Economic Impact Analysis for the

Mandatory Reporting of Greenhouse

Gas Emissions Under Subpart W Final

Rule (GHG Reporting)

   

Final Report

November 2010

i 

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 .................................................. 1-6 

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

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

1.3.1 Establishing Baseline and Years of Analysis ........................................... 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 ............................................................... 1-13 

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 ................................................ 2-10 

2.3.4 Other EPA Emission Inventories ........................................................... 2-11 
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2.3.5 State and Regional Voluntary Programs for Greenhouse Gas 

Emission Reporting ................................................................................ 2-11 

2.3.6 State and Regional Mandatory Programs for Greenhouse Gas 

Emission Reporting and Control ............................................................ 2-12 

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

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

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

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

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

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

4.2.2 Reporting Costs ........................................................................................ 4-2 

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

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

4.3.2 Labor Costs .............................................................................................. 4-6 

4.3.3 Capital and O&M Costs ........................................................................... 4-7 

4.3.4 Combustion Costs .................................................................................... 4-9 

4.4 Summary Results: Subpart W—Petroleum and Natural Gas Systems ................ 4-11 

4.4.1 Detailed Threshold Analysis .................................................................. 4-12 

4.4.2 Reporting Determination ....................................................................... 4-14 

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

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

4.5.1 Determining Labor Categories ............................................................... 4-21 

4.5.2 Allocating Responsibilities .................................................................... 4-22 

4.5.3 Annualizing Capital Costs and Determining O&M Costs ..................... 4-28 
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Section 5 Subpart W Analysis of Reporting Rule Options .................................................... 5-1

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

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

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

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

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

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

5.2.1 Identifying Affected Segments and Entities .......................................... 5-12 

5.2.2 Developing Small-Entity Economic Impact Measures .......................... 5-17 

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

5.3 Synopsis of Benefits ............................................................................................. 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 ...................................................................................... 6-1 

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

6.4 Unfunded Mandates Reform Act ........................................................................... 6-5 

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

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

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

6.7 Executive Order 13045: Protection of Children from Environmental Health 

and Safety Risks ..................................................................................................... 6-7 

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

Distribution, or Use ................................................................................................ 6-8 

6.9 National Technology Transfer Advancement Act ................................................. 6-8 

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice 

in Minority Populations and Low-Income Populations ......................................... 6-9 

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

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

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

7.2 Assessment of Costs and Benefits of the Mandatory Greenhouse Gas 

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

7.2.1 Estimated Costs and Impacts of the Mandatory Greenhouse Gas 

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

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

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

Section 8 Sources Consulted ..................................................................................................... 8-1
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LIST OF FIGURES 

Page

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

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

Figure 5-2 Summary of Basin vs. Field Decision .................................................................... 5-12 

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LIST OF TABLES 

Page

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

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

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

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

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

Table 4-2 Number of Facilities Reporting by Threshold and Industry Segment ...................... 4-5 

Table 4-3 Subpart W Petroleum and Natural Gas Systems: Labor Costs (2006$) ................... 4-7 

Table 4-4 Subpart W Petroleum and Natural Gas Systems: Capital and O&M Costs(2006$) 4-8 

Table 4-5 Subpart W Petroleum and Natural Gas Systems: Combustion Costs (2006$) ....... 4-11 

Table 4-6 Subpart W Facilities and Emissions Covered by Final Rule .................................. 4-11 

Table 4-7 Summary of National Costs and Costs per Representative Entity by Threshold ... 4-13 

Table 4-8 Summary of Reporting Determination Costs per Segment by Threshold .............. 4-15 

Table 4-9 Allocation of Facilities to Model Types ................................................................. 4-19 

Table 4-10 Labor Categories and Hourly Rates ........................................................................ 4-21 

Table 4-11 Loaded Hourly Rates for Goods-Producing Private Establishments ...................... 4-21 

Table 4-12 Responsibilities for Regulation Compliance by Labor Category ........................... 4-22 

Table 4-13 Responsibilities for Monitoring and Allocation of Labor Hours ............................ 4-23 

Table 4-14 Monitoring Program Compliance Capital Costs and Other O&M ......................... 4-29 

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 .................................................................................. 5-2 

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

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

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

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

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

Table 5-6 Subpart W Cost Estimates by Threshold .................................................................. 5-6 
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Table 5-7 Analysis of Alternative Monitoring Methods ........................................................... 5-9 

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

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

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

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

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

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

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

Table 5-13 Establishment Sales Tests by Industry and Enterprise Size: First-Year Costs ....... 5-18 

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

Costs ....................................................................................................................... 5-19 
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ACRONYMS AND ABBREVIATIONS 

API American Petroleum Institute 

ARP accidental release prevention 

BLS Bureau of Labor Statistics 

BOEMRE Bureau of Ocean Energy Management, Regulation, and Enforcement 

 

CAA Clean Air Act 

CARB California Air Resources Board 

CBI confidential business information 

CEMS continuous emission monitoring system 

CCAR California Climate Action Registry 

CFR Code of Federal Regulations 

CH4 methane 

CMOP Coalbed Methane Outreach Program 

CO2 carbon dioxide 

CO2e carbon dioxide-equivalent 

CRF capital recovery factor 

ERMR Essential Requirements for Mandatory Reporting 

DOD Department of Defense 

DOE Department of Energy 

DOT Department of Transportation 

EGU electric generating unit 

EIA Economic Impact Analysis 

EO executive order 

EPA U.S. Environmental Protection Agency 

ERMR Essential Requirements for Mandatory Reporting 

FAQ frequently asked questions 

FERC Federal Energy Regulatory Commission 

FR Federal Register 

GHG greenhouse gas 

GOADS Gulfwide Offshore Activity Data System 

GoM Gulf of Mexico 

GRI Gas Research Institute 

HHV high heating value 

ICR information collection request 

IPCC Intergovernmental Panel on Climate Change 

LDC local distribution company 
x 

LMOP Landfill Methane Outreach Program 

LNG liquefied natural gas 

M&R metering and regulating 

MMBtu million British thermal units 

MMS Minerals Management Service 

MtCO2e metric tons of carbon dioxide-equivalent 

MW megawatt 

NAICS North American Industry Classification System 

NEI National Emissions Inventory 

NESHAP National Emissions Standards for Hazardous Air Pollutants 

NTTAA National Technology Transfer and Advancement Act of 1995 

O&M operations and maintenance 

OECD Organisation for Economic Co-operation and Development 

OMB Office of Management and Budget 

PFC perfluorocarbon 

PRTR pollutant release and transfer registers 

PSD Prevention of Significant Deterioration 

QAPP Quality Assurance Project Plan 

QA/QC quality assurance/quality control 

OAQPS Office of Air Quality Planning and Standards 

R&D research and development 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

SBA Small Business Administration 

SBREFA Small Business Regulatory Enforcement Fairness Act 

SF6 sulfur hexafluoride 

SISNOSE significant impact on a substantial number of small entities 

SUSB Statistics of U.S. Businesses 

TCR The Climate Registry 

TRI Toxics Release Inventory 

TSD Technical Support Document 

UMRA Unfunded Mandates Reform Act 

UNFCCC United Nations Framework Convention on Climate Change 

U.S.C. United States Code 

USDA U.S. Department of Agriculture 

WBCSD World Business Council for Sustainable Development 
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WCI Western Climate Initiative 

WRI World Resources Institute 
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Disclaimer 

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

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

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

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

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

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

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

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

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

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

recommendation for use. 

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

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

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

statute or regulation, this document would not be controlling. 
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SECTION 1

INTRODUCTION AND BACKGROUND 

1.1 Background 

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

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

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

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

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

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

require mandatory reporting of [greenhouse gas] GHG emissions above 

appropriate threshold in all segments of the economy. 

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

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

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

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

Administrator deems it appropriate. The Administrator shall determine 

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

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

discretion to use existing reporting requirements for electric generating units 

under Section 821 of the Clean Air Act. 

EPA signed the final mandatory GHG reporting 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 data from two additional segments in the petroleum and natural gas source 

category. EPA also released an Economic Impact Analysis (EIA) in April 2010 that assessed the 

proposed rulemaking’s costs and benefits.1

 

 

1

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

(GHG Reporting); see www.epa.gov/climatechange/emissions/subpart/w.html. 
1-2 

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

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

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

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

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

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

equivalent (MtCO2e) process emissions, or, on average, $0.16/MtCO2e. This cost compares with 

the estimate of $0.38/ MtCO2e under the April 2009 proposal.2

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

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

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

2010 notice proposed hybrid methodologies to quantify GHG emissions from eight segments in 

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

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

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

significant and not enough reliable data are available to develop emission factors). The bulk of 

emissions will be quantified using engineering calculations based on actual facility or field data 

and using leak detection and “leaker” factors3. There are also some sources that would use 

population-based factors—often referred to as default factors—primarily for inaccessible sources 

or relatively small leaking sources. Consistent with the April 2010 proposed rulemaking and the 

Technical Support Document (TSD) (EPA-HQ-OAR-2009-0923-0027), the final rule and 

economic analysis use population-based factors. In addition, EPA finalized the proposal to use 

the MMS4

 Gulfwide Offshore Activity Data System (GOADS) process for collecting data from 

offshore production platforms. This approach leverages an existing GHG data collection process 

and minimizes burden. 

Today’s final rule includes several key changes that affect compliance cost estimates. 

First, the final rule provides equipment thresholds on several emission sources. Reporters will 

 

2

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

threshold determination and $3.3 million for combustion emission 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 quantification requires actual detection of a leak before application of a factor. This 

method provides a truer assessment of actual emissions than “population” emission factors, which are based on 

simple population count. The population count provides an estimate of “potential” emissions because it assumes a 

percentage of leaking components. 

4

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

Regulation, and Enforcement (BOEMRE). 
1-3 

use simple population-based emission factors for sources below the equipment threshold. 

Second, EPA has simplified the requirement for sampling of gas and emissions for many of the 

emission 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 reporting, 

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

emission costs for reporters changed from $0.36/MtCO2e in the April 2009 proposed rule to 

$0.28/MtCO2e in the April 2010 proposal, and to $0.33/MtCO2e 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/MtCO2e in the first 

year, which is less than the first year cost of $0.21/MtCO2e 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 that meet the emission 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 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 MtCO2e expected to be reported under Subpart C, 83.5 million MtCO2e are 

the combustion emissions from petroleum and natural gas facilities that would not have reported 

in the absence of Subpart W. The incremental combustion emission reporting is $3.3 million per 

year of the total combustion emission cost, or $0.04/MtCO2e. 

First-year 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 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 

 

5

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

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

year global warming potential from the Intergovernmental Panel on Climate Change (IPCC). Also, subsequentyear costs are the average of costs subsequent to first-year costs and thereby represent a “steady-state” time period. 
1-4 

installation of ports in vent lines for compressors and well equipment in the first year to enable 

spot measurement of emissions using devices such as vane anemometers. This is a one-time cost 

associated with reporting start-up; the only cost in subsequent years for those sources is to 

physically take spot measurements. 

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

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

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

is better understood in the industry. In sum, today’s final rule defines emissions from the 

petroleum and natural gas industry as follows: 

1) Vented emissions, which include intentional or designed releases of methane 

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

(not including stationary combustion flue gas) from emission 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 leaks, which mean those emissions that could not reasonably pass 

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

3) Flare combustion emissions, which include CH4, CO2, and nitrous oxide (N2O) 

emissions resulting from combustion of gas in flares. 

1.2 Role of the Economic Impact Analysis in the Rulemaking Process 

1.2.1 Legislative Authority and Context 

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

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

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

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) 

 

7

 The joint explanatory statement refers to “Section 821 of the Clean Air Act,” but Section 821 was part of the 1990 

CAA Amendments and was not codified into the CAA itself. 
1-5 

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

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

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

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

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

, determining if any 

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

standard, or “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)9. 

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

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

set forth in” Section 114[a]) and the reach of the phrase “carrying out any provision” of the 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. Thus, for example, 

utilizing Section 114, EPA could gather information relevant to carrying out provisions 

involving research (e.g., Section 103[g]); evaluating and setting standards (e.g., 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 

emissions from light-duty vehicles, “Light-Duty Vehicle Greenhouse Gas 

Emission Standards and Corporate Average Fuel Economy Standards,” (75 FR 

25324, May 7, 2010). 

 Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases 

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

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

Determine Pollutants Covered by Federal Prevention of Significant Deterioration 

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

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

 

8

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

“Hazardous Air Pollutants”; and Section 129 contains provisions for “solid waste combustion.” 9

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

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

information related to those areas. 
1-6 

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 and this final rulemaking do not indicate that EPA has 

made any final decisions on these other actions; however, the mandatory GHG reporting 

program will provide EPA, other government agencies, and outside stakeholders with economywide data on facility-level (and in some cases corporate-level) GHG emissions, which could 

assist in future policy development. 

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

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

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

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

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

continue to do so. Through data collected under this rule, EPA, states, 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 understanding of the factors that influence GHG emission 

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

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

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

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

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

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

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

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

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

associated with a range of reporting thresholds. 

This EIA 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. 
1-7 

EPA presents this EIA for Subpart W—Petroleum and Natural Gas Systems—pursuant to 

Executive Order 12866, the guidelines of Office of Management and Budget (OMB) Circular A4, and EPA’s Economic Guidelines10. These documents contain guidelines for assessing the 

benefits and costs of the selected regulatory option, as well as options that are more stringent or 

less stringent. Section 4 of the EIA presents the costs of the final rulemaking; Section 5 

summarizes the cost-effectiveness analysis of the program and also qualitatively describes the 

benefits of the final rulemaking. 

1.2.3 Illustrative Nature of the Analysis 

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

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

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

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

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

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

of baseline conditions and estimated costs of compliance. 

1.3 Overview and Design of the Economic Impact Analysis 

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

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

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

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

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

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

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

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

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

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

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

conclusions and findings. 

1.3.1 Establishing Baseline and Years of Analysis 

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

emissions for the petroleum and natural gas source category, productive capacity, existing 

 

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

circulars/a004/a-4.pdf. 
1-8 

emission monitoring, and reporting activities for this industry. While EPA recognizes that 

economic growth and changes in the structure of the economy over time will likely result in 

changes in both emissions and costs for those covered by Subpart W, attempting to project these 

changes would lead to an increased level of uncertainty without conveying comparable 

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

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

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

collected by the rule would greatly enhance future estimates. 

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

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

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

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

available information on segments and specific sources. 

