Economic Impact Analysis for the

Mandatory Reporting of Greenhouse

Gas Emissions Under Subpart W Final

Rule (GHG Reporting)

PRELIMINARY DRAFT

Final Report

NovemberAugust, 2010

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TABLE OF CONTENTS 

Page

Section 1 Introduction and Background .................................................................................. 1-1

1.1 Background ............................................................................................................ 1-1

1.2 Role of the Economic Impact Analysis in the Rulemaking Process ...................... 1-4

1.2.1 Legislative Authority and Context ........................................................... 1-4

1.2.2 Role of Statutory and Executive Orders .................................................. 1-7

1.2.3 Illustrative Nature of the Analysis ........................................................... 1-7

1.3 Overview and Design of the Economic Impact Analysis ...................................... 1-7

1.3.1 Establishing Baseline and Years of Analysis ........................................... 1-8

1.3.2 Developing the GHG Reporting Rule Considered in This 

Economic Impact Analysis ...................................................................... 1-8

1.3.3 Evaluating Costs and Benefits ............................................................... 1-14

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative ............................... 1-14

Section 2 Regulatory Background ............................................................................................ 2-1

2.1 EPA’s Overall Rulemaking Approach ................................................................... 2-1

2.1.1 Identifying the Goals of the Greenhouse Gas Reporting System ............ 2-1

2.1.2 Developing the Rule ................................................................................ 2-2

2.1.3 Evaluating Existing Greenhouse Gas Reporting Programs ..................... 2-2

2.1.4 Conducting Stakeholder Outreach to Identify Reporting Issues .............. 2-3

2.1.5 Considering Public Comments on Key Reporting Issues ........................ 2-4

2.1.6 Analyzing Emissions From the Petroleum and Natural Gas 

Industry .................................................................................................... 2-4

2.2 Sources Considered ................................................................................................ 2-5

2.3 How the Mandatory GHG Reporting Program Is Different From the Federal 

and State Programs EPA Reviewed ....................................................................... 2-6

2.3.1 Inventory of U.S. Greenhouse Gas Emissions and Sinks ........................ 2-7

2.3.2 Federal Voluntary Greenhouse Gas Programs ......................................... 2-9

2.3.3 Federal Mandatory Reporting Programs ................................................ 2-11

2.3.4 Other EPA Emission Inventories ........................................................... 2-11

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2.3.5 State and Regional Voluntary Programs for Greenhouse Gas 

Emission Reporting ................................................................................ 2-12

2.3.6 State and Regional Mandatory Programs for Greenhouse Gas 

Emission Reporting and Control ............................................................ 2-13

2.3.7 State Mandatory Greenhouse Gas Reporting Rules ............................... 2-14

Section 3 Development of the Mandatory GHG Reporting Rule .......................................... 3-1

3.1 Rule Dimensions for Which Options Were Identified ........................................... 3-1

3.1.1 Thresholds ................................................................................................ 3-2

3.1.2 Measurement Methodology ..................................................................... 3-3

3.2 Selected Option ...................................................................................................... 3-4

3.3 Alternative Scenarios Evaluated ............................................................................ 3-6

3.4 Data Quality for This Analysis ............................................................................... 3-6

Section 4 Engineering Cost Analysis ........................................................................................ 4-1

4.1 Introduction ............................................................................................................ 4-1

4.2 Overview of Cost Analysis .................................................................................... 4-2

4.2.1 Baseline Reporting ................................................................................... 4-2

4.2.2 Reporting Costs ........................................................................................ 4-3

4.3 Subpart W—Petroleum and Natural Gas Systems ................................................. 4-5

4.3.1 Overview .................................................................................................. 4-5

4.3.2 Labor Costs .............................................................................................. 4-7

4.3.3 Capital and O&M Costs ........................................................................... 4-9

4.3.4 Combustion Costs .................................................................................. 4-10

4.4 Summary Results: Subpart W—Petroleum and Natural Gas Systems ................ 4-14

4.4.1 Detailed Threshold Analysis .................................................................. 4-15

4.4.2 Reporting Determination ....................................................................... 4-17

4.5 Detailed Cost Assumptions: Subpart W—Petroleum and Natural Gas 

Systems ................................................................................................................. 4-19

4.5.1 Determining Labor Categories ............................................................... 4-24

4.5.2 Allocating Responsibilities .................................................................... 4-25

4.5.3 Annualizing Capital Costs and Determining O&M Costs ..................... 4-33
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Section 5 Subpart W Analysis of Reporting Rule Options .................................................... 5-1

5.1 Evaluating Alternative Options for Implementation of the Rule ........................... 5-4

5.1.1 Analysis of Alternative Threshold Options ............................................. 5-5

5.1.2 Analysis of Alternative Monitoring Method Options .............................. 5-9

5.1.3 Sensitivity of Subsequent-Year Cost Estimates ..................................... 5-10

5.1.4 Summary of Alternative Options for Onshore Facility Definition ........ 5-11

5.2 Assessing Economic Impacts on Small Entities .................................................. 5-13

5.2.1 Identifying Affected Segments and Entities .......................................... 5-13

5.2.2 Developing Small-Entity Economic Impact Measures .......................... 5-18

5.2.3 Results of Screening Analysis ............................................................... 5-21

5.3 Synopsis of Benefits ............................................................................................. 5-22

Section 6 Statutory and Executive Order Reviews ................................................................. 6-1

6.1 Executive Order 12866: Regulatory Planning and Review ................................... 6-1

6.2 Paperwork Reduction Act ...................................................................................... 6-2

6.3 Regulatory Flexibility Act ...................................................................................... 6-4

6.4 Unfunded Mandates Reform Act ........................................................................... 6-8

6.5 Executive Order 13132: Federalism ..................................................................... 6-10

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments ........................................................................................................ 6-10

6.7 Executive Order 13045: Protection of Children from Environmental Health 

and Safety Risks ................................................................................................... 6-13

6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, 

Distribution, or Use .............................................................................................. 6-13

6.9 National Technology Transfer Advancement Act ............................................... 6-13

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice 

in Minority Populations and Low-Income Populations ....................................... 6-14

Section 7 Conclusions and Implications ................................................................................... 7-1

7.1 Discussion of Results ............................................................................................. 7-1
iv 

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7.1.1 Development of the Proposed Rule ......................................................... 7-1

7.1.2 Affected Source Categories ..................................................................... 7-2

7.2 Assessment of Costs and Benefits of the Mandatory Greenhouse Gas 

Reporting Rule ....................................................................................................... 7-2

7.2.1 Estimated Costs and Impacts of the Mandatory Greenhouse Gas 

Reporting Program ................................................................................... 7-2

7.2.2 Summary of Qualitative Benefits Assessment ......................................... 7-2

7.3 What Did We Learn through This Analysis? ......................................................... 7-4

Section 8 Sources Consulted ..................................................................................................... 7-1

Section 1 Introduction and Background ................................................................................. 1-1

1.1 Background ............................................................................................................ 1-1

1.2 Role of the Economic Impact Analysis in the Rulemaking Process ...................... 1-4

1.2.1 Legislative Roles ...................................................................................... 1-4

1.2.2 Role of Statutory and Executive Orders ............................................. 1-71-6

1.2.3 Illustrative Nature of the Analysis ........................................................... 1-7

1.3 Overview and Design of the Economic Impact Analysis ...................................... 1-7

1.3.1 Baseline and Years of Analysis .......................................................... 1-81-7

1.3.2 Developing the GHG Reporting Rule Considered in This 

Economic Impact Analysis ...................................................................... 1-8

1.3.3 Evaluating Costs and Benefits ........................................................ 1-141-13

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative ........................ 1-141-13

Section 2 Regulatory Background ........................................................................................... 2-1

2.1 EPA’s Overall Rulemaking Approach ................................................................... 2-1

2.1.1 Identifying the Goals of the Greenhouse Gas Reporting System ............ 2-1

2.1.2 Developing the Rule ................................................................................ 2-2

2.1.3 Evaluation of Existing Greenhouse Gas Reporting Programs ................. 2-2

2.1.4 Stakeholder Outreach to Identify Reporting Issues ................................. 2-3

2.1.5 Analysis of Emissions from the Petroleum and Natural Gas 

Industry .................................................................................................... 2-4

2.2 Sources Considered ................................................................................................ 2-5
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2.3 How the Mandatory GHG Reporting Program Is Different from the Federal 

and State Programs EPA Reviewed ....................................................................... 2-6

2.3.1 Inventory of U.S. Greenhouse Gas Emissions and Sinks ........................ 2-7

2.3.2 Federal Voluntary Greenhouse Gas Programs ......................................... 2-9

2.3.3 Federal Mandatory Reporting Programs ......................................... 2-112-10

2.3.4 Other EPA Emissions Inventories ......................................................... 2-11

2.3.5 State and Regional Voluntary Programs for Greenhouse Gas 

Emissions Reporting ....................................................................... 2-122-11

2.3.6 State and Regional Mandatory Programs for Greenhouse Gas 

Emissions Reporting and Control ................................................... 2-132-12

2.3.7 State Mandatory Greenhouse Gas Reporting Rules ............................... 2-14

Section 3 Development of the Mandatory Reporting Rule ................................................... 3-1

3.1 Rule Dimensions for Which Options Were Identified ........................................... 3-1

3.1.1 Thresholds ................................................................................................ 3-2

3.1.2 Measurement Methodology ..................................................................... 3-3

3.2 Selected Option ...................................................................................................... 3-4

3.3 Alternative Scenarios Evaluated ....................................................................... 3-63-5

3.4 Data Quality for This Analysis ............................................................................... 3-6

Section 4 Engineering Cost Analysis .................................................................................. 4-14-8

4.1 Introduction ....................................................................................................... 4-14-8

4.2 Overview of Cost Analysis ............................................................................... 4-24-9

4.2.1 Baseline Reporting .............................................................................. 4-24-9

4.2.2 Reporting Costs ................................................................................... 4-34-9

4.3 Subpart W—Petroleum and Natural Gas Systems .......................................... 4-54-11

4.4 Summary Results: Subpart W—Petroleum and Natural Gas Systems ......... 4-144-18

4.5 Detailed Cost Assumptions: Subpart W—Petroleum and Natural Gas 

Systems .......................................................................................................... 4-194-22

4.5.1 Determining Labor Categories ........................................................ 4-244-28

4.5.2 Allocating Responsibilities ............................................................. 4-254-29

4.5.3 Capital Cost Annualization and O&M Costs .................................. 4-334-35
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Section 5 Subpart W Analysis of Reporting Rule Options ................................................... 5-1

5.1 Evaluating Alternative Options for Implementation of the Rule ...................... 5-35-4

5.1.1 Analysis of Alternative Threshold Options ........................................ 5-55-4

5.1.2 Analysis of Alternative Monitoring Method Options ......................... 5-95-8

5.1.3 Sensitivity of Subsequent Year Cost Estimates ................................ 5-105-9

5.1.4 Summary of Alternative Options for Onshore Facility Definition . 5-115-10

5.2 Assessing Economic Impacts on Small Entities ........................................... 5-135-12

5.2.1 Identify Affected Segments and Entities ........................................ 5-135-12

5.2.2 Develop Small Entity Economic Impact Measures ........................ 5-185-17

5.2.3 Results of Screening Analysis ........................................................ 5-215-20

5.3 Synopsis of Benefits ...................................................................................... 5-225-21

Section 6 Statutory and Executive Order Reviews ................................................................ 6-1

6.1 Executive Order 12866: Regulatory Planning and Review ................................... 6-1

6.2 Paperwork Reduction Act ...................................................................................... 6-2

6.3 Regulatory Flexibility Act ................................................................................. 6-46-3

6.4 Unfunded Mandates Reform Act ...................................................................... 6-86-6

6.5 Executive Order 13132: Federalism ................................................................ 6-106-7

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments ................................................................................................... 6-106-7

6.7 Executive Order 13045: Protection of Children from Environmental Health 

and Safety Risks .............................................................................................. 6-126-8

6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, 

Distribution, or Use ......................................................................................... 6-136-9

6.9 National Technology Transfer Advancement Act .......................................... 6-136-9

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice 

in Minority Populations and Low-Income Populations ................................ 6-146-10

Section 7 Conclusions and Implications .................................................................................. 7-1

7.1 Discussion of Results ............................................................................................. 7-1
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7.1.1 Development of the Proposed Rule ......................................................... 7-1

7.1.2 Affected Source Categories ..................................................................... 7-2

7.2 Assessment of Costs and Benefits of the Mandatory GHG Reporting Rule .......... 7-2

7.2.1 Estimated Costs and Impacts of the Mandatory GHG Reporting 

Program .................................................................................................... 7-2

7.2.2 Summary of Qualitative Benefits Assessment ......................................... 7-2

7.3 What Did We Learn through This Analysis? ......................................................... 7-4

Section 8 References ............................................................................................................ 7-18-1

ix 

LIST OF FIGURES 

Page

Figure 5-1 Average and Marginal Cost and Cost Differential per Metric Ton of Emissions 

Reported by Threshold ........................................................................................ 5-85-7

Figure 5-2 Summary of Basin vs. Field Decision ............................................................. 5-135-11

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LIST OF TABLES 

Page

Table 2-1 Sources of GHG Emissions Considered ................................................................... 2-5

Table 2-2 Segments Included in the Petroleum and Natural Gas Regulatory Analyses ........... 2-6

Table 3-1 Options Considered in Developing Scenarios for Regulation Under Subpart W 

(Final Option Indicated by Shading) ........................................................................ 3-2

Table 4-1 Selected Reporting Thresholds and Reporting Requirements .................................. 4-1

Table 4-2 Number of Facilities Reporting by Threshold and Industry Segment ...................... 4-7

Table 4-3 Subpart W Petroleum and Natural Gas Systems: Labor Costs (2006$) ................... 4-8

Table 4-4 Subpart W Petroleum and Natural Gas Systems: Capital and O&M Costs(2006$) 4-9

Table 4-5 Subpart W Petroleum and Natural Gas Systems: Combustion Costs (2006$) ....... 4-14

Table 4-6 Subpart W Facilities and Emissions Covered by Final Rule .................................. 4-14

Table 4-7 Summary of National Costs and Costs per Representative Entity by Threshold ... 4-16

Table 4-8 Summary of Reporting Determination Costs per Segment by Threshold .............. 4-18

Table 4-9 Allocation of Facilities to Model Types ................................................................. 4-23

Table 4-10 Labor Categories and Hourly Rates ........................................................................ 4-24

Table 4-11 Loaded Hourly Rates for Goods-Producing Private Establishments ...................... 4-25

Table 4-12 Responsibilities for Regulation Compliance by Labor Category ........................... 4-25

Table 4-13 Responsibilities for Monitoring and Allocation of Labor Hours ............................ 4-27

Table 4-14 Monitoring Program Compliance Capital Costs and Other O&M ......................... 4-33

Table 5-1 National Cost Estimates for Petroleum and Natural Gas Systems ........................... 5-2

Table 5-2 Equipment Leaks and Vented Emission Costs, Petroleum and Natural Gas 

Systems, First-Year Estimates .................................................................................. 5-3

Table 5-3 Equipment Leaks and Vented Emission Costs, Petroleum and Natural Gas 

Systems, Subsequent-Year Estimates ....................................................................... 5-3

Table 5-4 Summary of Threshold Cost-Effectiveness Analysis (First Year); Selected 

Hybrid Option Is 25,000 MtCO2e ............................................................................. 5-5

Table 5-5 Summary of Threshold Cost-Effectiveness Analysis (Subsequent Years) .............. 5-6

Table 5-6 Subpart W Cost Estimates by Threshold .................................................................. 5-7

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Table 5-7 Analysis of Alternative Monitoring Methods ......................................................... 5-10

Table 5-8 Emission Coverage and Entities Reporting for Field-Level Facility Definition 

(Onshore Production) .............................................................................................. 5-12

Table 5-9 Equipment Leaks, Vented, and Combustion Emission Cost for Field-Level

Facility Definition (Onshore Production) ............................................................... 5-12

Table 5-10 Number of Establishments by Affected Industry and Enterprise Size: 2002 ......... 5-15

Table 5-11 Number of Employees by Affected Industry and Enterprise Size: 2002 ................ 5-16

Table 5-12 Receipts by Affected Industry and Enterprise Size: 2002 ...................................... 5-17

Table 5-13 Establishment Sales Tests by Industry and Enterprise Size: First-Year Costs ....... 5-19

Table 5-14 Establishment Sales Tests by Industry and Enterprise Size: Subsequent-Year 

Costs ....................................................................................................................... 5-20

Table 2-1 Sources of GHG Emissions Considered ................................................................... 2-5

Table 2-2 Segments Included in the Petroleum and Natural Gas Regulatory Analyses ........... 2-6

Table 3-1 Options Considered in Developing Scenarios for Regulation under Subpart W 

(Final Option Indicated by Shading) ........................................................................ 3-2

Table 4-1 Selected Reporting Thresholds and Reporting Requirements ............................. 4-14-8

Table 4-2 Number of Facilities Reporting by Threshold and Industry Segment ............... 4-74-13

Table 4-3 Subpart W Petroleum and Natural Gas Systems: Labor Costs1 (2006$) ......... 4-134-17

Table 4-4 Subpart W Petroleum and Natural Gas Systems: Capital and O&M Costs2

(2006$) ............................................................................................................. 4-134-17

Table 4-5 Subpart W Petroleum and Natural Gas Systems: Combustion Costs (2006$) 4-144-18

Table 4-6 Subpart W Facilities and Emissions Covered by Final Rule ........................... 4-144-18

Table 4-7 Summary of Costs and Costs per Representative Entity by Threshold ........... 4-164-20

Table 4-8 Summary of Reporting Determination Costs per Segment by Threshold ....... 4-184-22

Table 4-9 Allocation of Facilities to Model Types .......................................................... 4-234-27

Table 4-10 Labor Categories and Hourly Rates ................................................................. 4-244-28

Table 4-11 Loaded Hourly Rates for Goods Producing Private Establishments ............... 4-254-29

Table 4-12 Responsibilities for Regulation Compliance by Labor Category .................... 4-254-29

Table 4-13 Responsibilities for Monitoring and Allocation of Labor Hours ..................... 4-274-30

Table 4-14 Monitoring Program Compliance Capital Costs and Other O&M .................. 4-334-36

Table 5-1 National Cost Estimates for Petroleum and Natural Gas Systems ........................... 5-2
xiii 

Table 5-2 Equipment Leaks and Vented Emissions Costs, Petroleum and Natural Gas 

Systems, First Year Estimates .................................................................................. 5-3

Table 5-3 Equipment Leaks and Vented Emissions Costs, Petroleum and Natural Gas 

Systems, Subsequent Year Estimates ....................................................................... 5-3

Table 5-4 Summary of Threshold Cost-Effectiveness Analysis (First Year): Selected 

Hybrid Option is 25,000 metric tons CO2e ............................................................... 5-5

Table 5-5 Summary of Threshold Cost-Effectiveness Analysis (Subsequent Years) .......... 5-65-5

Table 5-6 Subpart W Cost Estimates by Threshold ............................................................. 5-75-6

Table 5-7 Analysis of Alternative Monitoring Methods .................................................... 5-105-9

Table 5-8 Emissions Coverage and Entities Reporting for Field Level Facility Definition 

(Onshore Production) ....................................................................................... 5-125-11

Table 5-9 Equipment Leaks and Vented and Combustion Emissions Cost for Field Level 

Facility Definition (Onshore Production) ........................................................ 5-125-11

Table 5-10 Number of Establishments by Affected Industry and Enterprisea Size: 2002 . 5-155-14

Table 5-11 Number of Employees by Affected Industry and Enterprisea Size: 2002 ....... 5-165-15

Table 5-12 Receipts by Affected Industry and Enterprisea Size: 2002 .............................. 5-175-16

Table 5-13 Establishment Sales Tests by Industry and Enterprisea Size: First Year Costs5-195-18

Table 5-14 Establishment Sales Tests by Industry and Enterprisea Size: Subsequent Year 

Costs ................................................................................................................ 5-205-19
xiv 

ACRONYMS AND ABBREVIATIONS

API American Petroleum Institute

ARP accidental release prevention

BLS Bureau of Labor Statistics

BOEMRE Bureau of Ocean Energy Management, Regulation, and Enforcement

CAA Clean Air Act

CARB California Air Resources Board

CBI confidential business information

CEMS continuous emission monitoring system

CCAR California Climate Action Registry

CFR Code of Federal Regulations

CH4 methane

CMOP Coalbed Methane Outreach Program

CO2 carbon dioxide

CO2e carbon dioxide-equivalent

CRF capital recovery factor

ERMR Essential Requirements for Mandatory Reporting

DOD Department of Defense

DOE Department of Energy

DOT Department of Transportation

EGU electric generating unit

EIA Economic Impact Analysis

EO executive order

EPA U.S. Environmental Protection Agency

ERMR Essential Requirements for Mandatory Reporting

FAQ frequently asked questions

FERC Federal Energy Regulatory Commission

FR Federal Register

GHG greenhouse gas

GOADS Gulfwide Offshore Activity Data System

GoM Gulf of Mexico

GRI Gas Research Institute

HHV high heating value

ICR information collection request

IPCC Intergovernmental Panel on Climate Change

LDC local distribution company

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xv 

LMOP Landfill Methane Outreach Program

LNG liquefied natural gas

M&R metering and regulating

MMBtu million British thermal units

MMS Minerals Management Service

MtCO2e metric tons of carbon dioxide-equivalent

MW megawatt

NAICS North American Industry Classification System

NEI National Emissions Inventory

NESHAP National Emissions Standards for Hazardous Air Pollutants

NTTAA National Technology Transfer and Advancement Act of 1995

O&M operations and maintenance

OECD Organisation for Economic Co-operation and Development

OMB Office of Management and Budget

PFC perfluorocarbon

PRTR pollutant release and transfer registers

PSD Prevention of Significant Deterioration

QAPP Quality Assurance Project Plan

QA/QC quality assurance/quality control

OAQPS Office of Air Quality Planning and Standards

R&D research and development

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

SBA Small Business Administration

SBREFA Small Business Regulatory Enforcement Fairness Act

SF6 sulfur hexafluoride

SISNOSE significant impact on a substantial number of small entities

SUSB Statistics of U.S. Businesses

TCR The Climate Registry

TRI Toxics Release Inventory

TSD Technical Support Document

UMRA Unfunded Mandates Reform Act

UNFCCC United Nations Framework Convention on Climate Change

U.S.C. United States Code

USDA U.S. Department of Agriculture

WBCSD World Business Council for Sustainable Development
xvi 

WCI Western Climate Initiative

WRI World Resources Institute
xvii 

Disclaimer

The Environmental Protection Agency (EPA) regulations cited in this Economic Impact Analysis 

(EIA) contain legally-binding requirements. Several sections of the EIA offer illustrative 

examples for complying with the minimum requirements indicated by the regulations. This is 

done to provide information that may be helpful to understand the costs associated with 

reporters’ implementation efforts. Such recommendations are prefaced by the words “may” or 

“should” and are to be considered advisory. They are not required elements of the regulations 

cited in this EIA. Therefore, this document does not substitute for the regulations cited in this 

EIA, nor is it a regulation itself, so it does not impose legally-binding requirements on EPA or 

the regulated community. It may not apply to a particular situation based upon the circumstances. 

Mention of trade names or commercial products does not constitute endorsement or 

recommendation for use. 

While EPA has made every effort to ensure the accuracy of the discussion in this document, the 

obligations of the regulated community are determined by statutes, regulations or other legally 

binding requirements. In the event of a conflict between the discussion in this document and any 

statute or regulation, this document would not be controlling.

1-1 

SECTION 1

INTRODUCTION AND BACKGROUND 

1.1 Background 

On December 26, 2007, President Bush signed the fiscal year (FY) 2008FY2008

Consolidated Appropriations Amendment, which authorized funding for the U.S. Environmental 

Protection Agency (EPA) to develop and publish a draft rule on an accelerated schedule: 

[N]ot less than $3,500,000 shall be provided for activities to develop and publish 

a draft rule not later than 9 months after the date of enactment of this Act, and a 

final rule not later than 18 months after the date of enactment of this Act, to 

require mandatory reporting of [greenhouse gas] GHG emissions above 

appropriate threshold in all segments of the economy. 

The accompanying explanatory text stated that EPA shall “use its existing authority under the 

Clean Air Act” to develop a mandatory GHG reporting rule. 

The agency is further directed to include in its rule reporting of emissionsemission

resulting from upstream production and downstream sources, to the extent that the 

Administrator deems it appropriate. The Administrator shall determine 

appropriate thresholds of emissions above which reporting is required, and how 

frequently reports shall be submitted to EPA. The Administrator shall have 

discretion to use existing reporting requirements for electric generating units 

under Section 821 of the Clean Air Act. 

EPA signed the final mandatory GHG reporting ruleMandatory Reporting Rule (40 Code 

of Federal Regulations [CFR] Part 98) on September 22, 2009, which was published in the 

October 30, 2009 Federal Register (FR) (74 FR 56260). This rule did not include Subpart W, 

Petroleum and Natural Gas Systems, due to the extensive number of comments received on the 

April 10, 2009, proposal (74 FR 16448). Instead, EPA revised the Subpart W proposal based on 

its review of the comments and updated information about monitoring techniques. As a result, 

EPA issued a proposed rulemaking on April 12, 2010 (75 FR 18608) that would add Subpart W 

to 40 CFR Part 98 and collect emissionemissions data from two additional segments in the 

petroleum and natural gas source category. EPA also released an Economic Impact Analysis 

(EIA) in April, 2010 that assessed the proposed rulemaking’s costs and benefits.1

 

 

1

 Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Under Subpart W Rule 

(GHG Reporting);), see http://www.epa.gov/climatechange/emissions/subpart/w.html. 

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1-2 

This final EIA presents revised cost estimates that reflect the changes EPA made to the 

final rule based on its consideration of public comments. Overall, these changes have resulted in 

a lower cost per metric ton for industry segments to monitor and report emissions compared to 

the April 2010 proposed rulemaking. The estimated total cost for the petroleum and natural gas 

source category to comply with the final rule is $61.8 million in the first year. Of this total, it 

costs $40.1 million to monitor and report about 254 million metric tons of carbon dioxide 

equivalent (MtCO2eCO2e) process emissions, or, on average, $0.16/MtCO2e.metric ton CO2e.

This cost compares with the estimate of $0.38/ MtCO2emetric ton under the April, 2009 

proposal.2

Whereas the methodology proposed in April, 2009 for Subpart W involved 100- percent 

measurement for six segments (offshore production, onshore gas processing, transmission, 

underground storage, liquefied natural gas (LNG) storage and LNG import and& export), the 

April, 2010 notice proposed hybrid methodologies to quantify GHG emissions from eight 

segments in the petroleum and natural gas systems subpart (the original six, plus onshore 

production and natural gas distribution). Today’s rule finalizes the hybrid approach for the eight 

segments. Notably, it uses limited direct measurement (, i.e., only in areas where emissions are 

known to be significant and not enough reliable data are available to develop emissionemissions

factors).. The bulk of emissions will be quantified using engineering calculations based on actual 

facility or field data and using leak detection and “leaker” factors3. There are also some sources 

that would use population- based factors—often referred to as default factors—primarily for 

inaccessible sources or relatively small leaking sources. Consistent with the April, 2010 

proposed rulemaking and the Technical Support Document (TSD) (EPA-HQ-OAR-2009-0923-

0027), the final rule and economic analysis use population- based factors. In addition, EPA 

finalized the proposal to use the MMS4 Gulfwide Offshore Activity Data System (GOADS) 

process for collecting data from offshore production platforms. This approach leverages an 

existing GHG data collection process and minimizes burden. 

 

2

 For the final rule, the total cost estimate for the first year includes $18.4 million for non-reporters to make a 

threshold determination and $3.3 million for combustion emissionemissions reporting by reporters. The April,

2009 analysis did not include a burden estimate for non-reporters to make a threshold determination. 3 Leaker factors are developed by actual measurement of leaks from a large population of common fugitive or 

vented sources; the emission emissions quantification requires actual detection of a leak before application of a 

factor. This method provides a truer assessment of actual emissions than “population” emissionemissions factors, 

which are based on simple population count. The population count provides an estimate of “potential” emissions 

because it assumes a percentage of leaking components. 

4

 The Minerals Management Service (MMS) has been renamed the Bureau of Ocean Energy Management, 

Regulation, and Enforcement (BOEMRE).
1-3 

Today’s final rule includesThere are several key changes in today’s final rule that affect 

the compliance cost estimates. First, the final rule provides equipment thresholdsfloors on 

several emission emissions sources. Reporters will use a simple population- based 

emissionemissions factors for sources below the equipment threshold.floor. Second, EPA has 

simplified the requirementrequired for sampling of gas and emissions for many of the 

emissionemissions sources, thus considerably reducing burden. 

Overall, the hybrid methodology finalized in today’s rule results in a significant reduction 

in the compliance cost per metric ton of equipment leak and vented GHG emissionemissions

reporting, relative to the original proposal. For the six original segments, equipment leak and 

vented emissionemissions costs for reporters changed from $0.36/MtCO2emetric ton CO2e in the 

April, 2009 proposed rule to $0.28/MtCO2emetric ton CO2e in the April, 2010 proposal, and to 

$0.33/MtCO2emetric ton CO2e in the final rulemaking, based on average “first- year” costs. 5,6

These estimates do not account for onshore production and natural gas distribution, the two 

segments added in the April, 2010 proposal. Under the final rule, EPA estimates it will cost 

reporters on average, in eight segments, $0.16/MtCO2emetric ton CO2e in the first year, which is 

less than the first year cost of $0.21/MtCO2emetric ton CO2e in the April 2010 proposed 

rulemaking. 

