CHAPTER 9

. EMISSIONS A NALYSIS

TABLE OF CONTENTS

9.1 INTRODUCTION

................................ ................................ ................................ ........... 9

- 1

9.2 AIR QUALITY REGULATI ONS AND EMISSIONS IM PACTS

................................ . 9

- 2

9.3 POWER SECTOR AND SIT E EMISSIONS FACTORS

................................ ............... 9

- 3

9.4 UPSTREAM FACTORS

................................ ................................ ................................ . 9

- 4

9.5 EMISSIONS IMPACT RES ULTS

................................ ................................ .................. 9

- 5

9.5.1 Small Three

- Phase Air

- Cooled Air Conditioners and Heat Pumps <65,000

Btu/h

................................ ................................ ................................ ......................... 9

- 5

9.5.2 Water

- Source Heat Pumps

................................ ................................ ....................... 9

- 10

LIST OF TABLES

Table 9.3.1 Power Plant Emissions Factors (Small Commercial Air

- Cooled Air

Conditioners and Heat Pumps)

................................ ................................ ............ 9

- 4

Table 9.3.2 Power Plant Emissions Factors (Water

- Source Heat Pumps)

.............................. 9

- 4

Table 9.4. 1 Electricity Upstream Emissions Factors

................................ .............................. 9

- 5

Table 9.5.1 Cumulative Emissions Reduction for Potential Standard for Small Three

Phase Air

- Cooled Air Conditioners and Heat Pumps <65,000 Btu/h

.................. 9

- 6

Table 9.5.2 Cumulative Emissions Reduction for Potential Standard for Water

- Source

Heat Pumps

................................ ................................ ................................ ........ 9

- 10

LIST OF FIGURES

Figure 9.5.1 Small Commercial Air

- Cooled Air Conditioners and Heat Pumps: CO 2

Total Emissions Reduction

................................ ................................ .................. 9

- 7

Figure 9.5.2 Small Commercial Air

- Cooled Air Conditioners and Heat Pumps: SO 2

Total Emissions Reduction

................................ ................................ .................. 9

- 7

Figure 9.5.3 Small Commercial Air

- Cooled Air Conditioners and Heat Pumps: NO

x Total Emissions Reduction

................................ ................................ .................. 9

- 8

Figure 9.5.4 Small Commercial Air

- Cooled Air Conditioners and Heat Pumps: Hg

Total E missions Reduction

................................ ................................ .................. 9

- 8

Figure 9.5.5 Small Commercial Air

- Cooled Air Conditioners and Heat Pumps: N 2 O

Total Emissions Reduction

................................ ................................ .................. 9

- 9

Figure 9.5.6 Small Commercial Air

- Cooled Air Conditioners and Heat Pumps: CH 4

Total Emissions Reduction

................................ ................................ .................. 9

- 9

Figure 9.5.7 Water

- Source Heat Pumps: CO 2 Total Emissions Reduction

............................ 9

- 11

Figure 9.5.8 Water

- Source Heat Pumps: SO 2 Total Emissions Reduction

............................ 9

- 11

Figure 9.5.9 Water

- Source Heat Pumps: NO

x Total Emission s Reduction

........................... 9

- 12

Figure 9.5.10 Water

- Source Heat Pumps: Hg Total Emissions Reduction

.............................. 9

- 12

Figure 9.5.11 Water

- Source Heat Pumps: N 2 O Total Emissions Reduction

........................... 9

- 13

Figure 9.5.12 Water

- Source Heat Pumps: CH 4 Total Emissions Reduction

............................ 9

- 13

9

- iCHAPTER 9. E MISSIONS A NALYSIS

9.1 INTRODUCTION

The emissions analysis consists of two components. The first component estimates the

effect of potential energy conservation standards on power sector and site 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 nitro us 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 full

fuel

- 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 marg inal emissions intensity factors

calculated by DOE

. As of 2014, DOE is using a new methodology based on results published for

the Annual Energy Outlook 2014 ( AEO 2014 ) reference case and a set of side cases that

implement a variety of efficiency

- related po licies

. 1 The new methodology is described in c hapter

1 1 and in the report “Utility Sector Impacts of Reduced Electricity Demand” ( Coughlin

, 2014). 2

Site emissions of CO 2 and NO X are estimated using emissions intensity factors from a

publication of the Environmental Protection Agency (EPA)

. 3

Combustion emissions of CH 4 and N 2 O are estimated using emissions intensity factors

pub lished by the EPA , GHG Emissions Factors Hub. a The FFC upstream emissions a re

estimated based on the methodolo gy developed by Coughlin (2013). 4 The upstream emissions

include both emissions from fuel combustion during extraction, processing and transportation of

fuel, and “fugitive” emissions (direct leak age 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 are estimated using the energy

savings calculated in the national impact an alysis (chapter 8 ).

