# Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Under Subpart W Final Rule (GHG Reporting)

PRELIMINARY DRAFT Final Report

November August , 2010 Style Definition: TOC 1: Font: Times New Roman Bold, Bold Style Definition: Heading 4,l4: Indent: Left: 0", Outline numbered + Level: 4 + Numbering Style: 1, 2, 3, ... + Start at: 1 + Alignment: Left + Aligned at: 0.5" + Tab after: 1.1" + Indent at: 1.1", Tab stops: Not at 1.1" Style Definition: Heading 3,l3: Indent: Left: 0", Hanging: 0.5", Outline numbered + Level: 3 + Numbering Style: 1, 2, 3, ... + Start at: 1 + Alignment: Left + Aligned at: 0" + Tab after: 0.6" + Indent at: 0.6" Style Definition: Heading 2,l2: Indent: Left: 0", Hanging: 0.5", Outline numbered + Level: 2 + Numbering Style: 1, 2, 3, ... + Start at: 1 + Alignment: Left + Aligned at: 0.08" + Tab after: 0.68" + Indent at: 0.68"

Formatted: Font: 10 pt Formatted: Lefti Formatted: Centered Formatted: Font: Not Italic 

### 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 Field Code Changedii Formatted: Centered Formatted: Font: Not Italic 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 Analys is ......................

................................ ......................... 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 ..................... 4-33iii Formatted: Centered Formatted: Font: Not Italic 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 ............................................................................................. 7-1iv Formatted: Centered Formatted: Font: Not Italic 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 Benef its 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

............................................. 1-7 1

- 6 1.2.3 Illustrative Nature of the Analysis

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

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

.......................................................... 1-8 1

- 7 1.3.2 Developing the GHG Reporting Rule Considered in This Economic Impact Analysis

...................................................................... 1-8 1.3.3 Evaluating Costs and Benefits

........................................................ 1-14 1

- 13
1.4 Subpart W Selected Greenhouse Gas Reporting Alternative

........................ 1-14 1

- 13

Section 2 Regulatory Background
........................................................................................... 2-1
2.1 EPA’s Over all 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 Greenhou se 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

................................................................................................ 2-5v Formatted: Centered Formatted: Font: Not Italic 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

- 10 2.3.4 Other EPA Emissions Inventories

......................................................... 2-11 2.3.5 State and Regional Voluntary Programs for Greenhouse Gas Emissions Reporting

....................................................................... 2-12 2

- 11 2.3.6 State and Regional Mandatory Programs for Greenhouse Gas Emissions Reporting and Control

................................................... 2-13 2

- 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 Whic h 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

- 5
3.4 Data Quality for This Analysis

............................................................................... 3-6

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

- 8
4.1 Introduction

....................................................................................................... 4-1 4

- 8
4.2 Overview of Cost Analysis

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

- 9 4.2.1 Baseline Reporting

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

- 9 4.2.2 Reporting Costs

................................................................................... 4-3 4

- 9
4.3 Subpart W

— Petroleum and Natural Gas Systems

.......................................... 4-5 4

- 11
4.4 Summary Results: Subpart W

— Petroleum and Natural Gas Systems

......... 4-14 4

- 18
4.5 Detailed Cost Assumptions: Subpart W

— Petroleum and Natural Gas Systems

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

- 22

4.5.1 Determining Labor Categories

........................................................ 4-24 4

- 28 4.5.2 Allocating Responsibilities

............................................................. 4-25 4

- 29 4.5.3 Capital Cost Annualization and O&M Costs

.................................. 4-33 4

- 35vi Formatted: Centered Formatted: Font: Not Italic Section 5 Subpart W Analysis of Reporting Rule Options
................................................... 5-1
5. 1 Evaluating Alternative Options for Implementation of the Rule

...................... 5-3 5

- 4 5.1.1 Analysis of Alternative Threshold Options

........................................ 5-5 5

- 4 5.1.2 Analysis of Alternative Monitoring Method Options

......................... 5-9 5

- 8 5.1.3 Sensitivity of Subsequent Year Cost Estimates

................................ 5-10 5

- 9 5.1.4 Summary of Alternativ e Options for Onshore Facility Definition

. 5-11 5

- 10
5.2 Assessing Economic Impacts on S mall Entities

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

- 12 5.2.1 Identify Affected Segments and Entities

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

- 12 5.2.2 Develop Small Entity Economic Impact Measures

........................ 5-18 5

- 17 5.2.3 Results of Screening Analysis

........................................................ 5-21 5

- 20
5.3 Synopsis of Benefits

...................................................................................... 5-22 5

- 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

................................................................................. 6-4 6

- 3
6.4 Unfunded Mandates Reform Act

...................................................................... 6-8 6

- 6
6.5 Executive Order 13132 : Federalism

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

- 7
6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments

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

- 7
6.7 Executive Order 13045: Protection of Children from Environmental Health and Safety Risks

.............................................................................................. 6-12 6

- 8
6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use

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

- 9
6.9 National Technology Transfer Advancement Act

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

- 9
6.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low

- Income Populations

................................ 6-14 6

- 10

Section 7 Conclusions and Implications
.................................................................................. 7-1
7.1 Discussion of Results

............................................................................................. 7-1vii Formatted: Centered Formatted: Font: Not Italic 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
............................................................................................................ 7-1 8

- 1ix 

### LIST OF FIGURES

Page Figure 5-1 Average and Marginal Cost and Cost Differential per Metric Ton of Emissions Reported by Threshold ........................................................................................ 5-8 5

- 7 Figure 5-2 Summary of Basin vs. Field Decision ............................................................. 5-13 5

- 11

Field Code Changed Formatted: Check spelling and grammar, Not Expanded by / Condensed by Formatted: Check spelling and grammar, Not Expanded by / Condensed by Formatted: Check spelling and grammar, Not Expanded by / Condensed by

Field Code Changed Field Code Changed Field Code Changedxi 

### 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$) ................... 4-8 Table 4-4 Subpart W Petroleum and Natura l Gas Systems: Capital and O&M Costs (2006$) 4-9 Table 4-5 Subpart W Petroleum and Natural Ga s 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-Effectiv eness Analysis (First Year); Selected Hybrid Option Is 25,000 MtCO 2 e ............................................................................. 5-5 Table 5-5 Summary of Threshold Cost-Effect iveness Analysis (Subsequent Years) .............. 5-6 Table 5-6 Subpart W Cost Estimates by Threshold .................................................................. 5-7 Field Code Changedxii 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 Industr y 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 S cenarios for Regulation under Subpart W (Final Option Indicated by Shading)

........................................................................ 3-2 Table 4

- 1 Selected Reporting Thresholds and Reporting Requirements

............................. 4-1 4

- 8 Table 4

- 2 Number of Facilities Reporting by Threshold and Industry Segment

............... 4-7 4

- 13 Table 4

- 3 Subpart W Petroleum and Natural Gas Systems: Labor Costs 1 (2006$)

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

- 17 Table 4

- 4 Subpart W Petr oleum and Natural Gas Systems: Capital and O&M Costs 2 (2006$)

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

- 17 Table 4

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

- 18 Table 4

- 6 Subpart W Facilities and E missions Covered by Final Rule

........................... 4-14 4

- 18 Table 4

- 7 Summary of Costs and Costs per Representative Entity by Threshold

........... 4-16 4

- 20 Table 4

- 8 Summary of Reporting Determination Costs per Segment by Thres hold

....... 4-18 4

- 22 Table 4

- 9 Allocation of Facilities to Model Types

.......................................................... 4-23 4

- 27 Table 4

- 10 Labor Categories and Hourly Rates

................................................................. 4-24 4

- 28 Table 4

- 11 Loaded Hourly Rates for Good s Producing Private Establishments

............... 4-25 4

- 29 Table 4

- 12 Responsibilities for Regulation Compliance by Labor Category

.................... 4-25 4

- 29 Table 4

- 13 Responsibilities for Monitoring and Allocation of Labor Hour s
..................... 4-27 4

- 30 Table 4

- 14 Monitoring Program Compliance Capital Costs and Other O&M

.................. 4-33 4

- 36 Table 5

- 1 National Cost Estimates for Petr oleum and Natural Gas Systems

........................... 5-2xiii T able 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 Estimate s
....................................................................... 5-3 Table 5

- 4 Summary of Threshold Cost

- Effectiveness Analysis (First Year): Selected Hybrid Option is 25,000 metric tons CO 2 e
............................................................... 5-5 Table 5

- 5 Summary of Threshold Cost

- Effectiveness Analysis (Sub sequent Years)

.......... 5-6 5

- 5 Table 5

- 6 Subpart W Cost Estimates by Threshold

............................................................. 5-7 5

- 6 Table 5

- 7 Analysis of Alternative Monitoring Methods

.................................................... 5-10 5

- 9 Table 5

- 8 Emissions Coverage and Entities Reporting for Field Level Facility Definition (Onshore Production)

....................................................................................... 5-12 5

- 11 Table 5

- 9 Equipment Leaks and Vented and Combustion Emissions Cost for Field Level Facility Definition (Onshore Production)

........................................................ 5-12 5

- 11 Table 5

- 10 Number of Establishments by Affected Industry and Enterprise a Size: 2002

. 5-15 5

- 14 Table 5

- 11 Number of Employees by Affected Industry and Enterprise a Size: 2002

....... 5-16 5

- 15 Table 5

- 12 Receipts by Affected Industry and Enterprise a Size: 2002

.............................. 5-17 5

- 16 Table 5

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

- 18 Table 5

- 14 Establishment Sales Tests by Industry and Enterprise a Size: Subsequent Year Costs

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

- 19xiv 

### 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 CH 4 methane CMOP Coalbed Methane Outreach Program CO 2 carbon dioxide CO 2 e 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 Formatted: Section start: New pagexv LMOP Landfill Methane Outreach Program LNG liquefied natural gas M&R metering and regulating MMBtu million British thermal units MMS Minerals Management Service MtCO 2 e metric tons of carbon dioxide-equivalent MW megawatt
NAICS North American Indus try 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 Sign ificant 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 SF 6 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 Developmentxvi WCI Western Climate Initiative WRI World Resources Institutexvii Disclaimer The Environmental Protection Agency (EPA) regulatio ns cited in this Economic Impact Analysis (EIA) contain legally-binding requirements. Seve ral 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 pr oducts 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) 2008 FY2008 Consolidated Appropriations Amen dment, which authorized fundin g 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 emissions emission resulting from upstream production and downstream sources, to the extent that the Administrator deems it appropriate. The Administrator shall determine appropriate thresholds of emissions ab ove which reporting is required, and how frequently reports shall be submitted to EPA. The Administrator shall have discretion to use existing reporting requ irements for electric generating units under Section 821 of the Clean Air Act.
EPA signed the final mandatory GHG reporting rule Mandatory 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 emission emissions 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 Repor ting of Greenhouse Gas Emissions Under Subpart W Rule

(GHG Reporting ); ), see http:// www.epa.gov/climatechange/emissions/subpart/w.html. Formatted: No bullets or numbering1-2 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 ( MtCO 2 e CO 2 e ) process emissions, or , on average , $0.16/ MtCO 2 e. metric ton CO 2 e
. This cost compares with the estimate of $0.38/ MtCO 2 e metric 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 methodologi es 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 emission emissions factors ).