The cost estimates for today’s rule also account for the burden to report combustion 

emissions because some reporters that equal or exceed the Subpart W threshold for equipment 

leaks and vented emissions would need to report combustion emissions under Subpart C of 40 

CFR Part 98. In those cases, the reporters would not have triggered the Subpart C reporting 

threshold in the absence of Subpart W. ThoseHowever, those that meet the emissionemissions

threshold under Subpart W, however, are required to report combustion emissions under Subpart 

C, even if the combustion emissions alone do not exceed the Subpart C threshold. In short, EPA 

expects the addition of Subpart W to the GHG reporting ruleMRR to result in the reporting of 

additional combustion emissions under Subpart C, referred to as “incremental combustion 

emissions” in this document. Of the 162.2 million MtCO2emetric tons CO2e expected to be 

reported under Subpart C, 83.5 million MtCO2emetric tons CO2e are the combustion emissions 

from petroleum and natural gas facilities that would not have reported in the absence of Subpart 

 

5

 The $0.28 figure was incorrectly stated as $0.10/metric ton in the April 2010 EIA due to typographical error. 6

 Unless otherwise specified, this document reports all costs in 2006 dollars and the emissions as CO2e using a 100-

year global warming potential from the Intergovernmental Panel on Climate Change (IPCC).. Also, subsequentyear costs are the average of costs subsequent to first-year one costs, and thereby represent a “steady-state” time 

period. 
1-4 

W. The incremental combustion emissionemissions reporting is $3.3 million per year of the total 

combustion emissionemissions cost, or $0.04/MtCO2emetric ton CO2e. 

First-yearYear one costs for Subpart W vented and equipment leak emissions are 

significantly higher than the “subsequent- year” costs, totaling $40.1 million in the first year for 

equipment leaks and vented emissionemissions determination, decreasing to $15.1 million in 

subsequent years. The higher burden is due to start-up costs in the first year. For example, the 

rule requires the installation of ports in vent lines for compressors and well equipment in the first 

year to enable spot measurement of emissions using devices such as vane anemometers. This is 

a one-time cost associated with reporting start-up; the only cost in subsequent years for those 

sources is to physically take spot measurements. 

Today’s rule finalizes the approach in the April, 2010 proposal to define vented 

emissions separately from fugitive emissions, except that it replaces the term “fugitive 

emissions” with “equipment leak.” EPA made this change in response to public comments that 

“equipment leak” is better understood in the industry. In sum, today’s final rule defines 

emissions from the petroleum and natural gas industry as follows: 

1) Ventedvented emissions, which include intentional or designed releases of 

methane (CH4) and/or carbon dioxide (CO2) containing natural gas or 

hydrocarbon gas (not including stationary combustion flue gas) from 

emissionemissions sources including, but not limited to, open- ended lines, gas 

pneumatic- powered valves and pumps, equipment depressuring to the 

atmosphere, and compressor shaft seals.; 

2) Equipmentequipment leaks, which mean are defined to include those emissions 

thatwhich are unintentional and could not reasonably pass through a stack, 

chimney, vent, or other functionally -equivalent opening.; and 

3) Flareflare combustion emissions, which include CH4, CO2, and nitrous oxide 

(N2O) emissions resulting from combustion of gas in flares. 

1.2 Role of the Economic Impact Analysis in the Rulemaking Process 

1.2.1 Legislative Authority and Context 

This report analyzes the estimated economic impacts of the mandatory reporting program 

that EPA has developed for Subpart W, in accordance with the FY 2008FY08 Appropriations 

language, under the authority of Section 114 of the Clean Air Act [CAA]. Section 114 provides 

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EPA broad authority to collect data for the purpose of “carrying out any provision” of the Act 

(except for a provision of Title II with respect to manufacturers of new motor vehicles or new 

motor vehicle engines). Section 114(a)7

 of the CAA authorizes the Administrator to, inter alia,

require certain persons (see below),) on a one-time, periodic or continuous basis, to keep records, 

make reports, undertake monitoring, sample emissions, or provide such other information as the 

Administrator may reasonably require. This information may be required of any person who (i) 

owns or operates an emission source, (ii) manufactures control or process equipment, (iii) the 

Administrator believes may have information necessary for the purposes set forth in this section, 

or (iv) is subject to any requirement of the Act (except for manufacturers subject to certain Title 

II requirements). The information may be required for the purposes of developing an 

implementation plan, an emission standard under Sectionssections 111, 112 or 1298

, determining 

if any person is in violation of any standard or requirement of an implementation plan or 

emissionemissions standard, or “carrying out any provision” of the actAct (except for a provision 

of Title II with respect to manufacturers of new motor vehicles or new motor vehicle engines)9. 

The scope of the persons potentially subject to a Sectionsection 114(a)(1) information 

request (e.g., a person “who the Administrator believes may have information necessary for the 

purposes set forth in” Sectionsection 114[(a]))) and the reach of the phrase “carrying out any 

provision” of the actAct are quite broad. EPA’s authority to request information reaches to a 

source not subject to the CAA, and may be used for purposes relevant to any provision of the 

act.Act. Thus, for example, utilizing Sectionsection 114, EPA could gather information relevant 

to carrying out provisions involving research (e.g., Sectionsection 103[(g]);)); evaluating and 

setting standards (e.g., Sectionsection 111); and endangerment determinations contained in 

specific provisions of the Act (e.g., 202); as well as other programs. 

EPA has recently announced a number of climate change related actions, including: 

 Final rulemaking with the Department of Transportation (DOT) to limit 

GHGgreenhouse gas emissions from light-duty vehicles, “Light-Duty Vehicle 

Greenhouse Gas Emission Standards and Corporate Average Fuel Economy 

Standards,” (75 FR 25324, May 7, 2010).); 

 

7

 The joint explanatory statement refers to “Section 821 of the Clean Air Act,”” but Sectionsection 821 was part of 

the 1990 CAA Amendments and was not codified into the CAA itself. 8

 Section 111 of the CAA allows for “standards of performance for new stationary sources”; Section,” section 112 is 

for “Hazardoushazardous Air Pollutants”;,” and Sectionsection 129 contains provisions for “solid waste 

combustion.” 9

 Although there are exclusions in Sectionsection 114(a)(1) regarding certain Titletitle II requirements applicable to 

manufacturers of new motor vehicle and motor vehicle engines, Sectionsection 208 authorizes the gathering of 

information related to those areas. 
1-6 

 Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases 

Under Section 202(a) of the Clean Air Act (74 FR 18886, April 24, 2009).);

 Reconsideration of the memo entitled “EPA’s Interpretation of Regulations that 

Determine Pollutants Covered byBy Federal Prevention of Significant 

Deterioration (PSD) Permit Program” (73 FR 80300, December 31, 2008).); and 

 Granting the California Waiver (74 FR 32744, July 9, 2009).

These are all separate actions. Some are related to EPA’s response to the U.S. Supreme Court’s 

decision in Massachusetts v. EPA. 127 S.Ct. 1438 (2007);), others are EPA actions to address 

climate change. The GHG reporting ruleMRR and this final rulemaking do not indicate that EPA 

has made any final decisions on these other actions; however. However, the mandatory GHG 

reporting program will provide EPA, other government agencies, and outside stakeholders with 

economy-wide data on facility-level (and in some cases corporate-level) GHG emissions, which 

could assist in future policy development. 

Accurate and timely information on GHG emissions is essential for informing future 

climate change policy decisions. Although additional data collection (e.g., for other source 

categories such as indirect emissions or offsets) will no doubt be required as the development of 

climate policies evolves, the data collected in this rule will provide useful information for a 

variety of polices. Furthermore, many existing programs collect this type of information and will 

continue to do so. Through data collected under this rule, EPA, states,States and the public will 

gain a better understanding of the relative emissions of the petroleum and natural gas industry, 

and the distribution of emissions from individual facilities within different segments of this 

industry. The facility-specific data will also improve our understanding of the factors that 

influence GHG emission rates and actions that facilities are already taking to reduce emissions. 

The Agency considered a wide range of determining factors when selecting the 

alternatives for this rule. These included the consideration of costs and benefits, which are 

essential to making efficient, cost-effective decisions for implementation of these standards. 

Other important considerations included the language of the Appropriations Act and the 

accompanying explanatory statement related to source categories; consistency with other CAA 

or state-level regulatory programs that typically require facility- or unit- level data; the relative 

accuracy of different monitoring approaches and the monitoring methods already in use within 

the petroleum and natural gas industry; and the potential burden placed on small businesses 

associated with a range of reporting thresholds. 
1-7 

This EIAEconomic Impact Analysis is intended to inform the public about the selection 

criteria for this rule, which include, but are not limited to, the potential costs and benefits that 

may result when the mandatory reporting program is implemented. 

1.2.2 Role of Statutory and Executive Orders 

Several statutes and executive orders dictate the manner in which EPA considers 

rulemaking and apply to any public documentation. The analysis required by these statutes and 

executive orders is presented in Section 6. 

EPA presents this EIAEconomic Impact Analysis for Subpart W—Petroleum and Natural 

Gas Systems—pursuant to Executive Order 12866, the guidelines of Office of Management and 

Budget (OMB) Circular A-4, and EPA’s Economic Guidelines10. These documents contain 

guidelines for assessing the benefits and costs of the selected regulatory option, as well as 

options that are more stringent or less stringent. Section 4 of the EIAEconomic Impact Analysis

presents the costs of the final rulemaking; Sectionsection 5 summarizes the cost-effectiveness 

analysis of the program and. Section 5 also qualitatively describes the benefits of the final 

rulemaking. 

1.2.3 Illustrative Nature of the Analysis 

The analysis illustrates the types of costs and benefits that may accrue as a result of the 

program. The estimates of costs reflect existing production levels in Subpart W for certain 

petroleum and natural gas systems. Estimates of emissions are based on 2006 data, with a 

number of adjustments to reflect best and most current information from published sources 

(delineated in the TSD). When the reporting program takes effect, actual patterns of economic 

activity and emissions may differ from current conditions; however. However, these data provide 

estimates of baseline conditions and estimated costs of compliance. 

1.3 Overview and Design of the Economic Impact Analysis 

This EIA comprises seven sections. Following this introductory section, Section 2 

describes segments affected by Subpart W provisions and reviews existing reporting programs 

and how they treat comparable petroleum and natural gas systems. Section 3 describes the 

development of the rule, including control options and analyses of alternative scenarios. Section 

4 characterizes baseline conditions and presents engineering estimates of the costs of complying 

with Subpart W of the rule. Section 5 presents an assessment of the monitoring and reporting 

 

10 U.S. Office of Management and Budget. Circular A-4, September 17, 2003: http://www.whitehouse.gov/omb/ 

circulars/a004/a-4.pdf. 

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costs for the petroleum and natural gas industry, a qualitative examination of uncertainty related 

to measurement accuracy of monitoring methods prescribed, and an assessment of potential 

impacts on small entities. Section 5 also presents a brief qualitative examination of potential 

benefits of the rule. Section 6 provides a discussion of the Agency’s compliance with executive 

orders and other statutes during the development of the rule. Section 7 describes EPA’s 

conclusions and findings. 

1.3.1 Establishing Baseline and Years of Analysis 

Data used for the analysis represent the most recent data available on estimates of GHG 

emissionsemission for the petroleum and natural gas source category, productive capacity, 

existing emissionemissions monitoring, and reporting activities for this industry. While EPA 

recognizes that economic growth and changes in the structure of the economy over time will 

likely result in changes in both emissions and costs for those covered by Subpart W, attempting 

to project these changes would lead to an increased level of uncertainty without conveying 

comparable improvements in the assessment. Thus, EPA uses data representing essentially 

current conditions as a proxy for conditions present when the rule takes effect. Such estimates 

are inherently uncertain because data needed for more precise measurements are not available. 

The data collected by the rule would greatly enhance future estimates. 

1.3.2 Developing the GHG Reporting Rule Considered in This Economic Impact Analysis 

In order to ensure a comprehensive consideration of GHG emissions, EPA conducted 

numerous stakeholder meetings, evaluated more thanover 484 significant and detailed comments 

(more thanover 2,700 pages for Subpart W),) and conducted extensive review and analysis of 

available information on segments and specific sources. 

EPA examined existing GHG reporting programs prior to developing the rule. Although 

the mandatory GHG rule is unique, EPA carefully considered other federal and state programs 

during development of the rule to analyzesee how these programs treat emissions from the 

petroleum and natural gas industry. One of EPA’s goals was to develop a reporting rule for 

Subpart W units that, to the extent possible and appropriate, is consistent with existing GHG 

emission estimation and reporting methodologies, in order to reduce the burden of reporting for 

all parties involved. The TSD documents EPA’sour review of GHG monitoring protocols for 

each segment identified by Subpart W that is used by federal, state, regional, and international 

voluntary and mandatory GHG programs, and EPA’sour review of state mandatory GHG rules 

and how they treat equipment leak emissions from the petroleum and natural gas industry. 

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EPA’s overall rulemaking approach began with identifyingidentification of

anthropogenic sources in the U.S. GHG Inventory and Intergovernmental Panel on Climate 

Change (IPCC). The rule would require reporting of CO2 and CH4 equipment leak and vented 

emissions, as well as and combustion-related emissions11 of CO2, and CH4, and N2O as defined 

in the rule. The IPCC focuses on CO2, CH4, and N2O for both scientific assessments and 

emissionemissions inventory purposes because these are long-lived, well-mixed GHGs not 

controlled by the Montreal Protocol on Substances that Deplete the Ozone Layer. These GHGs 

are directly emitted by human activities, are reported annually in EPA’s Inventory of U.S. 

Greenhouse Gas Emissions and Sinks, and are the common focus of the climate change research 

community. 

EPA then conducted a review of existing methodologies and reporting programs (e.g., 

California Air Resources Board [CARB], The Climate Registry [TCR], 1605b of the Energy 

Policy Act). EPA’s review of existing reporting programs and measurement methodologies 

employed by existing federal and state programs is described in Section II of the 40 CFR Part 98 

preamble (74 FR 56260, October 30, 2009). A description specific to petroleum and natural gas 

can be found in Section C of the TSD. EPA used this information to inform its selection of 

measurement and reporting methods for this final rulemaking. 

Once EPA had a complete list of source categories relevant to the United States, the 

Agency systematically reviewed those source categories against the following criteria to develop 

the list of source categories included in the proposal: 

(1) Include source categories that emit the most significant amounts of GHGs, while also 

minimizing the number of reporters.; and 

(2) Include source categories that can be quantified with an appropriate level of accuracy. 

EPA identified sourceSource categories that would be required to report. EPA were 

identified. Sources were then screened sources by several key criteria, looking at the number of 

reporters versus the coverage of emissions under various thresholds, relevant and appropriate 

quantification methodologies, quantification accuracy, and administrative burden. Based on the 

source- level screening activities, EPA then developed possible reporting methodologies for the 

selected sources. were developed. The reporting methodologies identified fall into several 

 

11 OnlyIt must be noted that only flaring emissions are required for reporting under this subpart Subpart of the GHG 

reporting rule.MRR. All other combustion- related emissions are to be reported under Subpart C of the finalized 

GHG reporting rule.MRR.
1-10 

categories, including continuous emissionemissions monitoring, calculating emissions based on 

site-specific information, and calculating emissions based on default emissionemissions factors. 

In general, for 40 CFR Part 98, EPA selected a combination of continuous emissionemissions

monitoring and calculations based on site-specific information. 

For Subpart W, the April, 2009 proposed rule involved almost exclusive application of 

detection and direct spot measurement12 of vented and equipment leak emissions for the six 

segments (offshore production, onshore natural gas processing, transmission, underground 

storage, LNG storage and LNG import and export facilities). Both the April, 2010 proposed 

rulemaking and final rulemaking include eight segments—the original six plus onshore 

petroleum and natural gas production and natural gas distribution—and significantly 

reducereduces the sources that must be directly quantified. While direct spot measurement is still 

required to develop site or equipment-specific emissionemissions factors for some major sources, 

much of the emissionemissions quantification is through effective but less burdensome use of 

engineering estimates and leak detection with use of leaker factors and component population 

count and population (default) emission factors. 

Once the Subpart W segments and methodologies had been identified, EPA evaluated 

different rule options across the following dimensions: 

– Threshold (level of emissions below which entities are not required to report):);

o 1,000 MtCO2emetric tons CO2e/year;

o 10,000 MtCO2emetric tons CO2e/year;

o 25,000 MtCO2emetric tons CO2e/year; and

o 100,000 MtCO2emetric tons CO2e/year.

– Methodology for measuring emissions:;

o Direct spot measurement;

o Facility-specific calculation methods; and

o Leaker and default emissionemissions factors.

The Agency examined several options for each dimension to identify the selected option 

for the rule. 

 

12 Direct spot measurement means that the reading is taken only once in the reporting year and through direct 

measurement using a vane anemometer or similar equipment; the measurement is not “CEMS” (continuous 

emission monitoring system), as it is not continuous. 
1-11 

The options and alternatives evaluated are described in detail in Section 3. Section 4 

details the engineering cost analysis, which outlines the monitoring and reporting activities and 

costs for each source under Subpart W that is required to report. 

1.3.2.1 Summary of the Major Changes From thefrom April, 2009 Proposed Rulemaking to the 

April, 2010 Proposed Rulemaking 

EPA received approximately 16,800 public comments on the April, 2009 proposed 

rulemaking for all subparts; more thanover 1,200 pages of those comments focused on Subpart 

W. EPA held two public hearings and conducted an unprecedented level of outreach between 

signature of the proposal and the close of the public comment period. The followingBelow are 

the major changes reflected in the April, 2010 proposed rulemaking for Subpart W: 

– Two additional petroleum and natural gas system segments were added: onshore 

production and natural gas distribution. These segments represent the largest 

(onshore production) and fourth largest (natural gas distribution) segments for 

equipment leak, vented, and flared emissions in the petroleum and natural gas 

system source category. 

– Under the April, 2009 proposed rule for Subpart W, essentially 100 percent of the 

emissions were monitored using leak detection and direct measurement. In the 

April, 2010 proposed rule, the percentage of total equipment leak and vented 

emissions directly spot measured was reduced to 6 percent. 

– The methodology selected for individual sources in each of the proposed April,

2010 rule segments was determined based on the intent to achieve the most cost 

effective coverage of emissions. Therefore, in some cases accepted engineering 

estimates based on facility data werewas used;, in others, leak detection coupled 

with use of average leaking component (i.e. leaker) factors was used (this is more 

informative data on actual leaks for long- term tracking purposes than 

emissionemissions “population” factors based on component counts). 

– Use of population emission factors was proposed in several areas, primarily for 

minor equipment leak sources and also sources that are inaccessible or 

excessively burdensome for leak detection. To the degree possible, use of these 

factors was minimized. 

– In the case of offshore production, EPA proposed reporting of existing MMS 

GOADS emissionemissions results for offshore platforms in federalFederal Gulf 

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1-12 

of Mexico (GoM) waters to avoid redundancy of reporting efforts.13 EPAWe also 

required that facilities not covered by GOADS (stateState waters and 

federalFederal non-GoM platforms) use data collection and emissionemissions

calculation methods in accordance with the BOEMREMMS GOADS program to 

reduce burden and make emissionemissions reporting consistent across the 

segment. 

In addition to the Subpart W-specific changes above, the changes affecting all subparts of 

40 CFR Part 98 would likewise affect Subpart W reporters. These changes include: 

– Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that report 

less than 25,000 MtCO2emetric tons of CO2e for five5 years to cease annual 

reporting to EPA. 

– Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that report 

less than 15,000 MtCO2emetric tons of CO2e for three3 years to cease annual 

reporting to EPA. 

– Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that stop 

operating all GHG-emitting processes and operations covered by the rule to cease 

annual reporting to EPA. 

– Added a provision in 40 CFR 98.3 for submittingsubmittal of revised annual 

GHG reports to correct errors. 

– Added, in 40 CFR 98.3, an accuracy specification of plus or minus 5 percent for 

flow meters. 

– Excluded research and development (R&D)R&D activities from reporting under 

40 CFR part 98 by adding an exclusion in 40 CFR 98.2. 

– Revised the requirements of the designated representativeDesignated 

Representative in 40 CFR 98.4 to align them with those in 40 CFR 75 (accidental 

release prevention [ARP] regulations). 

 

13 Gulf Offshore Activities Data System (GOADS) is an inventory of air emissions from platforms operating in 

federalFederal waters in the Western Gulf of Mexico, developed by The Minerals Management Service (MMS

(now called BOEMRE).). The MMS mandated that all 2,5252525 offshore operators in the Gulf of Mexico 

conduct annual surveys (in 2000 and 2005) of their GHG and other hazardous pollutants. The MMS collects 

activity data from each platform that is then used to estimate emissions. The usual cycle for this data collection 

effort has been once in every three to four years. 
1-13 

– Changed record retention to three3 years instead of five5 years for most records 

(40 CFR 98.3). 

– In the recordkeeping section (40 CFR 98.3), clarified the contents of the 

monitoring plan (called the Quality Assurance Project Plan [QAPP]QAPP at 

proposal). 

– Revised several definitions in 40 CFR Partpart 98, Subpartsubpart A to address 

comments. 

Overall, the difference between the estimated annual cost of the April, 2010 proposed 

rulemaking for Subpart W and the estimated annual cost of the April, 2009 proposed rule 

resulted from the addition of two segments to Subpart W and the significant reduction in direct 

emissionemissions spot measurements. 

1.3.2.2 Summary of the Major Changes From thefrom April, 2010 Proposed Rulemaking to the 

September, 2010 Final Rulemaking 

 Based on its consideration of comments on the April, 2010 proposed rule, EPA 

incorporated the following changes in the final rule: 

– Provide an equipment thresholda floor for compressors, separators, and 

dehydrators such that sources below the equipment thresholdfloor use a simplified 

population emissionemissions factor approach and sources above the equipment 

thresholdfloor use actual monitoring.;

– Onshore production compressors use emission factor approach for estimating 

process emissions; actual monitoring is not required.

– Use of emissions factors for all pneumatic devices in onshore production. Also, 

reporters may count the pneumatic devices in their facilities over a period of three 

years, beyond which only changes have to be reported.

– Provide an external combustion equipment threshold of 5 mmBtu per hour for 

onshore production and LDCs. External combustion equipment with a rated heat 

capacity equal to or less than this equipment threshold only report the type and 

count of equipment within a facility.

– For onshore production, population emissionemissions factors will be applied to 

major equipment rather than individual components.;

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1-14 

– Sampling is not required for estimating combustion emissions estimation, 

determining the composition of natural gas, or assessing tank vapors; best 

available estimates are acceptable.; and

– Allow the use of leak detection equipment, such as organic vapor analyzers and 

toxic vapor analyzers, in addition to using infrared devices. 

TheseThe above changes significantly reduce burden and simplify emission reporting. of 

emissions. 

1.3.3 Evaluating Costs and Benefits 

To inform the selection of the option for the final rule, EPA conducted an EIAEconomic 

Impact Analysis across the dimensions identified above in Section 1.3.2. EPA estimated the costs 

of complying with each of the reporting alternatives, and assessed the cost-effectiveness of each 

alternative by examining the costs per million MtCO2emetric ton of CO2 equivalent (MMtCO2e)

reported. This cost-effectiveness metric was considered in combination with other important 

factors such as the potential impacts on small entities and consistency with other CAA or statelevel regulatory programs and monitoring methods already in use within the regulated industries. 

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative 

The selected option for Subpart W of the mandatory GHG reporting rule is outlined 

below. Section 5 provides cost comparisons for each alternative evaluated under the following 

two dimensions. The selected option strikes a balance between impacts on small entities, 

consistency with other programs, costs incurred by the reporting entities, and emissionemissions

coverage. 

– Threshold: 25,000 MtCO2emetric tons CO2e/year 

– The thresholds for the finalized GHG reporting ruleMRR fall generally into 

three groups: capacity, emissions, or entire source category (“All in”). In 

Subpart W, a facility that emits 25,000 MtCO2emetric tons CO2e/year or more 

reports all sources for which there are methods specified in the ruleRule. 

– Subpart W facilities determine their applicability by comparing their 

emissions to a threshold of 25,000 MtCO2emetric tons CO2e/year. 

– Subpart W segments evaluate threshold from an analysis of reported vented 

and equipment leaks and stationary combustion-based emissions. 

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– Methodology: Combination of direct measurement and source-specific 

calculation methodologies

– Direct spot measurement of site- or equipment- specific emission factors from 

sources at facilities that were deemed to be essential to collect based on the 

estimated volume of emissions and the lack of effective alternative 

methodologies or emissionemissions factors. 

– Source-specific engineering calculation methods using facility-specific 

information for other sources at the facility. 

– Source-specific calculation methods for equipment identified to be leaking. 

– Source-specific use of population- based emission factors for minor vented 

and equipment leaks or inaccessible sources. 

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SECTION 2

REGULATORY BACKGROUND 

The intent of this rule is to collect accurate and timely GHG emissionemissions data that 

can be used to inform future policies. Although the mandatory GHG rule is unique, EPA 

carefully considered other federal and state programs during development of the rule, and how 

these existing programs treat the petroleum and natural gas industry. The reporting program will 

supplement rather than duplicate other U.S. government GHG programs. EPA outlines the 

Agency’sWe outline EPA’s overall rulemaking approach, sources considered, and summarize 

theour review of GHG monitoring protocols for each petroleum and natural gas system used by 

federal, state, regional, and international voluntary and mandatory GHG programs, and 

EPA’sour review of state mandatory GHG rules below. For example, the monitoring and GHG 

calculation methodologies for many of the petroleum and natural gas systems are the same as, or 

similar to, the methodologies contained in state reporting programs. The remainder of the section 

provides an overview of related existing programs and discusses their relevance in the 

development of this rule. 

2.1 EPA’s Overall Rulemaking Approach 

In response to the FY 2008FY2008 Consolidated Appropriations Amendment, EPA has 

developed this rulemaking. The components of this development are explained in the following 

subsections. 

2.1.1 Identifying the Goals of the Greenhouse Gas Reporting System 

The mandatory reporting program outlined in Subpart W will provide comprehensive and 

accurate data thatwhich will inform future climate change policies. Potential future climate 

policies include research and development initiatives, economic incentives, new or expanded 

voluntary programs, adaptation strategies, emission standards, a carbon tax, or a cap -and -trade 

program. Because EPA doeswe do not know at this time the specific policies that will be 

adopted, the data reported through the mandatory reporting system should be of sufficient quality 

to support a range of approaches. Also, consistent with the FY 2008 Consolidated

Appropriations Amendment, the GHG reporting rule covers a broad range of source categories in 

the economy; however, this EIAEconomic Impact Analysis for the final rulemaking is specific to 

Subpart W, petroleum and natural gas systems. 

To these ends, EPAwe identified the following goals of the mandatory reporting system: 
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– Obtain data that are of sufficient quality that they can be used to support a 

range of future climate change policies and regulations. 

– Balance the rule coverage to maximize the amount of emissions reported 

while minimizing reporting from small emitters. 

– Create reporting requirements that are consistent with existing GHG reporting 

programs by using existing GHG emission estimation and reporting 

methodologies to reduce reporting burden, where feasible. 

2.1.2 Developing the Rule 

For Subpart W, EPA evaluated the requirements of existing GHG reporting programs, 

obtained input from stakeholders, analyzed reporting options, and developed the general 

reporting requirements and specific requirements for each of the GHG emitting processes listed 

in Subpart W. In addition, EPA considered public comments it received on both the original 

April, 2009 and April, 2010 proposed rulemakings as it determined the reporting requirements 

issued in today’s final rule. 

2.1.3 EvaluatingEvaluation of Existing Greenhouse Gas Reporting Programs 

A number of state and regional GHG reporting systems currently are in place or under 

development. EPA’s goal is to develop a reporting rule that, to the extent possible and 

appropriate, would rely on similar protocols and formats of the existing programs for petroleum 

and natural gas systems and, therefore, reduce the burden of reporting for all parties involved. 

Therefore, EPAwe performed a comprehensive review of existing voluntary and mandatory 

GHG reporting programs, as well as guidance documents for quantifying GHG equipment leaks 

from the petroleum and natural gas source category. These GHG reporting programs and 

guidance documents specifically related to the petroleum and natural gas source category 

include: 

– U.S. national programs, such as the U.S. GHG inventory, the ARP, Department of 

Energy (DOE) 1605(b) voluntary registry, and voluntary GHG partnership 

programs (e.g., Natural Gas STAR).);

– State and regional GHG reporting programs, such as The Climate Registry (TCR), 

the Regional Greenhouse Gas Initiative (RGGI), and programs in California, New 

Mexico, and New Jersey.;

– Reporting protocols developed by nongovernmental organizations, such as the 

World Resources Institute/World Business Council for Sustainable Development 

(WRI/WBCSD).); and
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– Programs from industrial trade organizations, such as the American Petroleum 

Institute’s Compendium of GHG Estimation Methodologies for the Petroleum and 

Gas Industry. 

In reviewing these programs, EPAwe analyzed the segments covered, thresholds for 

reporting, the monitoring or emission estimating methods used, the measures to ensureassure the 

quality of the reported data, the point of monitoring, data input needs, and information required 

to be reported and/or retained. EPAWe analyzed these provisions for suitability to a mandatory, 

federal GHG reporting program, and compiled the information. Section 2.3 describes the existing 

reporting programs examined regarding Subpart W. The full review of existing GHG reporting 

programs and guidance for all GHG reporting ruleMRR subparts may be found in the docket at 

EPA-HQ-OAR-2008-0508-054. 