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

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

during development of the rule to analyze 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, to reduce the burden of reporting for all parties 

involved. The TSD documents EPA’s 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 review of state mandatory GHG rules and how they treat 

equipment leak emissions from the petroleum and natural gas industry. 

EPA’s overall rulemaking approach began with identifying anthropogenic sources in the 

U.S. GHG Inventory and Intergovernmental Panel on Climate Change (IPCC). The rule would 

require reporting of CO2 and CH4 equipment leak and vented emissions, as well as combustionrelated emissions11 of CO2, CH4, and N2O as defined in the rule. The IPCC focuses on CO2, CH4, 

and N2O for both scientific assessments and emission inventory purposes because these are longlived, 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 

 

11 Only flaring emissions are required for reporting under this subpart of the GHG reporting rule. All other 

combustion-related emissions are to be reported under Subpart C of the finalized GHG reporting rule. 
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EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks, and are the common focus of the 

climate change research community. 

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

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

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

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

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

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

measurement and reporting methods for this final rulemaking. 

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

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

the list of source categories included in the proposal: 

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

minimizing the number of reporters. 

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

EPA identified source categories that would be required to report. EPA 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. The 

reporting methodologies identified fall into several categories, including continuous emission 

monitoring, calculating emissions based on site-specific information, and calculating emissions 

based on default emission factors. In general, for 40 CFR Part 98, EPA selected a combination of 

continuous emission monitoring and calculations based on site-specific information. 

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

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

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

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

 

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. 
1-10 

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

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

sources that must be directly quantified. While direct spot measurement is still required to 

develop site or equipment-specific emission factors for some major sources, much of the 

emission 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 MtCO2e/year 

o 10,000 MtCO2e/year 

o 25,000 MtCO2e/year 

o 100,000 MtCO2e/year 

– Methodology for measuring emissions: 

o Direct spot measurement 

o Facility-specific calculation methods 

o Leaker and default emission factors 

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

for the rule. 

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 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 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 are the 

major changes reflected in the April 2010 proposed rulemaking for Subpart W: 
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– Two additional petroleum and natural gas system segments were added: onshore 

production and natural gas distribution. These segments represent the largest 

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

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

system source category. 

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

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

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

emissions directly spot measured was reduced to 6 percent. 

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

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

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

estimates based on facility data were 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 

“population” factors based on component counts). 

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

minor equipment leak sources and also sources that are inaccessible or 

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

factors was minimized. 

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

GOADS emission results for offshore platforms in federal Gulf of Mexico (GoM) 

waters to avoid redundancy of reporting efforts.13 EPA also required that facilities 

not covered by GOADS (state waters and federal non-GoM platforms) use data 

collection and emission calculation methods in accordance with the BOEMRE 

GOADS program to reduce burden and make emission reporting consistent across 

the segment. 

 

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

federal waters in the Western Gulf of Mexico, developed by MMS (now called BOEMRE). The MMS mandated 

that all 2,525 offshore operators in the Gulf of Mexico conduct annual surveys (in 2000 and 2005) of their GHG 

and other hazardous pollutants. MMS collects activity data from each platform that is then used to estimate 

emissions. The usual cycle for this data collection effort has been once in every three to four years. 
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In addition to the Subpart W-specific changes above, the changes affecting all subparts of 

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

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

less than 25,000 MtCO2e for five years to cease annual reporting to EPA. 

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

less than 15,000 MtCO2e for three years to cease annual reporting to EPA. 

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

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

annual reporting to EPA. 

– Added a provision in 40 CFR 98.3 for submitting 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) activities from reporting under 40 

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

– Revised the requirements of the designated representative in 40 CFR 98.4 to align 

them with those in 40 CFR 75 (accidental release prevention [ARP] regulations). 

– Changed record retention to three years instead of five 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] at proposal). 

– Revised several definitions in 40 CFR Part 98, 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 

spot measurements. 
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1.3.2.2 Summary of the Major Changes From the 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 for separators, and dehydrators such that sources 

below the equipment threshold use a simplified population emission factor 

approach and sources above the equipment threshold use actual monitoring. 

– Onshore production compressors use emission factor approach for estimating 

process emissions; actual monitoring is not required. 

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

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

years, beyond which only changes have to be reported. 

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

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

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

count of equipment within a facility. 

– For onshore production, population emission factors will be applied to major 

equipment rather than individual components. 

– Sampling is not required for estimating combustion emissions, determining the 

composition of natural gas, or assessing tank vapors; best available estimates are 

acceptable. 

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

toxic vapor analyzers, in addition to using infrared devices. 

These changes significantly reduce burden and simplify emission reporting. 

1.3.3 Evaluating Costs and Benefits 

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

dimensions identified 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 MtCO2e reported. This cost-effectiveness metric was considered in combination 

with other important factors such as the potential impacts on small entities and consistency with 
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other CAA or state-level 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 coverage. 

– Threshold: 25,000 MtCO2e/year 

– The thresholds for the finalized GHG reporting rule fall generally into three 

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

W, a facility that emits 25,000 MtCO2e/year or more reports all sources for 

which there are methods specified in the rule. 

– Subpart W facilities determine their applicability by comparing their 

emissions to a threshold of 25,000 MtCO2e/year. 

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

and equipment leaks and stationary combustion-based emissions. 

– 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 factors. 

– Source-specific engineering calculation methods using facility-specific 

information for other sources at the facility. 

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

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

equipment leaks or inaccessible sources. 
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SECTION 2

REGULATORY BACKGROUND 

The intent of this rule is to collect accurate and timely GHG emission data that can be 

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

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

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

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

Agency’s overall rulemaking approach, sources considered, and summarize the review of GHG 

monitoring protocols for each petroleum and natural gas system used by federal, state, regional, 

and international voluntary and mandatory GHG programs, and EPA’s 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 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 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 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 for the final rulemaking is specific to Subpart W, petroleum and natural gas 

systems. 

To these ends, EPA identified the following goals of the mandatory reporting system: 

– Obtain data that are of sufficient quality that they can be used to support a 

range of future climate change policies and regulations. 
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– Balance the rule coverage to maximize the amount of emissions reported 

while minimizing reporting from small emitters. 

– Create reporting requirements that are consistent with existing GHG reporting 

programs by using existing GHG emission estimation and reporting 

methodologies to reduce reporting burden, where feasible. 

2.1.2 Developing the Rule 

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

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

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

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

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

issued in today’s final rule. 

2.1.3 Evaluating 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 performed a comprehensive review of existing voluntary and mandatory GHG 

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

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

documents specifically related to the petroleum and natural gas source category include: 

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

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

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

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

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

Mexico, and New Jersey. 

– Reporting protocols developed by nongovernmental organizations, such as the 

World Resources Institute/World Business Council for Sustainable Development 

(WRI/WBCSD). 

– Programs from industrial trade organizations, such as the American Petroleum 

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

Gas Industry. 
2-3 

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

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

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

to be reported and/or retained. EPA 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 subparts may be found in the docket at EPAHQ-OAR-2008-0508-054. 

2.1.4 Conducting Stakeholder Outreach to Identify Reporting Issues 

Early in the development process of the GHG reporting rule, 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 associations and firms in potentially affected industries/segments. 

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

planning organizations. 

– State and regional organizations already involved in GHG emission reporting, 

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

Initiative (WCI). 

– Environmental groups and other nongovernmental organizations. 

– U.S. Department of Interior, which has a program relevant to GHG emissions. 

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

timetable for developing a rule and encouraged stakeholders to provide input on key issues. 

Examples of topics discussed included existing GHG monitoring and reporting programs and 

lessons learned, thresholds for reporting, schedules for reporting, scope of reporting, handling of 

confidential data, data verification, and the role of states in administering the program. As 

needed, the EPA technical workgroups followed up with these stakeholder groups on a variety of 

methodological, technical, and policy issues. EPA staff also provided information to tribes 
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through conference calls with different Indian tribal working groups and organizations at EPA as 

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

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

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

period ended on June 9, 2009. Subpart W received comments from more than 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 4,000 

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

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

2.1.5 Considering 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 40 substantive written public 

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

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

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

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

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

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

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

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

2.1.6 Analyzing Emissions 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 frameworks, estimated emissions of GHGs, and 

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

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

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

rule for Subpart W with respect to the size of the entity required to report and the type of 

 

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 

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

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

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

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

2.2 Sources Considered 

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

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

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

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

identified in Table 2-2. 

Table 2-1 Sources of GHG Emissions Considered 

Source Subpart W: GHG Emissions Considered 

Downstream 

Direct emitters Stationary and portable combustion: Sources considered include stationary 

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

steam boilers, and heaters). 

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

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

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

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

device emissions. 

Equipment leaks: Emissions that 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 hydrocarbons, including CH4, CO2, and N2O 

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

extraction, processing, storage, and transport of fossil fuels to the point of final use. 
2-6 

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 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 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 and 

state programs during development of the rule. Documentation of EPA’s review of GHG 

monitoring protocols for each source category used by federal, state, and international voluntary 

and mandatory GHG programs, and EPA’s review of 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 methodologies contained in state reporting 

programs such as TCR, the California Climate Action Registry (CCAR), and 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 calculations to multiple programs, if desired. EPA will continue to work 

closely with states and state-based groups to ensure that the data management approach in this 

rule will lead to efficient submission of petroleum and natural gas data to multiple programs. 
2-7 

The intent of this rule is to collect a reasonable estimate of GHG emission data that can 

be used to inform future policy decisions. One goal in developing the rule is to be consistent with 

the GHG protocols and requirements of other state and federal programs, where appropriate, in 

order to make use of existing cooperative efforts and reduce the burden to petroleum and natural 

gas facilities submitting reports to other programs. EPA also needs to be sure, however, that the 

mandatory GHG reporting rule collects facility-specific vented and equipment leaks data of 

sufficient quality to achieve the Agency’s objectives. Therefore, some reporting requirements of 

this rule related to petroleum and natural gas equipment leaks are different from other federal 

and state programs. 

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

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

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

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

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

(SF6). 

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

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

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

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

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

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

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

methods for its emission estimates. 

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

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

Department of Transportation (DOT), the Department of Defense (DOD), and the State 

Department. 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, 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 emissions and uses top-down national energy data 
2-8 

and other national statistics. To achieve the goal of comprehensive national emission 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 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 contains estimates of vented emissions, equipment leaks, and combustion 

emissions from petroleum systems and from natural gas systems, which are both IPCC source 

categories. Regarding the quantification of CH4 emissions from natural gas systems, reductions 

achieved through the Natural Gas STAR program and National Emissions Standards for 

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

these programs). A detailed study by the Gas Research Institute (GRI)15 and EPA (GRI/EPA 

1996) is used as the basis for estimates of CH4 and non-combustion-related CO2 emissions from 

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

For petroleum and 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 levels. The final rule for Subpart W is estimated to significantly 

increase the level of emissions covered than are included in the 2008 U.S. Greenhouse Gas 

Inventory Report by reflecting improved estimates of emissions from key sources such as well 

liquid unloadings, well workovers, well completions and compressor wet seal degassing vents. 

These estimates are based on publicly available information from the EPA Natural Gas STAR 

Web site 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 and natural gas systems by improving the estimates of 

emissions and thereby advance the understanding of emission processes and monitoring 

methodologies. Facility, unit, and process level GHG emission data for all sources will improve 

the accuracy of future U.S. Greenhouse Gas Inventory Reports by confirming the national 

statistics and emission estimation methodologies used to develop the top-down inventory. The 

results can confirm shortcomings in the national statistics and identify where adjustments may be 

needed. 

 

15 Now the Gas Technology Institute 
2-9 

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

to produce the comprehensive annual national 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 and 

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

voluntary programs encourage emission reductions, clean energy, or energy efficiency; this 

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

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

GHG emission inventories or reporting of GHG emission reduction activities for sources that 

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

2.3.2.1 Non-CO2 Voluntary Partnership Programs 

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

aimed at reducing emissions from GHGs such as CH4, SF6, and PFCs. There are four segmentspecific 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 reduction partnerships for high-global-warmingpotential gases. The program specific to those entities that fall under Subpart W is the Natural 

Gas STAR partnership, which encourages companies across the natural gas and petroleum 

industries to adopt practices that reduce methane emissions. Industry partners voluntarily provide 

technical information on projects they undertake to reduce methane emissions on an annual 

basis, but they do not submit methane emission inventories. 

2.3.2.2 1605(b) Voluntary Registry 

The DOE Energy Information Administration 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, 2006 (71 FR 

20784); the rule is contained in 10 CFR Part 300. Unlike EPA’s proposal, which requires 

reporting of GHG 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 reduction projects to the registry. Large emitters (e.g., anyone that emits over 

10,000 MtCO2e per year) who wish to register emission reductions must submit annual 

company-wide GHG emission inventories following technical guidelines published by DOE and 
2-10 

must calculate and report net GHG emission 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, 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 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 reporting 

rule. Industry participation in the programs and reporting to the programs is entirely voluntary. A 

small number of sources report, compared to the number of facilities that will likely be affected 

by Subpart W of the mandatory GHG reporting rule. Most of the EPA voluntary programs do not 

require reporting of annual emission data, but are instead intended to encourage GHG reduction 

activities and track partners’ successes in implementing such projects. 

At the same time, aspects of the voluntary programs serve as useful starting points for the 

mandatory GHG reporting rule. GHG emission calculation principles and protocols have been 

developed for various types of emission sources by Climate Leaders, the DOE 1605(b) program, 

and some partnerships such as the SF6 reduction partnerships and SmartWay. Under these 

protocols, reporting companies monitor process or operating parameters to estimate greenhouse 

emissions, report annually, and retain records to document their GHG estimates. Through the 

voluntary programs, EPA, DOE, and participating companies have 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 

The Toxics Release Inventory (TRI) requires facility-level reporting of annual mass 

emissions of approximately 650 toxic chemicals. When facilities—in a wide range of industries, 

such as manufacturing industries and the petroleum industry—emit these chemicals above 
2-11 

established thresholds, they report. Facilities must submit annual reports of total stack and 

equipment leaks of the listed toxic chemicals using a standardized form that can be submitted 

electronically. No information is reported on the processes and emission 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 sources. The TRI 

program is similar, however, to the mandatory GHG reporting rule in that it requires direct 

emission 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 Inventories 

2.3.4.1 National Emissions Inventory 

EPA compiles the National Emissions Inventory (NEI), a database of air emission 

information provided primarily by state and local air agencies and tribes. The database contains 

information on stationary and mobile sources that emit criteria air pollutants and their precursors, 

as well as hazardous air pollutants. Stationary point source emissions that must be inventoried 

and reported are those that emit over a threshold amount of at least one criteria pollutant. Many 

states also inventory and report stationary sources that emit amounts below the thresholds for 

each pollutant. The point sources that NEI includes number more than 60,000 facilities. Required 

point source information consists of facility identification information as well as process 

information detailing the types of air pollution emission sources, air pollution emission estimates 

(including annual emissions), control devices in place, stack parameters, and location 

information. The NEI differs from the GHG reporting rule in that the NEI contains no GHG data, 

and the data are reported primarily by state agencies rather than directly reported by industries. 