. The bulk of emissions will be quantified us ing engineering calculations based on actual facility or field data and using leak detection and “leaker” factors 3 . 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 MMS 4 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 incl udes $18.4 million for non-reporters to make a

threshold determination and $3.3 million for combustion emission emissions 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” emission emissions factors, which are based on simple population count. The population c ount 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 includes T here are several key changes in today’s final rule that affect the compliance cost estimates. First, the final rule provides equipment thresholds floors on several emission emissions sources. Reporters will use a simple population

- based emission emissions factors for sources below the equipment threshold. floor. Second, EPA has simplified the requirement required for sampling of gas and emissions for many of the emission emissions 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 emission emissions reporting , relative to the original proposal. For the six original segments, equipment leak and vented emission emissions costs for reporters changed from $0.36/ MtCO 2 e metric ton CO 2 e in the April , 2009 proposed rule to $0.28/ MtCO 2 e metric ton CO 2 e in the April , 2010 proposal, and to $0.33/ MtCO 2 e metric ton CO 2 e 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/ MtCO 2 e metri c ton CO 2 e in the first year, which is less than the first year cost of $0.21/ MtCO 2 e metric ton CO 2 e 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. Those However, those that meet the emission emissions 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 rule MRR 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 MtCO 2 e met ric tons CO 2 e expected to be reported under Subpart C, 83.5 million MtCO 2 e metric tons CO 2 e are the combustion emissions from petroleum and natural gas facilities that woul d 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 CO 2 e using a 100-

year global warming potential from the Intergovernmental Panel on Climate Change ( IPCC ).

. Also, subsequent

year 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 emission e missions reporting is $3.3 million per year of the total combustion emission emissions cost, or $0.04/ MtCO 2 e metric ton CO 2 e
. First-year Year 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 emission emissions 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 li nes 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) Vented vented emissions, which include intentional or designed releases of methane ( CH 4 ) and/or carbon dioxide ( CO 2 ) containing natural gas or hydrocarbon gas (not including stationary combustion flue gas) from emission emissions 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) Equipment equipment leaks, which mean are defined to include those emissions that which are unintentional and could not reasonably pass through a stack, chimney, vent, or other functionally

- equivalent opening

. ; and
3) Flare flare combustion emissions, which include CH 4 , CO 2 , and nitrous oxide ( N 2 O ) 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 2008 FY08 Appropriations language, under the authority of Section 114 of the Clean Air Act [CAA]. Section 114 provides Formatted: No bullets or numbering1-5 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) manuf actures control or proce ss equipment, (iii) the Administrator believes may have information necessa ry 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 Sections sections 111, 112 or 129 8 , determining if any person is in violation of any standard or requirement of an implementation plan or emission emissions standard, or “carrying out any provision” of the act Act (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 Section section 114(a)(1) information request (e.g., a person “who the Administrator be lieves may have informa tion necessary for the purposes set forth in” Section section 114 [ ( a ]) )) and the reach of the phrase “carrying out any provision” of the act Act 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 Section section 114, EPA could gather information relevant to carrying out provisions involving research (e.g., Section section 103 [ ( g ]); )); evaluating and setting standards (e.g., Section section 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 GHG greenhouse 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 Section section 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 “ Hazardous hazardous Air Pollutants ”; ,” and Section section 129 contains provisions for “solid waste combustion.” 9 Although there are exclusions in Section section 114(a)(1) regarding certain Title title II requirements applicable to

manufacturers of new motor vehicle and motor vehicle engines, Section section 208 authorizes the gathering of information related to those areas.1-6  Proposed Endangerment and Cause or C ontribute 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 by By 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 rule MRR 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 governm ent agencies, and outside stakeholders with economy-wide data on facility-level (and in so me cases corporate-level) GHG emissions, which could assist in future policy development.
Accurate and timely informat ion on GHG emissions is essential for informing future climate change policy de cisions. Although additional data co llection (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 th is 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 taki ng to reduce emissions.
The Agency considered a wide range of determining factors when selecting the alternatives for this rule. Thes e included the consideration of costs and benefits, which are essential to making efficient, cost-effective deci sions 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 EIA Economic 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 EIA Economic 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 Guidelines 10 . 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 EIA Economic Impact Analysis presents the costs of the final rulemaking; Section section 5 summarizes the cost-effectiveness analysis of the program and

. Se ction 5 also qualitatively describe s 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. Followi ng 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. Formatted: No bullets or numbering

Formatted: No bullets or numbering

Formatted: No bullets or numbering1-8 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 presen ts 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 emissions emission for the petroleum and natural gas source category, productive capacity, existing emission emissions 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 pres ent 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 than over 484 significant and detailed comments ( more than over 2,700 pages for Subpart W ), ) and conducted extensive review and analysis of available information on se gments 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 analyze see 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’s our 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’s our review of state mandatory GHG rules and how they treat equipment leak emissions from the petroleum and natural gas industry. Formatted: No bullets or numbering

Formatted: No bullets or numbering1-9 EPA’s overall rulemaking approach began with identifying identification of anthropogenic sources in the U.S. GHG Inventory and Intergovernmental Panel on Climate Change (IPCC). The rule would require reporting of CO 2 and CH 4 equipment leak and vented emissions, as well as and combustion-related emissions 11 of CO 2 , and CH 4 , and N 2 O as defined in the rule. The IPCC focuses on CO 2 , CH 4 , and N 2 O for both scientific assessments and emission emissions 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 Cl imate 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 mo st 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 source Source 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 Only It 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 emission emissions monitoring, calculating emissions based on site-specific information, and calcu lating emissions based on default emission emissions factors. In general, for 40 CFR Part 98, EPA selected a combination of continuous emission emissions 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 measurement 12 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 reduce reduc es the sources that must be directly quanti fied. While direct spot measurement is still required to develop site or equipment-specific emission emissions factors for some major sources, much of the emission emissions 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 MtCO 2 e metric tons CO 2 e /year ;

o 10,000 MtCO 2 e metric tons CO 2 e /year ;

o 25,000 MtCO 2 e metric tons CO 2 e /year ; and

o 100,000 MtCO 2 e metric tons CO 2 e /year

.

– Methodology for measuring emissions : ;

o Direct spot measurement ;

o Facility-specific calculation methods ; and

o Leaker and default emission emissions 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 the from 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 than over 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 following Below 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 (n atural gas distribut ion) 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 were was 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 emission emissions “population” factors based on component counts).

– Use of population emission factors was proposed in several areas, primarily for minor equipment leak sources and al so 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 emission emissions results for offshore platforms in federal Federal Gulf Formatted: No bullets or numbering1-12 of Mexico (GoM) waters to avoid redundancy of reporting efforts. 13 EPA We also required that facilities not covered by GOADS ( state State waters and federal Federal non-GoM platforms) use data collection and emission emissions calculation methods in accordance with the BOEMRE MMS GOADS program to reduce burden and make emission emissions 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 Subpa rt W reporters. These changes include:

– Added a mechanism in 40 CFR 98.2 to allo w facilities and suppliers that report less than 25,000 MtCO 2 e metric tons of CO 2 e for five 5 years to cease annual reporting to EPA.

– Added a mechanism in 40 CFR 98.2 to allo w facilities and suppliers that report less than 15,000 MtCO 2 e metric tons of CO 2 e for three 3 years to cease annual reporting to EPA.

– Added a mechanism in 40 CFR 98.2 to a llow facilities and suppliers that stop operating all GHG-emitting processes and ope rations covered by the rule to cease annual reporting to EPA.

– Added a provision in 40 CFR 98.3 for submitting submittal 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 representative Designated Representat ive 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

federal Federal waters in the Western Gulf of Mexico , developed by The Minerals Management Service ( MMS (now called BOEMRE). ). The MMS mandated that all 2,525 2 525 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 es timate emissions. The usual cycle for this data collection effort has been once in ev ery three to four years.1-13 – Changed record retention to three 3 years instead of five 5 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 Part part 98, Subpart subpart 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 emission emissions spot measurements.
1.3.2.2 Summary of the Major Changes From the from 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 threshold a floor for compressors, separators, and dehydrators such that sources below the equipment threshold floor use a simplified population emission emissions factor approach and sources above the equipment threshold floor use actual monitoring

. ;

– Onshore production compressors use emi ssion 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 emission emissions factors will be applied to major equipment rather than individual components

. ; Formatted: No bullets or numbering1-14 – 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 additio n to using infrared devices.

These The 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 EIA Economic 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 MtCO 2 e metric ton of CO 2 equivalent (MMtCO 2 e) reported. This cost-effectiveness metric was co nsidered 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 emission emissions coverage.

– Threshold : 25,000 MtCO 2 e metric tons CO 2 e /year

– The thresholds for the finalized GHG reporting rule MRR fall generally into three groups: capacity, emissions, or entire source category (“All in”). In Subpart W, a facility that emits 25,000 MtCO 2 e metric tons CO 2 e /year or more reports all sources for which there are methods specified in the rule Rule

.

– Subpart W facilities determine thei r applicability by comparing their emissions to a threshold of 25,000 MtCO 2 e metric tons CO 2 e /year.

– Subpart W segments evaluate threshold from an analysis of reported vented and equipment leaks and stationary combustion-based emissions. Formatted: No bullets or numbering

Formatted: No bullets or numbering1-15 – 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 emission emissions factors.

– Source-specific engineering calculation methods using facility-specific information for other sources at the facility.

