CHAPTER 13. EMISSIONS IMPACT ANALYSIS

TABLE OF CONTENTS

13.1 INTRODUCTION

................................ ................................ .............................................. 13 -1

13.2 AIR QUALITY REGULATI ONS AND EMISSIONS IM PACTS

................................ 13 -1

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 U pstream Emissions Factors

........................................................ 13 -4

Table 13.5.1 Cumulative Emissions Reduction Estimated for Packaged Terminal

Air Conditioners and P ackaged Terminal Heat Pumps Trial Standard

Levels

................................ ................................ ............................................... 13 -5

Table 13.5.2 Cumulative Emissions Reduction Estimated for Packaged Terminal

Air Conditioners and Packaged Terminal Heat Pumps Trial Standard

Levels Compared to the Alternative Base Case

............................................ 13 -9

LIST OF FIGURES

Figure 13.1.1 Packaged Terminal Air Conditioners and Packaged Terminal Heat

Pumps: CO 2 Total Emissions Reduction

....................................................... 13 -6

Figure 13.1.2 Packaged Terminal Air Conditioners and Packaged Terminal Heat

Pumps: SO 2 Total Emissions Reduction

........................................................ 13 -6

Figure 13.1.3 Packaged Terminal Air Conditioners and Packaged Terminal Heat

Pumps: NO X Total Emissions Reduction

....................................................... 13 -7

Figure 13.1.4 Packaged Terminal Air Conditioners and Packaged Terminal Heat

Pumps: Hg Total Emissions Reduction

.......................................................... 13 -7

Figure 13.1.5 Packaged Terminal Air Conditioners and Packaged Terminal Heat

Pumps: N 2 O Total Emissions Reduction

....................................................... 13 -8

Figure 13.1.6 Packaged Terminal Air Conditioners and Packaged Terminal Heat

Pumps: 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 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 chain. These upstream activities comprise

extracting

, 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 full

- fuel

- cycle

(FFC) , i n accordance with DOE’s FFC Statement of Policy

. 76 FR 51282 (Aug ust 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. DOE used the version of NEMS

based on the Annual Energy Outlook 2013 (AEO 201 3). 1 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 201 2. 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 methodolo gy developed by Coughlin (2013). 3 The upstream emissions

include both emissions from fuel combustion during extract ion, 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 redu ctions are estimated using the energy

savings calculated in the national impact analysis ( C hapter 10).

13.2 AIR QUALITY REGULATIONS AND EMISSIONS IMPACTS

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.

a http://www.epa.gov/climateleadership/guidance/ghg -emissions.html

13-1Circuit) but parts of it remained in effect. On July 6, 2011 EPA issued a replacement for CAIR,

the Cross

- State Air Pollution Rule (C SAPR). 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 emis sions factors used for this analysis assume that CAIR remains a

binding regulation through 2040.

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

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 rulema kings, 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 stand ards.

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 establishe d 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 red uce 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 wou ld 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.

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

CAIR

, so DOE estimate d 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

emissions. DOE estimated mercury emissions reductions using the NEMS

- BT based on AEO

201 3 , which incorporates the MATS.

13-213.3 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 Annua l 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 f actor to estimate the reduction in generation for each trial standard level ( 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 space c ooling (50%) and lighting (50%) . DOE did not have data on the load shape

of PTACs and PTHPs , so it used a combination of the load shape s corresponding to commercial

cooling and lighting as a proxy to the load shape of PTACs and PTHPs

. The rationale is that

PTACs and PTHPs are not likely to be on 24 hours a day, so DOE allocated the energy savings

evenly across the other two

– intermediate (lighting) and peak (space cooling)

– loads . Therefore,

electric motors and lighting in industry and commercial buildings follow similar daily

operational timeframes. The factors presented in Table 13.3 .1 for each year are weighted

averages that take into account the projected shares of each of the source s used to generate

electricity to support commercial cooling (50%) and lighting (50%)

.

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* 2 01 7 2020 2025 2030 2035 2040

CO 2 kg/MWh 596 596 581 559 607 606

SO 2 g/MWh 680 680 896 917 972 1434

NOx g/MWh

- 114

- 114 11 121 213 302

Hg g/MWh 0.00153 0.00153 0.00091 0.00119 0.00130 0.00172

N 2 O g/MWh 7.0 7.2 7.2 7.1 7.1 6.9

CH 4 g/MWh 49 50 50 50 49 48

* Refers to site electricity savings.

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 (201 3). 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

ups tream 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 assoc iated 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 (particularly

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 electric ity 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* 201 7 2020 2025 2030 2035 2040