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 the physical units by the gas

global warming potential (GWP) over a 100 year time horizon. Base d on the Fifth Assessment

Report of the Intergovernmental Panel on Climate Change, 5 DOE used GWP value s of 28 for

CH 4 and 265 for N 2 O. b

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

- emissions.html

b The values are without inclusion of climate

- carbon feedbacks in response to emissions of the indicated non

- CO 2

gases.

9

- 19.2 AIR QUALITY REGULATI ONS AND E MISSIONS I MPACTS

Each annual version of the AEO incorporates the projected impacts of existing air quality

regulations on emissions. AEO 2014 generally represents current Federal and State legislation

and final implementation regulations in place as of the end of October 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 District of Columbia

(D.C.). SO 2 emissions from 28 eastern states and D.C. were also limited under the Clean Air

Inte rstate 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 201 4 emissions factors used for the present analysis assume that CAIR remains

a binding regulation through 2040. c

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 resulti ng 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 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 hydrogen chloride as a surrogate for acid gas hazardous air

pollutants (HAP), and also established a standa rd 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

- f ired power plants to comply with the MATS requirements for acid gas. AEO

201 4 assumes that, in order to continue operating, coal plants must have either flue gas

c On April 29, 2014, the U.S. Supreme Court reversed the judgment of the D.C. Circuit and remanded the case for

further proceedings consi stent 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 equita ble interpretation of the Clean Air Act provision

that provides statutory 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 201 4 , 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.

9

- 2desulfurization or dry sorbent injection systems installed by 201 6 . Both technologies, which a re

used to reduce acid gas emissions, also reduce SO 2 emissions. Under the MATS, e missions 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 201 6 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 estimated NOx emissions reductions from potential standards for those States.

The MATS limit mercury emissions from power plants, but t hey do not include

emissions caps and, as such, DOE’s energy conservation standards would likely reduce Hg

emissions. DOE estimated mercury emissions reductions using emissions factors based on AEO

2014 , which incorporates the MATS.

9.3 P O WER S E CTOR AND S ITE E MISSIONS F ACTORS

The analysis of power sector emissions uses marginal emissions intensity factors derived

from analysis of the AEO 2014 reference and a number of side cases incorporating enhanced

equipment efficiencies. To model the impact of a standard, DOE calculates factors that relate a

unit reduction to annual site electricity demand for a given end use to corresponding reductions

to installed capacity by fuel type , fuel use for generation, and power sector emissions . Details on

the approach use d may be found in Coughlin ( 2014 ).

Table 9.3.1 and Table 9.3.2 present the average power plant emissions factors for

selected years. These power plant emissions factors are derived from the emissions factors of the

plant types used to supply electricity to commercial buildings fo r space cooling and space

heating. The average factors for each year take into account the projected shares of each of the

sources in total electricity generation. For mall commercial air

- cooled air

- conditioning and

heating equipment , the emissions factors refer to the power plants that supply electricity for

space cooling. For water

- source heat pumps , the factors are calculated as the weighted average of

emissions factors of plants that supply electricity for space cooling (80%) and space heating

(20%).

9

- 3Table 9.3.1 P ower Plant Emissions Factors ( Small Commercial Air

- Cooled Air

Conditioners and Heat Pumps )

Unit* 202 0 2025 2030 2035 2040

CO 2 kg/MWh 695 620 560 514 472

SO 2 g/MWh 649 507 426 357 319

NOx g/MWh 536 450 394 348 316

Hg g/MWh 0.00200 0.00156 0.00132 0.00110 0.00098

N 2 O g/MWh 7.2 7.1 6.9 6.6 6.4

CH 4 g/MWh 50 49 48 46 45

* Refers to site electricity savings

.