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

– Source-specific use of population

- based emission factors for minor vented and equipment leaks or inaccessible sources.2-1 Formatted: Centered Formatted: Font: Not Italic SECTION 2 REGULATORY BACKGROUND
The intent of this rule is to collect accurate and timely GHG emission emissions 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. Th e reporting program will supplement rather than duplicate other U.S. government GHG programs. EPA outlines the Agency’s We outline EPA ’ s overall rulemaking approach, sources considered, and summarize the our review of GHG monitoring protocols for each petroleum and natural gas system used by federal, state, regional, and internationa l voluntary and mandatory GHG programs, and EPA’s our 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 2008 FY2008 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 that which 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 does we 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 EIA Economic Impact Analysis for the final rulemaking is specific to Subpart W, petroleum and natural gas systems.
To these ends, EPA we identified the following goals of the mandatory reporting system:2-2 Formatted: Centered Formatted: Font: Not Italic

– 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 dete rmined the reporting requirements issued in today’s final rule.
2.1.3 Evaluating Evaluation 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, EPA we 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 Busine ss Council for Sustainable Development (WRI/WBCSD ). ) ; and2-3 Formatted: Centered Formatted: Font: Not Italic

– Programs from industrial trade organizations, such as the American Petroleum Institute’s Compendium of GHG Estimati on Methodologies for the Petroleum and Gas Industry.
In reviewing these programs, EPA we analyzed the segments covered, thresholds for reporting, the monitoring or emission estimating methods used, the measures to ensure assure the quality of the reported data, the point of monitoring, data input needs, and information required to be reported and/or retained. EPA We 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 rule MRR 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 rule MRR , 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:

– Trade trade associations and firms in potentially affected industries/segments

. ;

– State state , local, and tribal environmental contro l agencies and regional air quality planning organizations

. ;

– State state and regional organizations already involved in GHG emission emissions reporting, such as TCR, California Ai r Resources Board (CARB), and Western Climate Initiative (WCI ). ); and

– Environmental environmental 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, EPA we 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 veri fication, and the role of states in administering the program. As needed, the EPA technical wo rkgroups followed up with these stakeholder groups on a variety of methodological, techni cal, and policy issues. EPA staff also provided2-4 Formatted: Centered Formatted: Font: Not Italic information to tribes through conference calls with different Indian tribal working groups and organizations at EPA as well as through indivi dual 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 than over 16,000 written public comments. The public comment period ended on June 9, 2009. Subpart W received comments from more than over 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 than over 4,000 people and 135 groups between proposal signature (March 10, 2009) and the close of thecomment period (June 9, 2009). Details of these meetings are available in the docket (EPA-HQOAR-2009-0923).
2.1.5 Considering Consideration 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 than over 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 significan tly 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 requ ired to monitor emissions. See the preamble of today’s final rule for a complete discussion of about these changes.
2.1.6 Analyzing Analysis of Emissions From from 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 fr ameworks, 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 scen arios 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-2008-0508-055.2-5 Formatted: Centered Formatted: Font: Not Italic rule for Subpart W with respect to the size of the entity requir ed 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 review ed 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 equipmen t 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 met hodologies for the sources in Subpart W identified in Table 2-2 Table 2

- 2

.

Table 2-1 Sources of GHG Emissions Considered Source Subpart W: GHG Emissions Emission Considered
Downstream

Direct emitters Stationary and portable combustion : Sources considered include stationary combustion units (e.g., drilling rigs, dehydrat ors, compressors, electrical generators, steam boilers, and heaters).

Vented emissions : Intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas) that result from the extraction, processing, storage, a nd 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 that which 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 : Unburned Means unburned hydrocarbons , including CH 4 , CO 2 , and N 2 O 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.2-6 Formatted: Centered Formatted: Font: Not Italic

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 From from 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 emission emissions 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 federal Federal and state State programs during development of the rule. Documentation of EPA’s our review of GHG monitoring protocols for each source category used by federal, state, and international voluntary and mandatory GHG programs, and EPA’s our review of state State 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 Formatted: body text_psg

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Formatted: English (U.S.)2-7 Formatted: Centered Formatted: Font: Not Italic methodologies contained in state State reporting programs such as TCR, the CCAR ( California Climate Action Registry (CCAR ), and state State 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 emission emissions calculations to multiple programs, if desired. EP A will continue to work closely with states and state-based groups to ensure that the data manageme nt 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 emission emissions 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 s ubmitting reports to other programs. EPA However, we also needs need 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 th is 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 annua l report presents historical U.S. emissions of CO 2 , CH 4 , N 2 O, hydrofluorocarbons (HFCs), , perfluorocarbons (PFCs), , and sulfur hexafluoride (SF 6 ).

.
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 State2-8 Formatted: Centered Formatted: Font: Not Italic 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 GHG greenhouse gas emissions , and uses top-down national energy data and other national statistics. To achieve the goal of comprehensive national emission emissions 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 emission emissions 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 inventory Inventory 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 CH 4 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) 15 16 and EPA (GRI/EPA 1996) is used as the basis for estimates of CH 4 and non-combustion-related CO 2 emissions from the U.S. natural gas industry in the report.

For petroleum Petroleum and natural gas Natural 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 emission emissions 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 reflecti ng 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 site Star 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 petroleum Petroleum and natural gas systems Natural Gas Systems by

15 Now the Gas Technology Institute 16 Now the Gas Technology Inst itute2-9 Formatted: Centered Formatted: Font: Not Italic improving the estimates of emissions and thereby advance the understanding of emission processes and monitoring methodologies. Facility, unit, and process level GHG emission emissions data for all sources will improve the accuracy of future U.S. Greenhouse Gas Inventory Reports by confirming the national stat istics and emission es timation 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 inventory Inventory , 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 andreduction programs that EPA reviewed when developing this proposal, including several nonCO 2 voluntary programs, and the DOE 1605(b) voluntary GHG registry. Several other federal voluntary programs encourage emission emissions 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 invent ories or reporting of GHG emission emissions reduction activities for sources that were considered for inclus ion in Subpart W of this final rulemaking.
2.3.2.1 Non-CO 2 Voluntary Partnership Programs Since the 1990s, EPA has operated a number of non-CO 2 voluntary partnership programs aimed at reducing emissions from GHGs such as CH 4 methane , SF 6 , 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 emission emissions 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 th at 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 emission emissions 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, Formatted: Font: (Default) Times New Roman, 12 pt

Formatted: No bullets or numbering2-10 Formatted: Centered Formatted: Font: Not Italic 2006 (71 FR 20784); the rule is contained in 10 CFR Part 300. Unlike EPA’s proposal, which requires reporting of GHG greenhouse 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 emission emissions reduction projects to the registry. Large emitters (e.g., anyone that emits over 10,000 MtCO 2 e metr ic tons of CO 2 e per year) who wish to register emission emissions reductions must submit annual company-wide GHG emission emissions inventories following technical guidelines published by DOE and must calculate and report net GHG emission emissions 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 previously above , 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 emission emissions 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 particip ation in the programs and report ing to the programs is entirely voluntary. A small number of sources report, compar ed 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 emission emissions 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 progr ams serve as useful starting points for the mandatory GHG reporting rule. GHG rules. 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 SF 6 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 have2-11 Formatted: Centered Formatted: Font: Not Italic

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 se gment s. Facilities must submit annual repo rts of total stack and equipment leaks of the listed toxic chemicals using a standardized form that which can be submitted electronically. No information is reported on the processes and emission emissions 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 emission emissions sources. The However, the TRI program is similar , however, to the mandatory GHG reporting rule in that it requires direct emission emissions 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 Emission Emissions Inventories
2.3.4.1 National Emissions Inventory EPA compiles the National Emissions Inventory (NEI), a database of air emission emissions information provided primarily by stat e 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 po llutants. 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 that source NEI includes number more than over 60,000 facilities. Required point source info rmation consists of facility identification information as well as ; process information detailing the types of air pollution emission sources, air pollution emission estimates (including annua l emissions), control devices in place, stack parameters, and location information. The NEI diffe rs from the GHG reporting rule in that the NEI contains no GHG data, and the data are reported primarily by state State agencies rather than directly reported by industries. In However, in developing the rule , however , EPA used the NEI to help determine sources that might need to re port under Subpart W of the GHG reporting rule. Formatted: Font color: Auto Formatted: Font color: Auto

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EPA We considered the types of facility and , process and activity data reported in NEI to support the emission emissions data as a possible model for the type s of data to be reported under the GHG reporting rule.
2.3.5 State and Regional Voluntary Programs for Greenhouse Gas Emission Emissions Reporting
A number of states States have demonstrated leadership and developed corporate voluntary GHG reporting programs individually or joined with other states States to develop GHG reporting programs as part of their appr oaches to addressing GHG emissions. The following discussion summarizes two prominen t voluntary efforts. In developing the GHG greenhou se 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 (verific ation) protocol, and several segment-specific protocols. Companies submit emission emissions 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. Emission Emissions 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 emission emissions measurement and verification protocols and reporting system capab le 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 has They have also released a general verification protocol , and an electronic reporting system. Several industr y-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 Formatted: English (U.S.) Formatted: English (U.S.) Formatted: English (U.S.)2-13 Formatted: Centered Formatted: Font: Not Italic 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 (CO 2 , CH 4 , N 2 O, HFCs, PFCs and SF 6 ) within each facility.
2.3.6 State and Regional Mandatory Programs for Greenhouse Gas Emission Emissions Reporting and Control
Several individual states States and regional groups of states States have demonstrated leadership and are developing or have developed mandatory GHG reporting programs and GHG emission emissions control programs. This section of the preamble summarizes two regional cap

- and

- trade programs and several state State mandatory reporting rules, which cover

— , or , for those programs still under developmen t, have the potential to cover

— the petroleum and natural gas segment. EPA recognizes We recognize that, like the current voluntary regional and state State programs, state State 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 Greenhou se Gas Initiative ( RGGI ) is a regional cap

- and

- trade program that covers CO 2 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 CO 2 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 emissi ons 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 states Western 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 design2-14 Formatted: Centered Formatted: Font: Not Italic 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 “industri al process emission sources, including petroleum and natural gas process emissions ” 17 , 18 ,” meaning that sources covered under Subpart W of the federal Federal 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 12 twelve states as of 2009; the rest will begin between 2010 and 2012. Reporting is typically annual, although so me states require quarterly reporting for EGUs, consistent with RGGI.
State rules differ with regard to which f acilities must report and which GHGs must be reported. Some states require all facilities th at must obtain Title V permits to report GHG emissions. Others require reporting for partic ular segments (e.g., large EGUs, cement plants, refineries). Some state rules apply to any facili ty 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 emissi ons may be deliberate (e.g., vented), fugitive (e.g., leaked), or accidental. 18 In the WCI design recommendations, process emissions ar e 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, Vi rginia, Washington, West Virginia, and Wisconsin.2-15 Formatted: Centered Formatted: Font: Not Italic threshold level of CO 2 . Some apply to any facility, or to fac ilities within listed industries, if their emissions exceed a specified threshold level of CO 2 e. Many of the state rules apply to six GHGs covered by 40 CFR Part 98 (CO 2 , CH 4 , N 2 O methane, nitrous oxide , HFCs, PFCs, SF 6 ); others apply only to CO 2 or a subset of the six gases. Most requir e 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 establis hed 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 segmen t, and electricity generation and cogeneration plants not within the operational control of la rger facilities and entities) are required to have filed file their first emission emissions data reports by April 1, 2009. The rest of the facilities and entities are to have reported report by June 1, 2009 (see http:// www.arb.ca.gov/cc/reporting/ghgrep/ghgschedadvisory.pdf). The ru le requires facility-level reporting of all GHGs (except PFCs) from cement manufacturing plants, electric powe r generation and retail markets, cogeneration plants, petroleum refineries, hydrogen plants, a nd facilities with statio nary combustion sources emitting greater than 25,000 MtCO 2 metric tons CO 2 per year. The California rule does not impact those facilities that would be s ubject to reporting unde r Subpart W of the federal Federal 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 nationa l and regional efforts, such as TCR and WCI, to assist with developing consistent reporti ng 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 theother dimensions. These alternatives were then evaluated based on estimated cost, costeffectiveness (cost per metric ton of emissions reported), and estimated im pacts on small entities. This process is discussed in greater detail in the following sections below

