hg Total Emissions Reduction .......................................................................... 13-8 Figure 13.5.5 N 2 O Total Emissions Reduction ........................................................................ 13-9 Figure 13.5.6 CH 4 Total Emissions Reduction ........................................................................ 13-9

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 mercury (Hg). The seco nd 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 cha in. 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) , i n 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 redu ctions 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 CO 2 , SO 2 , and Hg. For example, t he estimated amount of cumulative

emission reductions of CO2 ar e 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, w hich 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 201 3 generally represents current Federal and State legislation and final implementation regulations in place as of the end of December 2012. Where applicable,

s ite 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 (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 a re 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 CH 4 and CO 2

.

a http://www.epa.gov/climateleadership/guidance/ghg

- emissions.html

13 -1The emissions intensity factors are expressed in terms of physical units per MWh or MMBtu of site energy savings. Total emissions reductions are estimate d using the energy savings calculated in the national impact analysis (chapter 10).

For CH 4 and N 2 O, DOE also presents results in terms of units of carbon dioxide equivalent (CO 2 e). Gases are converted to CO 2 e by multiplying by the gas' global warming potential (GWP) over a 100 year time horizon. Based on the Fourth Assessment Report of the Intergover nmental Panel on Climate Change, b DOE used GWP values of 25 for CH 4 and 298 for

N 2 O.

13.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS

SO 2 emissions from aff ected 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 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 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 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 r esult 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. 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 Cha nge 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. 200 7. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA. p. 212.

13 -2established a standard for SO 2 (a non- HAP acid gas) as an alternative equivalent surrogate standard for acid gas HAP. The same controls are u sed 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 o f 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 estimate d NOx emissions 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 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. The se power plant emissions factors are derived from the emissions facto rs 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 -3Table 13.3.1 Power Plant Emissions Factors for Commercial Space Cooling End Use

Unit* 201 6 2020 2025 2030 2035 2040

CO 2 kg/MWh 589.0 589.0 603.2 593.4 734.4 795.4

SO 2 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

N 2 O g/MWh 6.9 7.2 7.2 7.1 7.1 6.9

CH 4 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.

E missions factors in AEO 2014 are significantly lower than in AEO 2013 for CO 2 , SO 2 , 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 d ocument.

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 furthe r 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% of total CO 2 emissions for natural gas and 1.7% for petroleum fuels. Fugitive emissions of methane 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% of total methane emissions for natural gas, about 95% for coal, and 93% 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 emiss ions factors using site (point of use) energy savings in

the denominator. Table 13.4.1 presents the electricity upstream emissions factors for selec ted

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* 2015 2020 2025 2030 2035 2040

CO 2 kg/MWh 28.5 27.3 26.9 26.8 26.9 26.3

SO 2 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

N 2 O g/MWh 0.25 0.25 0.25 0.25 0.24 0.24

CH 4 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 -5Table 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

CO 2 (million metric tons) 262 745 1049 1514

SO 2 (thousand tons) 725 2077 2927 4232

NO X (thousand tons) 129 375 528 767

Hg (tons) 0.88 2.52 3.55 5.13

N 2 O (thousand tons) 3.7 10.7 15.1 21.9

CH 4 (thousand tons) 19 54 77 111

Upstream Emissions

CO 2 (million metric tons) 9 25 36 52

SO 2 (thousand tons) 2 5 8 11

NO X (thousand tons) 124 350 492 710

Hg (tons) 0.00 0.01 0.02 0.03

N 2 O (thousand tons) 0.1 0.3 0.4 0.5

CH 4 (thousand tons) 753 2127 2996 4317

Total Emissions

CO 2 (million metric tons) 271 770 1085 1565

SO 2 (thousand tons) 727 2083 2934 4243

NO X (thousand tons) 252 725 1021 1477

Hg (tons) 0.89 2.53 3.57 5.16

N 2 O (thousand tons) 3.8 11.0 15.5 22.4

CH 4 (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 CO 2 , SO 2 , and Hg

. For example, the estimated decrease for CO 2 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 impac ts of equipment

sold in 2019-2048.

13 -6Figure 13.5.1 CO 2 Total Emissions Reduction

Figure 13.5.2 SO 2 Total Emissions Reduction 0.0 10000.0 20000.0 30000.0 40000.0 50000.0 60000.0 70000.0 80000.0201920242029203420392044204920542059206420692074kt CO 2 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

0.0 20000.0 40000.0 60000.0 80000.0 100000.0 120000.0 140000.0 160000.0 180000.0 200000.0201920242029203420392044204920542059206420692074ton SO 2 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

13 -7Figure 13.5.3 NO

x Total Emissions Reduction

Figure 13.5.4 Hg Total Emissions Reduction

-10000.0 0.0 10000.0 20000.0 30000.0 40000.0 50000.0 60000.0 70000.0201920242029203420392044204920542059206420692074ton NO

x Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

0.00 0.05 0.10 0.15 0.20 0.25201920242029203420392044204920542059206420692074ton Hg Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

13 -8Figure 13.5.5 N 2 O Total Emissions Reduction

Figure 13.5.6 CH 4 Total Emissions Reduction 0.0 200.0 400.0 600.0 800.0 1000.0 1200.0201920242029203420392044204920542059206420692074ton N 2 O Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4

0.0 20000.0 40000.0 60000.0 80000.0 100000.0 120000.0 140000.0 160000.0 180000.0 200000.0201920242029203420392044204920542059206420692074ton 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 , 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/in dex.html

3. Coughlin, K., Projections of Full

- Fuel -Cycle Energy and Emissions Metrics , 2013. Lawrence Berkeley National Laboratory. Report No. LBNL -6025E.

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