Table 9.3.2 Power Plant Emissions Factors ( W ater

- Source Heat Pumps )

Unit* 2020 2025 2030 2035 2040

CO 2 kg/MWh 705 628 567 519 477

SO 2 g/MWh 671 524 441 369 330

NOx g/MWh 549 460 402 355 322

Hg g/MWh 0.00207 0.00162 0.00136 0.00114 0.00102

N 2 O g/MWh 7.2 7.1 6.9 6.6 6.4

CH 4 g/MWh 50 49 48 46 45

* Refers to site electricity savings.

9.4 UPSTREAM FACTORS

The upstream emissions accounting uses the same approach as the upstream energy

accounting described in appendix 8A

. See also Coughlin (201 3 ) and Coughlin (2014). When

demand for a particular fuel is reduced, there is a corresponding reduction in the emissions from

com bustion 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 emi ssions associated

with the fuel used on site.

Fugitive emissions of CO 2 occur during oil and gas production, but are small relative to

combustion emi ssions. They comprise about 2.5 percent of total CO 2 em issions for natural gas

and 1.7 percent for petro leum 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 p ercent

of total methane emis sions 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. Fugitive emissions factors for

methane from coal mining and natural gas production were estimated based on a review of recent

studies compiled by Burnham (2011). 6 This review includes estimates of the difference between

9

- 4fugitive emissions factors for conventional production of natural vs. unconventional (shale or

tight gas). Thes e estimates rely in turn on data gathered by EPA under new GHG reporting

requirements for the petroleum and natural gas industries. 7

, 8 As more data are made available,

DOE will continue to update these estimated emissions factors.

For ease of application in its analysi s, DOE developed all of the emissions factors using

site (point of use) energy savings in the denominator. Table 9.4.1 presents the electricity

upstream emissions factors for selected years

. These were used to estimate the emissions

associated with the decreased electricity use. The caps that apply to power sector NO X emissions

do not apply to upstream combustion sources.

Table 9.4.1 Electricity Upstream Em issions Factors

Unit 202 0 2025 2030 2035 2040

CO 2 kg/MWh 29.1 29.4 29.7 29.9 29.8

SO 2 g/MWh 5.0 5.1 4.9 4.7 4.6

NOx g/MWh 368 375 382 387 387

Hg g/MWh 0.000012 0.000011 0.000011 0.000010 0.000010

N 2 O g/MWh 0.252 0.247 0.241 0.234 0.228

CH 4 g/MWh 2149 2195 2216 2248 2255

* Refers to site electricity savings.

9.5 E MISSIONS I MPACT RESULTS

9.5.1 Small Three

- Phase Air

- Cooled Air Conditioners and Heat Pumps <65,000 Btu/h

Table 9.5.1 presents the estimated cumulative emissions reductions for the lifetime of

equipment sold in 2017

- 2046 for the ASHRAE level and 2020

- 204 6 for each additional

efficiency level for the equipmen t classes triggered by ASHRAE, and 2019

- 2048 for split system

air conditioners . Negative values indicate that emissions increase.

9

- 5Table 9.5.1 Cumulative Emissions Reduction for Potential Standard for Small Three