. 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 emission emissions 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 emission emissions factors).
The options EPA considered for each dimension for Subpart W sources are discussed in the following sections below and summarized in Table 3-1 Table 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 Deve loping Scenarios for Regulation Under under Subpart W (Final Option Indicated by Shading)

Methodology Direct Measurement (CEMS) Hybrid: Direct spot measurement for major emission emissions sources and calculation methods for non-major sources Default emission emissions factors from EPA Threshold Capacity-based Emissions based 1,000 MtCO 2 e X X X
Emissions-based 10,000 MtCO 2 e X X X
Emissions-based 25,000 MtCO2e X X X
Emissions-based 100,000 MtCO2e X X X Hybrid: 25,000 MtCO 2 e 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, emission emiss ions -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 sections below , EPA ruled out these two options based on data limitations and other challenges.
3.1.1.1 Option 1: Capacity- Based Threshold based 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 th e 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 are is not currently universally available to EPA. Formatted: Font: Bold Formatted: Font: Bold Formatted: Font: Bold3-3 3.1.1.2 Option 2: Emission-Based Threshold Emissions

- based threshold (Selected) Option 2 involves the use of actual facility-level emissions of GHGs, measured in MtCO 2 e. metric tons of CO 2 - equivalent emissions ( M tCO 2 e). Various levels were considered, ranging from 1,000 MtCO 2 e to 100,000 MtCO 2 e. Obviously, lower thresholds would require more facilities to participate in the reportin g program. Given current data availability, an emission emissions -based threshold will generally focus on larger, emission emissions -intensive sources in the petroleum and natural gas segment for which emission emissions data are readily calculated or measured.
3.1.1.3 Option 3: Hybrid Threshold threshold The hybrid threshold option is a combination of three general groups: capacity, emissions, or entire source category (“ all All in”). The thresholds developed are generally equivalent to a facility-wide threshold of 25,000 MtCO 2 e metric tons of CO 2 e per year of actual emissions. The preference is to establish thresh olds 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. Second Secondly , 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 metho dology options, ranging from installing emission emissions monitoring equipment on all sources under Subpart W to using default emission emissions factors to estimate emissions. The measurement methodology options considered for Subpart W sources are discussed in the following sections below

. 3.1.2.1 Option 1: Direct Measurement measurement for All Reporters all reporters This option would apply direct measurement requirements to all reporters. It This 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

- volume3-4 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-S pecific Calculation for Other Sources (Selected direct measurement and facility

- specific calculation for other sources ( selecte d ) EPA’s final rule required measurement methodology option for Subpart W is a hybrid of direct measurement and facility-specific calcula tions, which is considerably less burdensome than Option 1. Specifically, EPA requires the use of direct spot measurement , where reliable emission emissions 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 emission emissions factors for leaking equipment (i.e. “leaker” factors). Us e of population count and default population emission emissions factors is required for smaller and inaccessible sources.
The hybrid approach results in a significantl y 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 follows below , Option 2 will enable EPA to monitor year-to-year changes in emission emissions levels from the petroleum and natural gas source category.
3.1.2.3 Option 3: Default Emission Factor Calculation emissions factor calculation for Both Combustion both comb ustion and Process Emissions process emissions Under Option 3, EPA would require petroleum and natural gas facil ities to base theirreported 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 previously above , EPA evaluated a variety of options for each dimension of the GHG reporting program , and selected a recommended option for each dimension. A summary of We 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 em issions from any other source category3-5 covered by the finalized GHG reporting rule MRR that may be present at the facility. A facility that emits 25,000 MtCO 2 e metric tons CO 2 e /year or more reports all sources for which there are methods in the finalized GHG reporting rule MRR and final rule for Subpart subpart 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 preamble Preamble , 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 combination Combination 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 that which are smaller, or are may be inaccessible for to direct measurement , will be quantified through the use of l eak detection and app lication of leaker emission emissions factors for leaking equipment. Population count and population emission emissions factors will be used for smaller and inaccessible

sources.

– EPA also requires source Source -specific calculation methods using facilityspecific information for other sources in the finalized GHG reporting rule MRR 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 3-1 Table 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 follows below : 1. A 1,000

- MtCO 2 e threshold; hybrid methodology

. 2. A 10,000

- MtCO 2 e threshold; hybrid methodology

. 3. A 25,000

- MtCO 2 e threshold; hybrid methodology

. 4. A 100,000

- MtCO 2 e threshold; hybrid methodology

. 5. A 25,000

- MtCO 2 e threshold; direct techniques (CEMS, flow meters, calibrated bagging, and high volume sampler) are used to measure emissions

. 6. A 25,000

- MtCO 2 e threshold; default emission emissions factors (simplified methods)
are used to measure emissions

.
The evaluation of the alternativ e reporting scenarios will allow policymakers policy 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, source s, 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 incr emental 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 cat egory, the number and types of production3-7 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 Subpart subpart 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 ch aracterization 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 metering Metering and regulating Regulating (M&R) stations. (b) Emissions reported separate ly for standby equipment; (c) Report activity data for each aggregated source type as follows: (1) Count of emission emissions sources. (2) Type of emission emi ssions 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 ga s 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. Each The 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 em issions from all source categories, including those source categories that do not exceed the applicable threshold. Formatted: Indent: Left: 0", First line: 0"4-2 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 combusti on-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 the aggregate costs for process and combustion emissions , above those covered by Subpart C alone.

EPA W e first provides provide 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 co st 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” co sts to meet reporting requirements. Specifically, EPA assumes we assum e that there will be additional co sts for any detection, sampling , and testing requirements in the methods used to quantify emissions from petroleum and natural gas

sources. EPA We are also assumes assuming 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 reco rds. The only signif icant element that EPA knows we 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. Formatted: Indent: Left: 0", First line: 0"

Formatted: Indent: Left: 0", First line: 0"4-3 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 emission emissions 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 emission emissions 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 as including :

– Monitoring monitoring (private): staff hours to operate and maintain emission emissions monitoring systems

. ;

– Reporting reporting (private): staff hours to gather and process available data and reporting it to EPA through electronic systems

. ; and

– Assuring assuring 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 emission emissions monitoring activities at a the 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 Formatted: Indent: Left: 0", First line: 0"

Formatted: Font: Italic4-4 employee compensation (comprising the basic wages and the corresponding benefits) and the overhead costs to the employer 20

. 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 basi c 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 has we 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 em ployee compensation. For the purposes of this analysis, EPA has we have also adopted the same overhead loading factor that Cody Rice (2002) used in her wage rate calculations. Thus the overhead loading factor that EPA we 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 th e 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 an d 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 7 seven 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 ot her equipments, organizational support, etc.) required for and used by the employee to effectively fulfill his/he r job responsibilities. These costs are over and above the employee compensation costs. Formatted: Font: Not Italic

Formatted: Font: Italic

Formatted: Font: Not Bold4-5 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 emission emissions 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 leve ls. Any natural gas tran smission 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 f acility. To determine the national cost from each segment, EPA we assigned a model facility cost that best fit the facility based on its emission emissions profile. Next, EPA we 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 varia tion 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 Formatted: Font: Italic

Formatted: Indent: Left: 0", First line: 0" Formatted: Font: Bold, Italic4-6 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 LNG Liquefied Natural Gas Storage 54 41 33 4 LNG Liquefied 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 two 2 hours overseeing the monitoring process per quarter , but are assumed not to perform any of the monitoring. It was assumed that junior en gineers and contracted technicians will do all of the monitoring, except in cases wh ere senior operators will log an y 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 one 1 hour and that will not Formatted: Keep with next, Keep lines together Formatted Table

Formatted: Font: Bold, Italic4-8 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 emission emissions source counts assigned to each of the model facilities to de termine 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 emission emissions monitoring.

Table 4

- 3 Table 4-3 below 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 Costs a (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 re porting unit/facility are $12,099 for the first year and $5,16 8 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 Field Code Changed Field Code Changed

Formatted: Font: Bold Formatted: Font: Bold Formatted: Font: Bold Field Code Changed Formatted: body text,bt,body tx,indent,flush,memo body text, Indent: First line: 0", Space After: 0 pt, Line spacing: single4-9 segment like in Table 4-3 Table 4

- 3 or and Table 4-4 Table 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 mon itoring emissions and archiving of information consist of purchasing equipment for emission emissions detection (or the portion of contractor purchases of equipment is apportioned to all its customers), emission emissions 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. E quipment leak monitoring does not have time-tested standards and equipment leak streams typically are not clean gas. For example, a centrifugal compressor wet seal degass ing 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 10 ten -year equipment life associated with long-standing, proven practices of measuring clean fuel streams a ssumed in the stationary combustion section.

Table 4-4 Table 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 re quired 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 because since the port can be installed when the compressor is either in standby mode or under maintenance. No Hence 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 Costs a (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 testing b n/a n/a n/a n/a n/a n/a Field Code Changed

Field Code Changed Formatted: Check spelling and grammar

Field Code Changed Formatted: Check spelling and grammar Formatted: Font: Bold, Italic

Field Code Changed4-10 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 low small 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 calculatio n 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 thes e 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 ha ve 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 the The costs to monitor and report incremental combustion-related emissions were estimated based on the approach used under 40 CFR part Part Formatted: Font: Bold, Italic4-11 98, subpart Subpart 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 CO 2 emission factor, a default high heating value of the fuel, and the annual fuel consumption from company records. EPA determined that entities that ne ed to report incremental combustion

- related emissions, as described above, would use the Tier 1 method as s et forth in Subpart C; these entities would likely not meet the requirements fo r 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 (HHV s) 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 ther mal 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 CFR Part 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 MtCO2e metric 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 Com bustion 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 EPA

HQ

- OAR

- 2008

- 0508

- 0004, U.S. EPA, Technical Support Document for Stationary Fuel Combus tion 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, di stillate fuel, and any pr oducts 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 segments Of these fuels , equipment using produced pipeline quality natural gas , distillate fuel, or products recovered from equipment leaks and vents are normally required to use Tier 2 methodology or higher. However, as As described previously above , 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 si ze would already be subject to reporting and would not be included in the incremental combustion emission emissions 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, r eporters 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 methodology costs for incremental combustion is a reasonable assumption for costing the subpart W rule

.4-13 Ta ble 4

- 3 Subpart W Petroleum and Natural Gas Systems: Labor Costs 1 (2006$)

Activity Estimated Labor Hours and Annual Labor Rates Labor Cost per Year per Reporting Unit/Facility Senior Management Middle Mana gement 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 $ 1 2 , 099 for the first year and $ 5 , 168 for the s ubsequent years.
Table 4

- 4 Subpart W Petroleum and Natural Gas Systems: Capital and O&M Costs 1 (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 testing 2 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
s ubsequent y ears. 2 Performance testing is not r equired 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 emission emissions reporting as applicable to an individual facility: 1,000 metric tons of CO 2 equivalent ( MtCO 2 e ) per year; 10,000 MtCO 2 e per year mtCO 2 e ; 25,000 MtCO 2 e per year mtCO 2 e ; and 100,000 MtCO 2 e per year. mtCO 2 e. A threshold analysis was then conducted on each segment to determine which level of threshold was most suitable for each industry segment. CH 4 , CO 2 , and N 2 O 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 high er number and share of facilities and emissions are covered by the rule. As the threshold increas es, smaller numbers and shares of facilities and emissions are affected. Of significant note, 85 pe rcent of emissions are covered at the selected 25,000 -MtCO 2 e metric ton CO 2 e threshold, but only 9 percent of facilities need to report. Furthermore Further , 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 MtCO 2 e /Year ) Covered Emissions (Million MtCO 2 e /

Year ) Percent of Emissions Covered Year) Year) 1,000 MtCO 2 e/yr Threshold 30,241 12,622 42% 396 391 99%

10,000 MtCO 2 e/yr Threshold 30,241 4,400 15% 396 362 91%

25,000 MtCO 2 e/yr 30,241 2,786 9% 396 337 85% Formatted: Tab stops: Not at 0.61"
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Formatted Table4-15 Threshold

100,000 MtCO 2 e/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 CH 4 and CO 2 emissions, and combustion CH 4 , CO 2 , and N 2 O 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 emission emissions factors available from GRI/EPA ( 1996 ), , back

- calculating the natural gas consumption in engines, and finally applying a CO 2 emission emissions factor to the natural gas consumed as fuel. N 2 O 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 fr om 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 ap plied 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 Formatted: Heading 4 Char,l4 Char, Font: Italic
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Formatted: body text_psg, None, Indent: First line: 0", Space After: 0 pt, Line spacing: single, Don't keep with next4-16 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 th reshold is to identify a level at which the incremental emission emissions 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 emission emissions 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 subset s 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 cost s and total per-entity costs for th e first year and for subsequent years.