In developing the rule, however, EPA used the NEI to help determine sources that might need to 

report under Subpart W of the GHG reporting rule. EPA considered the types of facility and 

process and activity data reported in NEI to support the emission data as a possible model for the 

types of data to be reported under the GHG reporting rule. 

2.3.5 State and Regional Voluntary Programs for Greenhouse Gas Emission Reporting 

A number of states have demonstrated leadership and developed corporate voluntary 

GHG reporting programs individually or joined with other states to develop GHG reporting 

programs as part of their approaches to addressing GHG emissions. The following discussion 

summarizes two prominent voluntary efforts. In developing the GHG rules, EPA reviewed the 

relevant protocols used by these programs as a starting point. The Agency recognizes that these 
2-12 

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 

CCAR is a voluntary GHG-registry already in use in California. CCAR has released 

several methodology documents, including a general reporting protocol, general certification 

(verification) protocol, and several segment-specific protocols. Companies submit emission 

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 

reporting; 2009 will be the last year it accepts such reporting. Emission 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 

TCR is a partnership formed by U.S. and Mexican states, Canadian provinces, and tribes 

to develop standard GHG emission measurement and verification protocols and reporting system 

capable of supporting mandatory or voluntary GHG emission reporting rules and policies for its 

member states. TCR has released a final General Reporting Protocol that contains procedures to 

measure and calculate GHG emissions from a wide range of source categories. It has also 

released a general verification protocol and an electronic reporting system. Several industryspecific 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 organizations that have agreed to voluntarily report their GHG 

emissions) implemented a pilot reporting program in 2008. Annual reports will be submitted 

covering six GHGs. Corporations must report facility-specific emissions broken out by type of 

emission source (e.g., stationary combustion, mobile combustion, process, equipment leak and 

indirect) and gas (CO2, CH4, N2O, HFCs, PFCs and SF6) within each facility. 

2.3.6 State and Regional Mandatory Programs for Greenhouse Gas Emission Reporting and 

Control 

Several individual states and regional groups of states have demonstrated leadership and 

are developing or have developed mandatory GHG reporting programs and GHG emission 

control programs. This section summarizes two regional cap and trade programs and several state 

mandatory reporting rules, which cover—or, for those programs still under development, have 

the potential to cover—the petroleum and natural gas segment. EPA recognizes that, like the 

current voluntary regional and state programs, state and regional mandatory reporting programs 
2-13 

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 

RGGI is a regional cap and trade program that covers CO2 emissions from electric 

generating units (EGUs) larger than 25 megawatts (MW) in member states in the Mid-Atlantic 

and Northeast. The program goal is to reduce CO2 emissions to 10 percent below 1990 levels by 

the year 2020. Certain types of offset projects will be allowed, and GHG offset protocols have 

been developed. The states participating in RGGI have adopted state rules (based on a model 

rule) to implement RGGI in each state. The RGGI cap and trade program took effect on January 

1, 2009. There has been some discussion of regulating additional sources of GHG emissions 

under the RGGI program in the future. 

2.3.6.2 Western Climate Initiative 

WCI is another regional cap and trade program being developed by a group of western 

states and Canadian provinces. The goal is to reduce GHG emissions to 15 percent below 2005 

levels by the year 2020. Draft options papers and program scope papers were released in early 

2008, public comments were reviewed, and final program design recommendations were made in 

September 2008. Other elements of the program, such as reporting requirements, market 

operations, and offset program development continue. WCI released its final version of the first 

group of Essential Requirements for Mandatory Reporting (ERMR) in July 2009, and it is 

anticipated that WCI jurisdictions will have rules implementing these reporting requirements in 

place for the 2010 reporting year or shortly thereafter. Petroleum and natural gas production 

facilities are not listed in the first reporting group, although petroleum refiners must report. 

Several source categories are being considered for inclusion in the cap and trade framework. One 

such category is “industrial process emission sources, including petroleum and natural gas 

process emissions”16, meaning that sources covered under Subpart W of the 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 

 

16 In the WCI design recommendations, process emissions are defined as including emissions from chemical, 

biological, and other non-combustion processes. These emissions may be deliberate (e.g., vented), fugitive (e.g., 

leaked), or accidental. 
2-14 

development. 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.17

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 states as of 2009; the rest will begin between 2010 and 2012. 

Reporting is typically annual, although some states require quarterly reporting for EGUs, 

consistent with RGGI. 

State rules differ with regard to which facilities must report and which GHGs must be 

reported. Some states require all facilities that must obtain Title V permits to report GHG 

emissions. Others require reporting for particular segments (e.g., large EGUs, cement plants, 

refineries). Some state rules apply to any facility with stationary combustion sources that emit a 

threshold level of CO2. Some apply to any facility, or to facilities within listed industries, if their 

emissions exceed a specified threshold level of CO2e. Many of the state rules apply to six GHGs 

covered by 40 CFR Part 98 (CO2, CH4, N2O, HFCs, PFCs, SF6); others apply only to CO2 or a 

subset of the six gases. Most require reporting at the facility level, or by unit or process within a 

facility. 

The level of specificity regarding GHG monitoring and calculation methods varies. Some 

of the states refer to use of protocols established by TCR or CCAR, to industry-specific protocols 

(such as methods developed by the American Petroleum Institute [API]), to accepted 

international methodologies such as IPCC, and/or to emission factors in EPA’s Compilation of 

Air Pollutant Emission Factors (known as AP-42) or other EPA guidance. 

2.3.7.1 California Mandatory Greenhouse Gas Reporting Rule 

The CARB mandatory reporting rule is an example of a state rule that covers multiple 

source categories and contains relatively detailed requirements, similar to this proposal 

developed by EPA. The regulation became effective on January 2, 2009. According to CARB, 

selected facilities (e.g. general stationary combustion facilities outside the petroleum-and-gas 

segment, and electricity generation and cogeneration plants not within the operational control of 

 

17 These are California, Colorado, Connecticut, Delaware, Hawaii, Iowa, Maine, Maryland, Massachusetts, New 

Jersey, New Mexico, North Carolina, Oregon, Virginia, Washington, West Virginia, and Wisconsin. 
2-15 

larger facilities and entities) are required to have filed their first emission data reports by April 1, 

2009. The rest of the facilities and entities are to have reported by June 1, 2009 (see 

www.arb.ca.gov/cc/reporting/ghg-rep/ghgschedadvisory.pdf). The rule requires facility-level 

reporting of all GHGs (except PFCs) from cement manufacturing plants, electric power 

generation and retail markets, cogeneration plants, petroleum refineries, hydrogen plants, and 

facilities with stationary combustion sources emitting greater than 25,000 MtCO2 per year. The 

California rule does not impact those facilities that would be subject to reporting under Subpart 

W of the 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 national and regional efforts, such as TCR 

and WCI, to assist with developing consistent reporting tools and procedures on a national and 

regional basis. 

3-1 

SECTION 3

DEVELOPMENT OF THE MANDATORY GHG REPORTING RULE 

To develop Subpart W of the Mandatory GHG Reporting Rule, EPA considered various 

dimensions of the reporting program and developed and evaluated several options for each 

dimension. After a preliminary evaluation of the options for each dimension, a recommended 

reporting program alternative was selected. Several possible program alternatives were selected, 

generally by varying one dimension at a time, while retaining the recommended option for the 

other dimensions. These alternatives were then evaluated based on estimated cost, costeffectiveness (cost per metric ton of emissions reported), and estimated impacts on small entities. 

This process is discussed in greater detail in the following sections. 

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 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 factors). 

The options EPA considered for each dimension for Subpart W sources are discussed in 

the following sections and summarized in 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 Developing Scenarios for Regulation Under Subpart W 

(Final Option Indicated by Shading) 

Methodology 

Direct 

Measurement 

(CEMS) 

Hybrid: Direct spot measurement 

for major emission sources and 

calculation methods for nonmajor sources 

Default 

emission 

factors from 

EPA 

Threshold 

Capacity-based 

Emissions based 1,000 

MtCO2e 

X X X 

Emissions-based 

10,000 MtCO2e 

X X X 

Emissions-based 

25,000 MtCO2e X X X 

Emissions-based 

100,000 MtCO2e X X X 

Hybrid: 25,000 

MtCO2e unless already 

reporting based on 

capacity under another 

program 

3.1.1 Thresholds 

Three options were considered in setting the threshold above which reporting of GHG 

emissions will be required for Subpart W: capacity-based thresholds, emission-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, EPA ruled out these two options based on data limitations 

and other challenges. 

3.1.1.1 Option 1: Capacity-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 the threshold might be a more straightforward way 

for facilities to know that they must report their GHG emissions, but the data on source-level 

capacity are not currently universally available to EPA. 
3-3 

3.1.1.2 Option 2: Emission-Based Threshold (Selected) 

Option 2 involves the use of actual facility-level emissions of GHGs, measured in 

MtCO2e. Various levels were considered, ranging from 1,000 MtCO2e to 100,000 MtCO2e. 

Obviously, lower thresholds would require more facilities to participate in the reporting program. 

Given current data availability, an emission-based threshold will generally focus on larger, 

emission-intensive sources in the petroleum and natural gas segment for which emission data are 

readily calculated or measured. 

3.1.1.3 Option 3: Hybrid Threshold 

The hybrid threshold option is a combination of three general groups: capacity, 

emissions, or entire source category (“all in”). The thresholds developed are generally equivalent 

to a facility-wide threshold of 25,000 MtCO2e per year of actual emissions. The preference is to 

establish thresholds for as many source categories as possible based on a capacity metric; for 

example, tons of product produced per year. A capacity-based threshold is least burdensome 

because a facility would not have to estimate emissions to determine if the rule applies. 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, in many of the petroleum and natural gas 

segments, the level of emissions from vented and equipment leaks are not related to capacity or 

throughput. Rather, emissions may be driven by design and operating factors. As an example, 

pneumatic controls on petroleum and natural gas facilities are designed to vent natural gas to 

drive valve movements. The level of venting is not dependent on throughput. 

3.1.2 Measurement Methodology 

EPA identified three measurement methodology options, ranging from installing 

emission monitoring equipment on all sources under Subpart W to using default emission factors 

to estimate emissions. The measurement methodology options considered for Subpart W sources 

are discussed in the following sections. 

3.1.2.1 Option 1: Direct Measurement for All Reporters 

This option would apply direct measurement requirements to all reporters. It would 

require facilities subject to Subpart W to use fuel-flow meters for gaseous fuels and for spot 

measurement of vented emissions from various equipment. In addition, it would require spot 

detection and quantification of equipment leaks by use of calibrated bagging or high-volume 

samplers throughout all segments. This option was the selected option for the proposed rule for 

Subpart W (74 FR 164888, April 10, 2009). 
3-4 

3.1.2.2 Option 2: Hybrid of Direct Measurement and Facility-Specific Calculation for Other 

Sources (Selected) 

EPA’s final rule required measurement methodology option for Subpart W is a hybrid of 

direct measurement and facility-specific calculations, which is considerably less burdensome 

than Option 1. Specifically, EPA requires the use of direct spot measurement, where reliable 

emission factors do not exist, as well as engineering calculations based on site-specific 

information to estimate emissions from the largest emission sources. Other sources will be 

quantified through the use of leak detection and application of emission factors for leaking 

equipment (i.e. “leaker” factors). Use of population count and default population emission 

factors is required for smaller and inaccessible sources. 

The hybrid approach results in a significantly lower cost burden to reporting parties yet 

provides a much more robust development of GHG emissions. Unlike Option 3, which is 

described in the section the follows, Option 2 will enable EPA to monitor year-to-year changes 

in emission levels from the petroleum and natural gas source category.

3.1.2.3 Option 3: Default Emission Factor Calculation for Both Combustion and Process 

Emissions 

Under Option 3, EPA would require petroleum and natural gas facilities to base their 

reported emissions on simplified calculations performed at the facility level, based on EPAprovided default population factors combined with the type of process, production rate, and/or 

the quantity of fuel/chemical inputs used. 

3.2 Selected Option 

As described previously, 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 

the recommended option for each dimension is provided as follows: 

– Threshold: Emission-based approach 

– For Subpart W sources, applicability is based on emissions. Emissions are the 

sum of vented emissions and equipment leaks, stationary and portable 

combustion emissions, as well as emissions from any other source category 

covered by the finalized GHG reporting rule that may be present at the 

facility. A facility that emits 25,000 MtCO2e/year or more reports all sources 

for which there are methods in the finalized GHG reporting rule and final rule 

for Subpart W. 
3-5 

– 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, 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 of direct measurement and source-specific 

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 are smaller, or are inaccessible for direct measurement, will be quantified 

through the use of leak detection and application of leaker emission factors for 

leaking equipment. Population count and population emission factors will be 

used for smaller and inaccessible sources. 

– EPA also requires source-specific calculation methods using facility-specific 

information for other sources in the finalized GHG reporting rule present at 

the facility subject to the Subpart W final rule. 

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), then varying the levels in 
3-6 

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: 

1. A 1,000-MtCO2e threshold; hybrid methodology 

2. A 10,000-MtCO2e threshold; hybrid methodology 

3. A 25,000-MtCO2e threshold; hybrid methodology 

4. A 100,000-MtCO2e threshold; hybrid methodology 

5. A 25,000-MtCO2e threshold; direct techniques (CEMS, flow meters, calibrated 

bagging, and high volume sampler) used to measure emissions 

6. A 25,000-MtCO2e threshold; default emission factors (simplified methods) used to 

measure emissions 

The evaluation of the alternative reporting scenarios will allow policymakers, regulated 

entities, and the general public to see the impact of each variation and assess their cost compared 

to the required option. Total costs, emissions, and cost-effectiveness of the alternative reporting 

scenarios for the petroleum and natural gas industry pursuant to Subpart W are discussed in 

Section 4. 

3.4 Data Quality for This Analysis 

EPA gathered existing data from EPA, industry trade associations, states, and publicly 

available data sources (e.g., labor rates from the Bureau of Labor Statistics [BLS]) to 

characterize the processes, sources, segments, and facilities affected. Costs were estimated based 

on the data collected and engineering analysis and models provided by EPA and its contractors. 