Phase Air

- Cooled Air Conditioners and Heat Pumps <65,00 0 Btu/h

Efficiency Level

ASHRAE/0 1 2 3 4 5

Power Sector Emissions

CO 2 (million metric tons) 3.7 8.9 16.8 20.8 24.3 25.9

SO 2 ( thousand tons ) 2.9 6.9 13.0 16.1 18.8 20.1

NO X (thousand tons) 2.8 6.7 12.6 15.6 18.2 19.4

Hg ( tons) 0.01 0.02 0.04 0.05 0.06 0.06

N 2 O ( thousand tons ) 0.05 0.13 0.24 0.30 0.35 0.37

CH 4 ( thousand tons ) 0.38 0.90 1.69 2.10 2.45 2.61

Upstream Emissions

CO 2 (million metric tons) 0.22 0.54 1.00 1.24 1.45 1.54

SO 2 ( thousand tons ) 0.04 0.09 0.17 0.22 0.25 0.27

NO X (thousand tons) 3.2 7.6 14.3 17.7 20.7 22.0

Hg ( tons) 0.0001 0.0002 0.0004 0.0005 0.0006 0.0006

N 2 O ( thousand tons ) 0.002 0.005 0.009 0.011 0.012 0.013

CH 4 ( thousand tons ) 19 45 83 103 121 128

Total FFC Emissions

CO 2 (million metric tons) 4.0 9.5 17.8 22.1 25.8 27.4

SO 2 ( thousand tons ) 2.9 7.0 13.2 16.4 19.1 20.3

NO X (thousand tons) 6.0 14.3 26.8 33.4 38.9 41.4

Hg ( tons) 0.01 0.02 0.04 0.05 0.06 0.06

N 2 O ( thousand tons ) 0.06 0.13 0.25 0.31 0.36 0.39

CH 4 ( thousand tons ) 19 45 85 105 123 131

Note: The potential emissions reduction for efficiency levels more stringent than those specified by ASHRAE

Standard 90.1

- 201 3 were calculated relative to the efficiency levels that would result if ASHRAE Standa rd 90.1

-

201 3 standards were adopted.

Figure 9.5.1 through Figure 9.5.6 show the annual reductions for total emissions for each

type of emission from each efficiency level . The reductions reflect the lifetime impacts of

equipment sold in 2017

- 2046 for the ASHRAE level and 2020

- 2046 for each additional

efficiency level for the equipment classes triggered by ASHRAE, and 2019

- 2048 for split system

air conditioners

.

9

- 6Figure 9.5.1 Small Commercial Air

- Cooled Air Conditioners and Heat

Pumps : CO 2 Total Emissions Reduction

Figure 9.5.2 Small Commercial Air

- Cooled Air Conditioners and Heat

Pumps : SO 2 Total Emissions Reduction

9

- 7Figure 9.5.3 Small Commercial Air

- Cooled Air Conditioners and Heat

Pumps : NO

x Total Emissions Reduction

Figure 9.5.4 Small Commercial Air

- Cooled Air Conditioners and Heat

Pumps : Hg Total Emissions Reduction

9

- 8Figure 9.5.5 Small Commercial Air

- Cooled Air Conditioners and Heat

Pumps : N 2 O Total Emissions Reduction

Figure 9.5.6 Small Commercial Air

- Cooled Air Conditioners and Heat

Pumps : CH 4 Total Emissions Reduction

9

- 99.5.2 Water

- Source Heat Pumps

Table 9.5.2 presents the estimated cumulative emissions reductions for the lifetime of

equipment sold in 20 16

- 20 45 for the ASHRAE level and 2020

- 2045 for each additional

efficiency leve l . Negative values indicate that emissions increase.

Table 9.5.2 Cumulative Emissions Reduction for Potential Standard for Water

Source Heat Pumps

Efficiency Level

ASHRAE/0 * 1 2 3 4 5

Power Sector Emissions

CO 2 (million metric tons)

- 1.4 16.3 30.5 41.6 56.8

SO 2 ( thousand tons )

- 1.1 12.9 24.2 32.9 44.9

NO X (thousand tons)

- 1.1 12.3 23.1 31.4 42.9

Hg ( tons)

- 0.003 0.040 0.075 0.101 0.139

N 2 O ( thousand tons )

- 0.02 0.23 0.44 0.60 0.81

CH 4 ( thousand tons )

- 0.14 1.63 3.06 4.17 5.69

Upstream Emissions

CO 2 (million metric tons)

- 0.08 0.97 1.81 2.47 3.37

SO 2 ( thousand tons )

- 0.01 0.17 0.32 0.43 0.59

NO X (thousand tons)

- 1.2 13.8 25.9 35.2 48.0

Hg ( tons)

- 0.00003 0.00037 0.00070 0.00095 0.00130

N 2 O ( thousand tons )

- 0.001 0.008 0.016 0.021 0.029

CH 4 ( thousand tons )

- 7.0 80.5 150.8 205.2 279.9

Total FFC Emissions

CO 2 (million metric tons)

- 1.5 17.3 32.4 44.0 60.1

SO 2 ( thousand tons )

- 1.1 13.1 24.5 33.3 45.5

NO X (thousand tons)

- 2.3 26.1 49.0 66.7 91.0

Hg ( tons)

- 0.004 0.040 0.075 0.102 0.140

N 2 O ( thousand tons )

- 0.02 0.24 0.45 0.62 0.84

CH 4 ( thousand tons )

- 7.2 82.1 153.9 209.4 285.6

Note: The potential emissions reduction for efficiency levels more stringent than those specified by ASHRAE

Standard 90.1

- 201 3 were calculated relative to the efficiency levels that would result if ASHRAE Standard 90.1

-

201 3 standards were adopted.