2.1.4 Conducting Stakeholder Outreach to Identify Reporting Issues 

Early in the development process of the GHG reporting ruleMRR, EPA conducted a 

proactive communications outreach program to inform the public about the rule development 

effort. EPA solicited input and maintained an open- door policy for those interested in discussing 

the rulemaking. Since January 2008, EPA staff has held more than 100 meetings with 

stakeholders, including the following: 

– Tradetrade associations and firms in potentially affected industries/segments.;

– Statestate, local, and tribal environmental control agencies and regional air quality 

planning organizations.;

– Statestate and regional organizations already involved in GHG emissionemissions

reporting, such as TCR, California Air Resources Board (CARB), and Western 

Climate Initiative (WCI).); and

– Environmentalenvironmental groups and other nongovernmental organizations. 

– EPA also met with U.S. Department of Interior, which has a program relevant to 

GHG emissions. 

During the meetings, EPAwe shared information about the statutory requirements and 

timetable for developing a rule and. Stakeholders were encouraged stakeholders to provide input 

on key issues. Examples of topics discussed included existing GHG monitoring and reporting 

programs and lessons learned, thresholds for reporting, schedules for reporting, scope of 

reporting, handling of confidential data, data verification, and the role of states in administering 

the program. As needed, the EPA technical workgroups followed up with these stakeholder 

groups on a variety of methodological, technical, and policy issues. EPA staff also provided 
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information to tribes through conference calls with different Indian tribal working groups and 

organizations at EPA as well as through individual calls with tribal board members of TCR.14

On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting rule. EPA held two 

public hearings, and received more thanover 16,000 written public comments. The public 

comment period ended on June 9, 2009. Subpart W received comments from more thanover 80 

entities with over 1,200 pages of comments, recommendations, and alternatives for 

consideration. 

In addition to the public hearings, EPA had an open- door policy, similar to the outreach 

conducted during the development of the proposal. As a result, EPA met with more thanover

4,000 people and 135 groups between proposal signature (March 10, 2009) and the close of the 

comment period (June 9, 2009). Details of these meetings are available in the docket (EPA-HQOAR-2009-0923). 

2.1.5 ConsideringConsideration of Public Comments on Key Reporting Issues 

EPA considered public comments submitted to the docket and those presented at hearings 

as it finalized the reporting requirements. In the context of the April, 2010 proposed rulemaking 

process, EPA held one public hearing and received more thanover 40 substantive written public 

comments. Most comments supported changes made in the proposed rule published on April 9, 

2010; however. However, various commenters expressed concern about the inclusion of the 

Onshore Production and Local Distribution segments and stated that the scope and cost burden of 

the proposal would be significantly exceed the costs estimated by EPA. In addition, many 

commenters suggested changes in methodology or quantification, which EPA incorporated into 

the final rule. For example, consistent with several commenters’ recommendations, EPA has 

provided flexibility in the types of leak detection equipment required to monitor emissions. See

the preamble of today’s final rule for a complete discussion ofabout these changes. 

2.1.6 AnalyzingAnalysis of Emissions Fromfrom the Petroleum and Natural Gas Industry 

For each of the petroleum and natural gas system segments mentioned in Section 2.2, 

EPA compiled information on current conditions in the segment, including information about 

existing monitoring equipment or reporting frameworks, estimated emissions of GHGs, and 

estimated productive capacity or throughput. Section 4 summarizes the incremental costs of 

measuring vented and equipment leak GHG emissions and conducting reporting activities for 

Subpart W facilities. Section 5 presents cost scenarios that vary the conditions of the reporting 

 

14 For a full list of organizations EPA met with when developing this rule, please see the EPA docket memo, EPAHQ-OAR-2008-0508-055. 
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rule for Subpart W with respect to the size of the entity required to report and the type of 

measurement required of the petroleum and natural gas segment. The scenarios specific to 

Subpart W are listed in Section 3. EPA also reviewed the benefits to stakeholders, including the 

public, the government, and industry, of a reporting system for petroleum and natural gas 

emissions in a qualitative analysis. These benefits are outlined in Section 5. 

2.2 Sources Considered 

A technical subgroup on vented and equipment leak emissions considered the following 

sources of emissions from the petroleum and natural gas industry, as shown in Table 2-1. Using 

screening criteria based on the feasibility of monitoring, verifying, and measuring these sources, 

the technical subgroup developed reporting methodologies for the sources in Subpart W 

identified in Table 2-2Table 2-2. 

Table 2-1 Sources of GHG Emissions Considered 

Source Subpart W: GHG EmissionsEmission Considered 

Downstream 

Direct emitters Stationary and portable combustion: Sources considered include stationary 

combustion units (e.g., drilling rigs, dehydrators, compressors, electrical generators, 

steam boilers, and heaters). 

Vented emissions: Intentional or designed releases of CH4 or CO2 containing natural 

gas or hydrocarbon gas (not including stationary combustion flue gas) that result 

from the extraction, processing, storage, and transport of fossil fuels to the point of 

final use. Examples include compressor seal vents, storage tank vents, or pneumatic 

device emissions. 

Equipment leaks: Emissions thatwhich are unintentional and could not reasonably 

pass through a stack, chimney, vent, or other functionally -equivalent opening. 

Examples include leaks from valves and connectors. 

Flare combustion: UnburnedMeans unburned hydrocarbons, including CH4, CO2, 

and N2O emissions resulting from the incomplete combustion of gas in flares from 

the extraction, processing, storage, and transport of fossil fuels to the point of final 

use. 
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Table 2-2 Segments Included in the Petroleum and Natural Gas Regulatory Analyses 

Subpart W Segments 

Onshore petroleum and natural gas production 

Offshore petroleum and natural gas production 

Natural gas transmission 

Natural gas processing 

Natural gas underground storage 

LNG storage 

LNG import & export terminals 

Natural gas distribution 

2.3 How the Mandatory GHG Reporting Program Is Different Fromfrom the Federal 

and State Programs EPA Reviewed 

The various existing state and federal programs EPA reviewed are diverse. They have 

different thresholds, require different pollutants and different types of emissionemissions sources 

to be reported, rely on different monitoring protocols, and require different types of data to be 

reported, depending on the purposes of each program. None of the existing programs require 

nationwide, mandatory GHG reporting by facilities in a large number of segments, so EPA’s 

mandatory GHG rule is unique in this regard. The remainder of this section focuses on existing 

state and federal programs that apply to petroleum and natural gas systems covered under 

Subpart W. 

Although the mandatory GHG rule is unique, EPA carefully considered other 

federalFederal and stateState programs during development of the rule. Documentation of 

EPA’sour review of GHG monitoring protocols for each source category used by federal, state, 

and international voluntary and mandatory GHG programs, and EPA’sour review of stateState

mandatory GHG rules can be found at EPA-HQ-OAR-2008-0508-056. The monitoring and GHG 

calculation methodologies for many source categories are the same as, or similar to, the 

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methodologies contained in stateState reporting programs such as TCR, the CCAR (California 

Climate Action Registry (CCAR), and stateState mandatory GHG reporting rules and similar to 

methodologies developed by EPA voluntary programs such as Climate Leaders. Similarity in 

methods will help maximize the ability of individual reporters to submit the emissionemissions

calculations to multiple programs, if desired. EPA will continue to work closely with states and 

state-based groups to ensure that the data management approach in this rule will lead to efficient 

submission of petroleum and natural gas data to multiple programs. 

The intent of this rule is to collect a reasonable estimate of GHG emissionemissions data 

that can be used to inform future policy decisions. One goal in developing the rule is to be 

consistent with the GHG protocols and requirements of other state and federal programs, where 

appropriate, in order to make use of existing cooperative efforts and reduce the burden to 

petroleum and natural gas facilities submitting reports to other programs. EPAHowever, we also 

needsneed to be sure, however, that the mandatory GHG reporting rule collects facility-specific 

vented and equipment leaks data of sufficient quality to achieve the Agency’s objectives. 

Therefore, some reporting requirements of this rule related to petroleum and natural gas 

equipment leaks are different from other federal and state programs. 

2.3.1 Inventory of U.S. Greenhouse Gas Emissions and Sinks 

The U.S. greenhouse gas inventory, prepared by EPA’s Office of Atmospheric Programs 

in coordination with the Office of Transportation and Air Quality, is an impartial, policy-neutral 

report that tracks annual GHG emissions. The annual report presents historical U.S. emissions of 

CO2, CH4, N2O, hydrofluorocarbons (HFCs),, perfluorocarbons (PFCs),, and sulfur hexafluoride

(SF6)..

The United States submits the Inventory of U.S. Greenhouse Gas Emissions and Sinks to 

the Secretariat of the United Nations Framework Convention on Climate Change (UNFCCC) as 

an annual reporting requirement. The UNFCCC treaty, ratified by the United States in 1992, sets 

an overall framework for intergovernmental efforts to tackle the challenge posed by climate 

change. The United States has submitted the GHG inventory to the United Nations every year 

since 1993. The annual Inventory of U.S. Greenhouse Gas Emissions and Sinks is consistent with 

national inventory data submitted by other UNFCCC parties, and uses internationally accepted 

methods for its emission estimates. 

In preparing the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks, EPA 

leads an interagency team that includes the DOE, the U.S. Department of Agriculture (USDA),,

the Department of Transportation (DOT), the Department of Defense (DOD), and the State 
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Department, and others. EPA collaborates with hundreds of experts representing more than a 

dozen federal agencies, academic institutions, industry associations, consultants, and 

environmental organizations. The Inventory of U.S. Greenhouse Gas Emissions and Sinks is 

peer-reviewed annually by domestic experts and by UNFCCC, and undergoes a 30-day public 

comment period, and is peer reviewed annually by UNFCCC review teams. 

The Inventory of U.S. Greenhouse Gas Emissions and Sinks is a comprehensive, topdown national assessment of national GHGgreenhouse gas emissions, and uses top-down 

national energy data and other national statistics. To achieve the goal of comprehensive national 

emissionemissions coverage for reporting under the UNFCCC, most GHG emissions in the 

report are calculated via activity data from national-level databases, statistics, and surveys. The 

use of the aggregated national data means that the national emissionemissions estimates are not 

broken down at the geographic or facility level. In contrast, this reporting rule focuses on 

bottom-up data and individual sources above appropriate thresholds. 

The inventoryInventory contains estimates of vented emissions, equipment leaks, and 

combustion emissions from petroleum systems and from natural gas systems, which are both 

IPCC source categories. Regarding the quantification of CH4 emissions from natural gas 

systems, reductions achieved through the Natural Gas STAR program and National Emissions 

Standards for Hazardous Air Pollutants (NESHAP) regulations are included (see below for more 

details on these programs). A detailed study by the Gas Research Institute (GRI)1516 and EPA 

(GRI/EPA 1996) is used as the basis for estimates of CH4 and non-combustion-related CO2

emissions from the U.S. natural gas industry in the report. 

For petroleumPetroleum and natural gasNatural Gas systems, EPA has been aware that 

there are a number of areas where the 2008 U.S. Greenhouse Gas Inventory Report assumptions 

may substantially underestimate actual emissionemissions levels. The final rule for Subpart W is 

estimated to significantly increase the level of emissions covered than are included in the 2008 

U.S. Greenhouse Gas Inventory Report by reflecting improved estimates of emissions from key 

sources such as well liquid unloadings, well workovers, well completions and compressor wet 

seal degassing vents. These estimates are based on publicly available information from the EPA 

Natural Gas STAR Web siteStar website and assumptions based on expert judgment. 

The final rule for Subpart W will therefore help to improve the development of future 

national inventories for petroleumPetroleum and natural gas systemsNatural Gas Systems by 

 

15 Now the Gas Technology Institute

16 Now the Gas Technology Institute
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improving the estimates of emissions and thereby advance the understanding of emission 

processes and monitoring methodologies. Facility, unit, and process level GHG 

emissionemissions data for all sources will improve the accuracy of future U.S. Greenhouse Gas 

Inventory Reports by confirming the national statistics and emission estimation methodologies 

used to develop the top-down inventory. The results can confirm shortcomings in the national 

statistics and identify where adjustments may be needed. 

Therefore, although the data collected under this rule will not replace the system in place 

to produce the comprehensive annual national inventoryInventory, it can serve as a useful tool to 

better improve the accuracy of future national-level inventories. 

2.3.2 Federal Voluntary Greenhouse Gas Programs 

EPA and other federal agencies operate a number of voluntary GHG reporting and 

reduction programs that EPA reviewed when developing this proposal, including several nonCO2 voluntary programs, and the DOE 1605(b) voluntary GHG registry. Several other federal 

voluntary programs encourage emissionemissions reductions, clean energy, or energy efficiency; 

this summary does not cover them all (for additional information see Review of Existing 

Programs, EPA-HQ-OAR-2008-0508-054). This summary focuses on programs that include 

voluntary GHG emission inventories or reporting of GHG emissionemissions reduction activities 

for sources that were considered for inclusion in Subpart W of this final rulemaking. 

2.3.2.1 Non-CO2 Voluntary Partnership Programs 

Since the 1990s, EPA has operated a number of non-CO2 voluntary partnership programs 

aimed at reducing emissions from GHGs such as CH4methane, SF6, and PFCs. There are four 

segment-specific voluntary methane reduction programs: Natural Gas STAR, Landfill Methane 

Outreach Partnership (LMOP), Coalbed Methane Outreach Programs (CMOP), and Ag STAR. 

In addition, there are segment-specific voluntary emissionemissions reduction partnerships for 

high- global- warming- potential gases. The program specific to those entities that fall under 

Subpart W is the Natural Gas STAR partnership, which encourages companies across the natural 

gas and petroleum industries to adopt practices that reduce methane emissions. Industry partners 

voluntarily provide technical information on projects they undertake to reduce methane 

emissions on an annual basis, but they do not submit methane emissionemissions inventories. 

2.3.2.2 1605(b) Voluntary Registry 

The DOE Energy Information Administration (EIA) established a voluntary GHG 

registry under Section 1605(b) of the Energy Policy Act of 1992. The program was recently 

enhanced and a final rule containing general reporting guidelines was published on April 21, 

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2006 (71 FR 20784); the rule is contained in 10 CFR Part 300. Unlike EPA’s proposal, which 

requires reporting of GHGgreenhouse emissions from facilities over a specific threshold, the 

DOE 1605(b) registry allows anyone (e.g., a public entity, private company, or an individual) to 

report their emissions and their emissionemissions reduction projects to the registry. Large 

emitters (e.g., anyone that emits over 10,000 MtCO2emetric tons of CO2e per year) who wish to 

register emissionemissions reductions must submit annual company-wide GHG 

emissionemissions inventories following technical guidelines published by DOE and must 

calculate and report net GHG emissionemissions reductions. The program offers a range of 

reporting methodologies from stringent direct measurement to simplified calculations using 

default factors and allows the reporters to report using the methodological option they choose. 

For the petroleum and natural gas industry, some methods for estimating emissions are outlined, 

but this petroleum and natural gas section in the 1605(b) Technical Guidelines is only meant to 

serve as a guide. Reporters can use established, published authorities’ estimation methods, which 

must be referenced. In addition, as mentioned previouslyabove, unlike EPA’s proposal, 

sequestration and offset projects can also be reported under the 1605(b) program. There is 

additional flexibility offered to small sources, which is that they can choose to limit annual 

inventories and emissionemissions reduction reports to a single type of activity rather than 

reporting company-wide GHG emissions, but they must still follow the technical guidelines. 

Reported data are made available on the Internet in a public- use database. 

2.3.2.3 Summary 

These voluntary programs are different in nature from the mandatory GHG emissions 

reporting rule. Industry participation in the programs and reporting to the programs is entirely 

voluntary. A small number of sources report, compared to the number of facilities that will likely 

be affected by Subpart W of the mandatory GHG reporting rule. Most of the EPA voluntary 

programs do not require reporting of annual emissionemissions data, but are instead intended to 

encourage GHG reduction activities and track partners’ successes in implementing such projects. 

At the same time, aspects of the voluntary programs serve as useful starting points for the 

mandatory GHG reporting rule. GHGrules. Greenhouse gas emission calculation principles and 

protocols have been developed for various types of emission sources by Climate Leaders, the 

DOE 1605(b) program, and some partnerships such as the SF6 reduction partnerships and 

SmartWay. Under these protocols, reporting companies monitor process or operating parameters 

to estimate greenhouse emissions, report annually, and retain records to document their GHG 

estimates. Through the voluntary programs, EPA, DOE, and participating companies have 
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gained understanding of processes that emit GHGs and experience in developing and reviewing 

GHG emission inventories. 

2.3.3 Federal Mandatory Reporting Programs 

2.3.3.1 Toxics Release Inventory (TRI)

The Toxics Release Inventory (TRI) requires facility-level reporting of annual mass 

emissions of approximately 650 toxic chemicals. When If they are above established thresholds, 

facilities— in a wide range of industries, such as report including manufacturing industries and , 

the petroleum industry—emit these chemicals above established thresholds, they report., and 

other industrial segments. Facilities must submit annual reports of total stack and equipment 

leaks of the listed toxic chemicals using a standardized form thatwhich can be submitted 

electronically. No information is reported on the processes and emissionemissions points 

included in the total emissions. The data reported to TRI are not directly useful for the GHG rule 

because TRI does not include GHG emissions and does not identify processes or 

emissionemissions sources. The However, the TRI program is similar, however, to the 

mandatory GHG reporting rule in that it requires direct emissionemissions reporting from a large 

number of facilities (roughly 23,000) across all major industrial segments. Therefore, EPA 

reviewed the TRI program for ideas regarding program structure and implementation. 

2.3.4 Other EPA EmissionEmissions Inventories 

2.3.4.1 National Emissions Inventory 

EPA compiles the National Emissions Inventory (NEI), a database of air 

emissionemissions information provided primarily by state and local air agencies and tribes. The 

database contains information on stationary and mobile sources that emit criteria air pollutants 

and their precursors, as well as hazardous air pollutants. Stationary point source emissions that 

must be inventoried and reported are those that emit over a threshold amount of at least one 

criteria pollutant. Many states also inventory and report stationary sources that emit amounts 

below the thresholds for each pollutant. The point sources thatsource NEI includes number more 

thanover 60,000 facilities. Required point source information consists of facility identification 

information as well as; process information detailing the types of air pollution emission sources, 

air pollution emission estimates (including annual emissions), control devices in place, stack 

parameters, and location information. The NEI differs from the GHG reporting rule in that the 

NEI contains no GHG data, and the data are reported primarily by stateState agencies rather than 

directly reported by industries. InHowever, in developing the rule, however, EPA used the NEI 

to help determine sources that might need to report under Subpart W of the GHG reporting rule. 

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EPAWe considered the types of facility and, process and activity data reported in NEI to support 

the emissionemissions data as a possible model for the types of data to be reported under the 

GHG reporting rule. 

2.3.5 State and Regional Voluntary Programs for Greenhouse Gas EmissionEmissions

Reporting 

A number of statesStates have demonstrated leadership and developed corporate 

voluntary GHG reporting programs individually or joined with other statesStates to develop 

GHG reporting programs as part of their approaches to addressing GHG emissions. The 

following discussion summarizes two prominent voluntary efforts. In developing the 

GHGgreenhouse rules, EPA reviewed the relevant protocols used by these programs as a starting 

point. The Agency recognizes We recognize that these programs may have additional monitoring 

and reporting requirements than those outlined in the rule in order to provide distinct program 

benefits. 

2.3.5.1 California Climate Action Registry 

The California Climate Action Registry (CCAR) is a voluntary GHG- registry already in 

use in California. CCAR has released several methodology documents, including a general 

reporting protocol, general certification (verification) protocol, and several segment-specific 

protocols. Companies submit emissionemissions reports using a standardized electronic system. 

Emission reports may be aggregated at the company level or reported at the facility level. CCAR 

is transitioning out of entity-emission emissions reporting;, and 2009 will be the last year it 

accepts such reporting. EmissionEmissions reporting can instead be conduced under CCAR’s 

sister organization The Climate Registry (TCR), which is based off of CCAR’s work. A number 

of members of CCAR have already made the transition over to TCR. 

2.3.5.2 The Climate Registry 

The Climate Registry (TCR) is a partnership formed by U.S. and Mexican states, 

Canadian provinces, and tribes to develop standard GHG emissionemissions measurement and 

verification protocols and reporting system capable of supporting mandatory or voluntary GHG 

emission reporting rules and policies for its member states. TCR has released a final General 

Reporting Protocol that contains procedures to measure and calculate GHG emissions from a 

wide range of source categories. It hasThey have also released a general verification protocol,

and an electronic reporting system. Several industry-specific draft protocols have been released 

recently for public comment, including Petroleum & Gas Exploration & Production Protocol 

and a verification protocol for this segment. Founding reporters (companies and other 

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organizations that have agreed to voluntarily report their GHG emissions) implemented a pilot 

reporting program in 2008. Annual reports will be submitted covering six GHGs. Corporations 

must report facility-specific emissions broken out by type of emission source (e.g., stationary 

combustion, mobile combustion, process, equipment leak and indirect) and gas (CO2, CH4, N2O, 

HFCs, PFCs and SF6) within each facility. 

2.3.6 State and Regional Mandatory Programs for Greenhouse Gas EmissionEmissions

Reporting and Control 

Several individual statesStates and regional groups of statesStates have demonstrated 

leadership and are developing or have developed mandatory GHG reporting programs and GHG 

emissionemissions control programs. This section of the preamble summarizes two regional cap

-and -trade programs and several stateState mandatory reporting rules, which cover—, or, for 

those programs still under development, have the potential to cover— the petroleum and natural 

gas segment. EPA recognizes We recognize that, like the current voluntary regional and 

stateState programs, stateState and regional mandatory reporting programs may evolve or 

develop to include additional monitoring and reporting requirements than those included in the 

rule. In fact, these programs may be broader in scope or more aggressive in implementation 

because the programs are either components of established reduction programs (e.g., cap and 

trade) or being used to design and inform specific measures that indirectly reduce GHG 

emissions (e.g., energy efficiency). 

2.3.6.1 Regional Greenhouse Gas Initiative 

The Regional Greenhouse Gas Initiative (RGGI) is a regional cap -and -trade program 

that covers CO2 emissions from electric generating units (EGUs) larger than 25 megawatts 

(MW) in member states in the Mid-Atlantic and Northeast. The program goal is to reduce CO2

emissions to 10 percent% below 1990 levels by the year 2020. Certain types of offset projects 

will be allowed, and GHG offset protocols have been developed. The states participating in 

RGGI have adopted state rules (based on a model rule) to implement RGGI in each state. The 

RGGI cap -and -trade program took effect on January 1, 2009. There has been some discussion 

of regulating additional sources of GHG emissions under the RGGI program in the future. 

2.3.6.2 Western Climate Initiative 

WCI is another regional cap -and -trade program being developed by a group of western 

statesWestern States and Canadian provinces. The goal is to reduce GHG emissions to 15 

percent below 2005 levels by the year 2020. Draft options papers and program scope papers were 

released in early 2008, public comments were reviewed, and final program design 
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recommendations were made in September 2008. Other elements of the program, such as 

reporting requirements, market operations, and offset program development continue. WCI 

released its final version of the first group of Essential Requirements for Mandatory Reporting 

(ERMR) in July 2009, and it is anticipated that WCI jurisdictions will have rules implementing 

these reporting requirements in place for the 2010 reporting year or shortly thereafter. Petroleum 

and natural gas production facilities are not listed in the first reporting group, although petroleum 

refiners must report. Several source categories are being considered for inclusion in the cap and 

trade framework. One such category is “industrial process emission sources, including petroleum 

and natural gas process emissions”17,

18,” meaning that sources covered under Subpart W of the 

federalFederal reporting rule may also be regulated under a future WCI program. The program 

might be phased in, starting with a few source categories and adding others over time. Points of 

regulation for some source categories, calculation methodologies, and other reporting program 

elements are under development. The WCI is also analyzing alternative or complementary 

policies other than cap -and -trade that could help reach GHG reduction goals. Options for rule 

implementation and for coordination with other rules and programs such as TCR are being 

investigated. 

2.3.7 State Mandatory Greenhouse Gas Reporting Rules 

Seventeen states have developed, or are developing, mandatory GHG reporting rules.19

The docket for 40 CFR Part 98 (74 FR 56260, October 30, 2009) contains a summary of these 

state mandatory rules (EPA-HQ-OAR-2008-0508-056). Final rules have not yet been developed 

by some of the states, so details of some programs are unknown. Reporting requirements have 

already entered into effect in 12twelve states as of 2009; the rest will begin between 2010 and 

2012. Reporting is typically annual, although some states require quarterly reporting for EGUs, 

consistent with RGGI. 

State rules differ with regard to which facilities must report and which GHGs must be 

reported. Some states require all facilities that must obtain Title V permits to report GHG 

emissions. Others require reporting for particular segments (e.g., large EGUs, cement plants, 

refineries). Some state rules apply to any facility with stationary combustion sources that emit a 

 

17 In the WCI design recommendations, process emissions are defined as including emissions from chemical, 

biological, and other non-combustion processes. These emissions may be deliberate (e.g., vented), fugitive (e.g., 

leaked), or accidental. 18 In the WCI design recommendations, process emissions are defined as including emissions from chemical, 

biological, and other non-combustion processes. These emissions may be deliberate (e.g., vented), fugitive (e.g., 

leaked), or accidental. 19 These are California, Colorado, Connecticut, Delaware, Hawaii, Iowa, Maine, Maryland, Massachusetts, 

New Jersey, New Mexico, North Carolina, Oregon, Virginia, Washington, West Virginia, and Wisconsin. 
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threshold level of CO2. Some apply to any facility, or to facilities within listed industries, if their 

emissions exceed a specified threshold level of CO2e. Many of the state rules apply to six GHGs 

covered by 40 CFR Part 98 (CO2, CH4, N2Omethane, nitrous oxide, HFCs, PFCs, SF6); others 

apply only to CO2 or a subset of the six gases. Most require reporting at the facility level, or by 

unit or process within a facility. 

The level of specificity regarding GHG monitoring and calculation methods varies. Some 

of the states refer to use of protocols established by TCR or CCAR, to industry-specific protocols 

(such as methods developed by the American Petroleum Institute [API]), to accepted 

international methodologies such as IPCC, and/or to emission factors in EPA’s Compilation of 

Air Pollutant Emission Factors (known as AP-42) or other EPA guidance. 

2.3.7.1 California Mandatory Greenhouse Gas Reporting Rule 

The CARB mandatory reporting rule of the California Air Resources Board (CARB) is 

an example of a state rule that covers multiple source categories and contains relatively detailed 

requirements, similar to this proposal developed by EPA. The regulation became effective on 

January 2, 2009. According to CARB, selected facilities (e.g. general stationary combustion 

facilities outside the petroleum-and-gas segment, and electricity generation and cogeneration 

plants not within the operational control of larger facilities and entities) are required to have

filedfile their first emissionemissions data reports by April 1, 2009. The rest of the facilities and 

entities are to have reportedreport by June 1, 2009 (see http://www.arb.ca.gov/cc/reporting/ghgrep/ghgschedadvisory.pdf). The rule requires facility-level reporting of all GHGs (except PFCs) 

from cement manufacturing plants, electric power generation and retail markets, cogeneration 

plants, petroleum refineries, hydrogen plants, and facilities with stationary combustion sources 

emitting greater than 25,000 MtCO2metric tons CO2 per year. The California rule does not 

impact those facilities that would be subject to reporting under Subpart W of the federalFederal

reporting rule. Part 75 (Acid Rain Program) data will be used for EGUs. The regulation contains 

specific GHG estimation methods that are largely consistent with CCAR protocols, and also 

relies on API protocols and IPCC/European Union protocols for certain types of sources. 

California continues to participate in other national and regional efforts, such as TCR and WCI, 

to assist with developing consistent reporting tools and procedures on a national and regional 

basis. 

3-1 

SECTION 3

DEVELOPMENT OF THE MANDATORY GHG REPORTING RULE 

To develop Subpart W of the Mandatory GHG Reporting Rule, EPA considered various 

dimensions of the reporting program and developed and evaluated several options for each 

dimension. After a preliminary evaluation of the options for each dimension, a recommended 

reporting program alternative was selected. Several possible program alternatives were selected, 

generally by varying one dimension at a time, while retaining the recommended option for the 

other dimensions. These alternatives were then evaluated based on estimated cost, costeffectiveness (cost per metric ton of emissions reported), and estimated impacts on small entities. 

This process is discussed in greater detail in the following sectionsbelow. 

3.1 Rule Dimensions for Which Options Were Identified 

Possible designs for Subpart W of the Mandatory GHG Reporting Rule were developed 

by varying options across two dimensions: 

1. Thresholds: Based on the discretion in the language of the appropriations bill that 

calls for emissionemissions reporting above appropriate thresholds in all segments of 

the economy, EPA has identified an appropriate threshold above which petroleum and 

natural gas facilities are required to report their GHG emissions. Types of thresholds 

considered were production or productive capacity, and emissions- based. 

2. Measurement Methodology: To be able to report their GHG emissions, facilities 

will be required to measure them using an appropriate methodology. Generally, 

measurement methodologies may be based on instrumentation and direct 

measurement, or on calculation methods based on other data available to the facility 

(e.g., activity data and emissionemissions factors). 