CO 2 kg/MWh 27.9 27.3 26.9 26.8 26.9 26.3

SO 2 g/MWh 5.0 5.3 5.3 5.2 5.2 5.1

NOx g/MWh 352.6 340.4 334.5 333.0 336.4 328.7

Hg g/MWh 0.0 0.0 0.0 0.0 0.0 0.0

N 2 O g/MWh 0.2 0.3 0.3 0.2 0.2 0.2

CH 4 g/MWh 2083.9 2024.9 2007.6 2025.4 2057.0 1998.8

* 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 Packaged Terminal Air

Conditioners and Packaged Terminal Heat Pumps Trial Standard Levels

Trial Standard Level

1 2 3 4 5

Primary Emissions

CO 2 (million metric tons) 1.06 4.15 8.23 10.52 10.81

SO 2 (thousand tons) 2.46 9.70 19.22 24.07 24.60

NO X (thousand tons) 0.48 1.90 3.76 4.63 4.69

Hg (tons) 0.00 0.01 0.02 0.03 0.03

N 2 O (thousand tons) 0.02 0.07 0.14 0.17 0.17

CH 4 (thousand tons) 0.10 0.39 0.77 0.98 1.01

Upstream Emissions

CO 2 (million metric tons) 0.05 0.18 0.36 0.47 0.48

SO 2 (thousand tons) 0.01 0.04 0.08 0.10 0.10

NO X (thousand tons) 0.65 2.53 5.02 6.43 6.62

Hg (tons) 0.00 0.00 0.00 0.00 0.00

N 2 O (thousand tons) 0.00 0.00 0.00 0.00 0.00

CH 4 (thousand tons) 3.92 15.36 30.51 39.10 40.22

Full Fuel Cycle Emissions

CO 2 (million metric tons) 1.10 4.33 8.60 10.98 11.29

SO 2 (thousand tons) 2.47 9.74 19.30 24.17 24.70

NO X (thousand tons) 1.12 4.42 8.78 11.06 11.31

Hg (tons) 0.00 0.01 0.02 0.03 0.03

N 2 O (thousand tons) 0.02 0.07 0.14 0.18 0.18

CH 4 (thousand tons) 4.02 15.75 31.28 40.08 41.22

Note: Components may not sum to total due to rounding.

Figure 13.1.1 through Figure 13.1.6 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 13.1.1 Packaged Terminal Air Conditioners and Packaged

Terminal Heat Pumps : CO 2 Total Emissions

Reduction

Figure 13.1.2 Packaged Terminal Air Conditioners and Packaged

Terminal Heat Pumps : SO 2 Total Emissions

Reduction 0.0 50.0 100.0 150.0 200.0 250.0 300.0 350.0 400.0 450.020172022202720322037204220472052205720622067kt CO 2 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0.0 200.0 400.0 600.0 800.0 1000.0 1200.020172022202720322037204220472052205720622067ton SO 2 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

13-6Figure 13.1.3 Packaged Terminal Air Conditioners and Packaged

Terminal Heat Pumps : NO X Total Emissions

Reduction

Figure 13.1.4 Packaged Terminal Air Conditioners and Packaged

Terminal Heat Pumps : Hg Total Emissions

Reduction 0.0 50.0 100.0 150.0 200.0 250.0 300.0 350.0 400.0 450.0 500.020172022202720322037204220472052205720622067ton NO

x Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.020172022202720322037204220472052205720622067ton Hg Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

13-7Figure 13.1.5 Packaged Terminal Air Conditioners and Packaged

Terminal Heat Pumps : N 2 O Total Emissions

Reduction

Figure 13.1.6 Packaged Terminal Air Conditioners and Packaged

Terminal Heat Pumps : CH 4 Total Emissions

Reduction 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.020172022202720322037204220472052205720622067ton N 2 O Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0.0 200.0 400.0 600.0 800.0 1000.0 1200.0 1400.0 1600.0 1800.020172022202720322037204220472052205720622067ton CH

4 Emissions Reduction

TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

13-8As described in Chapter 8, the alternative base case analysis was based off a scenario

where the mandatory efficiency level is the Federal minimum, against which DOE determined

the impacts on emissions. The estimated cumulative emissions reduction for PTAC s and PTHPs

are shown in Table 13.5 .2 , for informational purposes.

Table 13.5 .2 Cumulative Emissions Reduction Estima ted for Packaged Terminal Air

Conditioners and Packaged Terminal Heat Pumps Trial Standard Levels

Compared to the Alternative Base Case

Trial Standard Level

1 2 3 4 5

Primary Emissions

CO 2 (million metric tons) 1.02 4.17 8.26 10.54 10.83

SO 2 (thousand tons) 2.38 9.76 19.28 24.12 24.65

NO X (thousand tons) 0.46 1.91 3.77 4.64 4.70

Hg (tons) 0.00 0.01 0.02 0.03 0.03

N 2 O (thousand tons) 0.02 0.07 0.14 0.17 0.18

CH 4 (thousand tons) 0.10 0.39 0.77 0.98 1.01

Upstream Emissions

CO 2 (million metric tons) 0.05 0.18 0.37 0.47 0.48

SO 2 (thousand tons) 0.01 0.04 0.08 0.10 0.10

NO X (thousand tons) 0.62 2.54 5.03 6.45 6.63

Hg (tons) 0.00 0.00 0.00 0.00 0.00

N 2 O (thousand tons) 0.00 0.00 0.00 0.00 0.00

CH 4 (thousand tons) 3.79 15.45 30.60 39.19 40.31

Full Fuel Cycle Emissions

CO 2 (million metric tons) 1.07 4.35 8.62 11.01 11.31

SO 2 (thousand tons) 2.39 9.80 19.36 24.22 24.76

NO X (thousand tons) 1.08 4.45 8.80 11.08 11.33

Hg (tons) 0.00 0.01 0.02 0.03 0.03

N 2 O (thousand tons) 0.02 0.07 0.14 0.18 0.18

CH 4 (thousand tons) 3.88 15.84 31.37 40.17 41.31

Note: Components may not sum to total due to rounding.

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.

Lawrence Berkeley Nat ional Laboratory. Report No. LBNL

- 6025E.

13-10