EPA staff and contractors provided engineering expertise, knowledge of existing facility 

conditions and activities, and an estimate of incremental activities required to comply with the 

rule. Existing models, such as EPA’s CEMS cost model, were used for Subpart W to ensure 

consistency of cost inputs and assumptions. 

The most important elements affecting the data quality for this analysis include the 

number of affected facilities in each source category, the number and types of production 

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 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 
3-7 

industry surveys from the U.S. Census Bureau, trade associations, and operating permits. 

Information on measurements that are already made (and thus would not be associated with the 

rule) was obtained from discussions with industry representatives, knowledge gained from 

previous site visits, and other sources. The data collected to characterize the facilities in the 

Subpart W final rule are judged to be of good quality and the best that are publicly available. 

Other elements affecting the quality of the data include estimates of labor hours to 

perform specific activities, cost of labor, and cost of monitoring equipment. Estimates of labor 

hours were based on previous analyses of the costs of monitoring, reporting, and recordkeeping 

for other rules; information from the industry characterization on the number of units or process 

inputs and outputs to be monitored for Subpart W; and engineering judgment. Labor costs were 

taken from 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 and regulating (M&R) stations. 

(b) Emissions reported separately for standby equipment; 

(c) Report activity data for each aggregated source type as follows: 

 (1) Count of emission sources. 

 (2) Type of emission sources. 

 (3) Number of specified events per year or reporting period (such as blowdowns, 

well completions, etc.). 

 (4) Control measures and other equipment. 

 (5) Volume and flow rates. 

 (6) Input parameters for simulation software, if required. 

 (7) Flared/vented/and equipment leak data. 

(d) Minimum, maximum and average throughput for each operation listed in industry 

segments (a)(1) through (8) above. 

(e) For offshore petroleum and natural gas production facilities, the number of 

connected wells, and whether they are producing oil, gas, or both. 

(f) Report emissions separately for portable equipment for the following source types: 

drilling rigs, dehydrators, compressors, electrical generators, steam boilers, and 

heaters. 

 (1) Aggregate emissions by source type. 

 (2) Report count of each source type. 

Note: Many facilities that would be affected by the rule emit GHGs from multiple sources. Each facility must assess every 

source category that could potentially apply to each when determining if a threshold has been exceeded. If the threshold is 

exceeded for any source category, the facility must report emissions from all source categories, including those source 

categories that do not exceed the applicable threshold. 
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. 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 categories for which costs are determined. One is the cost 

to quantify process emissions (i.e., equipment leaks and vented emissions); the other is the cost 

to quantify the additional combustion-related emissions for facilities that did not exceed the 

Subpart C threshold with only combustion emissions. The total burden estimates presented for 

Subpart W are comprised of the costs for process and combustion emissions, above those 

covered by Subpart C alone. 

EPA first provides a general overview of baseline reporting and the two cost components 

associated with this information collection: 1) labor costs (i.e., the cost of labor by facility staff 

to meet the information collection requirements of the rule), and 2) capital and operating and 

maintenance costs (e.g., the cost of purchasing and installing monitoring equipment or contractor 

costs associated with providing the required information). Additional details of the data, 

methods, and assumptions underlying the costs are documented in this section. 

4.2.1 Baseline Reporting 

In general, the Subpart W analysis assumes that none of the facilities in the covered 

segments are currently reporting equipment leaks and vented emissions and that many of the 

requirements will result in “new” or “full” costs to meet reporting requirements. Specifically, 

EPA assumes that there will be additional costs for any detection, sampling, and testing 

requirements in the methods used to quantify emissions from petroleum and natural gas sources. 

EPA also assumes that additional costs will be incurred for preparing monitoring and quality 

assurance/quality control (QA/QC) plans, performing the calculations, reporting the results, and 

maintaining records. The only significant element that EPA knows 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. 

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 

sources in all segments of Subpart W. Key variables and data fields were clearly defined to 
4-3 

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 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 the private and public segments. Staff hours are estimated 

for activities such as: 

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

systems. 

– Reporting (private): staff hours to gather and process available data and reporting 

it to EPA through electronic systems. 

– 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 

monitoring activities at a 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. Thus, the wage rates calculated for 

different labor categories included the employer costs for employee compensation (comprising 

the basic wages and the corresponding benefits) and the overhead costs to the employer18. 

For each labor category applicable to Subpart W, the following formula was used to 

calculate the wage rates: 

 

18 For each employee, the employer also incurs overhead costs (comprising the rental costs of the office space, 

computer hardware and software, telecommunication and other equipments, organizational support, etc.) required 

for and used by the employee to effectively fulfill his/her job responsibilities. These costs are over and above the 

employee compensation costs. 
4-4 

Loaded Hourly Labor Rate ($/hr.) = Basic Wages ($/hr.) * 

(1 + Benefits Loading Factor + Overhead Loading Factor) 

The benefits loading factor corresponds to the relative share of benefits compensation in 

the total employee compensation (comprising basic wages and benefits). Although the benefits 

factor tends to vary by labor category and by industry (0.37 to 0.50), for purposes of this 

analysis, EPA has 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 industry-specific data on 

benefits paid to employees. 

The overhead loading factor corresponds to the share of overhead costs to the employer 

relative to the total employee compensation. For the purposes of this analysis, EPA has also 

adopted the same overhead loading factor that Rice (2002) used in her wage rate calculations. 

Thus the overhead loading factor that EPA 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 

This includes the cost of purchasing and installing monitoring equipment or contractor 

costs associated with providing the required information. Equipment costs include both the initial 

purchase price of monitoring equipment and any facility/process modification that may be 

required. Based on expert judgment, the engineering costs analyses annualized capital equipment 

costs with the appropriate lifetime and interest rate assumptions. The equipment life was set at 

five years for Subpart W sources with one-time capital costs amortized at a rate of 7 percent. 

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, 
4-5 

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 

source counts that can aggregate to any size company to determine its monitoring costs. For 

example, in natural gas transmission, a compressor station as a facility was modeled at the three 

different model size levels. Any natural gas transmission company can determine its monitoring 

costs by assigning the model facility costs to its facilities that are closest to the appropriate level 

of the model facility. To determine the national cost from each segment, EPA assigned a model 

facility cost that best fit the facility based on its emission profile. Next, EPA summed the costs 

assigned to each facility in the segment to produce the total national cost in each segment. 

Section 4.5 of this document describes the calculation in further detail. 

Facilities in onshore production, however, are defined as “all petroleum or natural gas 

equipment associated with all petroleum or natural gas production wells under common 

ownership or common control by an onshore petroleum and natural gas production owner or 

operator located in a single hydrocarbon basin,” as defined by the American Association of 

Petroleum Geologists. There is much larger variation in facility equipment by this definition, so 

developing model “small,” “medium,” and “large” facilities for monitoring costs is unintuitive 

and impractical. In this case, non-monitoring costs were estimated using the model 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 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. 

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
4-6 

Industry Segment 

Threshold 

1,000 10,000 25,000 100,000 

Transmission Compressor Stations 1,695 1,443 1,145 433

Natural Gas Storage 347 200 133 36

LNG Storage 54 41 33 4

LNG 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 hours overseeing the monitoring process per quarter but are assumed not to perform any 

of the monitoring. It was assumed that junior engineers and contracted technicians will do all of 

the monitoring, except in cases where senior operators will log any activity data required to 

estimate emissions over the course of the quarter. Several equipment types are common between 

different onshore segments and different facility sizes, but the actual monitoring time typically 

will not change per equipment unit. For example, centrifugal compressor seals are found in all 

onshore segments, except for natural gas distribution and onshore production. Measuring 

centrifugal compressor seal degassing vents was assumed to take one hour and that will not 

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 source counts assigned to 

each of the model facilities to determine the required labor hours. Once the labor hours were 

calculated, by category, for each of the cost elements, they were multiplied by the associated 

labor rates to estimate labor costs per facility. For offshore monitoring, costs were developed on 

a per-platform basis for non-GOADS reporters, based on expert judgment. The only remaining 
4-7 

facility costs are due to the annualized capital costs and travel, lodging, and shipping to conduct 

the actual emission monitoring. 

Error! Reference source not found.Table 4-3 presents labor cost numbers aggregated 

across all segments for Subpart W. These data are aggregated from individual tables for each 

segment. Except for onshore production, each segment has a table for small, medium, and large 

facilities. 

Table 4-3 Subpart W Petroleum and Natural Gas Systems: Labor Costsa

 (2006$) 

Activity 

Estimated Labor Hours and Annual Labor Rates 

Labor Cost per 

Year per 

Reporting 

Unit/Facility 

Senior 

Management 

Middle 

Management 

Junior 

Engineer/ or 

Technician Senior Operator 

($101.31/hr) ($88.79/hr) ($71.03/hr) ($63.89/hr) 

First 

Year 

Subseq. 

Year 

First 

Year 

Subseq. 

Year 

First 

Year 

Subseq. 

Year 

First 

Year 

Subseq. 

Year 

First 

Year 

Subseq. 

Year 

Planning 0.63 0.06 2.85 0.17 46.21 0.58 3.49 0.28 3,821 80

QA/QC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0 0

Recordkeeping 0.15 0.15 0.24 0.23 2.74 2.60 0.52 0.52 264 253

Sampling and analysis 

(calculations)

0.00 0.00 1.86 1.86 91.93 6.45 1.05 0.91 6,762 682

Reporting 0.05 0.04 1.24 1.08 4.13 3.73 13.81 13.10 1,291 1,202

Total 0.83 0.25 6.19 3.35 145.01 13.36 18.87 14.80 12,139 2,217

a

 Estimated onshore production average labor costs per year per reporting unit/facility are $12,099 for the first year and $5,168 

for the subsequent years. 

Unlike the other segments, onshore production labor costs were estimated by scaling up 

equipment-level labor hours, displayed later in this document in Table 4-13, 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 segment like in Table 4-3 or Table 4-4Error! Reference 

source not found.. The average operational and maintenance costs for the onshore production 

segment are shown below each table, however. 

4.3.3 Capital and O&M Costs 

The capital costs related to monitoring emissions and archiving information consist of 

purchasing equipment for emission detection (or the portion of contractor purchases of 
4-8 

equipment is apportioned to all its customers), emission 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-percent interest rate. Equipment leak monitoring does not have time-tested 

standards and equipment leak streams typically are not clean gas. For example, a centrifugal 

compressor wet seal degassing vent will contain fine droplets of seal petroleum with the gas. A 

five-year equipment life was chosen to be conservative in cost estimates, as opposed to the 10-

year equipment life associated with long-standing, proven practices of measuring clean fuel 

streams assumed in the stationary combustion section. 

Error! Reference source not found.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 required to pay for a 

one-time flow measurement port installation on compressor seal degassing vents and 

reciprocating rod packing vents. This approach assumes that there will be no disruption in the 

operations because the port can be installed when the compressor is either in standby mode or 

under maintenance. No adjustment is made, therefore, for production or operational loss. Firstyear labor costs include the labor required for registration, monitoring plan creation, and general 

planning procedures that are required only in the first year of compliance. The subsequent-year 

cost is a truer reflection of actual average costs over time. 

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

(2006$) 

Activity 

Cost Categories 

Capital and O&M Cost 

per Unit/Facility 

Capital 

Cost 

Equipment 

Lifetime 

(years) 

Annualized 

Capital Cost 

(per year) 

O&M 

Costs 

(per year)

First 

Year 

Subseq. 

Year 

Equipment (selection, 

purchase, installation) $1,676 6 $409 n/a $409 $409 

Performance testingb n/a n/a n/a n/a n/a n/a

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. 
4-9 

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 even if there are multiple compressors at the facility. 

This analysis includes the cost of incremental combustion reporting and combustion 

emissions above those that exceed the Subpart C threshold alone and would therefore already be 

have been reported under Subpart C. For purposes of cost estimation, EPA determined that 

under the final rule for Subpart W, entities that need to report incremental combustion-related 

emissions would use either the Tier 1 calculation methodology as set forth in Subpart C or the 

calculation methodology as set forth in Subpart W (40 CFR 98.233(z)). EPA determined that the 

entities reporting incremental emissions under subpart C would likely not meet the requirements 

for Tier 2 or higher methods. However, as these entities will be reporting combustion emissions 

under subpart C (except onshore production and LDCs), if a facility did meet the requirements 

for a tier other than Tier 1, the facility would have to use the required method, as specified in 

subpart C. 

Given that the combustion methodology in 40 CFR 98.233(z) is similar to the Tier 1 

calculation methodology, EPA estimated the costs to monitor and report incremental 

combustion-related emissions based on the approach used under 40 CFR part 98, subpart C. 19 

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-

 

19 40 CFR Part 98 used the IPCC tier concept to estimate combustions emissions (74 FR 56260, October 30, 2009). See EPAHQ-OAR-2008-0508-0004, U.S. EPA, Technical Support Document for Stationary Fuel Combustion Emissions: Proposed 

Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more information about the IPCC tier methodology 

(pgs 10-15). 
4-10 

specific default CO2 emission factor, a default high heating value of the fuel, and the annual fuel 

consumption from company records. 

EPA based its conclusion that entities would likely report incremental combustion 

emissions using the Tier 1 method on three considerations for applicability of the Tier 2 

calculation methodology and higher, as specified in Subpart C, to the petroleum and natural gas 

industry: 1) availability of high heating values (HHVs) for the fuels combusted at the frequency 

required by the Tier 2 calculation methodology, 2) the maximum-rated heat input capacity of the 

equipment, and 3) the type of fuel being combusted. First, in order to be allowed to use a Tier 2 

analysis, units must have a rated heat-input capacity less than or equal to 250 million British 

thermal units per hour (MMBtu/hr), combust a fuel found in Table C-1 of subpart C, and sample 

the HHV of the fuel consumed at the required frequency in 40 CFR 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. 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; 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. 

Third, the predominant fuels used in the petroleum and natural gas industry are produced 

natural gas, pipeline quality natural gas, distillate fuel, and any products recovered from 

equipment leaks and vents. The use of produced natural gas is predominant in onshore 

petroleum and natural gas production. Under the final rule for subpart W, reporters in this 

segment are allowed to use methods similar to Tier 1 for all combustion emissions sources that 

use produced natural gas. 

In the remaining segments, equipment using produced natural gas or products recovered 

from equipment leaks and vents are normally required to use Tier 2 methodology or higher. 