The options EPA considered for each dimension for Subpart W sources are discussed in 

the following sectionsbelow and summarized in Table 3-1Table 3-1. The table shows the 

combinations of options for specific dimensions. EPA conducted cost analysis for the 

combinations marked by X; the shaded box represents the final option. 
3-2 

Table 3-1 Options Considered in Developing Scenarios for Regulation Underunder

Subpart W (Final Option Indicated by Shading) 

Methodology 

Direct 

Measurement 

(CEMS) 

Hybrid: Direct spot measurement 

for major emissionemissions

sources and calculation methods 

for non-major sources 

Default 

emissionemissions

factors from EPA 

Threshold 

Capacity-based 

Emissions based 1,000 

MtCO2e X X X 

Emissions-based 

10,000 MtCO2e X X X 

Emissions-based 

25,000 MtCO2e X X X 

Emissions-based 

100,000 MtCO2e X X X 

Hybrid: 25,000 

MtCO2e unless already 

reporting based on 

capacity under another 

program 

3.1.1 Thresholds 

Three options were considered in setting the threshold above which reporting of GHG 

emissions will be required for Subpart W: capacity-based thresholds, emissionemissions-based 

thresholds, or a hybrid of the two. Within each option, various definitions and levels of the 

threshold were examined. EPA also considered capacity-based and hybrid threshold approaches 

in the preliminary phases of the analysis but did not include them in the final cost analysis. As 

explained in the following sectionsbelow, EPA ruled out these two options based on data 

limitations and other challenges. 

3.1.1.1 Option 1: Capacity-Based Thresholdbased threshold

A capacity-based threshold would be defined based on the emitting facility’s throughput, 

production, or productive capacity. In defining the capacity-based threshold, EPA considered 

that using a source-level capacity measure for the threshold might be a more straightforward way 

for facilities to know that they must report their GHG emissions, but the data on source-level 

capacity areis not currently universally available to EPA. 

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3.1.1.2 Option 2: Emission-Based ThresholdEmissions-based threshold (Selected) 

Option 2 involves the use of actual facility-level emissions of GHGs, measured in 

MtCO2e.metric tons of CO2-equivalent emissions (MtCO2e). Various levels were considered, 

ranging from 1,000 MtCO2e to 100,000 MtCO2e. Obviously, lower thresholds would require 

more facilities to participate in the reporting program. Given current data availability, an 

emissionemissions-based threshold will generally focus on larger, emissionemissions-intensive 

sources in the petroleum and natural gas segment for which emissionemissions data are readily 

calculated or measured. 

3.1.1.3 Option 3: Hybrid Thresholdthreshold

The hybrid threshold option is a combination of three general groups: capacity, 

emissions, or entire source category (“allAll in”). The thresholds developed are generally 

equivalent to a facility-wide threshold of 25,000 MtCO2emetric tons of CO2e per year of actual 

emissions. The preference is to establish thresholds for as many source categories as possible 

based on a capacity metric;, for example, tons of product produced per year. A capacity-based 

threshold is least burdensome, because a facility would not have to estimate emissions to 

determine if the rule applies. However, EPA faces two key challenges in trying to develop 

capacity thresholds, however. First, in most cases, especially involving equipment leak and 

vented emissions under Subpart W, data are insufficient to determine an appropriate capacity 

threshold. SecondSecondly, in many of the petroleum and natural gas segments, the level of 

emissions from vented and equipment leaks are not related to capacity or throughput. Rather, 

emissions may be driven by design and operating factors. As an example, pneumatic controls on 

petroleum and natural gas facilities are designed to vent natural gas to drive valve movements. 

The level of venting is not dependent on throughput. 

3.1.2 Measurement Methodology 

EPA identified three measurement methodology options, ranging from installing 

emissionemissions monitoring equipment on all sources under Subpart W to using default 

emissionemissions factors to estimate emissions. The measurement methodology options 

considered for Subpart W sources are discussed in the following sectionsbelow. 

3.1.2.1 Option 1: Direct Measurement measurement for All Reportersall reporters

This option would apply direct measurement requirements to all reporters. ItThis would 

require facilities subject to Subpart W to use fuel- flow meters for gaseous fuels and for spot 

measurement of vented emissions from various equipment. In addition, it would require spot 

detection and quantification of equipment leaks by use of calibrated bagging or high- volume 
3-4 

samplers throughout all segments. This option was the selected option for the proposed rule for 

Subpart W (74 FR 164888, April 10, 2009). 

3.1.2.2 Option 2: Hybrid of Direct Measurement and Facility-Specific Calculation for Other 

Sources (Selecteddirect measurement and facility-specific calculation for other sources 

(selected) 

EPA’s final rule required measurement methodology option for Subpart W is a hybrid of 

direct measurement and facility-specific calculations, which is considerably less burdensome 

than Option 1. Specifically, EPA requires the use of direct spot measurement, where reliable 

emissionemissions factors do not exist, as well as and engineering calculations based on sitespecific information to estimate emissions from the largest emission sources. Other sources will 

be quantified through the use of leak detection and application of emissionemissions factors for 

leaking equipment (i.e. “leaker” factors). Use of population count and default population 

emissionemissions factors is required for smaller and inaccessible sources. 

The hybrid approach results in a significantly lower cost burden to reporting parties yet 

provides a much more robust development of GHG emissions. Unlike Option 3, which is 

described in the section the followsbelow, Option 2 will enable EPA to monitor year-to-year 

changes in emissionemissions levels from the petroleum and natural gas source category.

3.1.2.3 Option 3: Default Emission Factor Calculationemissions factor calculation for Both 

Combustionboth combustion and Process Emissionsprocess emissions

Under Option 3, EPA would require petroleum and natural gas facilities to base their 

reported emissions on simplified calculations performed at the facility level, based on EPAprovided default population factors combined with the type of process, production rate, and/or 

the quantity of fuel/chemical inputs used. 

3.2 Selected Option 

As described previouslyabove, EPA evaluated a variety of options for each dimension of 

the GHG reporting program, and selected a recommended option for each dimension. A

summary ofWe summarize the recommended option for each dimension is provided as 

follows:below.

– Threshold: Emission-Emissions based approach 

– For Subpart W sources, applicability is based on emissions. Emissions are the 

sum of vented emissions and equipment leaks, stationary and portable 

combustion emissions, as well as emissions from any other source category 
3-5 

covered by the finalized GHG reporting ruleMRR that may be present at the 

facility. A facility that emits 25,000 MtCO2emetric tons CO2e/year or more 

reports all sources for which there are methods in the finalized GHG reporting 

ruleMRR and final rule for Subpartsubpart W. 

– For several segments in Subpart W, it was determined appropriate to require 

the threshold calculation by defining “facility” differently: 

o For onshore petroleum and natural gas production, the facility is 

defined as the equipment covered in the April, 2009 proposed rule and 

owned or operated by a single entity, as defined by the holder of a 

drilling or operating permit, located in a hydrocarbon basin. If a 

drilling or operating permit is not required, then the reporter is the 

entity that pays the taxes. EPA also analyzed the same facility 

definition, but as applied to a hydrocarbon field, as opposed to a 

hydrocarbon basin. As described in the preamblePreamble, the 

threshold determination and cost burden is required based on the basin 

level approach. 

o For natural gas distribution, a facility is defined as the local 

distribution company (LDC). Therefore, the threshold is based on total 

company level emissions of the LDC. 

– Methodology: A combinationCombination of direct measurement and sourcespecific calculation methodologies 

– For the Subpart W final rule, EPA is requiring the use of direct spot 

measurement and/or engineering calculations using site- specific information 

to estimate emissions from the largest emission sources. In addition, sources 

thatwhich are smaller, or are may be inaccessible forto direct measurement,

will be quantified through the use of leak detection and application of leaker 

emissionemissions factors for leaking equipment. Population count and 

population emissionemissions factors will be used for smaller and inaccessible 

sources. 

– EPA also requires sourceSource-specific calculation methods using facilityspecific information for other sources in the finalized GHG reporting 

ruleMRR present at the facility subject to the Subpart W final rule. 
3-6 

3.3 Alternative Scenarios Evaluated 

EPA developed alternative reporting scenarios and assessed the costs and emissions 

associated with each. As part of the April 2009 proposal, alternative scenarios were developed by 

creating the recommended scenario (the shaded option in Table 3-1Table 3-1), then varying the 

levels in one dimension while keeping the other three dimensions at the recommended options. 

The alternative reporting scenarios evaluated for the Subpart W final rule are listed as 

followsbelow: 

1. A 1,000- MtCO2e threshold; hybrid methodology.

2. A 10,000- MtCO2e threshold; hybrid methodology.

3. A 25,000- MtCO2e threshold; hybrid methodology. 

4. A 100,000- MtCO2e threshold; hybrid methodology.

5. A 25,000- MtCO2e threshold; direct techniques (CEMS, flow meters, calibrated 

bagging, and high volume sampler) are used to measure emissions.

6. A 25,000- MtCO2e threshold; default emissionemissions factors (simplified methods) 

are used to measure emissions.

The evaluation of the alternative reporting scenarios will allow policymakerspolicy 

makers, regulated entities, and the general public to see the impact of each variation and assess 

their cost compared to the required option. Total costs, emissions, and cost-effectiveness of the 

alternative reporting scenarios for the petroleum and natural gas industry pursuant to Subpart W 

are discussed in Section 4. 

3.4 Data Quality for This Analysis 

EPA gathered existing data from EPA, industry trade associations, states, and publicly 

available data sources (e.g., labor rates from the Bureau of Labor Statistics [BLS]) to 

characterize the processes, sources, segments, and facilities affected. Costs were estimated based 

on the data collected and engineering analysis and models provided by EPA and its contractors. 

EPA staff and contractors provided engineering expertise, knowledge of existing facility 

conditions and activities, and an estimate of incremental activities required to comply with the 

rule. Existing models, such as EPA’s CEMS “continuous emissions monitoring system” cost 

model, were used for Subpart W to ensure consistency of cost inputs and assumptions. 

The most important elements affecting the data quality for this analysis include the 

number of affected facilities in each source category, the number and types of production 
3-7 

processes that emit GHGs, process inputs and outputs (especially for monitoring procedures that 

involve a carbon mass balance), and the measurements that are already being made for reasons 

not associated with the Subpartsubpart W final rule (to allow only the incremental costs to be 

estimated). The background information for standards development, often collected from 

petroleum and natural gas industry surveys, was supplemented from numerous sources, including 

industry surveys from the U.S. Census Bureau, trade associations, and operating permits. 

Information on measurements that are already made (and thus would not be associated with the 

rule) was obtained from discussions with industry representatives, knowledge gained from 

previous site visits, and other sources. The data collected to characterize the facilities in the 

Subpart W final rule are judged to be of good quality and the best that are publicly available. 

Other elements affecting the quality of the data include estimates of labor hours to 

perform specific activities, cost of labor, and cost of monitoring equipment. Estimates of labor 

hours were based on previous analyses of the costs of monitoring, reporting, and recordkeeping 

for other rules; information from the industry characterization on the number of units or process 

inputs and outputs to be monitored for Subpart W; and engineering judgment. Labor costs were 

taken from the BLS and adjusted to account for overhead. Monitoring costs were generally based 

on cost algorithms or approaches that had been previously developed, reviewed, accepted as 

adequate, and used specifically to estimate the costs associated with various types of 

measurements and monitoring. The data quality associated with these elements of the cost 

analysis is analogous to the quality of data used in the development of numerous other 

Information Collection Requests. 

4-1 

SECTION 4

ENGINEERING COST ANALYSIS 

4.1 Introduction 

EPA estimated costs for each facility under Subpart W to comply with the rule and report 

GHG equipment leaks and vented GHG emissions. EPA used available industry and EPA data to 

characterize conditions at affected sources (i.e., affected facilities). Incremental monitoring, 

recordkeeping, and reporting activities were then identified for each type of facility, and the 

associated costs were estimated for Subpart W. Table 4-1 presents the reporting and verification 

requirements for petroleum and natural gas systems.

Table 4-1 Selected Reporting Thresholds and Reporting Requirements 

Subpart 

(Source 

Category) Industry Segment Reporting and Verification 

W—Petroleum 

& Natural Gas 

Systems 

(§98.230) 

(1) Onshore 

production 

(2) Offshore 

production 

(3) Natural gas 

processing 

(4) Natural gas 

transmission 

compression station 

(5) Natural gas 

underground 

storage 

(6) LNG storage 

(7) LNG import and 

 export terminals 

(8) Natural gas 

 distribution 

(a) Report annual emissions separately for each of the industry segment listed in (a)(1) 

through (8) below. For each segment, report emissions from each source type in the 

aggregate, unless specified otherwise. For example, an underground natural gas 

storage facility with multiple reciprocating compressors must report emissions from 

all reciprocating compressors as an aggregate number. 

 (1) Onshore petroleum and natural gas production facilities.;

 (2) Offshore petroleum and natural gas production facilities.;

 (3) Onshore natural gas processing facilities.;

 (4) Onshore natural gas transmission compression facilities.;

 (5) Underground natural gas storage facilities.;

 (6) Liquefied natural gas storage facilities.;

 (7) Liquefied natural gas import and export facilities.;

 (8) Natural gas distribution facilities. Report each source in the aggregate for 

 pipelines and for meteringMetering and regulatingRegulating (M&R) stations. 

(b) Emissions reported separately for standby equipment; 

(c) Report activity data for each aggregated source type as follows: 

 (1) Count of emissionemissions sources. 

 (2) Type of emissionemissions sources. 

 (3) Number of specified events per year or reporting period (such as blowdowns, 

well completions, etc.). 

 (4) Control measures and other equipment. 

 (5) Volume and flow rates. 

 (6) Input parameters for simulation software, if required. 

 (7) Flared/vented/and equipment leak data. 

(d) Minimum, maximum and average throughput for each operation listed in industry 

segments (a)(1) through (8) above. 

(e) For offshore petroleum and natural gas production facilities, the number of 

connected wells, and whether they are producing oil, gas, or both. 

(f) Report emissions separately for portable equipment for the following source types: 

drilling rigs, dehydrators, compressors, electrical generators, steam boilers, and 

heaters. 

 (1) Aggregate emissions by source type. 

 (2) Report count of each source type. 

Note: Many facilities that would be affected by the rule emit GHGs from multiple sources. EachThe facility must assess every 

source category that could potentially apply to each when determining if a threshold has been exceeded. If the threshold is 

exceeded for any source category, the facility must report emissions from all source categories, including those source 

categories that do not exceed the applicable threshold. 

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4.2 Overview of Cost Analysis 

The costs of complying with the rule will vary from one facility to another, depending on 

the types of emissions;, the number of affected sources at the facility;, existing monitoring, 

recordkeeping, and reporting activities at the facility; and other factors., etc. The costs include 

labor and capital costs for performing the monitoring, recordkeeping, and reporting activities 

necessary to comply with Subpart W. All costs referred to in the EIA are in 2006 dollars. 

There are two major emission emissions categories for which costs are determined. One 

is the cost to quantify process emissions (, i.e., equipment leaks and vented emissions);; the other 

is the cost to quantify the additional combustion-related emissions for facilities that did not 

exceed the Subpart C threshold with only combustion emissions. The total burden estimates 

presented for Subpart W are comprised of theaggregate costs for process and combustion 

emissions, above those covered by Subpart C alone. 

EPAWe first providesprovide a general overview of baseline reporting and the two cost 

components associated with this information collection: 1) —labor costs (i.e., the cost of labor 

by facility staff to meet the information collection requirements of the rule),) and 2) capital and 

operating and maintenance costs (e.g., the cost of purchasing and installing monitoring 

equipment or contractor costs associated with providing the required information). Additional 

details of the data, methods, and assumptions underlying the costs are documented in this 

section. 

4.2.1 Baseline Reporting 

In general, the Subpart W analysis assumes that none of the facilities in the covered 

segments are currently reporting equipment leaks and vented emissions and that many of the 

requirements will result in “new” or “full” costs to meet reporting requirements. Specifically, 

EPA assumeswe assume that there will be additional costs for any detection, sampling, and 

testing requirements in the methods used to quantify emissions from petroleum and natural gas 

sources. EPAWe are also assumesassuming that additional costs will be incurred for preparing 

monitoring and quality assurance/quality control (QA/QC) plans, performing the calculations, 

reporting the results, and maintaining records. The only significant element that EPA knowswe 

know reporters subject to Subpart W already gather is the measurements and records of 

consumption of raw materials, such as feedstocks, as part of their routine operation for 

accounting purposes. 

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4.2.2 Reporting Costs 

Costs for Subpart W were developed based on assessments of all estimated capital and 

operations and maintenance (O&M) costs to monitor, measure, detect and calculate the 

emissionemissions sources in all segments of Subpart W. Key variables and data fields were 

clearly defined to ensure that each segment developed costs around a standard set of methods 

and assumptions for Subpart W (e.g., method for annualization of capital costs, interest rate to be 

applied to capital). Cost estimates were developed for each threshold of emissions, based on the 

number of reporting entities in that threshold group and estimates of the specific capital and 

labor costs associated with conducting the emissionemissions reporting. 

4.2.2.1 Labor Costs

. The costs of complying with and administering this rule include the time of managers, 

technical, and administrative staff in both the private segment and the public segments.segment.

Staff hours are estimated for activities such asincluding: 

– Monitoring monitoring (private): staff hours to operate and maintain 

emissionemissions monitoring systems.;

– Reportingreporting (private): staff hours to gather and process available data and 

reporting it to EPA through electronic systems.; and

– Assuringassuring and releasing data (public): staff hours to quality- assure, 

analyze, and release reports. 

Staff activities and associated labor costs may vary over time. Thus, cost estimates are 

developed for start-up, first-time reporting, and subsequent reporting. 

Loaded hourly labor rates (also referred to as “wage rates”) were developed for several 

labor categories to represent the employer costs to use an hour of employees’ time in each of the 

manufacturing segment labor categories used in this analysis. The labor categories correspond to 

the job responsibilities of the personnel that are likely to be involved in GHG emissionemissions

monitoring activities at athe petroleum or natural gas facility to comply with the rulemaking. 

For purposes of this study, EPA adopted the methodology used by Rice (2002) to 

calculate the wage rates for the EPA’s TRI program.Toxics Release Inventory (TRI) Program.

Thus, the wage rates calculated for different labor categories included the employer costs for 

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employee compensation (comprising the basic wages and the corresponding benefits) and the 

overhead costs to the employer20. 

For each labor category applicable to Subpart W, the following formula was used to 

calculate the wage rates: 

Loaded Hourly Labor Rate ($/hr.) = Basic Wages ($/hr.) * 

(1 + Benefits Loading Factor + Overhead Loading Factor)).

The benefits loading factor corresponds to the relative share of benefits compensation in 

the total employee compensation (comprising basic wages and benefits). Although the benefits 

factor tends to vary by labor category and by industry (0.37 to 0.50), for purposes of this 

analysis, EPA haswe have assumed the benefits loading factor to remain the same for each labor 

category across all industries in the rule due to a lack of availability of necessary industryspecific data on benefits paid to employees. 

The overhead loading factor corresponds to the share of overhead costs to the employer 

relative to the total employee compensation. For the purposes of this analysis, EPA haswe have

also adopted the same overhead loading factor that Cody Rice (2002) used in her wage rate 

calculations. Thus the overhead loading factor that EPAwe used in the wage rate calculations 

remains the same for all labor categories and across all industry types in the rule. The overhead 

loading factor was assumed to be 0.17. 

For Subpart W, the combined “Benefits and Overhead Loading Factor” used is 0.67, or 

an overall adjustment of 1.67 times “Basic Wages.” 

4.2.2.2 Capital and O&M Cost

Costs. This includes the cost of purchasing and installing monitoring equipment or 

contractor costs associated with providing the required information. Equipment costs include 

both the initial purchase price of monitoring equipment and any facility/process modification that 

may be required. Based on expert judgment, the engineering costs analyses annualized capital 

equipment costs with the appropriate lifetime and interest rate assumptions. The equipment life 

was set at five years for Subpart W sources with one-time capital costs amortized at a rate of 

7seven percent. 

 

20 For each employee, the employer also incurs overhead costs (comprising the rental costs of the office space, 

computer hardware and software, telecommunication and other equipments, organizational support, etc.) required 

for and used by the employee to effectively fulfill his/her job responsibilities. These costs are over and above the 

employee compensation costs. 

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4.2.2.3 Other Recordkeeping and Reporting 

. Additional recordkeeping and reporting costs are added to Subpart W sources based on 

each segment’s estimated requirements. These costs are included in the “process emissions” total 

estimated costs. 

4.3 Subpart W—Petroleum and Natural Gas Systems 

4.3.1 Overview

. The relevant reporters covered in this section are those for offshore petroleum and 

natural gas production, onshore petroleum and natural gas production (including enhanced oil 

recovery, EOR), onshore natural gas processing, onshore natural gas transmission compression, 

onshore natural gas storage, LNG storage, LNG import and export and natural gas distribution. 

For each of the industry segments, with the exception of onshore production, operations 

had to be divided into single units or model facilities at three levels: ; “small, ,” “medium,,” and 

“large..” The monitoring costs were then developed per size level of a model facility. A model 

facility of a given level can be defined as the most convenient and logical unit with appropriate 

emissionemissions source counts that can aggregate to any size company to determine its 

monitoring costs. For example, in natural gas transmission, a compressor station as a facility was 

modeled at the three different model size levels. Any natural gas transmission company can 

determine its monitoring costs by assigning the model facility costs to its facilities that are 

closest to the appropriate level of the model facility. To determine the national cost from each 

segment, EPAwe assigned a model facility cost that best fit the facility based on its 

emissionemissions profile. Next, EPAwe summed the costs assigned to each facility in the 

segment to produce the total national cost in each segment. Section 4.5 of this document 

describes the calculation in further detail. 

Facilities in onshore production, however, are defined as “all petroleum or natural gas 

equipment associated with all petroleum or natural gas production wells under common 

ownership or common control by an onshore petroleum and natural gas production owner or 

operator located in a single hydrocarbon basin,”, as defined by the American Association of 

Petroleum Geologists. There is much larger variation in facility equipment by this definition, so 

developing model “small,””, “medium,””, and “large” facilities for monitoring costs is 

unintuitive and impractical. In this case, non-monitoring costs were estimated using the model 

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facilities, but equipment monitoring costs were estimated at the national level and then 

apportioned to individual operators in basins by production rates. 

Table 4-2 below provides a summary of the number of facilities that would have to report 

under the various thresholds analyzed for each of the industry segments covered by the rule. 
4-7 

Table 4-2 Number of Facilities Reporting by Threshold and Industry Segment 

.

Industry Segment 

Threshold 

1,000 10,000 25,000 100,000 

Onshore Production 8,169 1,929 981 385

Natural Gas Processing 566 396 289 130

Transmission Compressor Stations 1,695 1,443 1,145 433

Natural Gas Storage 347 200 133 36

LNGLiquefied Natural Gas Storage 54 41 33 4

LNGLiquefied Natural Gas

Terminals 5 4 4 4

Offshore Production 1192 184 58 4

Local Distribution Companies 594 203 143 66

4.3.2 Labor Costs

. To evaluate labor costs, it was necessary not only to determine the amount of time 

required for all of the tasks associated with monitoring, but also to determine who will perform 

each task. For the sake of this analysis, four labor categories were used. Assigning labor hours 

for all cost elements was based on expert judgment. When assigning hours, the size of the facility 

and role of the labor categories were taken into consideration. 

To estimate labor costs, it was assumed that all labor will be performed by middle 

managers, junior engineers, and senior operators. Middle managers are assumed to spend a total 

of two2 hours overseeing the monitoring process per quarter, but are assumed not to perform any 

of the monitoring. It was assumed that junior engineers and contracted technicians will do all of 

the monitoring, except in cases where senior operators will log any activity data required to 

estimate emissions over the course of the quarter. Several equipment types are common between 

different onshore segments and different facility sizes, but the actual monitoring time typically 

will not change per equipment unit. For example, centrifugal compressor seals are found in all 

onshore segments, except for natural gas distribution and onshore production. Measuring 

centrifugal compressor seal degassing vents was assumed to take one1 hour and that will not 

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change by segment or facility size. What changes is the number of centrifugal compressors 

located at facilities of different sizes. Thus, a series of universal assumptions about onshore 

monitoring times were created. These were multiplied by the emissionemissions source counts 

assigned to each of the model facilities to determine the required labor hours. Once the labor 

hours were calculated, by category, for each of the cost elements, they were multiplied by the 

associated labor rates to estimate labor costs per facility. For offshore monitoring, costs were 

developed on a per- platform basis for non-GOADS reporters, based on expert judgment. The 

only remaining facility costs are due to the annualized capital costs and travel, lodging, and 

shipping to conduct the actual emissionemissions monitoring. 

Table 4-3 Table 4-3below presents labor cost numbers aggregated across all segments for 

Subpart W. These data are aggregated from individual tables for each segment. Except for 

onshore production, each segment has a table for small, medium, and large facilities. 

Table 4-3 Subpart W Petroleum and Natural Gas Systems: Labor Costsa (2006$)

Activity

Estimated Labor Hours and Annual Labor Rates

Labor Cost per 

Year per 

Reporting 

Unit/Facility

Senior 

Management

Middle 

Management

Junior 

Engineer/ or 

Technician Senior Operator

($101.31/hr) ($88.79/hr) ($71.03/hr) ($63.89/hr)

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

First 

Year

Subseq.

Year

First 

Year

Subseq. 

Year

Planning 0.63 0.06 2.85 0.17 46.21 0.58 3.49 0.28 3,821 80

QA/QC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0 0

Recordkeeping 0.15 0.15 0.24 0.23 2.74 2.60 0.52 0.52 264 253

Sampling and analysis 

(calculations)

0.00 0.00 1.86 1.86 91.93 6.45 1.05 0.91 6,762 682

Reporting 0.05 0.04 1.24 1.08 4.13 3.73 13.81 13.10 1,291 1,202

Total 0.83 0.25 6.19 3.35 145.01 13.36 18.87 14.80 12,139 2,217

a

 Estimated onshore production average labor costs per year per reporting unit/facility are $12,099 for the first year and $5,168 

for the subsequent years.

Unlike the other segments, onshore production labor costs were estimated by scaling 

up equipment-level labor hours, displayed later in this document in Table 4-13

Table 4-13, to a national scale and then apportioning them by individual operator 

production rates. This approach was chosen over categorizing the operators by small, medium, 

and large because of the variety of operations present between operators in the onshore 

production segment. For this reason, the labor costs are not shown for the onshore production 

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segment like in Table 4-3Table 4-3 or and Table 4-4Table 4-4. The. However, the average 

operational and maintenance costs for the onshore production segment are shown separately in 

the bullets below each table, however. 

4.3.3 Capital and O&M Costs 

. The capital costs related to monitoring emissions and archiving of information consist of 

purchasing equipment for emissionemissions detection (or the portion of contractor purchases of 

equipment is apportioned to all its customers), emissionemissions measurement, and information 

storage. All costs are reported in 2006 U.S. dollars and annualization was assumed over an 

equipment life of five years with a 7-seven percent interest rate. Equipment leak monitoring 

does not have time-tested standards and equipment leak streams typically are not clean gas. For 

example, a centrifugal compressor wet seal degassing vent will contain fine droplets of seal 

petroleum with the gas. A five-year equipment life was chosen to be conservative in cost 

estimates, as opposed to the 10ten-year equipment life associated with long-standing, proven 

practices of measuring clean fuel streams assumed in the stationary combustion section. 

Table 4-4Table 4-4 shows the capital and operation and maintenance costs at the 25,000-

metric- ton threshold for the aggregated Subpart W segments, less onshore production. The 

disparity in first- year capital costs stems from the fact that each of the onshore segments that use 

compressors as part of normal operations are required to pay for a one-time flow measurement 

port installation on compressor seal degassing vents and reciprocating rod packing vents. This 

approach assumes that there will be no disruption in the operations becausesince the port can be 

installed when the compressor is either in standby mode or under maintenance. NoHence no

adjustment is made, therefore, for production or operational loss. First- year labor costs include 

the labor required for registration, creating a monitoring plan creation, and general planning 

procedures that are required only in the first year of compliance. The “subsequent- year” cost is a 

truer reflection of actual average costs over time. 

Table 4-4 Subpart W Petroleum and Natural Gas Systems: Capital and O&M Costsa 

(2006$) 

Activity

Cost Categories

Capital and O&M Cost 

per Unit/Facility

Capital 

Cost

Equipment 

Lifetime

(years)

Annualized 

Capital Cost 

(per year)

O&M

Costs 

(per year)

First 

Year

Subseq. 

Year

Equipment (selection, 

purchase, installation) $1,676 6 $409 n/a $409 $409 

Performance testingb n/a n/a n/a n/a n/a n/a

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Recordkeeping $78 5 $19 n/a $19 $19 

Travel N/A n/a n/a $848 $848 $848 

Total $1,754 n/a $428 $848 $1,276 $1,276 

a Estimated onshore production average capital and O&M costs per unit/facility are $57 for the first year and $57 for the 

subsequent years.

b Performance testing is not required under Subpart W, and therefore no costs are entered. 

4.3.4 Combustion Costs

. Combustion emissions occur in petroleum and natural gas systems primarily through 

natural gas used to drive compressor engines. Additional fuel is used to power drilling rigs 

(diesel) and for process heaters and boilers, glycol dehydrators, and some acid gas removal 

reboilers. Combustion emissions are included for the purposes of determining if Subpart W 

thresholds are met;, however, combustion emissions are reported separately under Subpart C for 

all industry segments, except onshore production and LDCs. Onshore production and LDC

combustion emissions will be reported under Subpart W. 

To estimate combustion emissions from compressor engines—the primary combustion 

application in Subpart W—only one emission factor was required per facility because the natural 

gas used for combustion is taken from one pipe of common fuel quality. Consequently the cost 

for monitoring fuel quality is relatively lowsmall even if there are multiple compressors at the 

facility. 

This analysis includes the cost of incremental combustion reporting and combustion 

emissions above those that exceed the Subpart C threshold alone and would therefore already be 

have been reported under Subpart C. For purposes of cost estimation, EPA determined that 

under the final rule for Subpart W, entities that need to report incremental combustion-related 

emissions would use either the Tier 1 calculation methodology as set forth in Subpart C or the 

calculation methodology as set forth in Subpart W (40 CFR 98.233(z)). EPA determined that the 

entities reporting incremental emissions under subpart C would likely not meet the requirements 

for Tier 2 or higher methods. However, as these entities will be reporting combustion emissions 

under subpart C (except onshore production and LDCs), if a facility did meet the requirements 

for a tier other than Tier 1, the facility would have to use the required method, as specified in 

subpart C.