Table 4-7 Summary of National Costs and Costs per Representative Entity by Threshold (Million 2006$) a

Threshold (MtCO 2 e/yr) First

Year Process Costs b Cost
s 1 Subseq.- Subsequent Year Process Costs a Costs 1 First

Year Combustion Costs Subseq.- Subsequent

Year Combustion Costs First

Year 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. b 1 Reporting and recordkeeping Record

- keeping costs are included in process costs Process 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 a nd capital associated with establishing modifications to enable ongoing quantification of key emission emissions sources. They include This includes costs to install m easurement 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.
4.4.1 4.4.2 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 MtCO 2 e to 10,000 MtCO 2 e, to 25,000 MtCO 2 e, and finally to 100,000 MtCO 2 e. 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 that expects most facilities will to use them to make a reporting determination. As a first step, facilities would enter basic activity data, such as number of compressors and compressor cylinders well count and drilling activity , into the tool to roughly assess whether they exce ed the threshold. The screening results should allow many most facilities to make their threshold determination. Some However, s ome 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 be tter 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 th e petroleum and natural gas i ndustry, approximately 2,786 facilities would likely meet th e 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 th e 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 methodologie s in the rule to make a determination. The costs for this activity are outlined as follows: below

. Formatted: Font: 12 pt4-18 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

Se g ment 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 Formatted: Indent: First line: 0.5"

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Formatted: Keep with next, Keep lines together4-19 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 determina tion of the costs noted in this section.
STEP 1: Model Fac ility 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 emission emissions 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 co sts to its facilities that are closest to the appropriate level of the model f acility. 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 es timating monitoring costs. In this case, nonmonitoring costs were estimated using the mode l-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 fac ilities, except as noted in onshore production. For onshore natural gas processing, onshore natural gas transmission, underground natural gas storage, LNG storage, import and export facili ties and natural gas distribution, equipment and component counts for medium facilities were as signed the national aver age activity factors from the national inventory National 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 emission emissions source counts was as signed to a “large” facility. If illogical values, such as in the case of compressors in natural gas transmission compressor stations, resulted from the Formatted: Indent: Left: 0", First line: 0"
Formatted: Indent: First line: 0.5"4-20 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, BOEMRE MMS 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 than over 100 percent, %, it would predict a negative lower bound for emission emissions source counts. For these cases, expert judgment was used. Expert judgment was also used, where necessary, to adjust emission emissions 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 annua l 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 co st, on an annual basis. Labor will be required for product resear ch for monitoring instruments before actual purchase. Before actual monitoring takes place, labor will have to be devoted to the4-21 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 each Each 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 requir ed 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 cost s; reporting costs are applied uniformly across segments reporting to the rule.
b. Recurring reporting costs consist of labor necessary to document collected emission emissions data from equipment leak monito ring 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 co sts 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 consist consists of labor required to validate to the EPA results from emission the monitoring of emissions and the follow-up from of 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 their To classify the facilities into different sizes, total combustion, equipment leaked, and vented CO 2 , N 2 O, and CH 4 emissions from individual facilities , expressed in CO 2 e
. , were rank listed in an ascending order. Cumulative emissions for the facilities were calculated by adding summing the emissions of an the individual facility to thos e of the facilities before it in the ascending list. The cumulative emissions, in combination with the total emissi ons from all facilities, were used to assign facilities to the small, medium, and large category.      

 ions TotalEmiss Emissions Cumulative 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 than over 67 percent in the ranked list were identified as a large facilities. facility. Table 4-9 Table 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 more further 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, 2000 MMS GOADS Emission Inventory , Report & Lasser , 2006 0–33% 34%–67% 68%–100%

Facility Count BOEMRE, 2000 MMS GOADS Emission Inventory , Report & Lasser , 2006 3,036 191 8

Mean Emissions (MtCO 2 e) This Analysis 1,430 22,733 483,806 Operator/Company a 1 Not estimated Onshore Petroleum and Natural Gas Production b Production 2 Facility Percentile HPDI , 2006 0–33% 34%–67% 68%–100% Facility Count HPDI , 2006 22,275 194 41 Operator/Company HPDI , 2006 — — — Mean Emissions (MtCO 2 e) This Analysis 3,988 451,120 2,170,820 Onshore Natural Gas Processing Facility Percentile API, 2008 Impact Assessment of Mandatory GHG Control Legislation API Processing Report 0–33% 34%–67% 68%–100%

Facility Count c 3 API, 2008 Impact Assessment of Mandatory GHG Control Legislation API Processing Report 486 64 16

Operator/Company API, 2008 Impact Assessment of Mandatory GHG Control Legislation API Processing Report 166 28 10

Mean Emissions (MtCO 2 e) 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 (MtCO 2 e) This Analysis 21,293 98,738 210,829 Natural Gas Underground Storage Facility Percentile EIA, 2006. Underground Storage Field Level Data EIA 0–33% 34%–67% 68%–100%

Facility Count EIA, 2006. Underground Storage Field Level Data EIA 325 50 22
Operator/Company EIA, 2006. Underground Storage Field Level Data EIA 102 37 17 Formatted Table

Formatted: Font: Italic

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Formatted: Font color: Black Formatted: Font color: Black4-24 Segment Data Source Small Facilities Medium Facilities Large Facilities Mean Emissions (MtCO 2 e) This Analysis 12,404 82,199 183,936 LNG Storage Facility Percentile GTI. 2007. The World Energy Source Book GTI 0–33% 34%–67% 68%–100%
Facility Count GTI. 2007. The World Energy Source Book GTI 141 12 4 Operator/Company GTI. 2007. The World Energy Source Book GTI 141 11 3 Mean Emissions (MtCO 2 e) 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 (MtCO 2 e) 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 (MtCO 2 e) This Analysis 5,840 167,066 536,719
Notes:

a The BOEMRE 2000 Gulfwide Emissions Inventory 1 MMS 2007 statistics reports 2,525 3,923 offshore platforms and

86 139 operators. No data are available for individual offshore platforms and their respective operators.
b 2 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.

c 3 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 mo nitoring, 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 Rate a 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 emission emissions sources. Interfaces between middle manager and senior operator to collect information and complete reports. $71.03/hour Formatted Table

Formatted: Indent: Left: 0", First line: 0"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 Co mpensation (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 4-11 Table 4

- 11

. below

. Since the petroleum and natural gas industry hourly rates are pays 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 ro le of the labor categories were taken into consideration. Table 4-12 summarizes these roles. Table 4-12 Responsibilities for Regula tion 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 Company a Com pany 1 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 Some 1 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 t able 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 Formatted Table

Formatted: body text,bt,body tx,indent,flush,memo body text, Space After: 0 pt, Line spacing: single, Tab stops: Not at 0"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 progr am; 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 Monitori ng and Allocation of Labor Hours

Element Onshore Responsibilities by Labor Category and Hours per Responsibility Detection Quantification Applicable Segments Onshore Facility Equipment Leaks Senior operator Operator 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 management Management 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 Formatted: Font: Not Bold

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Formatted Table4-28 Element Onshore Responsibilities by Labor Category and Hours per Responsibility Detection Quantification Applicable Segments medium facility, and 3 hours/ large facility) Middle management Ma nagement 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 management Management 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 management Manage ment 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 management Management 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 Table4-29 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 management Management 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 team Team 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 Table4-30 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 Table4-31 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 emission emissions 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 Table4-32 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 emi ssions from their operations. Specifically, the MMS GOADS program requires the monitoring of GHG emissions from platforms in state the Gulf of Mexico Federal waters

. Facilities under this f inal r ulemaking are required to report the same emissions data cal culated 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 federal Federal waters outside the Gulf of Mexico, GHG emissions will have to be estimated using the BOEMRE MMS GOADS procedures. EPA estimates the reporting cost for non-GOADS platforms to be $5,000 for first year of reporting. Formatted Table4-33 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 emission emissions monitoring.
4.5.3 Annualizing Capital Costs Cost Annualization and Determining O&M Costs The capital costs related to monitoring emissions and archiving of information consists of purchasing equipment for emission emissions detection, emission emissions measurement, and information storage. All costs are reported in 2006 U.S. dollars , and annualization was assumed over an equipment life of five 5 years with a 7 -percent % interest rate. From these factors, a capital recovery factor of 24 percent % was calculated using the formula provided as follows below :

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 annu al 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 emission emissions 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 Table4-34 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, 449 a 449 1

a Annual 1 Annual 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 emission emissions detection methods vary depending on the size of the comp any and its facilities. In the case of companies with small operations and few facilities, the cost s 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 pi pe 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 dete rmining 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 fac ilities that can be serviced (as determined the number of labor hours required to monitor a facility) each year, as shown in the equation as follows below :                  Contractor Serviced Facilities Contractor t ofEquipmen Equipment tal AnnualCapi Facility tal AnnualCapi # $ $

The travel, lodging, and shipping costs asso ciated 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 Table4-35 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 repo rting threshold. Average cost per facility was then determined by dividing th e 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 5-1 Table 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 emission emissions -based threshold of 25,000 MtCO 2 e metric tons CO 2 e for each facility and a hybrid of direct measurem ent 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 fo r 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 co mmunity, responding to inquires from affected facilities on monitoring and ap plicability requirements, and deve loping tools to assist in determining applicability. In addition to to tal national costs for petroleum and natural gas systems, EPA we also reports report average cost

- per
- metric

- ton to support additional analysis of the mandatory reporting programs. These costs are also shown on Table 5-1 Table 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 me tric 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 MtCO 2 e $/Mt $Million Million MtCO 2 e $/Mt 2006 2006 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. 13 a 13 1 $19.01 337.4 $0. 05 a 05 1 Public Sector, Total Total 2 $1.1 337.4 $0.003 $1.1 337.4 $0.003 TOTAL $62.9 337.4 $0. 13 b 1 3 3 $20.11 337.4 $0. 05 b 0 5 3 Note:

a 1 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).

b 2 Source: EPA 3 Excludes reporting determination for non-reporters; based on public sect or 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 thresholds floors on several emission emissions 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 equipmen t-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 5-2 Table 5

- 2 summarizes these changes based on year

one 1 costs for equipment leaks and vented emissions , and Table 5-3 Table 5

- 3 summarizes these changes based on subsequent

- year costs for equipment leaks and vented emissions. Formatted: Normal

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Formatted: Font: Not Bold Formatted: Font: Not Bold Formatted: Font: Bold5-3 Table 5-2 Equipment Leaks and Vented Emission Emissions Costs, Petroleum and Natural Gas Systems, First

- Year Estimates

Source Covered Emissions Cost Cost (MtCO 2 e) Million (2006$) (2006$/metric ton)
April Apr.

