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- i CHAPTER 13. EMISSION IMPACT ANAL YSIS

TABLE OF CONTENTS

13.1 Introduction

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13.2 Approach

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13.3 Air Quality Regulations and Emissions Impacts

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- 1 CHAPTER 13. EMISSION IMPACT ANAL YSIS

13.1 INTRODUCTION

The U.S. Department of Energy ( DOE ) conduct s an emissions analysis for the no tice of proposed rulemaking (NOPR) stage

. In the emissions analysis, DOE estimate s the reduction in

power sector and site combustion emissions of carbon dioxide (CO 2 ), nitrogen oxides (NO X ), sulfur dioxide (SO 2 )

, mercury (Hg)

, methane (CH 4 ) and nitrous oxide (N 2 O) from potential energy conservation standards for the considered equipment . In addition, DOE estimate s emissions impacts in production activities (extracting, processing, and transporting fuels) that provide the energy inputs to power plants and for site c ombustion . These 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 (Aug ust 18, 2011)), the FFC analysis includes impacts on emissions of m ethane and nitrous oxide, both of which are recognized as greenhouse gases.

13.2 APPROACH

DOE conducts the emissions analysis using emissions factors that are primarily derived

from data in the latest version of the Energy Information Administration’s ( EIA’s ) Annual Energy Outlook ( AEO) , supplemented by data from other sources. EIA prepares the AEO using the National Energy Modeling System (NEMS). a Site emissions of CO 2 and NO X are estimated using emissions intensity factors from a publication of the Environme ntal Protection Agency ( EPA )

. 1 Combustion emissions of CH 4 and N 2 O are estimated using emissions intensity factors published by the EPA GHG Emissions Factors Hub. b The FFC upstream emissions are estimated based on the methodology developed by Coughlin (2013). 2 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

.

13.3 AIR QUALITY REGUL ATIONS AND EMISSIONS IMPACTS

Each annual version of NEMS incorporates the projected impacts of existing air quality regulations for emissions. The text below refers to AEO 2014, which generally represents current legislation and environmental regulations, including recent government actions, for which implementing regulations were ava ilable as of October 31, 2013. The NOPR will use emissions

factors derived from the most current available AEO data

.

a For more information about NEMS, please refer to the U.S. Department of Energy, Energy Information

Administration documentation

. A useful summary is National Energy Modeling System: An Overview 200 9

, DOE/EIA

- 0581 ( October 200 9 ), available at: http://www.eia.gov/oiaf/aeo/overview/

. b Available at http://www.epa.gov/climateleadership/inventory/ghg

- emissions.htm

.13

- 2 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 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 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 it remained in effect. c 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. d The court ordered EPA to continue administering CAIR. AEO 2014 assumes that CAIR remains a binding regulation through 2040. e

The attainment of emission s caps is typically flexible among 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 adoption 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 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 HCl 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 4 a ssumes that, in order to continue operating, coal plants must have 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 that would be established by CSAPR, 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 regu lated EGU. Therefore, DOE believes that efficiency standards will reduce

SO 2 emissions in 201 6 and beyond.

c See North Carolina v. EPA , 550 F.3d 1176 (D.C. Cir. 2008); North Carolina v. EPA , 531 F.3d 896 (D.C. Cir. 2008).

d See EME Homer City Generat ion, LP v. EPA , 696 F.3d 7, 38 (D.C. Cir. 2012).

e 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 statut ory 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 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

- 3 CSAPR established a cap on NO X emissions in eastern States and the District of Columbia. Energy conservation standards are expected to have little or no physical effect on these 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 CSAPR. Therefore, DOE estimates NO X emissions reductions from potential standards in the States where emissions are not capped.

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. For this rulemaking, DOE plans to estimate mercury emissions reductions using emissions factors

based on AEO 201 4 , which incorporates the MATS.

Power plants may emit particulates from the smoke stack, which are known as direct particulate ma tter (PM) emissions. NEMS does not account for direct PM emissions from power plants. DOE is investigating the possibility of using other methods to estimate reduction in PM emissions due to standards. The great majority of ambient PM associated with power plants is in the form of secondary sulfates and nitrates, which are produced at a significant distance from power plants by complex atmospheric chemical reactions that often involve the gaseous emissions of power plants, mainly SO 2 and NO X . The monetary b enefits that DOE estimates for

reductions in SO 2 and NO X emissions resulting from standards are in fact primarily related to the

health benefits of reduced ambient PM.13

- 4 REFERENCES

1. U.S. Environmental Protection Agency, Compilat ion of Air Pollutant Emission Factors,

AP

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

. 1998< http://www.epa.gov/ttn/chief/ap42/ >

2. Coughlin, K., Projections of Full

- Fuel

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

- 6025E.