16 -i CHAPTER 16. EMISSIONS IMPACT ANALYSIS

TABLE OF CONTENTS

16.1 INTRODUCTION ......................................................................................................... 16-1 16.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS ............................... 16-1 16.3 POWER SECTOR EMISSIO NS FACTORS ................................................................ 16-3 16.4 UPSTREAM AND GHG EMI SSIONS FACTORS ...................................................... 16-3 REFERENCES .......................................................................................................................... 16-416 -1 CHAPTER 16. EMISSIONS IMPACT ANA LYSIS

16.1 INTRODUCTION

As p ar t of its notice of proposed rulemaking , the U.S. Department of Energy (DO E) will conduct an emissions analysis consisting of two components. The first component estimates the effect of potential energy conservation standards on power sector combustion 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 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 fullfuel

- 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 derived from runs of DOE’s NEMS -BT model, described in chapter 15 of the interim technical support document (TSD) . DOE will use the latest version of NEMS based on the Annual Energy Outlook (AEO)

. 1 Each annual version of NEMS incorporates the projected impacts of existing air quality regulations on emissions. For example, AEO2012 generally represented current Federal and State legislation and final implementation regulations in place as of the end of December 2011.

Combustion emissions of CH 4 and N 2 O are estimated using emissions intensity factors published by the U.S. Environmental Protection Agency ( EPA ), GHG Emissions Factors Hub. a The FFC upstream emissions a re estimated based on the methodology developed by Coughlin (2012). 2 The upstream emissio ns 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 factors are expressed in terms of physical units per MWh or MMBtu of site energy savings. Total emissions reductions will be estimated using the energy savings calculated in the national impact analysis (chapter 11 of the interim TSD ).

16.2 AIR QUALITY REGULATI ONS AND EMISSIONS IMPACT S

SO 2 emissions from affe cted 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 S tates and the District of Columbia (D.C.). SO 2 emissions from 28 eastern S tates 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,

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

- emissions.html16 -2 the Cross-State Air Pollution Rule (CSAPR). 76 FR 48208 (August 8, 2011). The AEO2012 NEMS assume d the implementation of CSAPR. b

The attainment of emissions caps is typically flexible among affected EGUs and is enforced through the use of emissions allowances and tradable permits. Under existing EPA regul ations, 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 recogniz ed 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. 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. AEO2012 assume d 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 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 o ffsetting 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 28 eastern S tates 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 CSAPR

, so DOE will estimate NO X 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

b On December 30, 2011, the D.C. Circuit stayed the new rules while a panel of judges reviews them, and told EPA to continue enforcing CAIR . S ee EME Homer City Generation, LP v. EPA

, Order, No. 11

- 1302 , Slip Op. at *2 (D.C. Cir. Dec. 30

, 2011). On August 21, 20 12, the D.C. Circuit vacated CSAPR. See EME Homer City Generation, LP v. EPA

, No. 11

- 1302

, 2012 WL 3570721 at *24 (D.C. Cir. Aug. 21, 2012). The court required EPA to continue administering CAIR. AEO2012 had been finalized prior to both these decisions, ho wever. DOE understands that CAIR and CSAPR are similar with respect to their effect on emissions impacts of energy efficiency standards.16 -3 emissions. DOE will estimate mercury emissions reductions using the NEMS -BT based on an AEO version that incorporates the MATS , if applicable.

16.3 POWER SECTOR EMIS SIONS FACTORS

The analysis of power sector emissions will use marginal emissions intensity factors derived from runs of DOE’s latest NEMS

- BT model

. To model the impact of a standard, DOE will input a reduction to annual energy demand for the corresponding end use in the appropriate start year. The NEMS -BT model will be 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 will be defined by dividing the reduction in the total emissions of a given pollutant by the reduction in total generation (in billion kWh). DOE will use the site energy savings multiplied by a T&D loss factor to estima te the reduction in generation for each TSL

. Details on this approach may be found in Coughlin (2012). 2

16.4 UPSTREAM AND GHG EMI SSIONS FACTORS

The u pstream emissions accounting will use the same approach as the upstream energy accounting. See also Coughlin (2012). 2 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 occ ur 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 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 percent of total methane 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 will develop all of the emissions factors using site (point of use) energy savings in the denominator.16 -4 REFERENCES

1

. U.S. Department of Energy–Energy Information Administration. Annual Energy Outlook 2012 with Projections to 2035. 2012. (Last accessed February 19, 2013.)

< www.eia.gov/forecasts/archive/aeo12/index.cfm >
2. Coughlin, K. 2013. Projections of Full- Fuel -Cycle Energy and Emissions Metrics. Lawrence Berkeley National Laboratory, Report Number LBNL-6025E.