However, as described previously, if the unit has a rated heat input less than or equal to 250 

MMBtu/hr, then the unit probably does not currently receive HHV at the required frequency for 

a Tier 2 and could use a Tier 1 analysis instead. If the unit has a maximum-rated heat-input 

capacity greater than 250 MMBtu/hr, then as just noted, emissions from a unit of this size would 

already be subject to reporting and would not be included in the incremental combustion 
4-11 

emission category considered in this analysis. In sum, the use of Tier 1 methodology for 

incremental combustion is a reasonable assumption for costing the subpart W rule. 

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 reporting as applicable to an 

individual facility: 1,000 MtCO2e per year; 10,000 MtCO2e per year; 25,000 MtCO2e per year; 

and 100,000 MtCO2e per year. A threshold analysis was then conducted on each segment to 

determine which level of threshold was most suitable for each industry segment. CH4, CO2, and 

N2O emissions from each segment were included in the threshold analysis. 

Table 4-6 shows the number and share of entities and emissions covered by the final rule. 

The table shows that at lower thresholds, a higher number and share of facilities and emissions 

are covered by the rule. As the threshold increases, smaller numbers and shares of facilities and 

emissions are affected. Of significant note, 85 percent of emissions are covered at the selected 

25,000-MtCO2e threshold, but only 9 percent of facilities need to report. Furthermore, both total 

emissions and covered emissions include incremental combustion emissions (i.e. those not 

triggered by the threshold of Subpart C alone). 

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

Threshold 

Number of 

Entities 

Number of 

Facilities 

Covered 

Percent of 

Facilities 

Covered 

Total 

Emissions 

(Million 

MtCO2e/Year) 

Covered 

Emissions 

(Million 

MtCO2e/ 

Year) 

Percent of 

Emissions 

Covered 

1,000 MtCO2e/yr

Threshold 30,241 12,622 42% 396 391 99%
4-12 

10,000 MtCO2e/yr

Threshold 30,241 4,400 15% 396 362 91%

25,000 MtCO2e/yr

Threshold 30,241 2,786 9% 396 337 85%

100,000 MtCO2e/yr

Threshold 30,241 1,062 4% 396 273 69%

4.4.1 Detailed Threshold Analysis 

For each segment, a threshold analysis was conducted to determine how many of the 

facilities in the segment exceed the various reporting thresholds, and the total emissions from 

these facilities. This analysis was conducted considering vented and equipment leaked CH4 and 

CO2 emissions, and combustion CH4, CO2, and N2O emissions. The vented emission and 

equipment leak estimates available from the U.S. GHG Inventory were used in the analysis. The 

emission 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 factors available from GRI/EPA (1996), back-calculating the natural gas consumption 

in engines, and finally applying a CO2 emission factor to the natural gas consumed as fuel. N2O 

emissions were calculated similarly. In the case of offshore petroleum and natural gas production 

platforms, combustion emissions are already available from the GOADS (2000) study analysis 

and hence were directly used for the threshold analysis. In addition to gas engines, combustion 

emissions from reboilers on glycol dehydrators, acid gas removal amine regeneration, diesel 

engines on drilling rigs, and heater-treaters were estimated for onshore production. The volume 

of fuel gas required by regular operation of a glycol dehydrator was calculated per volume of 

dehydrator input; then the API Compendium combustion emission factors for natural gas were 

applied to facilities’ fuel gas use based on their gas production rates. The same assumptions 

were made to calculate combustion emissions from acid gas removal amine regeneration heaters. 

Drilling rigs were assumed to operate two 1,500-horsepower diesel engines per well drilled, and 

assuming it requires 90 days to drill and complete any well. The API Compendium combustion 

emission factors for diesel engines were used to calculate the emissions. The total drilling 

emissions for the nation were calculated based on the number of drilling rigs in service, then 

apportioned to each basin by throughput. 
4-13 

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 

segments of the petroleum and natural gas industry. A detailed discussion on the threshold 

analysis is available in the TSD (EPA-HQ-OAR-2009-0923). 

The general rationale for selecting a reporting threshold is to identify a level at which the 

incremental emission 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 reporting coverage with minimal burden on the industry. 

Table 4-7 summarizes the national costs and costs per representative entity for each 

threshold. The first five columns report subsets of costs, including costs associated with 

processes (labor, annualized capital, and operating and maintenance costs), costs associated with 

stationary combustion, and costs associated with reporting and recordkeeping. The final four 

columns report total national costs and total per-entity costs for the first year and for subsequent 

years. 

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

(Million 2006$)a

Threshold 

(MtCO2e/yr) 

First-Year 

Process 

Costsb 

Subseq.- 

Year Process 

Costsa 

First-Year 

Combustion 

Costs 

Subseq.-Year 

Combustion 

Costs 

FirstYear 

National 

Costs 

First-Year 

Representative 

Entity Cost 

Subseq.-Year 

National 

Costs 

Subseq.-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

 Reporting and recordkeeping costs are included in process costs. 

Note that first-year costs are significantly higher than the subsequent-year average costs, 

due to the following reasons: 

 Initial start-up costs include labor and capital associated with establishing 

modifications to enable ongoing quantification of key emission sources. They include 

costs to install measurement ports in compressor and well vents. 

 For onshore production, reporting occurs annually, but the measurement of key 

sources is updated every two years. 
4-14 

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, at lower thresholds, a larger number of 

facilities in each subpart are covered by the rule and thus incur costs. For this reason, 

the total national costs, and total costs by cost subset, decline as the threshold increases 

from 1,000 MtCO2e to 10,000 MtCO2e, to 25,000 MtCO2e, and finally to 100,000 

MtCO2e. Cost per representative entity for a particular segment generally declines for 

Subpart W as the threshold increases. Reporting Determination 

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 most facilities will 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, into the tool to roughly assess whether they 

exceed the threshold. The screening results should allow many facilities to make their threshold 

determination. Some of the facilities may have to take steps in addition to the screening tools, 

however, to determine if they have to report. For example, facilities that estimate emissions 

close to the reporting threshold may want to conduct preliminary monitoring to better determine 

their emissions. Such facilities may also conduct preliminary monitoring in subsequent years to 

determine whether emissions in those years meet or exceed the reporting threshold. 

Of the 30,241 facilities in the petroleum and natural gas industry, approximately 2,786 

facilities would likely meet the threshold and have to report. The remaining 27,455 facilities are 

expected to be below the reporting threshold and would likely use the screening tool to make this 

reporting determination. In addition, 296 of the 27,455 facilities could have emissions close to 

the threshold and may supplement the screening tool analysis with some preliminary monitoring 

to determine whether or not they need to report; these 296 facilities are also assumed to conduct 

preliminary monitoring to make a reporting determination in subsequent years. 

Facilities are required to follow methodologies in the rule to make a determination. The 

costs for this activity are outlined as follows: 

Planning costs are assumed to include: 

 2.5 hours for regulatory review 

 2 hours to understand what operations information is required 
4-15 

 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 provides a summary of the determination costs by industry segment and 

threshold level. 

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

(2006$ in thousands)a

Segment 

 

Year 

Thresholds (metric tons) 

1,000 10,000 25,000 100,000 

Onshore petroleum and natural gas production First Year $9,146 $12,177 $12,496 $12,731 

Subsequent year $1,448 $604 $256 $92 

Offshore petroleum and natural gas production First Year $1,921 $2,886 $2,972 $2,996 

Subsequent year $241 $110 $33 $3 

Natural gas transmission First Year $259 $572 $903 $1,167 

Subsequent year $9 $114 $165 $6 

Natural gas processing First Year $0 $223 $310 $392 

Subsequent year $0 $94 $52 $6 

Natural gas underground storage First Year $56 $232 $292 $379 

Subsequent year $9 $58 $43 $19 

LNG storage First Year $4 $17 $26 $55 

Subsequent year $2 $2 $2 $2 

LNG import & export terminals First Year $13 $55 $68 $140 

Subsequent year $0 $0 $0 $0 

Natural gas distribution First Year $921 $1,276 $1,330 $1,406 

Subsequent year $133 $47 $32 $28 

Total First Year $12,320 $17,438 $18,396 $19,267

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).
4-16 

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

The cost assumptions are the basis for the determination of the costs noted in this section. 

STEP 1: Model Facility Development 

For each of the industry segments, with the exception of onshore production, operations 

had to be divided into single units or model facilities at three levels: small, medium, and large. 

The monitoring costs were then developed per size level of a model facility. A model facility of a 

given level can be defined as the most convenient and logical unit with appropriate emission 

source counts that can aggregate to any size company to determine its monitoring costs. For 

example, in onshore natural gas transmission, a compressor station as a facility was modeled at 

the different levels. Any transmission company can determine its monitoring costs by assigning 

model facility costs to its facilities that are closest to the appropriate level of the model facility. 

Facilities in onshore production, however, are defined as operators reporting all equipment 

covered at the basin-level. There is much larger variation in facilities’ equipment by this 

definition, so developing model “small,” “medium,” and “large” facilities is unintuitive and 

impractical for estimating monitoring costs. In this case, non-monitoring costs were estimated 

using the model-facility method and monitoring costs were estimated at the national level and 

then apportioned to individual operators in basins by production rates. 

For each of the sources designated for monitoring, both equipment and component counts 

were determined to define individual model facilities, except as noted in onshore production. For 

onshore natural gas processing, onshore natural gas transmission, underground natural gas 

storage, LNG storage, import and export facilities and natural gas distribution, equipment and 

component counts for medium facilities were assigned the national average activity factors from 

the national 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 

source counts was assigned to a “large” facility. If illogical values, such as in the case of 

compressors in natural gas transmission compressor stations, resulted from the 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 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 100 percent, it would predict a negative lower bound for 

emission source counts. For these cases, expert judgment was used. Expert judgment was also 

used, where necessary, to adjust emission source counts to reflect real-world scenarios. Both 
4-17 

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. Additionally, 

these cost elements are considered in two ways: costs associated with start-up, and recurring 

costs. Startup costs refer to a one-time cost associated with initiating the reporting process. 

Subsequent costs for reporting on an annual basis are less than the startup costs and are referred 

to as recurring costs. 

1. Regulation compliance determination costs 

a. Start-up costs consist entirely of the labor necessary to study and review the 

regulations to assure compliance, gather data on the facility, and fill out any 

appropriate forms. 

b. Recurring costs will be small and consist entirely of labor expenses. Small 

amounts of time will be required for the company to stay aware of any updates to 

regulations and to alter the facility information to reflect any new equipment or 

facilities brought into operation or taken offline. 

2. Monitoring costs 

a. Start-up monitoring costs consist of both labor and capital costs. Capital 

investment will be required for purchasing monitoring equipment. This capital 

cost will be accounted as annualized cost, on an annual basis. Labor will be 

required for product research for monitoring instruments before actual purchase. 

Before actual monitoring takes place, labor will have to be devoted to the 

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 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, 
4-18 

travel may be required for the monitoring team and/or the monitoring instruments 

may require shipping to multiple locations. 

3. Reporting costs 

a. There will be no start-up reporting costs; reporting costs are applied uniformly 

across segments reporting to the rule. 

b. Recurring reporting costs consist of labor necessary to document collected 

emission data from equipment leak monitoring and to submit the official report in 

each cycle (i.e., annually). 

4. Archiving and recordkeeping costs 

a. Start-up archiving and recordkeeping costs consist of labor and annualized capital 

purchase of storage space. For archiving reports and associated working 

documents, a physical storage system such as a file cabinet and an electronic 

storage system such as an external hard drive will be required. 

b. Recurring archiving and recordkeeping costs consist entirely of labor necessary to 

adequately archive each cycle’s report and associated working documents. 

5. Auditing costs 

a. There is no start-up cost associated with auditing. 

b. Recurring auditing costs consist of labor required to validate the EPA results from 

emission monitoring and the follow-up from rectifying any weaknesses found 

through the audit. The EPA audit is assumed to occur once in several years, not 

on an annual basis. 

STEP 3: Analyze Proportion of Facilities in Different Model Facility Levels 

Facilities were classified and rank-listed in ascending order based on their sizes, total 

combustion, equipment leaked, and vented CO2, N2O, and CH4 emissions, expressed in CO2e. 

Cumulative emissions for the facilities were calculated by adding the emissions of an individual 

facility to those of the facilities before it in the ascending list. The cumulative emissions, in 

combination with the total emissions from all facilities, were used to assign facilities to the 

small, medium, and large category. 
4-19 





 



  TotalEmissions

CumulativeEmissions Percentile(%) 

The facilities that accounted for the first 33 percent of the emissions nationally in the 

ranked list were identified as small facilities. The facilities that accounted for national emissions 

greater than 33 percent but less than 67 percent in the ranked list were identified as medium 

facilities. The facilities that accounted for national emissions greater than 67 percent in the 

ranked list were identified as large facilities. 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. 

3. Determine annualized capital costs and O&M costs for each of the cost elements. 

These steps are described in more detail as follows: 

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 GOADS 

Emission Inventory, 

Lasser, 2006 

0–33% 34%–67% 68%–100% 

 Facility Count BOEMRE, 2000 GOADS 

Emission Inventory, 

Lasser, 2006 

3,036 191 8 

Mean Emissions (MtCO2e) This Analysis 1,430 22,733 483,806 

 Operator/Company a Not estimated 

Onshore Petroleum and Natural Gas Productionb 

 Facility Percentile HPDI, 2006 0–33% 34%–67% 68%–100%

 Facility Count HPDI, 2006 22,275 194 41 

Operator/Company HPDI, 2006 — — — 

Mean Emissions (MtCO2e) This Analysis 3,988 451,120 2,170,820 

Onshore Natural Gas Processing 

 Facility Percentile API, 2008 Impact 

Assessment of Mandatory 

GHG Control Legislation

0–33% 34%–67% 68%–100% 

 Facility Count c API, 2008 Impact 486 64 16 
4-20 

Segment Data Source Small Facilities Medium Facilities Large Facilities 

Assessment of Mandatory 

GHG Control Legislation

 Operator/Company API, 2008 Impact 

Assessment of Mandatory 

GHG Control Legislation

166 28 10 

Mean Emissions (MtCO2e) This Analysis 36,486 275,823 1,137,595 

Onshore Natural Gas Transmission 

 Facility Percentile FERC, 2008 0–33% 34%–67% 68%–100% 

 Facility Count FERC, 2008 1,314 374 255 

 Operator/Company FERC, 2008 147 46 27 

Mean Emissions (MtCO2e) This Analysis 21,293 98,738 210,829 

Natural Gas Underground Storage 

 Facility Percentile EIA, 2006. Underground 

Storage Field Level Data

0–33% 34%–67% 68%–100% 

 Facility Count EIA, 2006. Underground 

Storage Field Level Data 325 50 22 

 Operator/Company EIA, 2006.Underground 

Storage Field Level Data 102 37 17 

Mean Emissions (MtCO2e) This Analysis 12,404 82,199 183,936 

LNG Storage 

 Facility Percentile GTI. 2007. The World 

Energy Source Book

0–33% 34%–67% 68%–100% 

 Facility Count GTI. 2007. The World 

Energy Source Book 141 12 4 

 Operator/Company GTI. 2007. The World 

Energy Source Book 141 11 3 

Mean Emissions (MtCO2e) This Analysis 20,972 55,340 223,275 

LNG Import and Export 

 Facility Percentile FERC, 2008 — 0–100% — 

 Facility Count FERC, 2008 — 5 — 

 Operator/Company Not estimated 

Mean Emissions (MtCO2e) This Analysis — 174,643 — 

Natural Gas Distribution 

 Facility Percentile DOT, 2006 0–33% 34%–67% 68%–100% 

 Facility Count DOT, 2006 1,360 50 17 

 Operator/Company DOT, 2006 1,268 49 16 

Mean Emissions (MtCO2e) This Analysis 5,840 167,066 536,719 

Notes: 

a

 The BOEMRE 2000 Gulfwide Emissions Inventory reports 2,525 offshore platforms and 86 operators. No data are available 

for individual offshore platforms and their respective operators. 

b 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

 Assumed one facility per company; no data available for small plants. 
4-21 

4.5.1 Determining Labor Categories 

To evaluate labor costs, it was necessary to not only determine the amount of time 

required for all of the tasks associated with monitoring, but also to determine who will perform 

each task. For the sake of this analysis, five labor categories were used, as shown in Table 4-10. 