* There are no reductions for the ASHRAE level b ecause there is no market share projected at the federal baseline in

the base case.

Figure 9.5.7 through Figure 9.5.12 show the annual reductions for total emissions for

each type of emission from each efficiency level . The reductions reflect the lifetime impacts of

equipment sold in 201 6

- 204 5 for the ASHRAE level and 2020

- 2045 for each additional

efficiency level.

9

- 10Figure 9.5.7 Water

- Source Heat Pumps : CO 2 Total Emissions Reduction

Figure 9.5.8 Water

- Source Heat Pumps : SO 2 Total Emissions Reduction 0.0 500.0 1000.0 1500.0 2000.0 2500.02016202120262031203620412046205120562061206620712076208120862091209621012106kt CO

2 Emissions Reduction

ASHRAE 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 1600.02016202120262031203620412046205120562061206620712076208120862091209621012106ton SO

2 Emissions Reduction

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

9

- 11Figure 9.5.9 Water

- Source Heat Pumps : NO

x Total Emissions Reduction

Figure 9.5.10 Water

- Source Heat Pumps : Hg Total Emissions Reduction 0.0 500.0 1000.0 1500.0 2000.0 2500.0 3000.0 3500.02016202120262031203620412046205120562061206620712076208120862091209621012106ton NO

x Emissions Reduction

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0.0000 0.0005 0.0010 0.0015 0.0020 0.0025 0.0030 0.0035 0.0040 0.0045 0.00502016202120262031203620412046205120562061206620712076208120862091209621012106ton Hg Emissions Reduction

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

9

- 12Figure 9.5.11 Water

- Source Heat Pumps : N 2 O Total Emissions Reduction

Figure 9.5.12 Water

- Source Heat Pumps : CH 4 Total Emissions Reduc tion 0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.02016202120262031203620412046205120562061206620712076208120862091209621012106ton N

2 O Emissions Reduction

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0.0 2000.0 4000.0 6000.0 8000.0 10000.0 12000.02016202120262031203620412046205120562061206620712076208120862091209621012106ton CH

4 Emissions Reduction

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

9

- 13REFERENCES

1. Energy Information Administration, Annual Energy Outlook 201 4 with Projections to

20 40 , 201 4 Washington, DC. < http://www.eia.gov/forecasts/aeo/pdf/0383(201 4 ).pdf >

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Berkeley National Laboratory. Report No. LBNL

- 6864E

.

3. U.S. Environmental Protection Agency, Compilation of Air Pollutant Emission Factors,

AP

- 42, Fifth Edition, Volume I: Stationary Point and Area Sources . 1998.

www.epa.gov/ttn/chief/ap42/index.html

4. Coughlin, K., Projections of Full

- Fuel

- Cycle Energy and Emissions Metrics , 2013.

Lawrence Berkeley National Laboratory. Report No. LBNL

- 6025E.

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Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report

of the Intergovernmental Panel on Climate Change , T.F. Stocker, D. Qin, G.

- K. Plattner,

M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex, an d P.M. Midgley,

Editor. 2013. Cambridge University Press: Cambridge, United Kingdom and New York,

NY, USA

6. Burnham, A., J. Han, C. E. Clark, M. Wang, J. B. Dunn, I. Palou

- Rivera, Life

- Cycle

Greenhouse Gas Emissions of Shale Gas, Natural Gas, Coal, and P etroleum

. Environmental Science & Technology , 2011. 46(2): pp. 619

- 627

7. U.S. Environmental Protection Agency, Fugitive Emissions Reporting from the

Petroleum and Natural Gas Industry , 2009. U.S. Environmental Protection Agency.

Washington, DC.

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Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution,

Background Supplemental Technical Support Document for the Final New Source

Performance Standa rds , 2012. U.S. Environmental Protection Agency. Washington, DC.

9

- 1