2009 Proposed

Rule April Apr. 2010 Proposed

Rule Final Rule April Apr. 2009 Proposed

Rule April Apr. 2010 Proposed

Rule Final Rule April Apr. 2009 Proposed

Rule April Apr. 2010 Proposed

Rule Final Rule Original Six Segments a Segments 1 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

a 1 Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG storage; LNG import/export.

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

- Year Estimates

Source Covered Emissions Cost Cost (MtCO 2 e) Million (2006$) ($/metric ton)
April Apr.

2009 Proposed

Rule April Apr. 2010 Proposed

Rule Final Rule April Apr. 2009 Proposed

Rule April Apr. 2010 Proposed

Rule Final Rule April Apr. 2009 Proposed

Rule April Apr. 2010 Proposed

Rule Final Rule
Original Six Segments a Segments 1 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

a 1 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 capit al 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 emissi ons threshold to make a reporting determination. Formatted Table5-4 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 Cost b ($Million) Annualized Cost c ($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 estim ates are conservative and should be viewed as an upperbound because the determination costs were applied at th e facility-level rather than the company-level. For example, for offshore production, determ ination 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 detail s 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 emission emiss ions threshold, EPA we compared the incremental emissions reported with the incremental costs (associated with the chan ge in the facilities that would be required to report their emissions). Similarly, in se lecting the reporting methodology option, EPA we compared the change in uncertainty with the change in costs associated with different emission5-5 measurement/estimation techniques. The metrics used and the results of the cost-effectiveness analysis are discussed in the following information below

. In addition, the final rule requires the determination of onshore reporting to be done with the assumption assuming 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 w ould affect the total emissions reported as well as cost, and is evaluated in the following sections below

. Six alternative options were therefor e evaluated for this analysis. While the Agency believes that we believe these alternatives represent the most likely variations in the selected option, EPA recognizes we 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 diffe rent 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 th e estimates of numbers of covered entities atvarious thresholds, form the basis for this analysis. Two metrics are used to evaluate the costeffectiveness of the emission emissions threshold. The first is the average cost per metric ton of emissions reported. The second metric for evaluatin g the threshold option is the marginal cost of additional reported emissions ($/ MtCO 2 e metric ton CO 2 e ) relative to the option adopted in the final rule. To compute this metric, EPA computed we compute the change in emissions reported by lowering or raising the threshold and divided divide this by the change in total reporting costs. Table 5-5 Table 5

- 4 provides the cost-effectiveness analysis for the various thresholds.
Table 5- 5 4 Summary of Threshold Cost-Effectiveness Analysis (First Year ); ): Selected Hybrid Option Is is 25,000 MtCO 2 e metric tons CO 2 e 1 Formatted: Caption5-6 Threshold (MtCO 2 e) Facilities Required to

Report Total Costs (Million 2006$) Downstream Emissions Reported (Million MtCO 2 e/ year) Percentage of Total Downstream

Emissions Reported Average Reporting Cost a Cost (2006$/Mt) Cost Differential a ,b Differentia l 1 (2006$/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 c osts ($/Mt): 1 ,000 metric tons CO 2 e = $0.38; 10,000 metric tons CO 2 e = $0.22; 25,000 metric tons CO 2 e = $0.18; and 100,000 metric tons CO 2 e = $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 MtCO 2 e metric ton s CO 2 e 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 are is presented for subsequent years in Table 5-6 Table 5

- 5

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

Threshold (MtCO 2 e) Facilities Required to

Re p ort Total Costs (million 2006 $/ $ /

y ear) Downstream Emissions Reported (Million MtCO 2 e) Percentage of Total Downstream

Emissions Re p orted Average Reporting Cost a Cost (2006$/Mt) Cost Differential a ,b Differentia l 1 (2006$/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 de termination costs results in th e following average reporting co sts ($/Mt): 1 ,000 metric tons CO 2 e = $0.19; 10,000 metric tons CO 2 e = $0.08; 25,000 metric tons CO 2 e = $0.06; and 100,000 metric tons CO 2 e = $0.04. b Cost difference relative to 25,000

- metric

- ton threshold

Table 5-7 Table 5

- 6 summarizes costs to report process and combustion emissions for all segments at four thresholds. Formatted Table

Formatted: Not Superscript/ Subscript

Formatted: Font: Not Bold, Superscript5-7 Table 5- 7 6 Subpart W Cost Estimates by Threshold

Threshold First Year Subsequent Years Million 2006$ $/Mt Million 2006$ $/Mt 1,000 MtCO 2 e $136.35 $0.35 $71.60 $0.18 10,000 MtCO 2 e $61.57 $0.17 $29.48 $0.08 25,000 MtCO 2 e $43.39 $0.13 $18.43 $0.05 100,000 MtCO 2 e $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 tota l 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 Formatted: Keep with next, Keep lines together Formatted: Keep lines together5-9 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 pr ovide the same estimate of total emissions by reporting facility. The However, the methods proposed for monitoring emissions will differ , however, in their precision in estimating actual emi ssions. 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. This In 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-lev el estimates, and in the other option, direct measurements are required for all sources. EPA uses We use the terms “ term direct measurement ” and “population factors” as shorthand to describe alternative options. For Subpart W, population emission factors and component count are is the basis for “default factors .” ”. Estimated costs for each monitoring method are shown in Table 5-8 Table 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 rule MRR 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 involv e 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- 8 7 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 emission em issions factors developed by the Gas Research Institute and EPA ( GRI/EPA ( 1996) as the basis for estimates of CH 4 and noncombustion-related CO 2 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 approach Hybrid 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. Based However, b ased 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 emission emissions determination would be very poor. Population-based factors determine the potential for emissions , assuming a percentage of known components that which may leak based on previous (and dated) studies.

The final

- rule

- required option of using leak detection as well as and a hybrid of spot direct measurement, engineering estimate s, leaker emission factors, and population

- based factors (for inaccessible sources) provides an emission emissions 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”) Formatted: Keep with next, Keep lines together

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Formatted: Indent: Left: 0", First line: 0"5-11 assumes that the number of entit ies would remain relatively constant. Thus, the analysis assumes a stable population where all entities subject to Subpa rt W bear a single first-year cost and then repeated subsequent-year costs.

In However, 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 firs t-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 are is due to labor associated with reviewing the regulation and pl anning 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 pla nning first-year labor costs be necessary.
The reviewing and planning costs are minimal in comparison to the significant other first

year 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 petroleu m and natural gas producers will report for each hydrocarbon basin. A basin is as identifi ed 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 5-9 Table 5

- 8 and Table 5-10 Table 5

- 9 below show a detailed emission emissions coverage and burden to reporter that would have been expect ed under a field-level facility definition. Formatted: Font: Not Bold Formatted: Font: Not Bold5-12 Table 5- 9 8 Emission Emissions Coverage and Entities Reporting for Field

- Level Facility Definition (Onshore Production)

Threshol d Level Emissions Covered Facilities Covered Million MtCO 2 e/ Metric

ton s CO 2 e/ 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- 10 9 Equipment Leaks, Vented, and Combustion Emission E missions Cost for Field

Level 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 emission emis sions coverage at different thresholds for the field- an d 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 -MtCO 2 e metric tons CO 2 e 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 -MtCO 2 e metric tons C O 2 e threshold, at which field-level is lower. Emission However, emissions coverage at the 100,000 -MtCO 2 e CO 2 e threshold under a field-level definition is very low , however —42 percent. Finally, the number of Formatted: Keep with next, Keep lines together

Formatted Table

Formatted: Font: 12 pt Formatted: Line spacing: At least 18 pt Field Code Changed5-13 entities reporting at a 25,000 -MtCO 2 e metric tons CO 2 e 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 Reported2006$/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 would will 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 it us to indicate whether the Agency EPA can certify the rule as not having a SISNOSE. The elements of this analysis included :

– Identifying identifying affected entities under Subpart W

. ,

– Selecting selecting and describing the measures and economic impact thresholds used in the analysis

. , and

– Determining a determining SISNOSE certification category.
5.2.1 Identifying Identify 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 St atistics of U.S. Businesses (SUSB) data provide provide s 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 Formatted: Line spacing: At least 18 pt
Formatted: Keep with next, Keep lines together

Formatted: Indent: Left: 0", First line: 0"5-14 Advocacy of the Small Business Administration (SBA) (SBA, 2008a). The data include the number of establishments ( Table 5-11 Table 5