Table 4-10 Labor Categories and Hourly Rates 

Labor Category Description Loaded Hourly Ratea 

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 sources. Interfaces 

between middle manager and senior operator to collect 

information and complete reports. 

$71.03/hour 

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: U.S. Department of Labor, 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. Since the petroleum 

and natural gas industry hourly rates are high compared to other industries, the top four nonlawyer 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 
4-22 

Refinery Engineer/Technician $63.89 

Industrial Engineer/Technician $55.20 

Administrative Support $29.65 

a

 Source: U.S. Department of Labor, Bureau of Labor Statistics, National Compensation Survey - Compensation Cost Trends, 

Employer Cost for Employee Compensation (ECEC), Customized Tables, as of March 11, 2003. 

4.5.2 Allocating Responsibilities 

Assigning labor hours for all cost elements was based on expert judgment. When 

assigning hours, the size of the facility and role of the labor categories were taken into 

consideration. Table 4-12 summarizes these roles. 

Table 4-12 Responsibilities for Regulation Compliance by Labor Category 

Cost Element 

Senior 

Management 

Middle 

Management Junior Engineer Senior Operator

Per Facility/ 

Per Companya

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 
4-23 

Cost Element 

Senior 

Management 

Middle 

Management Junior Engineer Senior Operator

Per Facility/ 

Per Companya

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 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. 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. 

Additionally, several pieces of equipment are common among different onshore segments 

and different facility sizes, but the actual monitoring time typically will not change per 

equipment unit. The series of universal assumptions about onshore monitoring times are also 

provided in Table 4-13. 

Table 4-13 does not include equipment monitoring on offshore petroleum and natural gas 

production facilities. Offshore production platforms are proposed to use data already collected 

for BOEMRE GOADS to estimate GHG emissions from their operations. Specifically, the 

BOEMRE GOADS program requires GHG emission monitoring from platforms in the Gulf of 

Mexico federal waters. Facilities under this final rulemaking are required to report the same 

emission data calculated by the GOADS program; hence, these platforms have minimal 

additional reporting burden. The cost burden model assumes that this monitoring requires 30 

minutes per platform. 

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

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

Onshore Facility Equipment Leaks 

Senior 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 

 Processing 
4-24 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

hours/large facility) 

Junior engineer Estimate emissions using 

leaker factors (2 

hours/facility) 

Processing 

Middle 

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/medium 

facility, and 3 hours/large 

facility) 

Transmission 

Middle 

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) 

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 

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 

Oversee part of the detection 

process and review results (2 

Oversee part of the 

measurement process and 

LNG Import and Export 

Facilities 
4-25 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

hours/reporting period) review results (1 hour/ 

reporting period) 

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 

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 

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 

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 One time labor cost to install 

port for hotwire anemometer 

($1,000 /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 

Processing, Transmission, 

Storage, LNG Storage, LNG 
4-26 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

minutes/compressor) 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 

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) 

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 
4-27 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

Senior operator Collect data collection (10 

minutes/dehydrator vent) 

Onshore Production, 

Processing 

Junior engineer Perform simulation runs (15 

minutes/dehydrator vent) 

Onshore Production, 

Processing 

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 calculation 

with gas-to-oil ration (GOR) 

measurement (1 hour/well) 

Onshore Production 

Natural Gas Pneumatic Bleed Devices 
4-28 

Element 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Detection Quantification Applicable Segments 

Junior engineer Determine high bleed or low 

bleed from manufacturer and 

apply appropriate population 

factor (10 

minutes/pneumatic device) 

Onshore Production, 

Processing, LNG Storage, 

LNG Import and Export 

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 platforms that are in state waters or in federal waters outside the Gulf of Mexico, 

GHG emissions will have to be estimated using the BOEMRE GOADS procedures. EPA 

estimates the reporting cost for non-GOADS platforms to be $5,000 for first year of reporting. 

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 monitoring. 

4.5.3 Annualizing Capital Costs and Determining O&M Costs 

The capital costs related to monitoring emissions and archiving information consists of 

purchasing equipment for emission detection, emission 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-percent interest rate. From these factors, a capital recovery factor of 24 

percent was calculated using the formula provided as follows: 
4-29 

(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 summarizes the annualized capital costs associated with the monitoring 

program. Additionally, the table describes the annual costs of travel, lodging, and shipping—the 

only other non-labor costs related to the monitoring program. 

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

Element Capital Cost 

Annualized 

Capital Cost 

Archiving 

Capital costs Cost of archiving material per facility assumes cost of 1 file 

cabinet, 4-drawer vertical from Office DepotTM ($140), and 

1 hard drive for data storage from SeagateTM ($95) 

$57 

Monitoring 

Equipment purchase Screening equipment is represented by a nominal $100,000 

cost for an infrared camera. It is assumed to be purchased 

by the contractors who will pass on the costs to as many 

facilities as they can provide a service each year. 

$24,389 

Equipment purchase Screening equipment in the distribution segment is 

represented by a nominal $10,000 cost for a laser emission 

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 

case, an AC adapter, data acquisition software, and 

anemometer electronic data logger will be purchased. 

$206 

Traveling Cost of traveling for an engineer to a facility from the home 

facility (therefore n-1 facilities to visit). Assuming travel 

cost is $0.485/mile, $150/night for overnight stay, 

$100/shipment for shipping equipment, and $100 per diem. 

$0–$10,449a

a

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 detection methods 

vary depending on the size of the company and its facilities. In the case of companies with small 

operations and few facilities, the costs passed on by contractors will be spread over many 

facilities. 
4-30 

Each facility is assumed to purchase an adequate flow meter to measure the emission 

rates from compressor seal vents either at the pipe end, if accessible, or a flow measurement port 

installed at a suitable location capturing all vent emissions. 

With the equipment costs per company determined, the final step was to divide company 

capital and O&M costs amongst individual facilities owned by a typical company. 

Step 3, described previously, provided the proportion of facilities that fall in the small, 

medium, and large categories. By determining the companies that fall in the three categories, the 

average number of small, medium, and large facilities per company was determined. To convert 

the annualized capital costs and equipment purchases, the costs per equipment were attributed to 

the number of facilities that can be serviced (as determined the number of labor hours required to 

monitor a facility) each year, as shown in the equation as follows: 





 



















  

Contractor

FacilitiesServiced

Contractor

ofEquipment

Equipment

AnnualCapital

Facility

$AnnualCapital $ #

The travel, lodging, and shipping costs associated with monitoring several facilities 

spread over large regions were calculated using the assumed costs in Table 4-14. Expert 

judgment based on the number of teams using equipment and the necessity of travel versus 

shipping between facilities was used to determine these costs. 

STEP 5: Estimate per Facility Costs for Each Threshold Level 

The total reporting costs across each segment were determined by assigning model 

facility costs (small, medium, and large) to individual facilities in the respective industry 

segments based on relative size and determining total costs from the entire segment. This was 

done for only those facilities that exceeded the reporting threshold. Average cost per facility was 

then determined by dividing the total segment costs by the number of facilities that exceeded the 

reporting threshold—small, medium, and large. In the case of onshore production, field-level 

monitoring costs were aggregated to the total national burden, then distributed to operators at the 

basin-level based on production rates. 
5-1 

SECTION 5

SUBPART W ANALYSIS OF REPORTING RULE OPTIONS 

For petroleum and natural gas systems, Subpart W, as shown in Table 5-1, 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 and $15.1 million in subsequent years. The 

estimates are based on the selected option for the final rule, which includes an annual emissionbased threshold of 25,000 MtCO2e for each facility and a hybrid of direct measurement and 

source-specific calculation methodologies. Section 3.2 provides more details about the selected 

option. 

EPA estimates that for Subpart W, the public-sector burden is about $1.1 million per 

year. Approximately $0.46 million per year is for verification activities, and about $0.66 million 

per year is for program implementation and developing and maintaining the data collection 

system. Program implementation activities include, but are not limited to, developing guidance 

and training materials to assist the regulated community, responding to inquires from affected 

facilities on monitoring and applicability requirements, and developing tools to assist in 

determining applicability. In addition to total national costs for petroleum and natural gas 

systems, EPA also reports average cost-per-metric-ton to support additional analysis of the 

mandatory reporting programs. These costs are also shown on 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) 

in the first year; these sources are only required to be estimated bi-annually to mitigate long-term 

burden. The average cost per metric ton for all reporters is about $0.13/metric ton in the first 

year, declining to an average of $0.05/metric ton in subsequent years. 
5-2 

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

First Year Subsequent Years 

Subpart W – Petroleum 

and Natural Gas systems NAICS 

$Million Million 

MtCO2e $/Mt 

$Million Million 

2006 2006 MtCO2e $/Mt 

Process Emissions 211, 486 $40.1 253.9 $0.16 $15.11 253.9 $0.06 

Combustion Emissions $3.3 83.5 $0.04 $3.32 83.5 $0.04 

 Reporting Determination $18.4 n/a n/a $0.58 n/a n/a 

Private Sector, Total $61.8 337.4 $0.13a $19.01 337.4 $0.05a 

Public Sector, Total $1.1 337.4 $0.003 $1.1 337.4 $0.003 

TOTAL $62.9 337.4 $0.13b $20.11 337.4 $0.05b 

Note: 

a 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 Excludes reporting determination for non-reporters; based on public sector cost plus private sector cost to report process and 

combustion emissions ($44 million in first year, $19 million in subsequent years). 

There is a notable reduction in reporting cost compared to the April 2010 proposal. The 

cost reduction resulted from changes such as providing equipment thresholds on several emission 

sources (e.g., tanks and dehydrators); simplified requirements for sampling and gas composition 

analysis; use of alternative leak detection equipment in some cases; and use of equipment-based 

emission factors instead of component-based 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 

summarizes these changes based on year-one costs for equipment leaks and vented emissions, 

and Table 5-3 summarizes these changes based on subsequent-year costs for equipment leaks 

and vented emissions. 

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

Systems, First-Year Estimates 

Source 

Covered Emissions Cost Cost 

(MtCO2e) Million (2006$) (2006$/metric ton) 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final 

Rule 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final Rule 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final Rule 

Original 

Six 

Segmentsa

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 
5-3 

Source 

Covered Emissions Cost Cost 

(MtCO2e) Million (2006$) (2006$/metric ton) 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final 

Rule 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final Rule 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final Rule 

Total 85 272 254 $32.5 $56.0 $40.1 $0.38 $0.21 $0.16 

a

 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 Costs, Petroleum and Natural Gas 

Systems, Subsequent-Year Estimates 

 

Source 

Covered Emissions Cost Cost 

(MtCO2e) Million (2006$) ($/metric ton) 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final 

Rule 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final Rule 

April 

2009 

Proposed 

Rule 

April 

2010 

Proposed 

Rule 

Final 

Rule 

Original 

Six 

Segmentsa

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

 Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG storage; LNG 

import/export. 

In addition, EPA developed annualized estimates of the costs. For each segment, EPA 

calculated the present value of the labor and capital costs to monitor and report emissions over a 

20-year time period using two discount rates (3 and 7 percent). The present value included the 

costs for facilities that do not meet the emissions threshold to make a reporting determination. 

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. 
5-4 

Table 5-4 Annualized Cost Estimates for Petroleum and Natural Gas Systems (2006$)a 

First Year Subsequent Year 

Annualized 

Costb 

($Million) 

Annualized 

Costc 

($Million) Segment 

National 

Cost 

($Million) 

Cost 

($/metric ton) 

National 

Cost 

($Million) 

Cost 

($/metric ton) 

Processing 8.13 0.26 2.10 0.07 2.43 2.57 

Transmission 16.87 0.40 6.49 0.15 7.02 7.26 

Underground Storage 2.73 0.35 1.02 0.13 1.10 1.14 

LNG Storage 0.70 0.41 0.26 0.15 0.28 0.29 

LNG import/export 0.14 0.44 0.03 0.09 0.04 0.04 

LDC 3.31 0.15 1.35 0.06 1.47 1.52 

Onshore Production 26.58 0.12 7.54 0.03 8.61 9.05 

Offshore Production 3.33 0.65 0.24 0.05 0.42 0.49 

TOTAL (8 Segments) 61.78 0.18 19.01 0.06 21.36 22.34 a Includes determination costs for non-reporters. These estimates are conservative and should be viewed as an upperbound because the determination costs were applied at the facility-level rather than the company-level. For 

example, for offshore production, determination costs were applied to each of the approximately 3,000 platforms in 

the Gulf of Mexico rather than to the roughly 86 operators in that region. See the memo, “Estimates of 

Determination Costs,” in the docket for complete details and additional determination cost estimates (EPA-HQOAR-2009-0923). 

b The cost to report annualized over 20 years at 3 percent. c The cost to report annualized over 20 years at 7 percent. 