Given that the combustion methodology in 40 CFR 98.233(z) is similar to the Tier 1 

calculation methodology, EPA estimated theThe costs to monitor and report incremental 

combustion-related emissions were estimated based on the approach used under 40 CFR partPart

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98, subpartSubpart C.

 21.22 Specifically, EPA applied the Tier 1 calculation methodology to 

estimate the costs to monitor combustion emissions that became subject to reporting as a result 

of today’s final rule. Table 4-5 presents incremental combustion cost estimates. 

The Tier 1 approach bases estimates on a fuel-specific default CO2 emission factor, a 

default high heating value of the fuel, and the annual fuel consumption from company records. 

EPA determined that entities that need to report incremental combustion-related emissions, as 

described above, would use the Tier 1 method as set forth in Subpart C; these entities would 

likely not meet the requirements for the Tier 2 or higher methods. 

EPA based its this conclusion that entities would likely report incremental combustion 

emissions using the Tier 1 method on three considerations for applicability of the Tier 2 

calculation methodology and higher, as specified in Subpart C, to the petroleum and natural gas 

industry: (1) availability of high heating values (HHVs) for the fuels combusted at the frequency 

required by the Tier 2 calculation methodology, (2) the maximum- rated heat input capacity of 

the equipment, and (3) the type of fuel being combusted. First, in order to be allowed required to 

use a Tier 2 analysis, units must have a rated heat- input capacity less than or equal to 250 

million British thermal units per hour (MMBtu/hr),, combust a fuel found in Table C-1 of 

subpart C, and sample the HHV of the fuel consumed at the required frequency in 40 CFRPart

98.34(a). It was determined that this minimum- required sampling frequency is not currently 

carried out at these smaller units, and therefore these units would not be required to use Tier 2 or 

higher. These units will generally follow Tier 1 methodology. . 

Second, Tier 3 and Tier 4 calculation methodologies generally apply to equipment with a 

maximum- rated heat- input capacity greater than 250 MMBtu/hr. A 250- MMBtu/hr rating 

means that the emissions from that individual unit alone will be greater than 25,000 

MtCO2emetric tons CO2e; these emissions would be subject to reporting under Subpart C even 

in the absence of Subpart W and therefore would not fall in the category of incremental 

combustion emissions considered in this analysis. 

 

21 40 CFR Part 98 used the IPCC tier concept to estimate combustions emissions (74 FR 56260, October 30, 2009). See EPAHQ-OAR-2008-0508-0004, U.S. EPA, Technical Support Document for Stationary Fuel Combustion Emissions: Proposed 

Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more information about the IPCC tier methodology 

(pgs 10-15). 22 40 CFR Part 98 used the IPCC Tier concept to estimate combustions emissions (74 FR 56260, October 30, 2009). See EPAHQ-OAR-2008-0508-0004, U.S. EPA, Technical Support Document for Stationary Fuel Combustion Emissions: Proposed 

Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more information about the IPCC Tier methodology 

(pgs 10-15).
4-12 

Third, the predominant fuels used in the petroleum and natural gas industry are produced 

natural gas, pipeline quality natural gas, distillate fuel, and any products recovered from 

equipment leaks and vents. The use of produced natural gas is predominant in onshore 

petroleum and natural gas production. Under the final rule for subpart W, reporters in this 

segment are allowed to use methods similar to Tier 1 for all combustion emissions sources that 

use produced natural gas. 

In the remaining segmentsOf these fuels, equipment using producedpipeline quality

natural gas, distillate fuel, or products recovered from equipment leaks and vents are normally 

required to use Tier 2 methodology or higher. However, asAs described previouslyabove, if the 

unit has a rated heat -input less than or equal to 250 MMBtu/hr, then the unit probably does not 

currently receive HHV at the required frequency for a Tier 2 and could use a Tier 1 analysis 

instead.. If the unit has a maximum- rated heat- input capacity greater than 250 MMBtu/hr, then 

as just noted, emissions from a unit of this size would already be subject to reporting and would 

not be included in the incremental combustion emissionemissions category considered in this 

analysis. Finally, the use of produced natural gas is predominant in onshore petroleum and 

natural gas production. Under the final rule, reporters are allowed to use methods similar to Tier 

1 for all combustion emissions sources that use produced natural gas. In sum, the use of Tier 1 

methodologycosts for incremental combustion is a reasonable assumption for costing the subpart 

W rule. 
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Table 4-3 Subpart W Petroleum and Natural Gas Systems: Labor Costs1 (2006$)

Activity

Estimated Labor Hours and Annual Labor Rates

Labor Cost per 

Year per 

Reporting 

Unit/Facility

Senior 

Management

Middle 

Management

Junior 

Engineer/ or 

Technician Senior Operator

($101.31/hr) ($88.79/hr) ($71.03/hr) ($63.89/hr)

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

Planning 0.73 0.08 3.29 0.19 55.68 0.67 4.02 0.32 $4,578 $93

QA/QC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0 0

Recordkeeping 0.16 0.16 0.27 0.26 2.91 2.75 0.56 0.56 $283 $270

Sampling and analysis 

(calculations)

0.00 0.00 1.83 1.83 97.70 6.80 1.11 1.03 $7,173 $711

Reporting 0.06 0.04 1.38 1.19 4.48 3.99 14.77 13.92 $1,390 $1,283

Total 0.95 0.28 6.78 3.48 160.77 14.21 20.46 15.82 $13,424 $2,357

1 Estimated Onshore Production average Labor Costs per Year per Reporting Unit/Facility are $12,099 for the first year and 

$5,168 for the subsequent years.

Table 4-4 Subpart W Petroleum and Natural Gas Systems: Capital and O&M Costs1

(2006$) 

Activity

Cost Categories

Capital and O&M Cost 

per Unit/Facility

Capital 

Cost

Equipment 

Lifetime

(years)

Annualized 

Capital Cost 

(per year)

O&M 

Costs 

(per year)

First 

Year

Subseq. 

Year

Equipment (selection, 

purchase, installation) $1,821 6 $444 n/a $444 $444 

Performance testing2 n/a n/a n/a n/a n/a n/a

Recordkeeping $86 5 $21 n/a $21 $21 

Travel N/A n/a n/a $825 $825 $825 

Total $1,906 n/a $465 $825 $1,290 $1,290 

1 Estimated Onshore Production average Capital and O&M Cost per Unit/Facility are $57 for the first year and $57 for the 

subsequent years. 2 Performance testing is not required under Subpart W therefore no costs are entered. 
4-14 

Table 4-5 Subpart W Petroleum and Natural Gas Systems: Combustion Costs (2006$) 

Activity 

Cost Categories 

Total Reporting Cost per 

Unit/Facility 

Capital 

Cost 

Equipment 

Lifetime 

(years) 

Annualized 

Capital Cost 

(per year) 

O&M 

Costs 

(per year)

First 

Year 

Subseq. 

Year 

Equipment (selection, 

purchase, installation) $3,500 10 $500 $1,700 $2,200 $2,200 

Total $3,500 $500 $1,700 $2,200 $2,200 

4.4 Summary Results: Subpart W—Petroleum and Natural Gas Systems 

For each segment in the petroleum and natural gas industry identified as amenable to a 

reporting program, four thresholds were considered for emissionemissions reporting as 

applicable to an individual facility: 1,000 metric tons of CO2 equivalent (MtCO2e) per year; 

10,000 MtCO2e per yearmtCO2e; 25,000 MtCO2e per yearmtCO2e; and 100,000 MtCO2e per 

year.mtCO2e. A threshold analysis was then conducted on each segment to determine which 

level of threshold was most suitable for each industry segment. CH4, CO2, and N2O emissions 

from each segment were included in the threshold analysis. 

Table 4-6 shows the number and share of entities and emissions covered by the final rule. 

The table shows that at lower thresholds, a higher number and share of facilities and emissions 

are covered by the rule. As the threshold increases, smaller numbers and shares of facilities and 

emissions are affected. Of significant note, 85 percent of emissions are covered at the selected 

25,000-MtCO2e metric ton CO2e threshold, but only 9 percent of facilities need to report. 

FurthermoreFurther, both total emissions and covered emissions include incremental combustion 

emissions (, i.e. those not triggered by the threshold of Subpart C alone).. 

Table 4-6 Subpart W Facilities and Emissions Covered by Final Rule 

Threshold 

Number of 

Entities 

Number of 

Facilities 

Covered 

Percent of 

Facilities 

Covered 

Total 

Emissions 

(Million 

MtCO2e/Year) 

Covered 

Emissions 

(Million 

MtCO2e/

Year) 

Percent of 

Emissions 

Covered 

Year) Year)

1,000 MtCO2e/yr

Threshold 30,241 12,622 42% 396 391 99%

10,000 MtCO2e/yr

Threshold 30,241 4,400 15% 396 362 91%

25,000 MtCO2e/yr 30,241 2,786 9% 396 337 85%

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Threshold 

100,000 MtCO2e/yr

Threshold 30,241 1,062 4% 396 273 69%

4.4.1 Detailed Threshold Analysis 

. For each segment, a threshold analysis was conducted to determine how many of the 

facilities in the segment exceed the various reporting thresholds, and the total emissions from 

these facilities. This analysis was conducted considering vented and equipment leaked CH4 and 

CO2 emissions, and combustion CH4, CO2, and N2O emissions. The vented emission and 

equipment leak estimates available from the U.S. GHG Inventory were used in the analysis. The 

emission However, the emissions estimates for four sources—well venting for liquids unloading, 

gas well venting during well completions, gas well venting during well workovers, and 

centrifugal compressor wet seal degassing venting—from the U.S. GHG Inventory were replaced 

with revised estimates, however, which are described in Appendix B of the TSD. 

Combustion emissions from processing, transmission, underground storage, LNG 

storage, and LNG import and export terminals were estimated using gas engine methane 

emissionemissions factors available from GRI/EPA (1996),, back- calculating the natural gas 

consumption in engines, and finally applying a CO2 emissionemissions factor to the natural gas 

consumed as fuel. N2O emissions were calculated similarly. In the case of offshore petroleum 

and natural gas production platforms, combustion emissions are already available from the 

GOADS (2000) study analysis and hence were directly used for the threshold analysis. In 

addition to gas engines, combustion emissions from reboilers on glycol dehydrators, acid gas 

removal amine regeneration, diesel engines on drilling rigs, and heater-treaters were estimated 

for onshore production. The volume of fuel gas required by regular operation of a glycol 

dehydrator was calculated per volume of dehydrator input; then the API Compendium 

combustion emission factors for natural gas were applied to facilities’ fuel gas use based on their 

gas production rates. The same assumptions were made to calculate combustion emissions from 

acid gas removal amine regeneration heaters. Drilling rigs were assumed to operate two 1,500-

horsepower diesel engines per well drilled, and assuming it requires 90 days to drill and 

complete any well. The API Compendium combustion emission factors for diesel engines were 

used to calculate the emissions. The total drilling emissions for the nation were calculated based 

on the number of drilling rigs in service, then apportioned to each basin by throughput. 

The threshold analysis for the rule includes equipment leak, vented, and combustion 

emissions and requires estimation of all emissions at a facility level. As a result, the total 

emissions from the threshold analysis do not necessarily match the U.S. GHG Inventory for all 

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segments of the petroleum and natural gas industry. A detailed discussion on the threshold 

analysis is available in the TSD (EPA-HQ-OAR-2009-0923). 

The general rationale for selecting a reporting threshold is to identify a level at which the 

incremental emissionemissions reporting between thresholds is the highest for the lowest 

incremental increase in number of facilities reporting between the same thresholds. This 

approach would ensure maximum emissionemissions reporting coverage with minimal burden on 

the industry. 

Table 4-7 summarizes the national costs and costs per representative entity for each 

threshold. The first five columns report subsets of costs, including costs associated with 

processes (labor, annualized capital, and operating and maintenance costs), costs associated with 

stationary combustion, and costs associated with reporting and recordkeeping. The final four 

columns report total national costs and total per-entity costs for the first year and for subsequent 

years. 

Table 4-7 Summary of National Costs and Costs per Representative Entity by Threshold 

(Million 2006$)a

Threshold 

(MtCO2e/yr) 

FirstYear 

Process 

Costsb

Cost

s

1

Subseq.-

Subsequent

Year Process 

Costsa

Costs1

FirstYear 

Combustion 

Costs 

Subseq.-

Subsequent 

Year 

Combustion 

Costs 

FirstYear 

National 

Costs 

First- Year 

Representative 

Entity Cost 

Subseq.-

Subsequent 

Year 

National 

Costs 

Subseq.-

Subsequent 

Year 

Representative 

Entity Cost 

1,000 $112.3 $46.4 $23.9 $23.9 $136.2 $0.011 $70.3 $0.006 

10,000 $53.0 $20.9 $6.6 $6.6 $59.6 $0.014 $27.5 $0.006 

25,000 $40.1 $15.1 $3.3 $3.3 $43.4 $0.016 $18.4 $0.007 

100,000 $23.1 $7.7 $0.9 $0.9 $24.0 $0.023 $8.6 $0.008 a Excludes determination costs for non-reporters; see next section for estimates of these costs. b1

 Reporting and recordkeepingRecord-keeping costs are included in process costsProcess Costs. 

Note that first-year one costs are significantly higher than the subsequent- year average 

costs, . This is due to the following reasons: 

 Initial start-up costs include labor and capital associated with establishing 

modifications to enable ongoing quantification of key emissionemissions sources.

They include This includes costs to install measurement ports in compressor and well 

vents. 
4-17 

 For onshore production, reporting occurs annually, but the measurement of key 

sources is updated every two years. 

4.4.14.4.2 Subsequent- year costs are therefore reported as an average of the cost for years 

two, three, and four. As described in Table 4-7 above, at lower thresholds, a larger 

number of facilities in each subpart are covered by the rule, and thus incur costs. For 

this reason, the total national costs, and total costs by cost subset, decline as the 

threshold increases from 1,000 MtCO2e to 10,000 MtCO2e, to 25,000 MtCO2e, and 

finally to 100,000 MtCO2e. Cost per representative entity for a particular segment 

generally declines for Subpart W as the threshold increases. Reporting Determination 

Reporting Determination. While the cost estimates for representative entities are 

assumed to capture the reporting determination burden (—i.e., the burden of estimating 

emissions to determine whether they exceed the reporting threshold), —they do not account for 

the reporting determinations made by facilities that fall below the threshold. EPA has therefore 

estimated the burden for reporting determinations made by these facilities in order to better 

reflect the rule’s total economic burden. 

EPA plans to develop screening tools and has assumed thatexpects most facilities willto

use them to make a reporting determination. As a first step, facilities would enter basic activity 

data, such as number of compressors and compressor cylinderswell count and drilling activity, 

into the tool to roughly assess whether they exceed the threshold. The screening results should 

allow manymost facilities to make their threshold determination. SomeHowever, some of the 

facilities may have to take steps in addition to the screening tools, however, to determine if they 

have to report. For example, facilities that estimate emissions close to the reporting threshold 

may want to conduct preliminary monitoring to better determine their emissions. Such facilities 

may also conduct preliminary monitoring in subsequent years to determine whether emissions in 

those years meet or exceed the reporting threshold. 

Of the 30,241 facilities in the petroleum and natural gas industry, approximately 2,786 

facilities would likely meet the threshold and have to report. The remaining 27,455 facilities are 

expected to be below the reporting threshold and would likely use the screening tool to make this 

reporting determination. In addition, 296 of the 27,455 facilities could have emissions close to 

the threshold and may supplement the screening tool analysis with some preliminary monitoring 

to determine whether or not they need to report; these 296 facilities are also assumed to conduct 

preliminary monitoring to make a reporting determination in subsequent years. 

Facilities are required to follow methodologies in the rule to make a determination. The 

costs for this activity are outlined as follows:below. 

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Planning costs are assumed to include: 

 2.5 hours for regulatory review 

 2 hours to understand what operations information is required 

 2 hours to gather operations data for screening tool(s) 

 14 hours to conduct preliminary monitoring 

Recordkeeping and reporting costs are assumed to include: 

 1 hour to use screening tool(s) and to review and report data 

Using the labor costs presented in Section 4.5.1, the cost of the reporting determination 

would be $573 per facility. The additional cost for those entities close to, but not exceeding, the 

threshold, to conduct preliminary monitoring, is $1,034. See the memo, Estimates of 

Determination Costs, in the docket for complete details about these calculations (EPA-HQ-OAR2009-0923). Table 4-8 Table 4-8 provides a summary of the determination costs by industry 

segment and threshold level. 

Table 4-8 Summary of Reporting Determination Costs per Segment by Threshold 

(2006$ in thousands)a

Segment 

 

Year 

Thresholds (metric tons) 

1,000 10,000 25,000 100,000 

Onshore petroleum and natural gas production First Year $9,146 $12,177 $12,496 $12,731 

Subsequent year $1,448 $604 $256 $92 

Offshore petroleum and natural gas production First Year $1,921 $2,886 $2,972 $2,996 

Subsequent year $241 $110 $33 $3 

Natural gas transmission First Year $259 $572 $903 $1,167 

Subsequent year $9 $114 $165 $6 

Natural gas processing First Year $0 $223 $310 $392 

Subsequent year $0 $94 $52 $6 

Natural gas underground storage First Year $56 $232 $292 $379 

Subsequent year $9 $58 $43 $19 

LNG storage First Year $4 $17 $26 $55 

Subsequent year $2 $2 $2 $2 

LNG import & export terminals First Year $13 $55 $68 $140 

Subsequent year $0 $0 $0 $0 

Natural gas distribution First Year $921 $1,276 $1,330 $1,406 

Subsequent year $133 $47 $32 $28 

Total First Year $12,320 $17,438 $18,396 $19,267

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Subsequent year $1,841 $1,030 $582 $156 a These estimates are conservative and should be viewed as an upper-bound because they were calculated at the facility-level 

rather than the company-level. For example, for offshore production, determination costs were applied to each of the 

approximately 3,000 platforms in the Gulf of Mexico rather than to the roughly 86 operators in that region. See the memo, 

“Estimates of Determination Costs,” in the docket for complete details and additional determination cost estimates (EPA-HQOAR-2009-0923).

4.5 Detailed Cost Assumptions: Subpart W—Petroleum and Natural Gas Systems 

The cost assumptions below are the basis for the determination of the costs noted in this 

section. 

STEP 1: Model Facility Development 

For each of the industry segments, with the exception of onshore production, operations 

had to be divided into single units or model facilities at three levels: ; “small, ,” “medium,,” and 

“large..” The monitoring costs were then developed per size level of a model facility. A model 

facility of a given level can be defined as the most convenient and logical unit with appropriate 

emissionemissions source counts that can aggregate to any size company to determine its 

monitoring costs. For example, in onshore natural gas transmission, a compressor station as a 

facility was modeled at the different levels. Any transmission company can determine its 

monitoring costs by assigning model facility costs to its facilities that are closest to the 

appropriate level of the model facility. Facilities in onshore production, however, are defined as 

operators reporting all equipment covered at the basin-level. There is much larger variation in 

facilities’ equipment by this definition, so developing model “small,” “medium,” and “large” 

facilities is unintuitive and impractical for estimating monitoring costs. In this case, nonmonitoring costs were estimated using the model-facility method and monitoring costs were 

estimated at the national level and then apportioned to individual operators in basins by 

production rates. 

For each of the sources designated for monitoring, both equipment and component counts 

were determined to define individual model facilities, except as noted in onshore production. For 

onshore natural gas processing, onshore natural gas transmission, underground natural gas 

storage, LNG storage, import and export facilities and natural gas distribution, equipment and 

component counts for medium facilities were assigned the national average activity factors from 

the national inventoryNational Inventory, or the nearest reasonable integer value. In some cases, 

the uncertainty associated with the activity factors were used to determine the lower bound on 

equipment and component counts, and assigned to a “small” facility. Similarly, the upper bound 

on emissionemissions source counts was assigned to a “large” facility. If illogical values, such 

as in the case of compressors in natural gas transmission compressor stations, resulted from the 

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above methodology; expert judgment was used to correct the values; bounding the aggregated 

activity levels to that of the national inventory. In the case of offshore petroleum and natural gas 

production, BOEMREMMS GOADS (-2000) data analysis by EPA was used in the same fashion 

as the national inventories. In some cases, the uncertainty estimates were not applicable. For 

example, if the uncertainty is greater thanover 100 percent,%, it would predict a negative lower 

bound for emissionemissions source counts. For these cases, expert judgment was used. Expert 

judgment was also used, where necessary, to adjust emissionemissions source counts to reflect 

real- world scenarios. Both equipment and component counts at facilities by segment and size 

are presented in the docket (EPA-HQ-OAR-2009-0923).)

STEP 2: Determine Cost Elements 

The total costs associated with complying with the April, 2009 proposed rulemaking 

were broken into five elements, each of which is described in the following information.below.

Additionally, these cost elements are considered in two ways: costs associated with start-up, and 

recurring costs. Startup costs refer to a one-time cost associated with initiating the reporting 

process. Subsequent costs for reporting on an annual basis are less than the startup costs and are 

referred to as recurring costs. 

1. Regulation compliance determination costs 

a. Start-up costs consist entirely of the labor necessary to study and review the 

regulations to assure compliance, gather data on the facility, and fill out any 

appropriate forms. 

b. Recurring costs will be small and consist entirely of labor expenses. Small 

amounts of time will be required for the company to stay aware of any updates to 

regulations and to alter the facility information to reflect any new equipment or 

facilities brought into operation or taken offline. 

2. Monitoring costs 

a. Start-up monitoring costs consist of both labor and capital costs. Capital 

investment will be required for purchasing monitoring equipment. This capital 

cost will be accounted as annualized cost, on an annual basis. Labor will be 

required for product research for monitoring instruments before actual purchase. 

Before actual monitoring takes place, labor will have to be devoted to the 
4-21 

development of a monitoring plan that will be used company-wide. Finally, 

selected employees will be trained on how to use the monitoring equipment. 

b. Recurring monitoring costs consist of labor, travel, and shipping of equipment. 

During eachEach cycle, labor will be required to conduct detection and 

quantification of emissions (, i.e., perform actual monitoring of emissions)..

Quantification may take place through direct measurement, use of engineering 

calculations and/or software, use of “leaker” emission factors for detected leaks, 

or use of component counts and population emission factors. For companies with 

multiple facilities, travel may be required for the monitoring team and/or the 

monitoring instruments may require shipping to multiple locations. 

3. Reporting costs 

a. There will be no start-up reporting costs; reporting costs are applied uniformly 

across segments reporting to the rule. 

b. Recurring reporting costs consist of labor necessary to document collected 

emissionemissions data from equipment leak monitoring and to submit the official 

report in each cycle (i.e., annually). 

4. Archiving and recordkeeping costs 

a. Start-up archiving and recordkeeping costs consist of labor and annualized capital 

purchase of storage space. For archiving reports and associated working 

documents, a physical storage system such as a file cabinet, and an electronic 

storage system such as an external hard drive, will be required. 

b. Recurring archiving and recordkeeping costs consist entirely of labor necessary to 

adequately archive each cycle’s report and associated working documents. 

5. Auditing costs 

a. There is no start-up cost associated with auditing. 

b. Recurring auditing costs consistconsists of labor required to validate to the EPA 

results from emission the monitoring of emissions and the follow-up fromof

rectifying any weaknesses found through the audit. The EPA audit is assumed to 

occur once in several years, not on an annual basis. 
4-22 

STEP 3: Analyze Proportion of Facilities in Different Model Facility Levels 

Facilities were classified and rank-listed in ascending order based on theirTo classify the 

facilities into different sizes, total combustion, equipment leaked, and vented CO2, N2O, and 

CH4 emissions from individual facilities, expressed in CO2e., were rank listed in an ascending 

order. Cumulative emissions for the facilities were calculated by addingsumming the emissions 

of anthe individual facility to those of the facilities before it in the ascending list. The cumulative 

emissions, in combination with the total emissions from all facilities, were used to assign 

facilities to the small, medium, and large category. 





 



  TotalEmissions

CumulativeEmissions Percentile(%)

The facilities that accounted for the first 33 percent% of the emissions nationally in the 

ranked list were identified as a small facilities.facility. The facilities that accounted for national 

emissions greater than 33 percent but less than 67 percent in the ranked list were identified as a 

medium facilities.facility. The facilities that accounted for national emissions greater thanover 67 

percent in the ranked list were identified as a large facilities.facility. Table 4-9Table 4-9 indicates 

the data sources used to apportion total GHG emissions to individual facilities, and the number 

of facilities that fall into each category per segment. 

STEP 4: Assigning Costs to Cost Elements 

Assigning costs to each of the cost elements was completed in three steps: 

1. Determine labor categories and associated labor rates.,

2. Allocate responsibilities to labor categories to estimate labor hours., and

3. Determine annualized capital costs and operation & maintenance (O&M) costs for 

each of the cost elements. 

These steps are described in morefurther detail as follows:below.
4-23 

Table 4-9 Allocation of Facilities to Model Types 

Segment Data Source Small Facilities Medium Facilities Large Facilities 

Offshore Petroleum and Natural Gas Production 

 Facility Percentile BOEMRE, 2000MMS

GOADS Emission 

Inventory,Report &

Lasser, 2006 

0–33% 34%–67% 68%–100% 

 Facility Count BOEMRE, 2000MMS

GOADS Emission 

Inventory,Report &

Lasser, 2006 

3,036 191 8 

Mean Emissions (MtCO2e) This Analysis 1,430 22,733 483,806 

 Operator/Company a1 Not estimated 

Onshore Petroleum and Natural Gas ProductionbProduction2

 Facility Percentile HPDI, 2006 0–33% 34%–67% 68%–100%

 Facility Count HPDI, 2006 22,275 194 41 

Operator/Company HPDI, 2006 — — — 

Mean Emissions (MtCO2e) This Analysis 3,988 451,120 2,170,820 

Onshore Natural Gas Processing 

 Facility Percentile API, 2008 Impact 

Assessment of Mandatory 

GHG Control 

LegislationAPI 

Processing Report

0–33% 34%–67% 68%–100% 

 Facility Count c3 API, 2008 Impact 

Assessment of Mandatory 

GHG Control 

LegislationAPI 

Processing Report

486 64 16 

 Operator/Company API, 2008 Impact 

Assessment of Mandatory 

GHG Control 

LegislationAPI 

Processing Report

166 28 10 

Mean Emissions (MtCO2e) This Analysis 36,486 275,823 1,137,595 

Onshore Natural Gas Transmission 

 Facility Percentile FERC, 2008 0–33% 34%–67% 68%–100% 

 Facility Count FERC, 2008 1,314 374 255 

 Operator/Company FERC, 2008 147 46 27 

Mean Emissions (MtCO2e) This Analysis 21,293 98,738 210,829 

Natural Gas Underground Storage 

 Facility Percentile EIA, 2006. Underground 

Storage Field Level 

DataEIA

0–33% 34%–67% 68%–100% 

 Facility Count EIA, 2006. Underground 

Storage Field Level 

DataEIA

325 50 22 

 Operator/Company EIA, 2006.Underground 

Storage Field Level 

DataEIA

102 37 17 

Formatted Table

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4-24 

Segment Data Source Small Facilities Medium Facilities Large Facilities 

Mean Emissions (MtCO2e) This Analysis 12,404 82,199 183,936 

LNG Storage 

 Facility Percentile GTI. 2007. The World 

Energy Source BookGTI

0–33% 34%–67% 68%–100% 

 Facility Count GTI. 2007. The World 

Energy Source BookGTI 141 12 4 

 Operator/Company GTI. 2007. The World 

Energy Source BookGTI 141 11 3 

Mean Emissions (MtCO2e) This Analysis 20,972 55,340 223,275 

LNG Import and Export 

 Facility Percentile FERC, 2008 — 0–100% — 

 Facility Count FERC, 2008 — 5 — 

 Operator/Company Not estimated 

Mean Emissions (MtCO2e) This Analysis — 174,643 — 

Natural Gas Distribution 

 Facility Percentile DOT, 2006 0–33% 34%–67% 68%–100% 

 Facility Count DOT, 2006 1,360 50 17 

 Operator/Company DOT, 2006 1,268 49 16 

Mean Emissions (MtCO2e) This Analysis 5,840 167,066 536,719 

Notes: 

a

 The BOEMRE 2000 Gulfwide Emissions Inventory1 MMS 2007 statistics reports 2,5253,923 offshore platforms and 

86139 operators. No data are available for individual offshore platforms and their respective operators. 

b2 The onshore production burden analysis was conducted using a hybrid approach. Capital costs and some recurring O&M costs 

were assigned on a small, medium, and large basis; however, the majority of the recurring O&M costs were determined by 

apportioning nationwide costs by individual operator throughput. 

c3

 Assumed one facility per company; no data available for small plants. 

4.5.1 Determining Labor Categories 

To evaluate labor costs, it was necessary to not only determine the amount of time 

required for all of the tasks associated with monitoring, but also to determine who will perform 

each task. For the sake of this analysis, five labor categories were used, as shown in Table 4-10. 

Table 4-10 Labor Categories and Hourly Rates 

Labor Category Description Loaded Hourly Ratea Rate

Senior Manager Oversees work at a high level. Is the final authority on 

all reporting requirements. 

$101.31/hour 

Middle Manager Oversees junior engineer’s progress and reports; also 

interacts with senior manager. Does not gather 

information, write reports, or perform monitoring. 