- 10 ), employment ( Table 5-12 Table 5

- 11 ), and receipts ( Table 5-13 Table 5

- 1 2 ) and present information on all entities in an industry covered by Subpart W of the rule; however, many of these en tities 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 cens us 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, di vidends, 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 fo rms 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 assumes we assume in this analysis that the “enterprise” definition above is consistent with the concept of ultimate pare nt company that is typically used for Small Business Regulatory Enforcement Fair ness Act (SBREFA) screening analyses , and the terms are used interchangeably. EPA We also reports report the SBA size standard(s) for each industry group in order to facilitate comparisons and different thresholds.5-15Table 5-1110Number of Establishments by Affected Industry and EnterpriseaSize: 2002SBA SizeStandard(effectiveMarch 11,2008)TotalEstablishmentsOwned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees20 to 99Employees100 to 499Employees<500to 749Employees<500to749Employees750 to 999Employees1,000 to1,499EmployeesOnshore petroleum andnatural gasproduction; offshorepetroleum and naturalgas production;onshore natural gasprocessing211 Crude Petroleum and NaturalGas Extraction500 7,629 5836 456 292606,5846,5846064 31Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 Pipeline Transportation ofNatural Gasb1,936 81 27 6116936361692 20Natural gas distribution 221210 Natural Gas Distribution 500 2,897 483 86 131700686870033 73aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified 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 annualpayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment ofall associated establishments.BecauseSincethe SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company,EPA assumeswe assumein this analysis that theenterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small BusinessRegulatory Enforcement Fairness Act (SBREFA)screening analyses.bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts.Formatted:Font: 9 pt5-16Table 5-1211Number of Employees by Affected Industry and EnterpriseaSize: 2002SBA SizeStandard(effectiveMarch 11,2008)TotalEmployeesOwned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees20 to 99Employees100 to 499Employees<500to 749Employees<500to 749Employees750 to 999Employees1,000 to1,499EmployeesOnshore petroleum andnatural gasproduction; offshorepetroleum and naturalgas production;onshore natural gasprocessing211 Crude Petroleum andNatural Gas Extraction500 88,280 19,336 12,113 11,65643,1052,4212,42143,1053,551 1,061Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 Pipeline Transportation ofNatural Gasb37,450 347 157 1,0531,834cc1,934ccNatural gas distribution 221210 Natural Gas Distribution 500 86,890 1,956 1,899 4,3988,4201,9601,9608,4202,631 5,014aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified 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 annualpayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment ofall associated establishments.Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company,EPA assumeswe assumein this analysis that theenterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small BusinessRegulatory Enforcement Fairness Act (SBREFA)screening analyses.bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts.cThe U.S. Census Bureau has missing data for this employee range.Formatted:Font: 9 pt5-17Table 5-1312Receipts by Affected Industry and EnterpriseaSize: 2002SBA SizeStandard(effectiveMarch11, 2008)TotalReceipts($Million)Owned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees($thousands)20 to 99Employees($thousands100 to 499Employees($thousands)<500to 749Employees($thousands)<500to 749Employees($thousands)750 to 999Employees($thousands)1,000 to1,499Employees($thousands)Onshore petroleum andnatural gas production;offshore petroleumand natural gasproduction; onshorenatural gas processing211 Crude Petroleum andNatural Gas Extraction500 $160,879 $7,573 $6,790 $9,609 $23,9724,609$4,60923,972$3,991 $2,805Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 Pipeline Transportationof Natural Gasb$35,897 $1,035 $106c$394c$2,566cc$2,566ccNatural gas distribution 221210 Natural Gas Distribution 500 $67,275 $2,524 $4,642 $2,878 $13,127865$86513,127$2,116 $3,757aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified 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 annualpayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment ofall associated establishments.Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company,EPA assumeswe assumein this analysis that theenterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small BusinessRegulatory 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. The receipts for the1oneto 20 range therefore underestimate true value.Formatted:Font: 9 ptFormatted:Font: 9 pt5-18 5.2.2 Developing Develop 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 EPA us 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 EPA us to account for differences in establishment r eceipts 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 1,49 9 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 recei pts for enterprises within several employment categories 24 (first

- year costs: Table 5-14 Table 5

- 13 ; subsequent

- year costs: Table 5-15 Table 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.

23 Metrics The following metrics for other small

- entity economic impact measures (if applicable) would potentially include :

 Small governments (if applicable): “Revenue” test; annuali zed compliance cost as a percentage of annual government

revenues.

 Small non-profits (if applicable): “Expenditure” test; annua lized compliance cost as a percentage of annual operating

expenses. 24 The ratios for For the 1 one 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 co st-to-sales ratios (e.g., 1.22% for NAICS 211).

### 5-19Table 5-1413Establishment Sales Tests by Industry and EnterpriseaSize: First-Year CostsSBA SizeStandard(effectiveMarch 11,2008)AverageCost PerEntity($1,000/entity)AllEnterprisesOwned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees20 to 99Employees100 to 499Employees<500to 749Employees<500to 749Employees750 to 999Employees1,000 to 1,499EmployeesOnshore petroleum andnatural gas production;offshore petroleum andnatural gas production;onshore natural gasprocessing211 Crude Petroleum andNatural GasExtraction500$17.1 0.08% 1.32% 0.11% 0.05% 0.47%02%0.02%47%0.03% 0.02%Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 PipelineTransportation ofNatural Gasb$15.70.08% 0.12% 0.40%c0.24%c0.10%cc0.10%c cNatural gas distribution 221210 Natural GasDistribution500 $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 werespecified under common ownership or control. The enterprise and theestablishment are the same for single-establishment firms. Eachmulti-establishment company forms one enterprise—the enterpriseemployment and annual payroll are summed from the associatedestablishments. 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 anestablishment’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 SmallBusiness 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 consistentwith 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 receiptsfor these categories underestimate true value.

### 5-20Table 5-1514Establishment Sales Tests by Industry and EnterpriseaSize: Subsequent-Year CostsaThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified 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 annualpayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment ofall associated establishments.Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company,EPA assumeswe assumein this analysis that the enterprisedefinition above is consistent with the concept of ultimate parent company that is typically used for Small Business RegulatoryEnforcement Fairness Act (SBREFA) screeninganalyses.bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts.cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receiptsfor these categories underestimate the true value,which results in conservative estimates of cost-to-sales ratios.SBA SizeStandard(effectiveMarch 11,2008)AverageCost PerEntity($/entity)AllEnterprisesOwned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees20 to 99Employees100 to 499Employees<500to 749Employees<500to 749Employees750 to 999Employees1,000 to1,499EmployeesOnshore petroleum andnatural gas production;offshore petroleum andnatural gas production;onshore natural gasprocessing211 Crude Petroleum andNatural GasExtraction500$7.5 0.04% 0.58% 0.05% 0.02% 0.21%01%0.01%21%0.01% 0.01%Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 PipelineTransportation ofNatural Gasb $6.90.04% 0.05% 0.18%c0.11%c0.05%cc0.05%c cNatural gas distribution 221210 Natural GasDistribution500 $9.2 0.04% 0.18% 0.02% 0.04% 0.05%07%0.07%05%0.01% 0.02%Formatted:Font: 9 ptFormatted:Font: 9 ptFormatted:Font: 9 pt5-21 5.2.3 Results of Screening Analysis The Regulatory Flexibility Act generally requir es 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 subs tantial 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, EPA we 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 -MtCO 2 e metric ton of CO 2 e 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, EP A has concluded that this action will not have a significant economic impact on a substantial number of small entities. As shown in Table 5-14 Table 5

- 13 and Table 5-15 Table 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 single singly family owning a few production wells) that are highly unlikely to cross the 25,000 -MtCO 2 e metric tons CO 2 e 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 smal l 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 threshold 20 employee category subject to the final rule

. 5.3 Synopsis of Benefits
Under the Mandatory mandatory GHG Reporting Rule, reporting rule EPA requires the collection to collect and verification of emission verify emissions data from Subpart W facilities. This section reviews the benefits of a mand atory reporting program for Subpart W facilities based on previous experience with emission emissions inventory programs in the United States and abroad.
Recent policy discussions have highlighted pote ntial 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 making the ability of the public to make petroleum and natural gas facilities accountab le for their equipment leaks and vented emissions. A GHG reporting system will also have the benefit of providing policymakers policy makers and analysts with a data set that is co mprehensive 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, which disclosure that provides firms with incen tives to reduce emissions voluntarily , and provides emission emissions data to service industries, such as insurance and financial markets. Availability of emission emissions 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. Accu rate and transparent information is necessary for the implementation of efficient appr oaches that meet environmental goals with the lowest cost to the economy. Formatted: Indent: Left: 0", First line: 0"6-1 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 Mandatory mandatory GHG Reporting Rule reporting 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 therefor e subject to Office of Management and Budget (OMB) review and the requirements of the EO. The Order defines “signific ant 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 envir onment, 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 im pact 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 O rder 12866, it has been determined that this f inal r ule is a “ significant regulatory action” because it raises novel legal or policy issues arising out of legal mandates, the President’s priorities, or the Formatted: Space After: 0 pt

Formatted: body text_psg

Formatted: No bullets or numbering
Field Code Changed

Formatted: ___GHG PARAGRAPH, Adjust space between Latin and Asian text, Adjust space between Asian text and numbers Formatted: Font: Times New Roman6-2 principles set forth in the EO

. . Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO Executive Order 12866.

However, this action is not an “economically significant regulatory action” under EO 12866 because it is un likely to have an annual economic effect of $100 million or mor e. Nonetheless, EPA has prepared this analysis of the potential costs and benefits associated with this action.

In the economic analysis , EPA has identified the regulato ry options considered, their costs, and the emissions that would likely be report ed 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 6 2 million during the first year of the program and 19 mi llion in subsequent years . The analysis also estimates about $ 1. 1 million of annual programmatic costs for EPA.

. In addition, EPA has conducted a quali tative 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 industry systems , 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 Field Code Changed Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman

Formatted: No bullets or numbering Formatted: Font: Times New Roman

Formatted: ___GHG PARAGRAPH, Line spacing: 1.5 lines Formatted: Font: Times New Roman

Formatted: Font: Times New Roman, Underline Formatted: Font: Times New Roman Formatted: Font: Times New Roman, Underline Formatted: Font: Times New Roman Formatted: Font: Times New Roman, Underline Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: ___GHG PARAGRAPH, Line spacing: 1.5 lines Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman6-3 actions that facilities are al ready taking to reduce emissions. Additionally, EPA will be able to track the trend of emissions from facilities within the petroleum and natural gas industry systems over time, particularly in response to policies and potential regulations. The data collected by this rule will improve EPA’s ab ility to formulate climate change policy options and to assess which segments of the petroleum and gas industry systems would be affected, and how these segments systems would be affected by the options. This information collection is mandat ory and will be carried out under CAA section Sections 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 part Part 2. However, emissions data information collected under CAA section Sections 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 respondents in 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

.

25 Although 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 pre amble, EPA is initiating a separate notice and comment process to make CBI determ inations for the data collected under this rulemaking. EPA intends to issue this notice in early 2010, and will in clude in the notice the data proposed for collection in this rulemaking 26 Burden is defined at 5 CFR 1320.3(b). These cost nu mbers 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. Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman6-4 ). Burden is defined at 5 CFR Part 1320.3(b). These cost numbers differ from those shown elsewhere in the EIA for these subparts Economic 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 subparts Economic Impact Analysis for the first year of the rule an d 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 A gency to administer the program. The ICR focuses on differentiates between respondent burden , while the EIA includes both national compliance costs and the burden for EPA to implement the rule cost 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 displa ys a currently valid OMB control number. The OMB control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR part Part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part P art 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in this the 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 signifi cant 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 im pacts of this final rule on small entities, small entity is defined as: (1) A a 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 Formatted: ___GHG PARAGRAPH, Indent: First line: 0", Space After: 0 pt, Line spacing: 1.5 lines Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman

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Formatted: Font: Times New Roman Formatted: ___GHG PARAGRAPH, Line spacing: 1.5 lines Formatted: Font: Times New Roman6-5 organization that is any not-for-profit enterprise that which is independently owned and operated and is not dominant in its field.