5.1 Evaluating Alternative Options for Implementation of the Rule 

The selected option was evaluated based on a cost-effectiveness analysis. For example, in 

selecting the emission threshold, EPA compared the incremental emissions reported with the 

incremental costs (associated with the change in the facilities that would be required to report 

their emissions). Similarly, in selecting the reporting methodology option, EPA compared the 

change in uncertainty with the change in costs associated with different emission 

measurement/estimation techniques. The metrics used and the results of the cost-effectiveness 

analysis are discussed in the following information. 

In addition, the final rule requires the determination of onshore reporting to be done with 

the assumption 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 
5-5 

companies to report on a field-level basis. This alternative would affect the total emissions 

reported as well as cost, and is evaluated in the following sections. 

Six alternative options were therefore evaluated for this analysis. While the Agency 

believes that these alternatives represent the most likely variations in the selected option, EPA 

recognizes that, in some cases, particular interests may wish to evaluate more nuanced 

alternative options. To maintain transparency in the analysis, data necessary to conduct further 

alternative option analyses can be found in Section 4 of this document. 

5.1.1 Analysis of Alternative Threshold Options 

The threshold determines the number of entities required to report GHG emissions under 

Subpart W of the rule. The higher the threshold, the more entities that are excluded. It is assumed 

that the per-unit/entity cost does not change at different thresholds so that changes in the national 

cost estimates are driven by the number of reporting entities. The per-unit/entity costs outlined in 

Section 4 for Subpart W facilities, along with the estimates of numbers of covered entities at 

various thresholds, form the basis for this analysis. Two metrics are used to evaluate the costeffectiveness of the emission threshold. The first is the average cost per metric ton of emissions 

reported. The second metric for evaluating the threshold option is the marginal cost of additional 

reported emissions ($/MtCO2e) relative to the option adopted in the final rule. To compute this 

metric, EPA computed the change in emissions reported by lowering or raising the threshold and 

divided this by the change in total reporting costs. Table 5-5 provides the cost-effectiveness 

analysis for the various thresholds. 

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

Hybrid Option Is 25,000 MtCO2e 

Threshold (MtCO2e) 

Facilities 

Required to 

Report 

Total 

Costs 

(Million 

2006$) 

Downstream 

Emissions 

Reported 

(Million 

MtCO2e/year) 

Percentage of 

Total 

Downstream 

Emissions 

Reported 

Average 

Reporting 

Costa

(2006$/Mt) 

Cost 

Differentiala

,b 

(2006$/Mt ) 

1,000 12,622 $136.35 391 99% $0.35 $1.73 

10,000 4,400 $61.57 362 91% $0.17 $0.73 

25,000 2,786 $43.39 337 85% $0.13 $0.00 

100,000 1,062 $25.06 273 69% $0.09 ($0.28) a

 Excludes determination costs for non-reporters. Inclusion of determination costs results in the following average reporting costs 

($/Mt): 1,000 metric tons CO2e = $0.38; 10,000 metric tons CO2e = $0.22; 25,000 metric tons CO2e = $0.18; and 100,000 metric 

tons CO2e = $0.16. b

 Cost difference relative to 25,000-metric-ton threshold 

The analysis shows a cost reduction of $0.28 per metric ton by moving from the selected 

threshold of 25,000 MtCO2e to a higher threshold (100,000 metric tons); the total emissions 

covered decrease significantly—about 16 percent. Similarly, by moving the threshold from 
5-6 

25,000 to 10,000, the difference increases by $0.73 per metric ton, and the emissions captured 

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 presented for subsequent years in Table 

5-6. 

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

Threshold (MtCO2e) 

Facilities 

Required to 

Report 

Total Costs 

(million 

2006$/year) 

Downstream 

Emissions 

Reported 

(Million 

MtCO2e) 

Percentage of 

Total 

Downstream 

Emissions 

Reported 

Average 

Reporting 

Costa 

(2006$/Mt) 

Cost 

Differentiala

,b 

(2006$/Mt)

1,000 12,622 $71.60 391 99% $0.18 $0.99 

10,000 4,400 $29.48 362 91% $0.08 $0.44 

25,000 2,786 $18.43 337 85% $0.05 $0.00 

100,000 1,062 $9.61 273 69% $0.03 ($0.14) a Excludes determination costs for non-reporters. Inclusion of determination costs results in the following average reporting costs 

($/Mt): 1,000 metric tons CO2e = $0.19; 10,000 metric tons CO2e = $0.08; 25,000 metric tons CO2e = $0.06; and 100,000 metric 

tons CO2e = $0.04. b

 Cost difference relative to 25,000-metric-ton threshold 

Table 5-7 summarizes costs to report process and combustion emissions for all segments 

at four thresholds. 

Table 5-7 Subpart W Cost Estimates by Threshold 

Threshold 

First Year Subsequent Years 

Million 

2006$ $/Mt Million 2006$ $/Mt 

1,000 MtCO2e $136.35 $0.35 $71.60 $0.18 

10,000 MtCO2e $61.57 $0.17 $29.48 $0.08 

25,000 MtCO2e $43.39 $0.13 $18.43 $0.05 

100,000 MtCO2e $25.06 $0.09 $9.61 $0.04 

The selection decision weighed the marginal cost of capturing additional emissions with 

the percentage of emissions needed to accurately estimate national GHG emissions. This analysis 

is shown in Figure 5-1, which illustrates the total average cost per metric ton and the marginal 

cost per metric ton for Subpart W as a function of the percentage of total emissions reported. 
5-7 

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
5-8 

5.1.2 Analysis of Alternative Monitoring Method Options 

Each monitoring technique for which reporting costs were estimated for Subpart W in 

Section 4 was assumed in the burden analysis to provide the same estimate of total emissions by 

reporting facility. The methods proposed for monitoring emissions will differ, however, in their 

precision in estimating actual emissions. Therefore, the gain from increasing the cost of 

monitoring is to have more precise estimates of facility emissions. The methods considered for 

determining emissions ranged from applying average industry parameters (referred to as 

“population emission factors,” or “default parameters”) to material inputs or throughputs, to the 

use of direct measurement techniques. This section evaluates 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 facilitylevel estimates, and in the other option, direct measurements are required for all sources. EPA 

uses the terms “direct measurement” and “population factors” as shorthand to describe 

alternative options. For Subpart W, population emission factors and component count are the 

basis for “default factors.” Estimated costs for each monitoring method are shown in Table 5-8. 

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 to monitor and measure only 3 percent of the 

emissions. 

These costs were re-estimated for the entire petroleum and natural gas segment in the 

final rule. These costs involve the use of direct measurement techniques, including metering of 

all vents, calibrated bagging, or use of high-volume samplers to measure equipment leaks and 

inaccessible leaks, and so on. These costs involve additional equipment as well as significantly 

higher labor costs. If the same direct measurement techniques were required in this rule, the costs 

would be particularly high for the new onshore production and natural gas distribution segments. 

The overall costs for the direct measurement option are about $100 million (annually) 

higher than the selected option. 
5-9 

Table 5-8 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 factors developed by GRI/EPA (1996) as the 

basis for estimates of CH4 and non-combustion-related CO2 emissions. These factors are used 

with a population count of equipment and components to arrive at a “population factor” cost 

estimate. The reduction in cost from the selected hybrid 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 on the analysis, 

however, 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 determination would be very poor. Population-based 

factors determine the potential for emissions, assuming a percentage of known components that 

may leak based on previous (and dated) studies. 

The final-rule-required option of using leak detection as well as a hybrid of spot direct 

measurement, engineering estimates, leaker emission factors, and population-based factors (for 

inaccessible sources) provides an emission 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”) 

assumes that the number of entities would remain relatively constant. Thus, the analysis assumes 
5-10 

a stable population where all entities subject to Subpart W bear a single first-year cost and then 

repeated subsequent-year costs. 

In reality, however, over time some existing facilities close or go out of business and new 

facilities come into existence, which is sometimes referred to as entry and exit in an industry. 

This phenomenon may affect the cost of the rule because as entities “turn over,” the new entrants 

presumably will bear first-year costs that are slightly higher than subsequent-year costs. 

The largest contribution to non-recurring first-year costs for Subpart W compliance is for 

flow measurement port installation in compressor seal vent lines. When a company goes out of 

business and sells its assets to either a new or existing business, these ports will already be 

installed; 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 due to labor 

associated with reviewing the regulation and planning accordingly for compliance. These costs 

will not be necessary when an existing company, which already reports, acquires a reporting 

facility from a failing business. Only in the case of a new business entity acquiring an existing 

or new reporting station will these reviewing and planning first-year labor costs be necessary. 

The reviewing and planning costs are minimal in comparison to the significant other firstyear costs of reporting for Subpart W; therefore, the impact of business transitions on rule 

reporting costs for Subpart W are assumed minimal.

5.1.4 Summary of Alternative Options for Onshore Facility Definition 

The final rule specifies that onshore petroleum and natural gas producers will report for 

each hydrocarbon basin. A basin is as identified by the American Association of Petroleum 

Geologists’ three-digit Geologic Province Code. The reporters will be owners or operators in a 

basin; 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 and Table 5-10 show a detailed 

emission coverage and burden to reporter that would have been expected under a field-level 

facility definition. 
5-11 

Table 5-9 Emission Coverage and Entities Reporting for Field-Level Facility Definition 

(Onshore Production) 

Threshold 

Level 

Emissions Covered Facilities Covered 

Million 

MtCO2e/ 

year 

Percent Number Percent 

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

Facility Definition (Onshore Production) 

Threshold 

Level 

Equipment Leak and Vented Emission Costs (2006$) Combustion Emission Costs (2006$) 

First-Year Costs Subsequent-Year Costs First-Year 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 presents a comparison of average costs (years 1, 2, and 3) and emission coverage at 

different thresholds for the field- and basin-level options. Specifically, it shows that the fieldlevel option would result in a significantly lower coverage in emissions reported—57 percent at 

field-level versus 85 percent at the basin-level for a 25,000-MtCO2e threshold. In addition, the 

cost to report under the field-level definition is higher than under the basin-level definition at all 

thresholds, except at 100,000-MtCO2e threshold, at which field-level is lower. Emission 

coverage at the 100,000-MtCO2e threshold under a field-level definition is very low, however—

42 percent. Finally, the number of entities reporting at a 25,000-MtCO2e threshold for basinlevel definition is lower, at 981 in comparison to the 1,157 entities reporting for a field-level 

definition. 
5-12 

Figure 5-2 Summary of Basin vs. Field Decision 

0.13

0.76

0.04

0.07

0.24

0.07

0.05 0.03

-

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

30% 40% 50% 60% 70% 80% 90% 100% 110%

Percent of Total Onshore Emissions Reported

2006$/metric tons

Field Level Basin Level

5.2 Assessing Economic Impacts on Small Entities 

The first step in this assessment was to determine whether the rule would 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 to indicate whether the 

Agency can certify the rule as not having a SISNOSE. The elements of this analysis included: 

– Identifying affected entities under Subpart W. 

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

the analysis. 

– Determining a SISNOSE certification category. 

5.2.1 Identifying Affected Segments and Entities 

The affected entities covered by the rule were identified during the development of the 

cost analysis for the reporting rule. The Statistics of U.S. Businesses (SUSB) data provide 

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 Advocacy of the 

Small Business Administration (SBA) (SBA, 2008a). The data include the number of 

establishments (Table 5-11), employment (Table 5-12), and receipts (Table 5-13) and present 

information on all entities in an industry covered by Subpart W of the rule; however, many of 

these entities would not be expected to report under the selected option because they would fall 
5-13 

below the 25,000 hybrid threshold. SUSB also provides this data by enterprise employment size. 

The census definitions in this data set are as follows: 

– Establishment: An establishment is a single physical location where business is 

conducted or where services or industrial operations are performed. 

– Employment: Paid employment consists of full- and part-time employees, 

including salaried officers and executives of corporations, who were on the 

payroll in the pay period including March 12, 2002. Included are employees on 

sick leave, holidays, and vacations; not included are proprietors and partners of 

unincorporated businesses. 

– Receipts: Receipts (net of taxes) are defined as the revenue for goods produced or 

distributed, or services provided, including revenue earned from premiums, 

commissions and fees, rents, interest, dividends, and royalties. Receipts exclude 

all revenue collected for local, state, and federal taxes. 

– Enterprise: An enterprise is a business organization consisting of one or more 

domestic establishments that were specified under common ownership or control. 

The enterprise and the establishment are the same for single-establishment firms. 

Each multi-establishment company forms one enterprise—the enterprise 

employment and annual payroll are summed from the associated establishments. 

Enterprise size designations are determined by the summed employment of all 

associated establishments. 

Because the SBA’s business size definitions (SBA, 2008c) apply to an establishment’s “ultimate 

parent company,” EPA assumes in this analysis that the “enterprise” definition above is 

consistent with the concept of ultimate parent company that is typically used for Small Business 

Regulatory Enforcement Fairness Act (SBREFA) screening analyses, and the terms are used 

interchangeably. EPA also reports the SBA size standard(s) for each industry group in order to 

facilitate comparisons and different thresholds. 
5-14 

Table 5-11 Number of Establishments by Affected Industry and Enterprisea Size: 2002 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total 

Establishments

Owned by Enterprises with:

Industry NAICS NAICS Description 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

< 500 

Employees 

50

Em

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and Natural 

Gas Extraction 

500 7,629 5836 456 292 6,584 

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline Transportation of 

Natural Gas 

b 1,936 81 27 61 169 

Natural gas distribution 221210 Natural Gas Distribution 500 2,897 483 86 131 700 

aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under com

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterppayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated estaBecause the SBA’s business size definitions (www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumes in this analysis th

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBRE

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. 
5-15 

Table 5-12 Number of Employees by Affected Industry and Enterprisea Size: 2002 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total 

Employees

Owned by Enterprises with:

Industry NAICS NAICS Description 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

< 500 

Employees 

50

Em

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and 

Natural Gas Extraction 

500 88,280 19,336 12,113 11,656 43,105 

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline Transportation of 

Natural Gas 

b 37,450 347 157 1,053 1,834 

Natural gas distribution 221210 Natural Gas Distribution 500 86,890 1,956 1,899 4,398 8,420 

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under com

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterppayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated estaSince the SBA’s business size definitions (www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumes in this analysis that 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBRE

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. cThe U.S. Census Bureau has missing data for this employee range. 
5-16 

Table 5-13 Receipts by Affected Industry and Enterprisea Size: 2002 

SBA Size 

Standard 

(effective 

March 

11, 2008)

Total 

Receipts 

($Million)

Owned by Enterprises with:

Industry NAICS NAICS Description 

1 to 20 

Employees 

($ 

thousands) 

20 to 99 

Employees 

($ 

thousands 

100 to 499 

Employees 

($ 

thousands) 

< 500 

Employees 

 ($ 

thousands) 

500 

Emp

thou

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and 

Natural Gas Extraction 

500 $160,879 $7,573 $6,790 $9,609 $23,972 $4

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline Transportation 

of Natural Gas 

b $35,897 $1,035 $106c $394c $2,566 

Natural gas distribution 221210 Natural Gas Distribution 500 $67,275 $2,524 $4,642 $2,878 $13,127 $a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under com

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterppayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated estaSince the SBA’s business size definitions (www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumes in this analysis that 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBRE

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. c The U.S. Census Bureau has missing data for this employee range. The receipts for the 1 to 20 range therefore underestimate true value. 
5-17 

5.2.2 Developing Small-Entity Economic Impact Measures 

Because Subpart W covers businesses, the analysis generated a set of sales tests 

(represented as cost-to-receipt ratios)20 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 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 to 

account for differences in establishment receipts between large and small enterprises and 

differences in small business definitions across affected Subpart W industries. It is also a 

conservative approach because it does not screen out entities that would be below the reporting 

threshold. It is also conservative because an establishment’s parent company (the “enterprise”) 

may have other economic resources that could be used to cover the costs of the reporting 

program. It must be noted that the 1,000 to 1,499 employee category does not belong to the small 

business category; however, the category has been included to provide a comparison with small 

business cost-to-receipt ratios. 