$88.79/hour 

Junior Engineer Conducts monitoring of emissionemissions sources. 

Interfaces between middle manager and senior operator 

to collect information and complete reports. 

$71.03/hour 

Formatted Table

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4-25 

Senior Operator Primarily interfaces with junior engineer to collect 

facility information and assist with initiating the 

reporting process and reporting. Sometimes logs data 

used in the monitoring process. 

$63.89/hour 

Technician Contracted by the company to perform basic leak 

detection activities. 

$55.20/hour 

a

 Source:1 All data from U.S. Department of Labor, Bureau of Labor Statistics, National Compensation Survey -

Compensation Cost Trends, Employer Cost for Employee Compensation (ECEC), Customized Tables, as of March 11, 2003.

These labor rates originate from an analysis of loaded hourly rates for goods and 

producing private establishments at the end of 2007, shown in Table 4-11Table 4-11. below.

Since the petroleum and natural gas industry hourly rates arepays comparatively high compared

to other industries, the top four non-lawyer categories were used to be conservative in this 

approximation. Specifically, the labor rate of senior managers were assumed to be that of 

refinery mangers;, middle manager labor rates were assumed to be that of electricity managers;,

junior engineer labor rates were assumed to be that of industrial managers;, senior operator labor 

rates were assumed to be that of refinery engineers/technicians;, and contracted technician labor 

rates were assumed to be that of industrial engineer/technician category. 

Table 4-11 Loaded Hourly Rates for Goods- Producing Private Establishments 

Labor Category Loaded Hourly Rate ($/hour)a

Electricity Manager $88.79 

Refinery Manager $101.31 

Industrial Manager $71.03 

Lawyer $101.00 

Electricity Engineer/Technician $60.84 

Refinery Engineer/Technician $63.89 

Industrial Engineer/Technician $55.20 

Administrative Support $29.65 

a

 Source:1 All data from U.S. Department of Labor, Bureau of Labor Statistics, National Compensation Survey - Compensation Cost 

Trends, Employer Cost for Employee Compensation (ECEC), Customized Tables, as of March 11, 2003. 

4.5.2 Allocating Responsibilities 

Assigning labor hours for all cost elements was based on expert judgment. When 

assigning hours, the size of the facility and role of the labor categories were taken into 

consideration. Table 4-12 summarizes these roles. 

Table 4-12 Responsibilities for Regulation Compliance by Labor Category 

Formatted: Indent: Left: 0", First line: 

0"
4-26 

Cost Element 

Senior 

Management 

Middle 

Management Junior Engineer Senior Operator

Per Facility/ 

Per 

Companya

Com

pany1

Facility data To review 

reporting 

documentation/ 

systems and 

facility data 

To review 

reporting 

documentation/ 

systems and 

facility data 

To initiate 

reporting process 

and prepare 

facility data 

To prepare and 

review reporting 

process 

documentation 

and facility data 

Per facility 

Regulation 

review 

To review the 

new regulations 

To review the new 

regulations 

To examine and 

identify potential 

new regulations 

To review the new 

regulations 

identified and 

determine their 

applicability 

Per company 

Plan 

development 

To review the 

monitoring plan 

To review the 

monitoring plan 

To develop a 

monitoring plan 

To develop and 

review the 

monitoring plan 

Per company 

Equipment 

purchase 

To approve the 

equipment 

purchase 

To review the 

equipment to be 

purchased 

To identify and 

purchase the 

equipment 

To review the 

equipment to be 

purchased 

Per company 

Start-up/ 

training 

 To review training 

plan 

To acquire 

training 

To provide and 

acquire training 

Per facility 

Data 

documentation 

To review the 

reporting 

documentation 

To prepare and 

complete the 

reporting 

documentation 

To prepare 

reporting 

documentation 

To prepare and 

complete 

reporting 

documentation 

Per facility 

Report 

submission 

To ensure the 

completion of the 

reporting 

documentation 

To submit the 

report 

 Per Facility 

Archiving 

reports 

 To archive the 

reporting 

documentation 

To archive the 

reporting 

documentation 

Per facility 

Audit To review the 

audit results 

To review the 

audit results 

To assist and 

provide 

information on 

EPA audits 

 Per facility 

Audit follow-up To review the 

audit follow-up 

results and 

approve 

corrective 

measures 

To review the 

audit follow-up 

results and review 

corrective 

measures 

To determine 

corrective 

measures from 

EPA audit 

To assist in 

determining 

corrective 

measures from 

EPA audit 

Per facility 

a Some1

Some activities only have to be done at the company level, with information and/or equipment shared 

among facilities of the company. 

The labor costs associated with performing the actual annual monitoring were 

omitted from Table 4-12.the table above. For these costs, it was assumed that all labor will be 

performed by middle managers, junior engineers, senior operators, and contracted technicians. 

The assumed responsibilities and associated hours are organized in

Table 4-13

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4-27 

Table 4-13. Additionally, several pieces of equipment are common among different 

onshore segments and different facility sizes, but the actual monitoring time typically will not 

change per equipment unit. The series of universal assumptions about onshore monitoring times 

are also provided in Table 4-13.

Table 4-13 does not include equipment monitoring on offshore petroleum and natural gas

production facilities. Offshore production platforms are proposed to use data already collected 

for BOEMRE GOADS to estimate GHG emissions from their operations. Specifically, the 

BOEMRE GOADS program requires GHG emission monitoring from platforms in the Gulf of 

Mexico federal waters. Facilities under this final rulemaking are required to report the same 

emission data calculated by the GOADS program; hence, these platforms have minimal 

additional reporting burden. The cost burden model assumes that this monitoring requires 30 

minutes per platform. 

Table 4-13 Responsibilities for Monitoring and Allocation of Labor Hours 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

Onshore Facility Equipment Leaks 

Senior operatorOperator Count large, major pieces 

of equipment (0.5 minutes/

/ equipment) 

 Onshore Production 

Processing Facility Equipment Leaks 

Technician Conduct equipment leak 

detection survey (8 hours/

small facility, 12 hours/

medium facility, or 16 

hours/large facility) 

 Processing 

Junior engineer Estimate emissions using 

leaker factors (2 

hours/facility) 

Processing 

Middle 

managementManagement

Oversee part of the 

detection process and 

review results (1 

hour/reporting period) 

Oversee part of the 

measurement process and 

review results (1 hour/

reporting period) 

Processing 

Transmission Facility Equipment Leak 

Technician Conduct equipment leak 

detection survey (17 hours/

small facility, 19 hours/

medium facility, and 19 

hours/large facility) 

 Transmission 

Junior engineer Estimate emissions using 

leaker factors (2 hours/ 

small facility, 2 hours/

Transmission 

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Formatted Table
4-28 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

medium facility, and 3 

hours/ large facility) 

Middle 

managementManagement

Oversee part of the 

detection process and 

review results (1 

hour/reporting period) 

Oversee part of the 

measurement process and 

review results (1 hour/hours

reporting period) 

Transmission 

Underground Storage Facility Equipment Leak 

Technician Conduct equipment leak 

detection survey (47 hours/

small facility, 53 hours/

medium facility, and 63 

hours/large facility) 

 Storage 

Junior engineer Estimate emissions using 

leaker factors (2 hours/ 

small facility, 3 hours/

medium facility, and 2 

hours/ large facility) 

Storage 

Middle 

managementManagement

Oversee part of the 

detection process and 

review results (1 

hour/reporting period) 

Oversee part of the 

measurement process and 

review results (2 hours/

reporting period) 

Storage 

LNG Import/Export Terminal Equipment Leak 

Technician Conduct equipment leak 

detection survey (43 hours/

facility) 

 LNG Import and Export 

Facilities 

Junior engineer Estimate emissions using 

leaker factors (2 hour/ 

facility) 

LNG Import and Export 

Facilities 

Middle 

managementManagement

Oversee part of the 

detection process and 

review results (2 

hours/reporting period) 

Oversee part of the 

measurement process and 

review results (1 hour/ 

reporting period) 

LNG Import and Export 

Facilities 

LNG Storage Facility Equipment Leak 

Technician Conduct equipment leak 

detection survey (12 hours/

small facility, 19 hours/

medium facility, and 24 

hours/large facility) 

 LNG Storage 

Junior engineer Estimate emissions using 

leaker factors (2 hours/ 

small facility, 2 hours/

medium facility, and 3 

hours/ large facility) 

LNG Storage 

Middle 

managementManagement

Oversee part of the 

detection process and 

review results (1 

hour/reporting period) 

Oversee part of the 

measurement process and 

review results (1 hour/

reporting period) 

LNG Storage 

Formatted Table
4-29 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

LDC Above Grade M&R Station Equipment Leak 

Technician Conduct equipment leak 

detection survey (1 minute/

station) 

 Distribution 

Junior engineer Estimate emissions using 

leaker factors (8 hours/

reporting period) 

Distribution 

Middle 

managementManagement

Oversee part of the 

detection process and 

review results (2 

hours/reporting period) 

Oversee part of the 

measurement process and 

review results (1 hour/

reporting period) 

Distribution 

Reciprocating Compressor Equipment Leak 

Technician Check unit for equipment 

leaks (1 hour/

compressor) 

 Processing 

Technician Check unit for equipment 

leaks (1.5 hours/

compressor) 

Transmission, Storage, 

LNG Storage, LNG Import 

and Export Facilities 

Junior engineer Apply emission factors or 

leaker factors (time 

accounted for by facility 

equipment leaks 

quantification) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Reciprocating Compressor Rod Packing Emissions 

Maintenance teamTeam One time labor cost to 

install port for hotwire 

anemometer ($1,000 /1000 / 

compressor) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Technician Check packing open-ended 

lines for emissions (10 

minutes/ compressor) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Technician Measure rod packing 

emissions (10 minutes/

compressor) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Junior engineer Calculate rod packing 

emissions (30 minutes/

compressor) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Centrifugal Compressor Equipment Leaks 

Technician Check unit for equipment 

leaks (1 hour/

compressor) 

 Processing 

Technician Check unit for equipment 

leaks (2 hours/

compressor) 

 Storage, LNG Import and 

Export Facilities 

Formatted Table
4-30 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

Technician Check unit for equipment 

leaks (2.5 hours/

compressor) 

 LNG Storage 

Centrifugal Compressor Seals 

Maintenance team One- time labor cost to 

install port for hotwire 

anemometer ($5,000/ / 

compressor) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Technician Measure degassing vent 

emissions (10 minutes/

compressor) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Junior engineer Calculate degassing vent 

emissions (30 minutes/

compressor) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Unconventional Well Completion and Workover 

Junior engineer Measure flowback from 

completion or workover (8 

hours/ field) 

Onshore Production 

Conventional Well Completion and Workover 

Junior engineer Ask completion or 

workover contractor for 

time of venting (5 minutes/

per completion or 

workover) 

Onshore Production 

Well Liquid Unloading 

Junior engineer Measure flow from well 

blowdown (5 

minutes/unloaded well) 

Onshore Production 

Acid Gas Removal Vent Stacks 

Junior engineer Perform simulation runs 

(10 minutes/AGR 

vent)Vent)

Processing 

Kimray Pumps 

Junior engineer Accounted for in station 

equipment leaks– certain 

portion of time is assumed 

to be for engineering 

estimation of sources 

Onshore Production, 

Processing, Transmission, 

Storage 

Dehydrator Vent Stacks > 400 thousand cubic feet 

Senior operator Collect data collection (10 

minutes/dehydrator vent) 

Onshore Production, 

Processing 

Junior engineer Perform simulation runs 

(15 minutes/dehydrator 

vent) 

Onshore Production, 

Processing 

Formatted Table
4-31 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

Junior engineer Accounted for in station 

equipment leaks – certain 

portion of time is assumed 

to be for engineering 

estimation of sources 

Transmission, Storage 

Dehydrator Vent Stacks <400 thousand cubic feet 

Senior operator Count dehydrator (0.5 

minutes/dehydrator vent) 

Onshore Production, 

Processing 

Wellhead Equipment Leaks 

Junior engineer Apply emission factor – 

accounted for in station 

equipment leaks 

Onshore Production, 

Storage 

Storage Tanks > 10 barrels per day 

Senior operator Collect separator pressure 

(1 minute/ separator) 

Onshore Production,

Junior engineer Collect data and perform 

simulation runs (30 

minutes/ separator) 

Onshore Production, 

Storage Tanks < 10 barrels per day 

Senior operator Count separator (0.5 

minutes/ separator) 

Onshore Production 

Natural Gas Distribution Pipelines 

Junior engineer Estimate emissions using 

population emission factor 

– time accounted for in 

station equipment leaks 

Distribution 

Below Grade Metering & Regulating Stations 

Junior engineer Estimate emissions using 

population emission factor 

– time accounted for in 

station equipment leaks 

Distribution 

Well Testing 

Junior engineer Perform emissions 

calculation with GOR 

measurement (1 hour/ 

well) 

Onshore Production 

Associated Gas Venting and Flaring 

Junior engineer Perform emissionemissions

calculation with gas-to-oil 

ration (GOR) measurement 

(1 hour/ well) 

Onshore Production 

Natural Gas Pneumatic Bleed Devices 

Junior engineer Determine high bleed or 

low bleed from 

manufacturer and apply 

Onshore Production, 

Processing, LNG Storage, 

LNG Import and Export 

Formatted Table
4-32 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

appropriate population 

factor (10 

minutes/pneumatic device) 

Facilities, Distribution 

Junior engineer Check devices and take 

inventory of brand/models 

(8 minute/pneumatic device) 

Determine high bleed or 

low bleed from 

manufacturer and apply 

appropriate population 

factor (10 

minutes/pneumatic device) 

Transmission, Storage 

Flare Stacks 

Junior engineer Collect data for emission 

estimate (10 minutes/ 

station) 

Estimate emissions using 

emission factor (10 

minutes/ 

station) 

Processing 

Junior engineer Apply emission factor – 

accounted for in station 

equipment leaks 

Onshore production 

Blowdown Vent Stacks 

Junior engineer Perform emissions 

calculation (8 minutes/ 

station) 

Processing, Transmission, 

Storage, LNG Storage, 

LNG Import and Export 

Facilities 

Junior engineer Accounted for in station 

equipment leaks 

Distribution 

For

Table 4-13 does not include equipment monitoring on offshore petroleum and natural gas 

production facilities. Offshore production platforms that are proposed to use data already 

collected for MMS GOADS to estimate greenhouse gas emissions from their operations. 

Specifically, the MMS GOADS program requires the monitoring of GHG emissions from 

platforms in statethe Gulf of Mexico Federal waters. Facilities under this final rulemaking are 

required to report the same emissions data calculated by the GOADS Program. Hence these 

platforms have minimal additional reporting burden. The cost burden model assumes that this 

requires 30 minutes per platform. 

However, platforms that are in State waters or in federalFederal waters outside the Gulf 

of Mexico, GHG emissions will have to be estimated using the BOEMREMMS GOADS 

procedures. EPA estimates the reporting cost for non-GOADS platforms to be $5,000 for first 

year of reporting. 

Formatted Table
4-33 

Once the labor hours were calculated, by category, for each of the cost elements, they 

were multiplied by the associated labor rates to estimate labor costs per facility. The only 

remaining facility costs are due to the annualized capital costs and travel, lodging, and shipping 

to conduct the actual emissionemissions monitoring. 

4.5.3 Annualizing Capital CostsCost Annualization and Determining O&M Costs 

The capital costs related to monitoring emissions and archiving of information consists of 

purchasing equipment for emissionemissions detection, emissionemissions measurement, and 

information storage. All costs are reported in 2006 U.S. dollars, and annualization was assumed 

over an equipment life of five5 years with a 7-percent% interest rate. From these factors, a 

capital recovery factor of 24 percent% was calculated using the formula provided as 

followsbelow: 

(1 ) 1

(1 )

 

  n

n

r

r r CRF

where CRF is the capital recovery factor, r is the interest rate, and n is the life expectancy in 

years. Table 4-14 below summarizes the annualized capital costs associated with the monitoring 

program. Additionally, the table describes the annual costs of travel, lodging, and shipping—the 

only other non-labor costs related to the monitoring program. 

Table 4-14 Monitoring Program Compliance Capital Costs and Other O&M 

Element Capital Cost 

Annualized 

Capital Cost 

Archiving 

Capital costs Cost of archiving material per facility assumes cost of 1 file 

cabinet, 4-drawer vertical from Office DepotTM ($140), and 

1 hard drive for data storage from SeagateTM ($95) 

$57 

Monitoring 

Equipment purchase Screening equipment is represented by a nominal $100,000 

cost for an infrared camera. It is assumed to be purchased 

by the contractors who will pass on the costs to as many 

facilities as they can provide a service each year. 

$24,389 

Equipment purchase Screening equipment in the distribution segment is 

represented by a nominal $10,000 cost for a laser 

emissionemissions detector. It is assumed to be purchased 

by the local distribution companies over the infrared camera 

due to its low cost. 

$2,439 

Measurement 

Equipment purchase Hotwire anemometers are required for compressor vents. It 

is assumed that the hotwire anemometer, a vinyl carrying 

$206 

Formatted: Indent: Left: 0", First line: 

0"

Formatted Table
4-34 

Element Capital Cost 

Annualized 

Capital Cost 

case, an AC adapter, data acquisition software, and 

anemometer electronic data logger will be purchased. 

Traveling Cost of traveling for an engineer to a facility from the home 

facility (therefore n-1 facilities to visit). Assuming travel 

cost is $0.485/mile, $150/night for overnight stay, 

$100/shipment for shipping equipment, and $100 per diem. 

$0–$10,449a

4491

a

Annual1Annual travel costs are highly variable depending on the facility type, proximity, and ownership structure. Annual travel 

costs are estimated to vary from $0 to $10,449. 

As shown in Table 4-14, the equipment leaks and vented emissionemissions detection 

methods vary depending on the size of the company and its facilities. In the case of companies 

with small operations and few facilities, the costs passed on by contractors will be spread over 

many facilities. 

Each facility is assumed to purchase an adequate flow meter to measure the emission 

rates from compressor seal vents either at the pipe end, if accessible, or a flow measurement port 

installed at a suitable location capturing all vent emissions. 

With the equipment costs per company determined, the final step was to divide company 

capital and O&M costs amongst individual facilities owned by a typical company. 

Step 3, described previously, above provided the proportion of facilities that fall in the 

small, medium, and large categories. By determining the companies that fall in the three 

categories, the average number of “small, ,” “medium,,” and “large” facilities per company was 

determined. To convert the annualized capital costs and equipment purchases, the costs per 

equipment were attributed to the number of facilities that can be serviced (as determined the 

number of labor hours required to monitor a facility) each year, as shown in the equation as 

followsbelow: 





 



 













   Contractor

FacilitiesServiced

Contractor

ofEquipment

Equipment

AnnualCapital

Facility

$AnnualCapital $ #

The travel, lodging, and shipping costs associated with monitoring several facilities 

spread over large regions were calculated using the assumed costs in Table 4-14. Expert 

judgment based on the number of teams using equipment and the necessity of travel versus 

shipping between facilities was used to determine these costs. 

Formatted Table
4-35 

STEP 5: Estimate per Facility Costs for Each Threshold Level 

The total reporting costs across each segment were determined by assigning model 

facility costs (small, medium, and large) to individual facilities in the respective industry 

segments based on relative size and determining total costs from the entire segment. This was 

done for only those facilities that exceeded the reporting threshold. Average cost per facility was 

then determined by dividing the total segment costs by the number of facilities that exceeded the 

reporting threshold—small, medium, and large. In the case of onshore production, field-level 

monitoring costs were aggregated to the total national burden, then distributed to operators at the 

basin-level based on production rates. 

5-1 

SECTION 5

SUBPART W ANALYSIS OF REPORTING RULE OPTIONS 

For petroleum and natural gas systems, Subpart W, as shown in Table 5-1Table 5-1, the 

total cost of the reporting rule to the private sector is estimated to be $61.8 million in the first 

year and $19.0 million in subsequent years (2006$). These estimates include costs for reporters 

to monitor and report emissions and the costs for non-reporters to make a reporting 

determination. Of the costs to report emissions meeting or exceeding the threshold, equipment 

leaks and vented emissions are $40.1 million in the first year one and $15.1 million in 

subsequent years. The estimates are based on the selected option for the final rule, which 

includes an annual emissionemissions-based threshold of 25,000 MtCO2emetric tons CO2e for 

each facility and a hybrid of direct measurement and source-specific calculation methodologies. 

Section 3.2 provides more details about the selected option. 

EPA estimates that for Subpart W, the public- sector burden is about $1.1 million per 

year. Approximately $0.46 million per year is for verification activities, and about $0.66 million 

per year is for program implementation and developing and maintaining the data collection 

system. Program implementation activities include, but are not limited to, developing guidance 

and training materials to assist the regulated community, responding to inquires from affected 

facilities on monitoring and applicability requirements, and developing tools to assist in 

determining applicability. In addition to total national costs for petroleum and natural gas 

systems, EPAwe also reportsreport average cost- per- metric- ton to support additional analysis 

of the mandatory reporting programs. These costs are also shown on Table 5-1Table 5-1. 

The first- year costs are higher due to initial program start-up costs—, in particular; the 

investment to secure equipment and install flow measurement ports in vent lines to allow 

measurement. Initial- year costs are also higher because reporters are required to quantify 

various key sources (e.g., well liquids unloadings, well workovers, compressor wet seal 

degassing vents, etc) in the first year; these sources are only required to be estimated bi-annually 

to mitigate long- term burden. The average cost per metric ton for all reporters is about 

$0.13/metric ton in the first year, declining to an average of $0.05/metric ton in subsequent 

years. 
5-2 

Table 5-1 National Cost Estimates for Petroleum and Natural Gas Systems 

First Year Subsequent Years 

Subpart W – Petroleum 

and Natural Gas systems NAICS 

$Million Million 

MtCO2e $/Mt 

$Million Million 

2006 2006 MtCO2e $/Mt 

Process Emissions 211, 486 $40.1 253.9 $0.16 $15.11 253.9 $0.06 

Combustion Emissions $3.3 83.5 $0.04 $3.32 83.5 $0.04 

 Reporting Determination $18.4 n/a n/a $0.58 n/a n/a 

Private Sector, Total $61.8 337.4 $0.13a

131 $19.01 337.4 $0.05a051 

Public Sector, TotalTotal2

$1.1 337.4 $0.003 $1.1 337.4 $0.003 

TOTAL $62.9 337.4 $0.13b

133 $20.11 337.4 $0.05b053 

Note: 

a1 Excludes reporting determination for non-reporters; based on private sector cost to report process and combustion emissions 

($43 million in first year, $18 million in subsequent years). 

 

b2 Source: EPA 3 Excludes reporting determination for non-reporters; based on public sector cost plus private sector cost to report process and 

combustion emissions ($44 million in first year, $19 million in subsequent years). 

There is a notable reduction in reporting cost compared to the April, 2010 proposal. The 

cost reduction resulted from changes such as providing equipment thresholdsfloors on several 

emissionemissions sources (e.g., tanks and , dehydrators, and compressors); simplified 

requirements for sampling and gas composition analysis; use of alternative leak detection 

equipment in some cases; and use of equipment-based emission factors instead of componentbased emission factors. A slight decrease in the emissions expected to be reported also 

accounted for the lower cost estimate. The slight decrease in reported emissions resulted from 

data corrections in the transmission and LNG storage segments and use of different well property 

databases in onshore production. Table 5-2Table 5-2 summarizes these changes based on yearone 1 costs for equipment leaks and vented emissions, and Table 5-3Table 5-3 summarizes these 

changes based on subsequent- year costs for equipment leaks and vented emissions. 

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5-3 

Table 5-2 Equipment Leaks and Vented EmissionEmissions Costs, Petroleum and 

Natural Gas Systems, First- Year Estimates 

Source 

Covered Emissions Cost Cost 

(MtCO2e) Million (2006$) (2006$/metric ton) 

AprilApr.

2009 

Proposed 

Rule 

AprilApr.

2010 

Proposed 

Rule 

Final 

Rule 

AprilApr.

2009 

Proposed 

Rule 

AprilApr.

2010 

Proposed 

Rule 

Final 

Rule 

AprilApr.

2009 

Proposed 

Rule 

AprilApr.

2010 

Proposed 

Rule 

Final 

Rule 

Original Six 

Segmentsa

Segments1 85 94.3 78.7 $32.5 $26.7 $26.2 $0.38 $0.28 $0.33 

Onshore Production 

n/a 154.9 152.4 n/a $27.7 $11.9 n/a $0.18 $0.08 

Local Distribution 

n/a 22.7 22.7 n/a $1.6 $2.0 n/a $0.07 $0.09 

Total 85 272 254 $32.5 $56.0 $40.1 $0.38 $0.21 $0.16 

a1

 Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG storage; LNG 

import/export. 

Table 5-3 Equipment Leaks and Vented EmissionEmissions Costs, Petroleum and 

Natural Gas Systems, Subsequent- Year Estimates 

 

Source 

Covered Emissions Cost Cost

(MtCO2e) Million (2006$) ($/metric ton) 

AprilApr.

2009 

Proposed 

Rule 

AprilApr.

2010 

Proposed 

Rule 

Final 

Rule 

AprilApr.

2009 

Proposed 

Rule 

AprilApr.

2010 

Proposed 

Rule 

Final 

Rule 

AprilApr.

2009 

Proposed 

Rule 

AprilApr.

2010 

Proposed 

Rule 

Final 

Rule 

Original Six 

SegmentsaSegments1 85 94.3 78.7 $28.1 $11.8 $8.7 $0.33 $0.13 $0.11 

Onshore Production 

n/a 154.9 152.4 n/a $8.6 $5.1 n/a $0.06 $0.03 

Local Distribution 

n/a 22.7 22.7 n/a $1.0 $1.3 n/a $0.04 $0.06 

Total 85 272 254 $28.1 $21.4 $15.1 $0.33 $0.08 $0.06 

a1

 Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG storage; LNG 

import/export. 

In addition, EPA developed annualized estimates of the costs. For each segment, EPA 

calculated the present value of the labor and capital costs to monitor and report emissions over a 

20-year time period using two discount rates (3 and 7 percent). The present value included the 

costs for facilities that do not meet the emissions threshold to make a reporting determination. 

Formatted Table
5-4 

EPA then calculated an annual value of the present value at discount rates of 3 and 7 percent. 

Table 5-4 presents the annualized cost estimates for each segment as well as the first-year and 

subsequent-year estimates. 

Table 5-4 Annualized Cost Estimates for Petroleum and Natural Gas Systems (2006$)a

First Year Subsequent Year

Annualized 

Costb

($Million)

Annualized 

Costc

($Million) Segment

National 

Cost 

($Million)

Cost 

($/metric ton) 

National 

Cost 

($Million)

Cost 

($/metric ton) 

Processing 8.13 0.26 2.10 0.07 2.43 2.57

Transmission 16.87 0.40 6.49 0.15 7.02 7.26

Underground Storage 2.73 0.35 1.02 0.13 1.10 1.14

LNG Storage 0.70 0.41 0.26 0.15 0.28 0.29

LNG import/export 0.14 0.44 0.03 0.09 0.04 0.04

LDC 3.31 0.15 1.35 0.06 1.47 1.52

Onshore Production 26.58 0.12 7.54 0.03 8.61 9.05

Offshore Production 3.33 0.65 0.24 0.05 0.42 0.49

TOTAL (8 Segments) 61.78 0.18 19.01 0.06 21.36 22.34 a Includes determination costs for non-reporters. These estimates are conservative and should be viewed as an upperbound because the determination costs were applied at the facility-level rather than the company-level. For 

example, for offshore production, determination costs were applied to each of the approximately 3,000 platforms in 

the Gulf of Mexico rather than to the roughly 86 operators in that region. See the memo, “Estimates of 

Determination Costs,” in the docket for complete details and additional determination cost estimates (EPA-HQOAR-2009-0923).

b The cost to report annualized over 20 years at 3 percent. c The cost to report annualized over 20 years at 7 percent.

5.1 Evaluating Alternative Options for Implementation of the Rule 

The selected option was evaluated based on a cost-effectiveness analysis. For example, in 

selecting the emissionemissions threshold, EPAwe compared the incremental emissions reported 

with the incremental costs (associated with the change in the facilities that would be required to 

report their emissions). Similarly, in selecting the reporting methodology option, EPAwe

compared the change in uncertainty with the change in costs associated with different emission 
5-5 

measurement/estimation techniques. The metrics used and the results of the cost-effectiveness 

analysis are discussed in the following informationbelow. 

In addition, the final rule requires the determination of onshore reporting to be done with 

the assumptionassuming that reporting parties report emissions and, for onshore production, that 

they determine threshold on a basin level. In other words, owners or operators in the onshore 

production segment must report based on total emissions in all petroleum and natural gas 

production fields in a defined basin. EPA also examined an option to require onshore production 

companies to report on a field- level basis. This alternative would affect the total emissions 

reported as well as cost, and is evaluated in the following sectionsbelow. 

Six alternative options were therefore evaluated for this analysis. While the Agency

believes thatwe believe these alternatives represent the most likely variations in the selected 

option, EPA recognizeswe recognize that, in some cases, particular interests may wish to 

evaluate more nuanced alternative options. To maintain transparency in the analysis, data 

necessary to conduct further alternative option analyses can be found in Section 4 of this 

document. 