First, EPA examined the effect of Subpart W on small businesses usin g 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 comput e 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 1,00 0 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 o f these methods.
These sales tests examine the average establishment’s total annualized mandatory reporting costs to the average establishment recei pts for enterprises within several employment categories

. The average entity costs used to compute the sale s 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, b ecause the reporting costs are likely lower than average entity estimate s provided by the engineering c ost analysis.
EPA believes the selected thresholds maximi ze the rule coverage with o ver 85 percent of all U.S. petroleum and natural gas systems emissions reported by approximately 2, 786 reporters, while keeping reporting bur den to a minimum and excluding small emitters. Furth ermore, many Subpart W industry stakeholders with whom EPA met expressed support for a 25,000 metric ton of CO 2 e threshold because it sufficiently captures the majority of GHG emissions in the United Stat es while excluding smaller facilities and sources. After considering the economic impacts impact of this final action the rule on small entities, I certify EPA has concluded that this action will not have a significant economic impact on a substantial number of small entities. Formatted: Font: Times New Roman

Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman Formatted: Font: Times New Roman6-6 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 percen tage of sales and determ ines 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 presumed the se gments that may be likely to have small businesses covered by the reporting program. It is important to note th at this analysis does not screen out entities that would be below the reporting threshold. Although the costs to r eceipts 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 mtCO 2 e 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 addition Second , EPA determined that the final rulemaking would not have a significant impact on small governme ntal jurisdictions. EPA determined that one segment of the petroleum and natural gas industry might incl ude small governments affected by the final Formatted: ___GHG PARAGRAPH, Line spacing: 1.5 lines Formatted: Font: (Default) Times New Roman Formatted: Font: Times New Roman

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revenues.

Third, EPA concluded that the f inal r ulemaking 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 allows is proposing different monitoring methods for different emissions s ources, 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 establishing is proposing annual instead of more frequent reporting.

Through comprehensive outreach activities prior to proposal of the initial rule original

MRR , EPA held approximately 100 meetings and/or conference calls with representatives of the primary audience groups, including numerous trad e 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 initial original proposal, EPA posted a guide for small businesses on the EPA GHG reporting rule website Web 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 final April, 2010 proposed rule. EPA We continued to meet with stakeholders and en tered documentation of all meetings into the docket. Formatted: Font: Times New Roman

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Formatted: Font: Times New Roman6-8 During rule implementation, EPA would will 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 w ould be useful to small businesses. EPA intends to develop a range of compliance assistance tools and material s 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 pot ential impacts of the f inal r ule on small entities and welcome comments on issues related to such impacts.

6.4 Unfunded Mandates Reform Act
This The 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 regulator y actions on State, local, and tribal governments and the private segment. Unde r section 202 of UMRA, EPA ge nerally must prepare a written stateme nt, 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 alterna tive that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, sect ion 205 allows EPA to adopt an alternative other than the least costly, most cost

- effective or least bur densome alternative if the Administrator publishes with the final rule an explana tion why that alternative was not adopted.
Before EPA establishes any re gulatory requirements that may significantly or uniquely affect small governments, including T ribal gov ernments, 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 Formatted: Font: Times New Roman

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Formatted: No bullets or numbering6-9 and timely input in t he development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the re gulatory 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 sector segment 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 than beyond the existing regulations will not surpass $100 million

. in the aggregate in any year. Thus, this today's f inal rule is not subject to the requirements of sections 202 or and 205 of UMRA.

This f inal 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 CO 2 e 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 th at directly emits greenhouse gases above threshold levels. In addition, this
f inal r ule 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 f inal r ule is expected to be minimal. Formatted: ___GHG PARAGRAPH, Indent: First line: 0", Space After: 0 pt, Line spacing: 1.5 lines, Adjust space between Latin and Asian text, Adjust space between Asian text and numbers Formatted: Font: Times New Roman

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Formatted: Font: Times New Roman6-10 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 th e development of regulatory policies that have federalism implications . It will not .” “Policies that have federalism implications” is d efined in the executive order to include regulations that have “ substantial direct effects on the States states , on the relationship between the national government and the States states, or on the distribution of power and responsibilities among the various levels of government.”

This f inal r ule does not have F ederalism implications. It will not have substantial direct effects on the states, on the relationship be tween the national government and the states , or on the distribution of power and responsibilities among the various levels of government, as specified in EO Executive 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 States states or localities to collect GHG data and/or regulate GHG emissions. Thus, EO Executive Order 13132 does not apply to this action. f inal r ule

.
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), re quires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that ha ve 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 Formatted: No bullets or numbering

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. In a separate analysis, EPA researched additional available data to determine which tribal entities may own or oper ate petroleum and natural gas systems that could be impacted by this final action. As a result of those analysis analyse s , EPA found one tribe that may potentially be impacted by this final actio n. 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 program 40 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 cap acity of all stationary fuel combustion units at a facility is 30 million British therma l units per hour (mmBtu/hr) or greater, and the facility emits 25,000 metric tons of CO2e or mo re per year from all stationary fuel combustion

sources.
In addition, EPA sought opportunities to provide in formation 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: Consultation process of deve loping the Mandatory Reporting Program to permit them to have meaningful and Coordination with Indian timely input into its development. First, EPA sought opportunities to provide information to Tribal Governments governments and representatives during deve lopment of 40 CFR part 98, and in Part 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 , Formatted: Font color: Black

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Formatted: Font color: Black Formatted: Font color: Black Formatted: Font color: Black Formatted: Font color: Black Formatted: Font color: Black Formatted: Font color: Black Formatted: Normal, Indent: First line: 0.5", Line spacing: 1.5 lines, Don't adjust space between Latin and Asian text, Don't adjust space between Asian text and numbers Formatted: Font color: Black Formatted: Font color: Black Formatted: Font color: Black Formatted: Font color: Black Formatted: Font color: Black6-12 EPA staff provided information to tribes through conference calls with multiple Indian working groups and organizations at EPA that interact w ith 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 rul e 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 vari ous 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 pre pared a guidance sheet for Tribal governments on the p roposed r ule. It was posted on the MRR website and published in the Tribal Air Newsle tter. For a complete list of tribal contacts, see the “Summary of EPA Outreach Activities for Developing the Greenhou se Gas Reporting Rule,” in the Docket for this rulemak ing (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 news letter—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 Pr ogram, 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. Formatted: Font color: Black6-13 6.7 Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks This action is not subject to EO EPA interprets Executive Order 13045 (62 F.R. 19885, April 23, 1997) as applying only to those regulatory actions that concern heal th 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 intend ed 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 “signifi cant energy action” as defined in EO Executive 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 has we have concluded that this final rule is not likely to have any adverse energy effects.
This final rule proposal relates to moni toring, reporting , and recordkeeping at petroleum and gas facilities that directly emit over 25,000 mtCO 2 e and GHGs from petroleum and natural gas systems ; it does not impact energy supply, distribution or use. Therefore, EPA concludes we 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, samp ling 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. Formatted: No bullets or numbering, Tab stops: 0.5", List tab

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Formatted: Font: Times New Roman6-14 This f inal rulemaking involves provides 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 voluntar y consensus standards bodies, including the following: ASTM, ASME, ISO, Gas Processors Association, and American Gas Association. organizations

. These voluntary consensus st andards will help facilities monitor, report, and keep records of greenhouse gas GHG emissions. No new test methods were developed for this final rule. Instead, EPA reviewed from existing rules for source categories and voluntary greenhouse gas GHG programs and , EPA identified existing means of monitoring, reporting, and keeping records of greenhouse gas GHG 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 f inal r ule 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 mu ltiple 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 Federal federal executive policy on environmental justice. Its main provision directs Federal federal agencies, to the greatest extent practicable and pe rmitted 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. Formatted: Font: Times New Roman

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Formatted: Font: Times New Roman6-15 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 provide d to human health or the environment because ; it is a rule addressing information collection and reporting procedures. Formatted: Font: Times New Roman Formatted: ___GHG PARAGRAPH, Line spacing: 1.5 lines Formatted: Font: Times New Roman Formatted: Font: Times New Roman7-1 SECTION 7 CONCLUSIONS AND IMPLICATIONS

In this EIA E conomic Impact Analysis , EPA has examined the regulatory background, the development of the mandatory GHG meporting reporting rule for Subpart W, and estimated the costs and benefits of implementing this subpart. This section presents EPA’s our 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— threshold Threshold and monitoring methodology Monitoring Methodology —that were finalized in today’s rule. The final rule calls for:

– A a threshold of 25,000

- MtCO 2 e threshold for all facilities

. , and

– A a 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 developmen t of the proposal included the following: 1. A 1,000

- MtCO 2 e threshold; selected options for methodology, frequency, and verifier. 2. A 10,000

- MtCO 2 e threshold; selected options for methodology, frequency, and verifier. 3. A 100,000

- MtCO 2 e threshold; selected options for methodology, frequency, and verifier. Formatted: Indent: Left: 0", First line: 0"7-2 4. The measurement variable is changed to direct spot measurement; selected option for threshold. 5. The measurement variable is changed to default emission emissions factors; selected option for threshold.
7.1.2 Affected Source Categories EPA considered direct emitters of equipm ent 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 Be nefits of the Mandatory Greenhouse Gas GHG Reporting Rule
7.2.1 Estimated Costs and Impacts of the Mandatory Greenhouse Gas GHG Reporting Program Under the final rule, EPA estimates that 2,786 entities would be covered by Subpart W of the rule, directly emitting 337 million Million MtCO 2 e 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 EP A 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 es timate 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 emission emissions inventory programs. Formatted: Indent: Left: 0", First line: 0", Tab stops: 0.5", List tab7-3 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 making the ability of the public to make facilities accountable for their emissions. Bene fits to petroleum and natural gas industry include identifying the identification of GHG reduction opportunities and disclosing information disclosure , which provides firms with incenti ves to reduce emissions voluntarily , and provides emission emissions data to service industries, such as insurance and financial markets. A GHG reporting system will also have the benefit of providing policymakers policy 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 EIA economic 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-t o-know laws concerning emissions

. ;

– More information will to enable citizens to negotiate directly with emitters. polluters; and

– More information will to enable environmentally aware consumers to alter their consumption habits based on GHG emissions of producers.

– Industry

– Public relations: Having having independent, verifiable data to present to the public would demonstrate appropriate environmental stewardship.7-4 – Standardization: Uniform uniform industry standards would reduce the cost of reporting relative to non-uniform, jurisdic tion-specific, and allow facilities to benchmark their performance against other similar facilities.

– Potential cost savings: Mandatory mandatory monitoring may uncover previously unmeasured wasteful proces ses, yielding cost-saving conservation opportunities that would offset some of the costs of monitoring.

– Potential customer data for service industries: Information information about GHG-emitting firms will be useful for firms that market emission emissions

reduction technologies, and to insu rance 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 w ould reduce the difficulties associated with comparing across different reporting standards across states or programs.

– Compliance and policy evaluation: Publ icly 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 Formatted: Indent: Left: 0", First line: 0"7-5 percent of 2007 gross domestic product. GDP. Thus, despite the ov erall national costs, macroeconomic impacts are not anticipated, and EP A does not believe that the final rule will impose significant economic impacts on a su bstantial number of small entities.

A review of the literature enabled EPA us to characterize the expected types of benefits, which will be experienced by stakeholders, in cluding 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

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