13

- i CHAPTER 13. EMISSIONS ANALYSIS

TABLE OF CONTENTS

13.1 INTRODUCTION

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

- 1

13.2 APPROACH

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

- 1

13.3 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS

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

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- 1 CHA PTER 13. EMISSIONS ANALYSIS

13.1 INTRODUCTION

DOE will conduct an emissions analysis for the no tice of proposed rulemaking

. In the emissions analysis, DOE will estimate the reduction in power sector emissions of carbon dioxide (CO 2 ), nitrogen oxides (NO X ), sulfur dioxide (SO 2 ) and mercury (Hg) from potential energy conservation standards for the considered products. In addition, DOE will estimate emissions impacts in production activities (extracting, processing, and transporting fuels) that provide the energy inputs to power plants. 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

Pol icy (76 FR 51282 (Aug. 18, 2011)), the FFC analysis includes impacts on emissions of methane and nitrous oxide, both of which are recognized as greenhouse gases.

13.2 APPROACH

The analysis of power sector emissions uses marginal emissions intensity factors d erived

from runs of the NEMS model. DOE use s the version of NEMS based on the most recent Annual Energy Outlook (AEO)

. Site emissions of CO 2 and NO X are estimated using emissions intensity factors from a publication of the EPA

. 1 Combustion emissions of CH 4 and N 2 O are estimated using emissions intensity factors published by the Environmental Protection Agency (EPA)

GHG Emissions Factors Hub. a 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 REGULATIONS AND EMISSIONS IMPACTS

Each annual version of NEMS incorporates the projected impacts of existing air quality regulations on emissions. The text below refers to the Annual Energy Outlook 201 3 (AEO 2013)

.

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 remains in effect. 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). On July 6, 2011 EPA issued a replacement for CAIR, the Cross

- State Air Pollution Rule (CSAPR; also known as the Transport Rule). 76 FR 48208 (August 8, 2011).

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

- emissions.html13

- 2 The attainment of emissions caps is typically flexible among EGUs and is en forced 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 of fsetting 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 redu ctions 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,

20 11. 77 FR 9304 (Feb. 16, 2012) b 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 stand ard 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 M ATS, 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 that would be established by CSAPR, so it is unlikely that excess SO 2 emissions

allowance s 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.

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 fro m 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, D OE plans to estimate mercury emissions reductions using emissions factors

based on AEO 201 3 , which incorporates the MATS.

Power plants may emit particulates from the smoke stack, which are known as direct particulate matter (PM) emissions. NEMS does not a ccount for direct PM emissions from power plants. DOE is investigating the possibility of using other methods to estimate reduction in PM

b On July 20, 2012, EPA announced a partial stay, for a limited duration, of the effectiveness of national new source emission standards for hazardous air pollutants from coal

- and oil

- fired electric utility steam generating units. More

at: www.epa.gov/airq uality/powerplanttoxics/pdfs/20120727staynotice.pdf13

- 3 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 benefits that DOE estimates for

reduc tions 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, 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/ >

2. Coughlin, K., Projections of Full

- Fuel

- Cycle Energy and Emissions Metrics , 2013.

Law rence Berkeley National Laboratory. Report No. LBNL

- 6025E.