5.1.1 Analysis of Alternative Threshold Options 

The threshold determines the number of entities required to report GHG emissions under 

Subpart W of the rule. The higher the threshold, the more entities that are excluded. It is assumed 

that the per-unit/entity cost does not change at different thresholds so that changes in the national 

cost estimates are driven by the number of reporting entities. The per-unit/entity costs outlined in 

Section 4 for Subpart W facilities, along with the estimates of numbers of covered entities at 

various thresholds, form the basis for this analysis. Two metrics are used to evaluate the costeffectiveness of the emissionemissions threshold. The first is the average cost per metric ton of 

emissions reported. The second metric for evaluating the threshold option is the marginal cost of 

additional reported emissions ($/MtCO2emetric ton CO2e) relative to the option adopted in the 

final rule. To compute this metric, EPA computedwe compute the change in emissions reported 

by lowering or raising the threshold and divideddivide this by the change in total reporting costs. 

Table 5-5Table 5-4 provides the cost-effectiveness analysis for the various thresholds. 

Table 5-54 Summary of Threshold Cost-Effectiveness Analysis (First Year);): Selected 

Hybrid Option Isis 25,000 MtCO2emetric tons CO2e

1

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5-6 

Threshold (MtCO2e) 

Facilities 

Required to 

Report 

Total 

Costs 

(Million 

2006$) 

Downstream 

Emissions 

Reported 

(Million 

MtCO2e/ year) 

Percentage of 

Total 

Downstream 

Emissions 

Reported 

Average 

Reporting 

Costa

Cost

(2006$/Mt) 

Cost 

Differentiala

,bDifferentia

l

1

 

(2006$/Mt ) 

1,000 12,622 $136.35 391 99% $0.35 $1.73 

10,000 4,400 $61.57 362 91% $0.17 $0.73 

25,000 2,786 $43.39 337 85% $0.13 $0.00 

100,000 1,062 $25.06 273 69% $0.09 ($0.28) a

 Excludes determination costs for non-reporters. Inclusion of determination costs results in the following average reporting costs

($/Mt): 1,000 metric tons CO2e = $0.38; 10,000 metric tons CO2e = $0.22; 25,000 metric tons CO2e = $0.18; and 100,000 metric 

tons CO2e = $0.16. b

 Cost difference relative to 25,000- metric- ton threshold 

The analysis shows a cost reduction of $0.28 per metric ton by moving from the selected 

threshold of 25,000 MtCO2emetric tons CO2e to a higher threshold (100,000 metric tons); the 

total emissions covered decrease significantly—about 16 percent. Similarly, by moving the 

threshold from 25,000 to 10,000, the difference increases by $0.73 per metric ton, and the 

emissions captured by increase by 6 percent. Finally, lowering the threshold from 25,000 to 

1,000 yields the highest increase in cost difference ($1.73 per metric ton)), and increases the 

percentage of covered emissions by approximately 14 percent. Similar data areis presented for 

subsequent years in Table 5-6Table 5-5. 

Table 5-65 Summary of Threshold Cost-Effectiveness Analysis (Subsequent Years) 

Threshold (MtCO2e) 

Facilities 

Required to 

Report 

Total Costs 

(million 

2006$/$ / 

year) 

Downstream 

Emissions 

Reported 

(Million 

MtCO2e)

Percentage of 

Total 

Downstream 

Emissions 

Reported

Average 

Reporting 

Costa

Cost

(2006$/Mt)

Cost 

Differentiala

,bDifferentia

l

1

 

(2006$/Mt)

1,000 12,622 $71.60 391 99% $0.18 $0.99 

10,000 4,400 $29.48 362 91% $0.08 $0.44 

25,000 2,786 $18.43 337 85% $0.05 $0.00 

100,000 1,062 $9.61 273 69% $0.03 ($0.14) a Excludes determination costs for non-reporters. Inclusion of determination costs results in the following average reporting costs 

($/Mt): 1,000 metric tons CO2e = $0.19; 10,000 metric tons CO2e = $0.08; 25,000 metric tons CO2e = $0.06; and 100,000 metric 

tons CO2e = $0.04. b

 Cost difference relative to 25,000- metric- ton threshold 

Table 5-7Table 5-6 summarizes costs to report process and combustion emissions for all 

segments at four thresholds. 

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5-7 

Table 5-76 Subpart W Cost Estimates by Threshold 

Threshold 

First Year Subsequent Years 

Million 

2006$ $/Mt Million 2006$ $/Mt 

1,000 MtCO2e $136.35 $0.35 $71.60 $0.18 

10,000 MtCO2e $61.57 $0.17 $29.48 $0.08 

25,000 MtCO2e $43.39 $0.13 $18.43 $0.05 

100,000 MtCO2e $25.06 $0.09 $9.61 $0.04 

The selection decision weighed the marginal cost of capturing additional emissions with 

the percentage of emissions needed to accurately estimate national GHG emissions. This analysis

is shown in Figure 5-1, which illustrates the total average cost per metric ton and the marginal 

cost per metric ton for Subpart W as a function of the percentage of total emissions reported. 
5-8 

Figure 5-1 Average Cost and Cost Differential per Metric Ton of Emissions Reported by 

Threshold 

a. Average Cost

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

% of Total Emissions Reported

$/tonne

First Year Subsequent Years Average 1K Threshold

100K Threshold

10K Threshold

25K Threshold

b. Cost Differential 

($0.50)

$0.00

$0.50

$1.00

$1.50

$2.00

55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

% of Total Emissions Reported

$/tonne

First Year Subsequent Years Average 1K Threshold

100K Threshold

10K Threshold

25K Threshold

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5-9 

5.1.2 Analysis of Alternative Monitoring Method Options 

Each monitoring technique for which reporting costs were estimated for Subpart W in 

Section 4 was assumed in the burden analysis to provide the same estimate of total emissions by 

reporting facility. TheHowever, the methods proposed for monitoring emissions will differ, 

however, in their precision in estimating actual emissions. Therefore, the gain from increasing 

the cost of monitoring is to have more precise estimates of facility emissions. The methods 

considered for determining emissions ranged from applying average industry parameters 

(referred to as “population emission factors,” or “default parameters”) to material inputs or 

throughputs, to the use of direct measurement techniques. ThisIn this section evaluates, we 

evaluate the change in cost and the change in accuracy for two alternative monitoring options for 

Subpart W. Generally speaking, under one of the alternatives, population factors would be used 

in lieu of direct measurements and facility-level estimates, and in the other option, direct 

measurements are required for all sources. EPA usesWe use the terms “term direct 

measurement” and “population factors” as shorthand to describe alternative options. For Subpart 

W, population emission factors and component count areis the basis for “default factors.””.

Estimated costs for each monitoring method are shown in Table 5-8Table 5-7. 

For Subpart W, the direct measurement option greatly expands to use direct measurement 

of all vented and equipment leak sources. This is the methodology used in the April, 2009 

proposed rule. The costs associated with this case in the April, 2009 proposed rule (which did not 

include the onshore production and natural gas distribution) resulted in Subpart W incurring 19

percent% of the total costs in the GHG reporting ruleMRR to monitor and measure only 3

percent% of the emissions. 

These costs were re-estimated for the entire petroleum and natural gas segment in the 

final rule. These costs involve the use of direct measurement techniques, including metering of 

all vents, calibrated bagging, or use of high- volume samplers to measure equipment leaks and 

inaccessible leaks, and so on. These costs involve additional equipment as well as significantly 

higher labor costs. If the same direct measurement techniques were required in this rule, the costs 

would be particularly high for the new onshore production and natural gas distribution segments. 

The overall costs for the direct measurement option are about $100 million (annually) 

higher than the selected option. 
5-10 

Table 5-87 Analysis of Alternative Monitoring Methods 

Direct Measurement (DM) Selected Option (Hybrid Approach) Population Factors 

Segment First Year 

(million 2006$) 

Subsequent Years 

(million 2006$) 

First Year 

(million 2006$)

Subsequent Years

(million 2006$) 

First Year 

(million 2006$)

Subsequent Years 

(million 2006$) 

Subpart W—

Petroleum and 

Natural Gas 

Systems 

$294.6 $126.9 $43.39 $18.43 $27.6 $17.4 

For the “population factor” option, Subpart W sources were assumed to have emissions 

quantified entirely by the application of emissionemissions factors developed by the Gas 

Research Institute and EPA (GRI/EPA (1996) as the basis for estimates of CH4 and noncombustion-related CO2 emissions. These factors are used with a population count of equipment 

and components to arrive at a “population factor” cost estimate. The reduction in cost from the 

selected hybrid approachHybrid Approach for this option is significant, with first- year costs 

declining by $15.8 million, and subsequent- year costs declining by $1.0 million. 

5.1.2.1 Monitoring Method Uncertainty 

The use of direct measurement methods would provide the most certain quantification of 

Subpart W emissions, assuming that measurements were taken using consistent monitoring 

protocols across reporters. If emission sources are measured as estimated in the burden analysis, 

there should be a high certainty level in the emissions quantified. BasedHowever, based on the 

analysis, however above, the costs to gather and quantify these emissions would be very high. 

The use of population- based factors would result in a significantly lower burden, 

although the certainty level of the emissionemissions determination would be very poor. 

Population-based factors determine the potential for emissions, assuming a percentage of known 

components thatwhich may leak based on previous (and dated) studies. 

The final- rule- required option of using leak detection as well asand a hybrid of spot 

direct measurement, engineering estimates, leaker emission factors, and population- based 

factors (for inaccessible sources) provides an emissionemissions estimate with significantly more 

certainty than population based factors at a more reasonable burden. 

5.1.3 Sensitivity of Subsequent- Year Cost Estimates 

National cost estimates for the final rule were developed based on the current population 

of entities in the petroleum and natural gas segment. The forward analysis (“subsequent years”) 

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assumes that the number of entities would remain relatively constant. Thus, the analysis assumes 

a stable population where all entities subject to Subpart W bear a single first-year cost and then 

repeated subsequent-year costs. 

InHowever, in reality, however, over time some existing facilities close or go out of 

business and new facilities come into existence, which. This is sometimes referred to as entry 

and exit in an industry. This phenomenon may affect the cost of the rule because as entities “turn 

over,”” the new entrants presumably will bear first-year costs that are slightly higher than 

subsequent- year costs. 

The largest contribution to non-recurring first-year costs for Subpart W compliance is for 

flow measurement port installation in compressor seal vent lines. When a company goes out of 

business and sells its assets to either a new or existing business, these ports will already be 

installed; so much of the first-year compliance costs will not apply to a company acquiring an 

already-reporting facility. The remainder of first-year costs that do not repeat areis due to labor 

associated with reviewing the regulation and planning accordingly for compliance. These costs 

will not be necessary when an existing company, which already reports, acquires a reporting 

facility from a failing business. Only in the case of a new business entity acquiring an existing 

or new reporting station will these reviewing and planning first-year labor costs be necessary. 

The reviewing and planning costs are minimal in comparison to the significant other firstyear costs of reporting for Subpart W;, therefore, the impact of business transitions on rule 

reporting costs for Subpart W are assumed minimal.

5.1.4 Summary of Alternative Options for Onshore Facility Definition 

The final rule specifies that onshore petroleum and natural gas producers will report for 

each hydrocarbon basin. A basin is as identified by the American Association of Petroleum 

Geologists’Geologists three-digit Geologic Province Code. The reporters will be owners or 

operators in a basin; however. However, EPA also considered an alternate option to define a 

facility at a field- level. One such definition is available from the Energy Information 

Administration Petroleum and Gas Field Code Master. The field-level option would require 

aggregation of emissions by owners or operators at a field-level to apply the threshold. Table 

5-9Table 5-8 and Table 5-10Table 5-9 below show a detailed emissionemissions coverage and 

burden to reporter that would have been expected under a field-level facility definition. 

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Table 5-98 EmissionEmissions Coverage and Entities Reporting for Field- Level Facility 

Definition (Onshore Production) 

Threshol

d Level Emissions Covered Facilities Covered 

Million 

MtCO2e/

Metric 

tons 

CO2e/ye

ar 

Percent Numbe

r 

Perce

nt 

1,000 219.1 83% 22,459 33%

10,000 171.9 65% 2,549 4% 

25,000 150.3 57% 1,157 2% 

100,000 110.4 42% 306 0.4% 

Table 5-109 Equipment Leaks, Vented, and Combustion EmissionEmissions Cost for FieldLevel Facility Definition (Onshore Production) 

Threshold 

Level 

Equipment Leak and Vented Emission Costs (2006$) Combustion Emission Costs (2006$) 

First-Year 1 Costs Subsequent- Year Costs First-Year 1 Costs Subsequent- Year 

Costs 

Annualized 

Capital Cost 

O&M 

Cost 

Annualized 

Capital Cost O&M Cost Annualized 

Capital Cost 

O&M 

Cost 

Annualized 

Capital Cost 

O&M 

Cost 

1,000 $57.3 $7,274 $57.3 $3,069 $500 $1,700 $500 $1,700 

10,000 $57.3 $8,855 $57.3 $3,834 $500 $1,700 $500 $1,700 

25,000 $57.3 $10,334 $57.3 $4,549 $500 $1,700 $500 $1,700 

100,000 $57.3 $14,963 $57.3 $6,622 $500 $1,700 $500 $1,700 

Figure 5-2

Figure 5-2 presents a comparison of average costs (years 1, 2, and 3) and emissionemissions

coverage at different thresholds for the field- and basin-level options. Specifically, it shows that 

the field-level option would result in a significantly lower coverage in emissions reported—57 

percent at field-level versus 85 percent at the basin-level for a 25,000-MtCO2e metric tons CO2e

threshold. In addition, the cost to report under the field-level definition is higher than under the 

basin-level definition at all thresholds, except at 100,000-MtCO2e metric tons CO2e threshold, at 

which field-level is lower. Emission However, emissions coverage at the 100,000-MtCO2e CO2e

threshold under a field-level definition is very low, however—42 percent. Finally, the number of 

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5-13 

entities reporting at a 25,000-MtCO2e metric tons CO2e threshold for basin- level definition is 

lower, at 981 in comparison to the 1,157 entities reporting for a field-level definition. 

Figure 5-2 Summary of Basin vs. Field Decision 

 

0.13

0.76

0.04

0.07

0.24

0.07

0.05 0.03

-

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

30% 40% 50% 60% 70% 80% 90% 100% 110%

Percent of Total Onshore Emissions Reported

2006$/metric tons

Field Level Basin Level

5.2 Assessing Economic Impacts on Small Entities 

The first step in this assessment was to determine whether the rule wouldwill have a 

significant impact on a substantial number of small entities (SISNOSE) under Subpart W. To 

make this determination, EPA used a screening analysis that allows itus to indicate whether the 

AgencyEPA can certify the rule as not having a SISNOSE. The elements of this analysis 

included:

– Identifyingidentifying affected entities under Subpart W.,

– Selectingselecting and describing the measures and economic impact thresholds 

used in the analysis., and

– Determining adetermining SISNOSE certification category. 

5.2.1 IdentifyingIdentify Affected Segments and Entities 

The affected entities covered by the rule were identified during the development of the 

cost analysis for the reporting rule. The Statistics of U.S. Businesses (SUSB) data 

provideprovides national information on the distribution of economic variables by the size of 

entity. These data were developed in cooperation with, and partially funded by, the Office of 

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Advocacy of the Small Business Administration (SBA) (SBA, 2008a). The data include the 

number of establishments (Table 5-11Table 5-10), employment (Table 5-12Table 5-11), and 

receipts (Table 5-13Table 5-12) and present information on all entities in an industry covered by 

Subpart W of the rule; however, many of these entities would not be expected to report under the 

selected option because they would fall below the 25,000 hybrid threshold. SUSB also provides 

this data by enterprise employment size. The census definitions in this data set are as follows: 

– Establishment: An establishment is a single physical location where business is 

conducted or where services or industrial operations are performed. 

– Employment: Paid employment consists of full- and part-time employees, 

including salaried officers and executives of corporations, who were on the 

payroll in the pay period including March 12, 2002. Included are employees on 

sick leave, holidays, and vacations; not included are proprietors and partners of 

unincorporated businesses. 

– Receipts: Receipts (net of taxes) are defined as the revenue for goods produced or,

distributed, or services provided, including revenue earned from premiums, 

commissions and fees, rents, interest, dividends, and royalties. Receipts exclude 

all revenue collected for local, state, and federal taxes. 

– Enterprise: An enterprise is a business organization consisting of one or more 

domestic establishments that were specified under common ownership or control. 

The enterprise and the establishment are the same for single-establishment firms. 

Each multi-establishment company forms one enterprise—the enterprise 

employment and annual payroll are summed from the associated establishments. 

Enterprise size designations are determined by the summed employment of all 

associated establishments. 

Because the SBA’s business size definitions (SBA, 2008c) apply to an establishment’s “ultimate 

parent company,” EPA assumeswe assume in this analysis that the “enterprise” definition above 

is consistent with the concept of ultimate parent company that is typically used for Small 

Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses, and the terms are 

used interchangeably. EPAWe also reportsreport the SBA size standard(s) for each industry 

group in order to facilitate comparisons and different thresholds. 
5-15 

Table 5-1110 Number of Establishments by Affected Industry and Enterprisea Size: 2002 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total 

Establishments

Owned by Enterprises with:

Industry NAICS NAICS Description 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

< 500

to 749 

Employees

< 500 to 

749 

Employees

750 to 999 

Employees 

1,000 t

1,499 

Employ

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and Natural 

Gas Extraction 

500 7,629 5836 456 292 606,584 6,58460 64 3

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline Transportation of 

Natural Gas 

b 1,936 81 27 61 16936 36169 2 2

Natural gas distribution 221210 Natural Gas Distribution 500 2,897 483 86 131 70068 68700 33 7

aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. 

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments. BecauseSince the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumeswe assume in this analysis that the 

enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. 
5-16 

Table 5-1211 Number of Employees by Affected Industry and Enterprisea Size: 2002 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total 

Employees

Owned by Enterprises with:

Industry NAICS NAICS Description 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

< 500

to 749 

Employees

< 500 to 749 

Employees 

750 to 999 

Employees 

1,000 

1,499 

Employ

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and 

Natural Gas Extraction 

500 88,280 19,336 12,113 11,656 43,1052,421 2,42143,105 3,551 1,0

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline Transportation of 

Natural Gas 

b 37,450 347 157 1,053 1,834c c1,934 c 

Natural gas distribution 221210 Natural Gas Distribution 500 86,890 1,956 1,899 4,398 8,4201,960 1,9608,420 2,631 5,0

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. 

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumeswe assume in this analysis that the 

enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. cThe U.S. Census Bureau has missing data for this employee range. 
5-17 

Table 5-1312 Receipts by Affected Industry and Enterprisea Size: 2002 

SBA Size 

Standard 

(effective 

March 

11, 2008)

Total 

Receipts 

($Million)

Owned by Enterprises with:

Industry NAICS NAICS Description 

1 to 20 

Employees 

($ 

thousands) 

20 to 99 

Employees 

($ 

thousands 

100 to 499 

Employees 

($ 

thousands) 

< 500

to 749 

Employees 

($ 

thousands) 

< 500 to 749 

Employees 

($ 

thousands) 

750 to 999 

Employees 

($ 

thousands) 

1,000 to 

1,499 

Employee

($ 

thousand

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and 

Natural Gas Extraction 

500 $160,879 $7,573 $6,790 $9,609 $23,9724,60

9

$4,60923,97

2

$3,991 $2,805 

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline Transportation 

of Natural Gas 

b $35,897 $1,035 $106c $394c $2,566c c$2,566 c 

Natural gas distribution 221210 Natural Gas Distribution 500 $67,275 $2,524 $4,642 $2,878 $13,127865 $86513,127 $2,116 $3,757 a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. 

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumeswe assume in this analysis that the 

enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. c The U.S. Census Bureau has missing data for this employee range. The receipts for the 1one to 20 range therefore underestimate true value. 
5-18 

5.2.2 DevelopingDevelop Small- Entity Economic Impact Measures 

Because Subpart W covers businesses, the analysis generated a set of sales tests 

(represented as cost-to-receipt ratios)23 for NAICS codes associated with the affected Subpart W 

segments. Although the appropriate SBA size definition should be applied at the parent company 

(enterprise) level, data limitations allowed EPAus only to compute and compare ratios for a model 

establishment for eight enterprise size ranges (i.e., all categories, enterprises with 1 to 20 

employees, 20 to 99 employees, 100 to 499 employees, 500 to 749 employees, less than 500 

employees, 750 to 999 employees, and 1,000 to 1,499 employees). This approach allows EPAus

to account for differences in establishment receipts between large and small enterprises and 

differences in small business definitions across affected Subpart W industries. It is also a 

conservative approach because it does not screen out entities that would be below the reporting 

threshold. It is also conservative, because an establishment’s parent company (the “enterprise”) 

may have other economic resources that could be used to cover the costs of the reporting 

program. It must be noted that the 1,000 to 1,499 employee category does not belong to the small 

business category; however. However, the category has been included to provide a comparison 

with small business cost-to-receipt ratios. 

These sales tests examine the average establishment’s total annualized mandatory 

reporting costs to the average establishment receipts for enterprises within several employment 

categories24 (first- year costs: Table 5-14Table 5-13; subsequent- year costs: Table 5-15Table 

5-14). The average entity costs used to compute the sales test are the same across all of these 

enterprise size categories. As a result, the sales -test will overstate the cost-to-receipt ratio for 

establishments owned by small businesses, because the reporting costs are likely lower than 

average entity estimates provided by the engineering cost analysis. 

 

23MetricsThe following metrics for other small- entity economic impact measures (if applicable) would potentially include:

 Small governments (if applicable): “Revenue” test; annualized compliance cost as a percentage of annual government 

revenues. 

 Small non-profits (if applicable): “Expenditure” test; annualized compliance cost as a percentage of annual operating 

expenses. 24The ratios forFor the 1one to 20 employee category are conservative because they include SUB, we exclude SUSB data for 

enterprises with zero employees; these. These enterprises did not operate the entire year. Exclusion of enterprises with zero 

employees would result in slightly lower cost-to-sales ratios (e.g., 1.22% for NAICS 211). 
5-19

Table 5-1413 Establishment Sales Tests by Industry and Enterprisea Size: First- Year Costs 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($1,000/ 

entity) 

All 

Enterprises 

Owned by Enterprises with:

Industry NAICS NAICS Description 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

< 500

to 749 

Employees

< 500 to 749 

Employees

750 to 999 

Employees 

1,000 to 

Emplo

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and 

Natural Gas Extraction 

500 $17.1 0.08% 1.32% 0.11% 0.05% 0.47%02% 0.02%47% 0.03% 0.02

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline 

Transportation of Natural Gas 

b $15.7 0.08% 0.12% 0.40%c 0.24%c 0.10% c c0.10% c c 

Natural gas distribution 221210 Natural Gas 

Distribution 

500 $13.9 0.06% 0.27% 0.03% 0.06% 0.07%11% 0.11%07% 0.02% 0.03

aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the 

establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated 

establishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA’s business size definitions (www.sba.gov/size) apply to an 

establishment’s ultimate parent company, EPA assumes in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate true value. 
5-20

Table 5-1514 Establishment Sales Tests by Industry and Enterprisea Size: Subsequent- Year Costs a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumeswe assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate the true value, which results in conservative estimates of cost-to-sales ratios. 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($/entity)

All 

Enterprises 

Owned by Enterprises with:

Industry NAICS NAICS Description 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

< 500

to 749 

Employees

< 500 to 749 

Employees 750 to 999 

Employees 

1,000 to 

1,499 

Employee

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and 

Natural Gas Extraction 

500 $7.5 0.04% 0.58% 0.05% 0.02% 0.21%01% 0.01%21% 0.01% 0.01% 

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline 

Transportation of Natural Gas 

b $6.9 0.04% 0.05% 0.18%c 0.11%c 0.05% c c0.05% c c 

Natural gas distribution 221210 Natural Gas 

Distribution 

500 $9.2 0.04% 0.18% 0.02% 0.04% 0.05%07% 0.07%05% 0.01% 0.02% 
5-21 

5.2.3 Results of Screening Analysis 

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will 

not have a significant economic impact on a substantial number of small entities. Small entities 

include small businesses, small governmental jurisdictions, and small not-for-profit enterprises. 

For the purposes of assessing the impacts of Subpart W of the rule on small entities, 

EPAwe defined a small entity as (1) a small business, as defined by SBA’s regulations at 13 CFR 

Part 121.201, ; (2) a small governmental jurisdiction that is a government of a city, county, town, 

school district, or special district with a population of less than 50,000,; or (3) a small 

organization that is any not-for-profit enterprise, that is independently owned and operated, and

is not dominant in its field. 

EPA believes the selected thresholds maximize the rule coverage with 85 percent% of all 

U.S. petroleum and natural gas systems emissions reported by approximately 2,786 reporters, 

while keeping reporting burden to a minimum and excluding small emitters. Furthermore, many 

Subpart W industry stakeholders with whom EPA met expressed support for a 25,000-MtCO2e

metric ton of CO2e threshold because it sufficiently captures the majority of GHG emissions in 

the United States while excluding smaller facilities and sources. After considering the economic 

impact of the final rule on small entities, EPA has concluded that this action will not have a 

significant economic impact on a substantial number of small entities. As shown in Table 

5-14Table 5-13 and Table 5-15Table 5-14, the average ratio of annualized reporting program 

costs to receipts of establishments owned by model small enterprises was less than 1 percent%

for industries presumed likely to have small businesses covered by the reporting program. 

The only exception to this is the ratio for 1 to -20 employee range for crude petroleum 

and natural gas extraction, which is greater than 1 percent but less than 2 percent. As previously 

noted, While a majority of the small business analysis does not screen out entities that would be 

below enterprises in the reporting threshold. Based on further analysis of petroleum and natural 

gas industry fall in the 1-20 employee range, most of the production data in HPDI, EPA 

estimates that in, and therefore emissions, comes from large corporations. In fact, the top 20 

large corporations in the U.S. account for 85 percent of the total oil and 77 percent of the total 

gas produced in the country. In most cases, the small enterprises have very small operations 

(such as a singlesingly family owning a few production wells) that are highly unlikely to cross 

the 25,000-MtCO2e metric tons CO2e reporting threshold. 
5-22 

In other cases, a small enterprise (less than 20 employees) may own large operations but 

conduct nearly all of its operations through service providers, so that it has few employees of its 

own.contractors. Such enterprises, however, tend to have higher annual revenues than those with 

small operations and therefore have lower cost-to-sales ratios. The review of production data by 

operator. In addition, these enterprises constitute a small fraction of the over 19,000 enterprises

in HPDI shows a ratio of the less than one percent for the operators expected to meet the 

reporting threshold20 employee category subject to the final rule. 

5.3 Synopsis of Benefits 

Under the Mandatorymandatory GHG Reporting Rule,reporting rule EPA requires the

collectionto collect and verification of emissionverify emissions data from Subpart W facilities. 

This section reviews the benefits of a mandatory reporting program for Subpart W facilities 

based on previous experience with emissionemissions inventory programs in the United States 

and abroad. 

Recent policy discussions have highlighted potential benefits to society of the mandatory 

GHG reporting program (Pew, 2008). Benefits to the public include: building public confidence 

through clear and transparent emission measures and reports and makingthe ability of the public 

to make petroleum and natural gas facilities accountable for their equipment leaks and vented 

emissions. A GHG reporting system will also have the benefit of providing policymakerspolicy 

makers and analysts with a data set that is comprehensive for the petroleum and natural gas 

industry if reporting is conducted under Subpart W and other applicable subparts. Benefits to the 

industry include: identifying the identification of cost-effective GHG reduction opportunities and 

disclosing information, whichdisclosure that provides firms with incentives to reduce emissions 

voluntarily, and provides emissionemissions data to service industries, such as insurance and 

financial markets. Availability of emissionemissions information to the public, consumers, 

investors, corporations, and government regulators provides a sound basis for future policy 

analysis, which. This benefits society as a whole. Accurate and transparent information is 

necessary for the implementation of efficient approaches that meet environmental goals with the 

lowest cost to the economy. 

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SECTION 6

STATUTORY AND EXECUTIVE ORDER REVIEWS 

This section describes EPA’s compliance with applicable executive orders and statutes 

during the development of Subpart W of the Mandatorymandatory GHG Reporting 

Rulereporting rule. 

6.1 Executive Order 12866: Regulatory Planning and Review 

Under Executive Order (EO) 12866 (, (58 Federal Register (FR) 51735, October 4, 

1993), this ) the Agency must

determine whether the regulatory action is “significant” and therefore subject to Office of

Management and Budget (OMB) review and the requirements of the EO. The Order defines

“significant regulatory action” as one that is likely to result in a "rule that may:

1. Have an annual effect on the economy of $100 million or more or adversely affect in a 

material way the economy, a sector of the economy, productivity, competition, jobs, the 

environment, public health or safety, or State, local, or Tribal governments or 

communities;

2. Create a serious inconsistency or otherwise interfere with an action taken or planned by 

another agency;

3. Materially alter the budgetary impact of entitlement, grants, user fees, or loan programs 

or the rights and obligations of recipients thereof; or

4. Raise novel legal or policy issues arising out of legal mandates, the President’s priorities, 

or the principles set forth in the EO.

Pursuant to the terms of Executive Order 12866, it has been 

determined that this final rule is a “significant regulatory action” because it 

raises novel legal or policy issues arising out of legal mandates, the President’s priorities, or the 

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principles set forth in the EO.. Accordingly, EPA submitted this action to the Office of 

Management and Budget (OMB) for review under EOExecutive Order 12866.

However, this action is not an “economically significant regulatory action” under EO 

12866 because it is unlikely to have an annual economic effect of $100 million or more. 

Nonetheless, EPA has prepared this analysis of the potential costs and benefits associated with 

this action. 

In the economic analysis, EPA has identified the regulatory options considered, their 

costs, and the emissions that would likely be reported under each option, and explained the 

selection of the option chosen for the rule. The cost analysis, presented in Section 4, estimates 

that under the regulatory option, the total annualized cost of Subpart W for the private sector will 

be approximately 62 million during the first year of the program and 19 million in subsequent 

years. The analysis also estimates about $1.1 million of annual programmatic costs for EPA.. In 

addition, EPA has conducted a qualitative assessment of the benefits of the rule, which are 

reported in Section 5. Overall, EPA has concluded that the costs of the proposed mandatory 

GHG reporting rule for Subpart W are outweighed by the potential benefits of more 

comprehensive information about GHG emissions.

6.2 Paperwork Reduction Act 

The information collection requirements in this final rule have been submitted for 

approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 

44 U.S.C. 3501 et seq. The Information Collection Request (ICR) document prepared by EPA 

has been assigned EPA ICR number 2376.02. The information collection 

requirements are not enforceable until OMB approves them.

EPA plans to collect complete and accurate economy-wide data on facility-level 

GHG emissions from the petroleum and natural gas industry. . Accurate and timely information 

on GHG emissions is essential for informing future climate change policy decisions. Through 

data collected under this rule, EPA will gain a better understanding of the relative emissions of 

different segments of the petroleum and natural gas industrysystems, and the distribution of 

emissions from individual facilities within those industries. systems. The facility-specific data 

will also improve our understanding of the factors that influence GHG emission rates and the 

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actions that facilities are already taking to reduce emissions. Additionally, EPA will be able to 

track the trend of emissions from facilities within the petroleum and natural gas 

industrysystems over time, particularly in response to policies and potential regulations. The 

data collected by this rule will improve EPA’s ability to formulate climate change policy options 

and to assess which segments of the petroleum and gas industrysystems would be affected, 

and how these segmentssystems would be affected by the options. 

This information collection is mandatory and will be carried out under CAA 

sectionSections 114. and 208. Information identified and marked as Confidential 

Business Information (CBI) will not be disclosed except in accordance with 

procedures set forth in 40 CFR partPart 2. However, emissions datainformation collected 

under CAA sectionSections 114 cannot and 208 generally cannot be claimed as CBI 

and will be made public.

25.

The projected cost and hour respondent burden for non-Federal respondentsin the 

ICR is $27.7 million and 396,474 hours per year. The estimated average burden per response is 

90.71 hours; the frequency of response is annual for all respondents that must comply with the 

final rule’s reporting requirements; and the estimated average number of likely respondents per 

year is 2,786. The cost burden to respondents resulting from the collection of information 

includes the total capital and start-up cost annualized over the equipment’s expected 

useful life (averaging $0.74 million), per year) a total operation and maintenance 

component (averaging $1.7 million per year), and a labor cost component (averaging $25.3 

million per year)

26. 

 

25Although CBI determinations are usually made on a case-by-case basis, EPA has issued guidance in an earlier 

Federal Register notice on what constitutes emissions data that cannot be considered CBI (956 FR 7042 – 7043, 

February 21, 1991). As discussed in Section II.R of the 40 CFR Part 98 final rule preamble, EPA is initiating a 

separate notice and comment process to make CBI determinations for the data collected under this rulemaking. 

EPA intends to issue this notice in early 2010, and will include in the notice the data proposed for collection in this

rulemaking 26 Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown elsewhere in the Economic 

Analysis because the ICR costs represent the average cost over the first three years of the proposed rule, but costs 

are reported elsewhere in the Economic Analysis for the first year of the proposed rule and for subsequent years of 

the proposed rule. In addition, the ICR focuses on respondent burden, while the Economic Analysis includes EPA 

Agency costs.

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6-4 

). Burden is defined at 5 CFR Part 1320.3(b). These cost numbers differ from those 

shown elsewhere in the EIA for these subpartsEconomic Impact Analysis because the 

information collection request (ICR) costs represent the average cost over the first three years of 

the rule, but costs are reported elsewhere in the EIA for the subpartsEconomic Impact 

Analysis for the first year of the rule and for subsequent years of the rule. In addition, the

Also, the total cost estimate of the rule in the Economic Impact 

Analysis includes the cost to the Agency to administer the 

program. The ICR focuses ondifferentiates between respondent burden, while the 

EIA includes both national compliance costs and the burden for EPA to implement the rulecost 

to the Agency. 

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR partPart 9. When this 

ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR partPart

9 in the Federal Register to display the OMB control number for the approved information 

collection requirements contained in thisthe final rule. 

6.3 Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) generally requires an agency to 

prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the agency 

certifies that the rule will not have a significant economic impact on a substantial number of 

small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts of this final rule on small entities, small entity is 

defined as: (1) Aa small business as defined by the Small Business Administration’s regulations 

at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, 

town, school district or special district with a population of less than 50,000; and (3) a small 

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organization that is any not-for-profit enterprise thatwhich is independently owned and 

operated and is not dominant in its field. 

First, EPA examined the effect of Subpart W on small businesses using data collected by 

SUSB and SBA on the number of establishments, enterprises, employees, and receipts of 

businesses to allocate first-year and subsequent year costs to small businesses and assess the 

impact. Data limitations allowed EPA to only to compute and compare ratios for a model 

establishment for six enterprise size ranges (i.e., all categories, enterprises with 1 to 20 

employees, 20 to 99 employees, 100 to 499 employees, 500 to 749 employees, less than 500 

employees, 750 to 999 employees, and 1,000 to 1,499 employees). This approach is conservative

because an establishment’s parent company (the “enterprise”) may have other economic 

resources that could be used to cover the costs of the reporting program. Section 5.2 provides 

further description of these methods.

These sales tests examine the average establishment’s total annualized mandatory 

reporting costs to the average establishment receipts for enterprises within several employment 

categories. The average entity costs used to compute the sales test are the same across all of 

these enterprise size categories. As a result, the sales-test will overstate the cost-to-receipt ratio 

for establishments owned by small businesses, because the reporting costs are likely lower than 

average entity estimates provided by the engineering cost analysis.

EPA believes the selected thresholds maximize the rule 

coverage with over 85 percent of all U.S. petroleum and natural 

gas systems emissions reported by approximately 2,786 reporters, 

while keeping reporting burden to a minimum and excluding small 

emitters. Furthermore, many Subpart W industry stakeholders with 

whom EPA met expressed support for a 25,000 metric ton of CO2e 

threshold because it sufficiently captures the majority of GHG 

emissions in the United States while excluding smaller 

facilities and sources. After considering the economic impactsimpact of this final 

actionthe rule on small entities, I certifyEPA has concluded that this action will not 

have a significant economic impact on a substantial number of small entities.

 

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The small entities directly regulated by this final rule include small businesses in the 

petroleum and gas industry, small governmental jurisdictions and small non-profits. EPA has 

determined that some small businesses will be affected because their production processes emit 

GHGs exceeding the reporting threshold.

For affected small entities, EPA conducted a screening assessment comparing 

compliance costs for affected industry segments to petroleum and gas-specific data on revenues 

for small businesses. This ratio constitutes a “sales” test that computes the annualized 

compliance costs of this final rule as a percentage of sales and determines whether the ratio 

exceeds some level (e.g., 1 percent or 3 percent). The cost-to-sales ratios were constructed at the 

establishment level (average compliance cost for the establishment/ average establishment 

revenues). 

As shown in Table 5-14, the The average ratio of annualized reporting program costs to 

receipts of establishments owned by model small enterprises was less than 1 percent for 

industries presumedthe segments that may be likely to have small businesses covered 

by the reporting program. It is important to note that this analysis does not screen out entities 

that would be below the reporting threshold. Although the costs to receipts for entities in 

onshore production with 1-20 employees is slightly over 1 percent, most of these facilities would 

likely not exceed the 25,000 mtCO2e threshold, a threshold supported by many stakeholders as 

one that sufficiently captures the majority of GHG emissions while excluding small facilities. 

Subpart W in the reporting program. 

EPA also concluded that the final rulemaking would not affect a small organization that 

is any not-for-profit enterprise that is independently owned and operated and is not dominant in 

its field. Specifically, the data listing entities in each segment of the petroleum and natural gas 

industry did not include any non-profit entities.

In additionSecond, EPA determined that the final rulemaking would not have a 

significant impact on small governmental jurisdictions. EPA determined that one segment of the 

petroleum and natural gas industry might include small governments affected by the final 

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rulemaking. A comparison of the compliance costs to the revenue of potentially affected small 

governmental jurisdictions revealed that the costs of the rule are less than 1 percent% of 

revenues. 

Third, EPA concluded that the final rulemaking would not affect a small organization that 

is any not-for-profit enterprise which is independently owned and operated and is not dominant 

in its field. Specifically, the data listing entities in each segment of the petroleum and natural gas 

industry did not include any non-profit entities. 

Although this final rule will not have a significant economic impact on a substantial 

number of small entities, EPA nonetheless took several steps to reduce the impact of this final 

rule on small entities. For example, EPA determined appropriate thresholds that reduce the 

number of small businesses reporting. In addition, EPA allowsis proposing different 

monitoring methods for different emissions sources, requiring direct measurement only for 

selected sources. Also, EPA intends to provide a screening tool that will help small businesses 

make a reporting determination (see Section II.F.6 of the preamble). Finally, EPA is 

establishingis proposing annual instead of more frequent reporting. 

Through comprehensive outreach activities prior to proposal of the initial ruleoriginal 

MRR, EPA held approximately 100 meetings and/or conference calls with representatives of the 

primary audience groups, including numerous trade associations and industries in the petroleum 

and gas industry that include small business members. EPA’s outreach activities prior to 

proposal of the initial rule are documented in the memorandum, “Summary of EPA Outreach 

Activities for Developing the Greenhouse Gas Reporting Rule,,” located in Docket No. EPAHQ-OAR-2008-0508-053.055. After the initialoriginal proposal, EPA posted a guide for 

small businesses on the EPA GHG reporting rule websiteWeb site, along with a general fact 

sheet for the rule, information sheets for every source category, and an FAQ document. EPA 

also operated a hotline to answer questions about the finalApril, 2010 proposed rule. 

EPAWe continued to meet with stakeholders and entered documentation of all meetings into the 

docket. 

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During rule implementation, EPA wouldwill maintain an “open door” policy for 

stakeholders to ask questions about the final rule or provide suggestions to EPA about the types 

of compliance assistance that would be useful to small businesses. EPA intends to develop a 

range of compliance assistance tools and materials and conduct extensive outreach for the final 

rule. 

 

EPA has We have therefore concluded that this final action will not have a significant 

economic impact on a substantial number of small entities. We continue to be 

interested in the potential impacts of the final rule on small 

entities and welcome comments on issues related to such impacts.

6.4 Unfunded Mandates Reform Act 

ThisThe UMRA seeks to protect State, local, and Tribal governments from the imposition 

of unfunded Federal mandates. In addition, the Act seeks to strengthen the partnership between 

the Federal government and State, local, and Tribal governments and ensure that the Federal 

government covers the costs incurred during compliance with Federal mandates.

Title II of the UMRA of 1995, Public Law 104-4, establishes requirements for Federal 

agencies to assess the effects of their regulatory actions on State, local, and tribal governments 

and the private segment. Under section 202 of UMRA, EPA generally must prepare a written 

statement, including a cost-benefit analysis, for proposed and final rules with Federal mandates 

that may result in expenditures to State, local, and Tribal governments, in the aggregate, or to the 

private segment, of $100 million or more in any one year.

Before promulgating an EPA rule for which a written statement is needed, section 205 of 

UMRA generally requires EPA to identify and consider a reasonable number of regulatory 

alternatives and adopt the least costly, most cost-effective or least burdensome alternative that

achieves the objectives of the rule. The provisions of section 205 do not apply when they are

inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other

than the least costly, most cost-effective or least burdensome alternative if the Administrator

publishes with the final rule an explanation why that alternative was not adopted.

Before EPA establishes any regulatory requirements that may significantly or uniquely

affect small governments, including Tribal governments, it must have developed under section

203 of UMRA a small government agency plan. The plan must provide for notifying potentially

affected small governments, enabling officials of affected small governments to have meaningful

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and timely input in the development of EPA regulatory proposals with significant Federal

intergovernmental mandates, and informing, educating, and advising small governments on

compliance with the regulatory requirements.

EPA has determined that the Subpart W rule does not contain a Federal 

mandate that may result in expenditures of $100 million or more for State, local, and Tribal 

governments, in the aggregate, or the private sectorsegment in any one year. EPA estimated 

Expenditures associated with compliance, defined as the cost to 

individual facilities that may have to report to this final rule using actual facility characteristics 

such as throughput and size. EPA also determined the incremental costs to non-reporters 

for determination to report. The sum of these costs for the entire industry has been estimated to 

be less thanbeyond the existing regulations will not surpass $100 

million. in the aggregate in any year. Thus, thistoday's final rule is not 

subject to the requirements of sections 202 orand 205 of UMRA. 

This final rule is also not subject to the requirements of section 203 of UMRA 

because it contains no regulatory requirements that might significantly or uniquely affect small 

governments. Based on EPA’s analysis of the rule’s impact on small entities, the Agency 

determined that natural gas distribution is the only industry segment that would potentially have 

small governments affected by the rule. In this segment, however, the facilities owned or 

operated by small governments are expected to be too small to trigger the 25,000 metric tons 

CO2e reporting threshold. This regulation applies to facilities that 

directly emit greenhouses gases. It does not apply to 

governmental entities unless the government entity owns a 

facility in the petroleum and gas industry that directly emits 

greenhouse gases above threshold levels. In addition, this 

final rule does not impose any implementation responsibilities 

on State, local, or Tribal governments and it is not expected to 

increase the cost of existing regulatory programs managed by 

those governments. Thus, the impact on governments affected by 

the final rule is expected to be minimal.

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6.5 Executive Order 13132: Federalism 

This action does not have Executive Order 13132, entitled “Federalism” (64 FR 43255, 

August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and 

timely input by state and local officials in the development of regulatory policies that have 

federalism implications. It will not.” “Policies that have federalism implications” is defined in 

the executive order to include regulations that have “substantial direct effects on the Statesstates, 

on the relationship between the national government and the Statesstates, or on the distribution 

of power and responsibilities among the various levels of government.”

This final rule does not have Federalism implications. It will not have substantial direct 

effects on the states, on the relationship between the national government and the states, or on 

the distribution of power and responsibilities among the various levels of government, as 

specified in EOExecutive Order 13132. 

This regulation applies directly to to public- or private-segment

facilities that directly emit GHGs from petroleum and natural gas facilities 

that emit greenhouse gases. Few, if any, State or local systems. Relatively few 

government facilities would be affected. This regulation also does not limit the power of 

Statesstates or localities to collect GHG data and/or regulate GHG emissions. Thus, 

EOExecutive Order 13132 does not apply to this action. final rule.

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments 

Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal 

Governments” (59 FR 22951, November 6, 2000), requires EPA to develop an accountable 

process to ensure “meaningful and timely input by tribal officials in the development of 

regulatory policies that have tribal implications.”

EPA has concluded that this action may have tribal implications., as specified in 

Executive Order 13175 (65 FR 67249, November 9, 2000). However, it will neither impose 

substantial direct compliance costs on tribal governments, nor preempt Tribal law. 

EPA conducted an analysis to determine potential impact of this action on tribes that own 

or operate petroleum and natural gas systems (EPA-HQ-OAR-2009-0923-XXX). First First, 

when conducting an emissions reporting threshold analysis, EPA analyzed a comprehensive 

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listing of all operators of petroleum and natural gas systems in the United States in conducting 

the threshold analysis.. In a separate analysis, EPA researched additional available data to 

determine which tribal entities may own or operate petroleum and natural gas systems that could 

be impacted by this final action. As a result of those analysisanalyses, EPA found one tribe that 

may potentially be impacted by this final action. Finally, during the comment period for the 

April 2010 proposal, EPA received comment from one tribe, Southern Ute, which were specific 

to the proposed reporting methodologies. 

As further discussed in the 2009 final rule that, which established the Greenhouse Gas 

reporting program40 CFR part 98, EPA believes that there are minimal impacts to tribes. Tribes 

could be required to submit an annual GHG report for any facility that they own or operate that is 

subject to 40 CFR part 98. Landfills and stationary combustion equipment are the rule. 

Specifically,types of facilities owned or operated by tribes that would most likely trigger 

applicability. Tribes that own or operate large industrial emission sources such as cement plants, 

coal mines, or oil and gas operations could also be required to report emissions under this 

rulemaking. It should be noted that the owner or operator of any privately owned sources located 

on a reservation would be required to report for any applicable facility. The rule would apply to 

all types of stationary combustion equipment (except for emergency generators and portable 

equipment) if the aggregate maximum rated heat input capacity of all stationary fuel combustion 

units at a facility is 30 million British thermal units per hour (mmBtu/hr) or greater, and the 

facility emits 25,000 metric tons of CO2e or more per year from all stationary fuel combustion 

sources. 

In addition, EPA sought opportunities to provide information to tribal governments and 

representatives during rule development. As stated Specifically, EPA consulted with tribal 

officials early in IV.F of the preamble, Executive Order 13175: Consultationprocess of 

developing the Mandatory Reporting Program to permit them to have meaningful and 

Coordination with Indiantimely input into its development. First, EPA sought opportunities to 

provide information to Tribal Governmentsgovernments and representatives during development

of 40 CFR part 98, and inPart 98 that was proposed in April 2009 and finalized in September 

2009. Today’s action is a supplement to that rule.

In consultation with EPA’s American Indian Environment Office, EPA’s outreach plan 

for the Greenhouse Gas Reporting Rule included tribes. EPA conducted several conference calls 

with Tribal organizations during During the initial rule proposal phase of Part 98. For example, 

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EPA staff provided information to tribes through conference calls with multiple Indian working 

groups and organizations at EPA that interact with tribes and through individual calls with two 

Tribal board members of The Climate Registry (TCR). tribal board members of TCR. In 

addition, EPA prepared a short article on the GHG reporting rule that appeared on the front page 

of a tribal newsletter—Tribal Air News—that was distributed to EPA/OAQPS’s network of tribal 

organizations. EPA gave a presentation on various climate efforts, including the mandatory 

reporting rule, at the National Tribal Conference on Environmental Management in June, 2008. 

In addition, EPA had copies of a short information sheet distributed at a meeting of the National 

Tribal Caucus. EPA participated in a conference call with tribal air coordinators in April 2009 

and prepared a guidance sheet for Tribal governments on the proposed rule. It was posted on the 

MRR website and published in the Tribal Air Newsletter. For a complete list of tribal contacts, 

see the “Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting 

Rule,” in the Docket for this rulemaking (EPA-HQ-OAR-2008-0508-055).

In addition, EPA prepared a short article on the Greenhouse Gas Reporting Program that 

appeared on the front page of a Tribal newsletter—Tribal Air News—that was distributed to 

EPA/OAQPS’s network of Tribal organizations. EPA gave a presentation on various climate 

efforts, including the Greenhouse Gas Reporting Program, at the National Tribal Conference on 

Environmental Management on June 24-26, 2008. In addition, EPA distributed copies of a short 

information sheet at a meeting of the National Tribal Caucus. See the Summary of EPA 

Outreach Activities for Developing the GHG reporting rule, in Docket No. EPA-HQ-OAR-2008-

0508-055 for a complete list of Tribal contacts. EPA participated in a conference call with 

Tribal air coordinators in April 2009 and prepared a guidance sheet for Tribal governments on 

the final Part 98. It was posted on the Greenhouse Gas Reporting Program website and 

published in the Tribal Air Newsletter. 

As required by section 7(a), EPA’s Tribal Consultation Official has certified that the 

requirements of the Executive Order have been met in a meaningful and timely manner. A copy 

of the certification is included in the docket for this action.

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6.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks 

 This action is not subject to EOEPA interprets Executive Order 13045 (62 F.R. 19885, 

April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, 

such that the analysis required under Section 5-501 of the executive order has the potential to 

influence the regulation. This action is not subject to Executive Order 13045 because it does not 

establish an environmental standard intended to mitigate health or safety risks. Also, this is not 

an economically significant rule under EO 12866, and thus EO 13045 does not apply.

6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, 

Distribution, or Use 

This final rule is not a “significant energy action” as defined in EOExecutive Order

13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect 

on the supply, distribution, or use of energy. Further, EPA haswe have concluded that this final 

rule is not likely to have any adverse energy effects. 

This final ruleproposal relates to monitoring, reporting, and recordkeeping at 

petroleum and gas facilities that directly emit over 25,000 mtCO2e andGHGs from 

petroleum and natural gas systems; it does not impact energy supply, 

distribution or use. Therefore, EPA concludeswe conclude that this final rule is not likely to 

have any adverse effects on energy supply, distribution, or use.

6.9 National Technology Transfer and Advancement Act 

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. Voluntary consensus standards are technical standards 

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide 

Congress, through OMB, with explanations when the Agency decides not to use available and 

applicable voluntary consensus standards.

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This final rulemaking involvesprovides the option of using technical 

standards. EPA provides the flexibility to use any one of the voluntary from consensus 

based standards from at least seven different voluntary consensus standards bodies, including 

the following: ASTM, ASME, ISO, Gas Processors Association, and American Gas 

Association. organizations. These voluntary consensus standards will help facilities 

monitor, report, and keep records of greenhouse gasGHG emissions. No new test methods were 

developed for this final rule. Instead, EPA reviewedfrom existing rules for source categories 

and voluntary greenhouse gasGHG programs and, EPA identified existing means of monitoring, 

reporting, and keeping records of greenhouse gasGHG emissions. The existing methods 

(voluntary consensus standards) include a broad range of measurement techniques, including 

many for combustion sources such as methods to analyze fuel and measure its heating value;,

methods to measure gas or liquid flow;, and methods to gauge and measure petroleum and 

petroleum products. The test methods are incorporated by reference 

into the rule and are available as specified in Section 98.7 of 

subpart A. Additional methods that would be incorporated under 

this final rule are GlyCalc and E&P tanks. 

By incorporating voluntary consensus standards into this final rule, EPA is both meeting 

the requirements of the NTTAA and presenting multiple options and flexibility for measuring 

greenhouse gas emissions. GHGs.

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations 

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federalfederal

executive policy on environmental justice. Its main provision directs Federalfederal

agencies, to the greatest extent practicable and permitted by law, to make environmental justice 

part of their mission by identifying and addressing, as appropriate, disproportionately high and 

adverse human health or environmental effects of their programs, policies, and activities on 

minority populations and low-income populations in the United States. 

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EPA has determined that this final rule will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income populations because it does 

not affect the level of protection provided to human health or the environment because; it is a 

rule addressing information collection and reporting procedures.

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SECTION 7

CONCLUSIONS AND IMPLICATIONS 

In this EIAEconomic Impact Analysis, EPA has examined the regulatory background, the 

development of the mandatory GHG meportingreporting rule for Subpart W, and estimated the

costs and benefits of implementing this subpart. This section presents EPA’sour overall 

conclusions. 

7.1 Discussion of Results 

EPA has developed this final rule in response to language contained in the FY 2008 

Consolidated Appropriations amendment (December 26, 2007), which authorized funding for 

EPA to publish the rule on an accelerated schedule. The major market failure that the rule is 

designed to address is one of inadequate or asymmetric information: while existing state and 

federal programs collect similar data, the resulting data are neither comprehensive nor consistent 

for Subpart W sources. As such, they are an inadequate basis for the formation or evaluation of 

future climate policy that will impact the petroleum and natural gas segments. 

7.1.1 Development of the Proposed Rule 

EPA examined several regulatory alternative scenarios that were developed by varying 

options across two program dimensions—thresholdThreshold and monitoring 

methodologyMonitoring Methodology—that were finalized in today’s rule. The final rule calls 

for: 

– Aa threshold of 25,000- MtCO2e threshold for all facilities., and

– Aa hybrid methodology, including use of limited direct spot measurement, 

facility-specific calculation methods, and use of emission factors (leaker and 

population factors).)

Other scenarios evaluated during the development of the proposal included the following: 

1. A 1,000- MtCO2e threshold; selected options for methodology, frequency, and 

verifier. 

2. A 10,000- MtCO2e threshold; selected options for methodology, frequency, and 

verifier. 

3. A 100,000- MtCO2e threshold; selected options for methodology, frequency, and 

verifier. 

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4. The measurement variable is changed to direct spot measurement; selected option for 

threshold. 

5. The measurement variable is changed to default emissionemissions factors; selected 

option for threshold. 

7.1.2 Affected Source Categories 

EPA considered direct emitters of equipment leaks and vented GHGs under Subpart . 

From these emission sources, EPA identified eight segments under the Subpart W source 

category for which costs and impacts were examined. 

7.2 Assessment of Costs and Benefits of the Mandatory Greenhouse GasGHG

Reporting Rule 

7.2.1 Estimated Costs and Impacts of the Mandatory Greenhouse GasGHG Reporting 

Program 

Under the final rule, EPA estimates that 2,786 entities would be covered by Subpart W of 

the rule, directly emitting 337 millionMillion MtCO2e per year. The total annualized costs 

incurred under the rule by these entities would be $61.8 million for the first year and $19.0 

million for subsequent years. 

Overall, economic impacts on industry segments are measured by comparing per-entity 

costs with average per entity receipts. These cost-to-sales ratios are less than 1 percent% for 

establishments owned by small businesses that EPA considers most likely to be covered by the 

reporting program (e.g., establishments owned by a business with 20 or more employees) and 

small government entities. This analysis enables EPA to determine that the final rule will not 

have a significant economic impact on a substantial number of small entities. Overall, Subpart W 

of the rule will impose national costs exceeding $61.8 million in the first year and $19.0 million 

in subsequent years; the costs will be widely dispersed throughout the economy and relatively 

low on a per-entity basis. The estimated national costs represent less than 0.001 percent% of 

2007 gross domestic product. Thus, EPA does not estimate that there will be significant impacts 

on the economy in general or on individual segments or small entities within Subpart W. 

7.2.2 Summary of Qualitative Benefits Assessment 

EPA did not quantify the estimated benefits of the final rule. Instead, a qualitative 

assessment was performed, based on information from the literature and previous benefits 

assessments of existing emissionemissions inventory programs. 

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Recent policy discussions have highlighted potential benefits to society of the GHG 

reporting program (Pew, 2008). Benefits to the public include building public confidence 

through clear and transparent emission measures and reports and makingthe ability of the public 

to make facilities accountable for their emissions. Benefits to petroleum and natural gas industry 

include identifyingthe identification of GHG reduction opportunities and disclosing 

informationdisclosure, which provides firms with incentives to reduce emissions voluntarily, and 

provides emissionemissions data to service industries, such as insurance and financial markets. A 

GHG reporting system will also have the benefit of providing policymakerspolicy makers and 

analysts with a comparable data set that is comprehensive and reduces the potential for policy 

bias. In addition, a mandatory reporting system is a key element to an overall GHG policy; no 

effort can succeed without it. 

Studies published by the Organization for Economic Co-operation and Development 

(OECD) (2005) and U.S.EPA (2003) have documented benefits to various stakeholders, 

including the public, industry, investors, and government, of existing pollutant release and 

transfer registers (PRTRs).) These benefits are likely similar to the benefits that would be 

experienced as a result of the mandatory GHG reporting rule, and thus they provide a basis for a 

qualitative characterization of those benefits. The studies examined in Section 5 of this 

EIAeconomic impact analysis describe the following types of benefits: 

– Public 

– More information will lead to increased levels of trust towards government 

and industry where there are right-to-know laws concerning emissions.;

– More information willto enable citizens to negotiate directly with 

emitters.polluters; and

– More information willto enable environmentally aware consumers to alter 

their consumption habits based on GHG emissions of producers. 

– Industry 

– Public relations: Havinghaving independent, verifiable data to present to the 

public would demonstrate appropriate environmental stewardship. 
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– Standardization: Uniformuniform industry standards would reduce the cost of 

reporting relative to non-uniform, jurisdiction-specific, and allow facilities to 

benchmark their performance against other similar facilities. 

– Potential cost savings: Mandatorymandatory monitoring may uncover 

previously unmeasured wasteful processes, yielding cost-saving conservation 

opportunities that would offset some of the costs of monitoring. 

– Potential customer data for service industries: Informationinformation about 

GHG-emitting firms will be useful for firms that market emissionemissionsreduction technologies, and to insurance companies for assessing risk. 

– Investors 

– Information about emissions will enable investors to implement socially 

responsible investing using GHG emission information if they so choose. 

– Government 

– Policy development: The greatest benefit to government of mandatory GHG 

reporting is the comprehensive, consistent data it would provide, enabling 

government to develop accurate, informed future GHG policy. 

– Comparability: A mandatory system would reduce the difficulties associated 

with comparing across different reporting standards across states or programs. 

– Compliance and policy evaluation: Publicly available nationwide data on 

GHG emissions will enable government to develop and robustly evaluate 

environmental policies, and to ensure compliance with the policies once 

implemented. 

7.3 What Did We Learn through This Analysis? 

EPA’s examination of the costs and benefits of the provisions in Subpart W of the 

mandatory GHG reporting rule revealed that the final rule will impose an estimated $30.9 

million (based on average of first- year and subsequent- year costs) in monitoring, 

recordkeeping, and reporting costs on emitters of GHGs that are widely distributed throughout 

the U.S. economy. Impacts of the costs on individual segments and entities are expected to be 

generally small, comprising less than 1 percent of entity receipts and approximately 0.001 

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percent of 2007 gross domestic product.GDP. Thus, despite the overall national costs, 

macroeconomic impacts are not anticipated, and EPA does not believe that the final rule will 

impose significant economic impacts on a substantial number of small entities. 

A review of the literature enabled EPAus to characterize the expected types of benefits, 

which will be experienced by stakeholders, including the public, industry, investors, and 

government. Based on this qualitative assessment and evidence from other existing programs, 

EPA expects the benefits of the final rule to be substantial. 

7-1 

SECTION 8

SOURCES CONSULTED

Section 8

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