These sales tests examine the average establishment’s total annualized mandatory 

reporting costs to the average establishment receipts for enterprises within several employment 

categories21 (first-year costs: Table 5-14; subsequent-year costs: Table 5-15). 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. 

 

20Metrics for other small-entity economic impact measures (if applicable) would potentially include: 

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

revenues. 

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

expenses. 21The ratios for the 1 to 20 employee category are conservative because they include SUB data for enterprises with zero 

employees; these enterprises did not operate the entire year. Exclusion of enterprises with zero employees would result in 

slightly lower cost-to-sales ratios (e.g., 1.22% for NAICS 211). 
5-18

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

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($1,000/ 

entity) 

All 

Enterprises 

Owned by Enterprises w

Industry NAICS NAICS Description 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

< 500 

Employees 

5

E

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and 

Natural Gas Extraction 

500 $17.1 0.08% 1.32% 0.11% 0.05% 0.47% 

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline 

Transportation of Natural Gas 

b $15.7 0.08% 0.12% 0.40%c 0.24%c 0.10% 

Natural gas distribution 221210 Natural Gas 

Distribution 

500 $13.9 0.06% 0.27% 0.03% 0.06% 0.07% 

aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or 

establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are s

establishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA’s business size definitions (www

establishment’s ultimate parent company, EPA assumes in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company thaBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses. 

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate true 
5-19

Table 5-15 Establishment Sales Tests by Industry and Enterprisea Size: Subsequent-Year Costs a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under comThe enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterppayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated estaSince the SBA’s business size definitions (www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumes in this analysis that 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBRE

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories u

which results in conservative estimates of cost-to-sales ratios. 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($/entity)

All 

Enterprises 

Owned by Enterprises w

Industry NAICS NAICS Description 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

< 500 

Employees 

50

Em

Onshore petroleum and 

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 

211 Crude Petroleum and 

Natural Gas Extraction 

500 $7.5 0.04% 0.58% 0.05% 0.02% 0.21% 

Onshore natural gas 

transmission; underground natural gas storage; LNG storage; LNG import and export 

486210 Pipeline 

Transportation of Natural Gas 

b $6.9 0.04% 0.05% 0.18%c 0.11%c 0.05% 

Natural gas distribution 221210 Natural Gas 

Distribution 

500 $9.2 0.04% 0.18% 0.02% 0.04% 0.05% 
5-20 

5.2.3 Results of Screening Analysis 

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will 

not have a significant economic impact on a substantial number of small entities. Small entities 

include small businesses, small governmental jurisdictions, and small not-for-profit enterprises. 

For the purposes of assessing the impacts of Subpart W of the rule on small entities, EPA 

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, independently owned and operated, and not dominant in its field. 

EPA believes the selected thresholds maximize the rule coverage with 85 percent of all 

U.S. petroleum and natural gas systems emissions reported by approximately 2,786 reporters, 

while keeping reporting burden to a minimum and excluding small emitters. Furthermore, many 

Subpart W industry stakeholders with whom EPA met expressed support for a 25,000-MtCO2e 

threshold because it sufficiently captures the majority of GHG emissions in the United States 

while excluding smaller facilities and sources. After considering the economic impact of the final 

rule on small entities, EPA has concluded that this action will not have a significant economic 

impact on a substantial number of small entities. As shown in Table 5-14 and Table 5-15, 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, the small business analysis does not screen out entities that would be below the reporting 

threshold. Based on further analysis of production data in HPDI, EPA estimates that in most 

cases, the small enterprises have very small operations (such as a single family owning a few 

production wells) that are highly unlikely to cross the 25,000-MtCO2e reporting threshold. 

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. 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 
5-21 

operator in HPDI shows a ratio of less than one percent for the operators expected to meet the 

reporting threshold. 

5.3 Synopsis of Benefits 

Under the Mandatory GHG Reporting Rule, EPA requires the collection and verification 

of emission data from Subpart W facilities. This section reviews the benefits of a mandatory 

reporting program for Subpart W facilities based on previous experience with emission inventory 

programs in the United States and abroad. 

Recent policy discussions have highlighted potential benefits to society of the mandatory 

GHG reporting program (Pew, 2008). Benefits to the public include: building public confidence 

through clear and transparent emission measures and reports and making petroleum and natural 

gas facilities accountable for their equipment leaks and vented emissions. A GHG reporting 

system will also have the benefit of providing policymakers and analysts with a data set that is 

comprehensive for the petroleum and natural gas industry if reporting is conducted under 

Subpart W and other applicable subparts. Benefits to the industry include: identifying costeffective GHG reduction opportunities and disclosing information, which provides firms with 

incentives to reduce emissions voluntarily and provides emission data to service industries, such 

as insurance and financial markets. Availability of emission information to the public, 

consumers, investors, corporations, and government regulators provides a sound basis for future 

policy analysis, which benefits society as a whole. Accurate and transparent information is 

necessary for the implementation of efficient approaches that meet environmental goals with the 

lowest cost to the economy. 

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 GHG Reporting Rule. 

6.1 Executive Order 12866: Regulatory Planning and Review 

Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a 

"significant regulatory action” because it raises novel legal or policy issues arising out of legal 

mandates, the President’s priorities, or the principles set forth in the EO. Accordingly, EPA 

submitted this action to the Office of Management and Budget (OMB) for review under EO 

12866. 

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. 

EPA plans to collect complete and accurate 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 and the distribution of emissions from individual facilities 

within those industries. The facility-specific data will also improve our understanding of the 

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

emissions. Additionally, EPA will be able to track the trend of emissions from facilities within 

the petroleum and natural gas industry over time, particularly in response to policies and 

potential regulations. The data collected by this rule will improve EPA’s ability to formulate 

climate change policy options and to assess which segments of the petroleum and gas industry 

would be affected, and how these segments would be affected by the options. 
6-2 

This information collection is mandatory and will be carried out under CAA section 114. 

Information identified and marked as CBI will not be disclosed except in accordance with 

procedures set forth in 40 CFR part 2. However, emissions data collected under CAA section 

114 cannot generally be claimed as CBI and will be made public. 

The projected cost and hour burden for non-Federal respondents 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 cost annualized over the equipment’s expected useful life (averaging $0.74 million), 

a total operation and maintenance component (averaging $1.7 million per year), and a labor cost 

component (averaging $25.3 million per year)22. 

Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown 

elsewhere in the EIA for these subparts 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 for the first year of the rule and for subsequent years of the rule. In 

addition, the ICR focuses on respondent burden, while the EIA includes both national 

compliance costs and the burden for EPA to implement the rule. 

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is 

approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the 

Federal Register to display the OMB control number for the approved information collection 

requirements contained in this final rule. 

 

22 Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown elsewhere in the Economic 

Analysis because the ICR costs represent the average cost over the first three years of the proposed rule, but costs 

are reported elsewhere in the Economic Analysis for the first year of the proposed rule and for subsequent years of 

the proposed rule. In addition, the ICR focuses on respondent burden, while the Economic Analysis includes EPA 

Agency costs. 
6-3 

6.3 Regulatory Flexibility Act 

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any 

rule subject to notice and comment rulemaking requirements under the Administrative Procedure 

Act or any other statute unless the agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small entities include small 

businesses, small organizations, and small governmental jurisdictions. 

For purposes of assessing the impacts of this final rule on small entities, small entity is 

defined as: (1) 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 

organization that is any not-for-profit enterprise that is independently owned and operated and is 

not dominant in its field. 

After considering the economic impacts of this final action on small entities, I certify that 

this action will not have a significant economic impact on a substantial number of small entities. 

 

The small entities directly regulated by this final rule include small businesses in the 

petroleum and gas industry, small governmental jurisdictions and small non-profits. EPA has 

determined that some small businesses will be affected because their production processes emit 

GHGs exceeding the reporting threshold. 

For affected small entities, EPA conducted a screening assessment comparing 

compliance costs for affected industry segments to petroleum and gas-specific data on revenues 

for small businesses. This ratio constitutes a “sales” test that computes the annualized 

compliance costs of this final rule as a percentage of sales and determines whether the ratio 

exceeds some level (e.g., 1 percent or 3 percent). The cost-to-sales ratios were constructed at the 

establishment level (average compliance cost for the establishment/ average establishment 

revenues). 
6-4 

As shown in 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. It is 

important to note that this analysis does not screen out entities that would be below the reporting 

threshold. Although the costs to receipts for entities in onshore production with 1-20 employees 

is slightly over 1 percent, most of these facilities would likely not exceed the 25,000 mtCO2e 

threshold, a threshold supported by many stakeholders as one that sufficiently captures the 

majority of GHG emissions while excluding small facilities. 

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, EPA determined that the final rulemaking would not have a significant 

impact on small governmental jurisdictions. EPA determined that one segment of the petroleum 

and natural gas industry might include small governments affected by the final rulemaking. A 

comparison of the compliance costs to the revenue of potentially affected small governmental 

jurisdictions revealed that the costs of the rule are less than 1 percent of revenues. 

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 different monitoring methods for 

different emissions sources, requiring direct measurement only for selected sources. Also, EPA 

intends to provide a screening tool that will help small businesses make a reporting 

determination (see Section II.F.6 of the preamble). Finally, EPA is establishing annual instead of 

more frequent reporting. 

Through comprehensive outreach activities prior to proposal of the initial rule, EPA held 

approximately 100 meetings and/or conference calls with representatives of the primary audience 
6-5 

groups, including numerous trade associations and industries in the petroleum and gas industry 

that include small business members. EPA’s outreach activities prior to proposal of the initial 

rule are documented in the memorandum, Summary of EPA Outreach Activities for Developing 

the Greenhouse Gas Reporting Rule, located in Docket No. EPA-HQ-OAR-2008-0508-053. 

After the initial proposal, EPA posted a guide for small businesses on the EPA GHG reporting 

rule website, 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 rule. EPA continued to meet with stakeholders and entered documentation of all meetings 

into the docket. 

During rule implementation, EPA would maintain an “open door” policy for stakeholders 

to ask questions about the final rule or provide suggestions to EPA about the types of compliance 

assistance that would be useful to small businesses. EPA intends to develop a range of 

compliance assistance tools and materials and conduct extensive outreach for the final rule. 

 

EPA has therefore concluded that this final action will not have a significant economic 

impact on a substantial number of small entities. 

6.4 Unfunded Mandates Reform Act 

This 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 in 

any one year. EPA estimated 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 

costs to non-reporters for determination to report. The sum of these costs for the entire industry 

has been estimated to be less than $100 million. Thus, this rule is not subject to the requirements 

of sections 202 or 205 of UMRA. 

This 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 
6-6 

operated by small governments are expected to be too small to trigger the 25,000 metric tons 

CO2e reporting threshold. 

6.5 Executive Order 13132: Federalism 

This action does not have federalism implications. It will not have substantial direct 

effects on the States, on the relationship between the national government and the States, or on 

the distribution of power and responsibilities among the various levels of government, as 

specified in EO 13132. This regulation applies directly to petroleum and natural gas facilities 

that emit greenhouse gases. Few, if any, State or local government facilities would be affected. 

This regulation also does not limit the power of States or localities to collect GHG data and/or 

regulate GHG emissions. Thus, EO 13132 does not apply to this action. 

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments 

EPA has concluded that this action may have tribal implications. 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, EPA analyzed a 

comprehensive listing of all operators of petroleum and natural gas systems in the United States 

in conducting the threshold analysis. In a separate analysis, EPA researched additional available 

data to determine which tribal entities may own or operate petroleum and natural gas systems 

that could be impacted by this final action. As a result of those analysis, EPA found one tribe that 

may potentially be impacted by this final action. Finally, during the comment period for the 

April 2010 proposal, EPA received comment from one tribe, Southern Ute, which were specific 

to the proposed reporting methodologies. 

As further discussed in the 2009 final rule that established the Greenhouse Gas reporting 

program, EPA believes that there are minimal impacts to tribes. Tribes could be required to 

submit an annual GHG report for any facility they own or operate that is subject to the rule. 

Specifically, tribes that own or operate oil and gas operations could 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. 
6-7 

EPA sought opportunities to provide information to tribal governments and representatives 

during rule development. As stated in IV.F of the preamble, Executive Order 13175: 

Consultation and Coordination with Indian Tribal Governments of 40 CFR part 98, and 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 the proposal phase of Part 98. For example, EPA staff provided 

information to tribes through conference calls with multiple Indian working groups and 

organizations at EPA that interact with tribes and through individual calls with two Tribal board 

members of The Climate Registry (TCR). 

In addition, EPA prepared a short article on the Greenhouse Gas Reporting Program that 

appeared on the front page of a Tribal newsletter—Tribal Air News—that was distributed to 

EPA/OAQPS’s network of Tribal organizations. EPA gave a presentation on various climate 

efforts, including the Greenhouse Gas Reporting Program, at the National Tribal Conference on 

Environmental Management on June 24-26, 2008. In addition, EPA distributed copies of a short 

information sheet at a meeting of the National Tribal Caucus. See the Summary of EPA 

Outreach Activities for Developing the GHG reporting rule, in Docket No. EPA-HQ-OAR-2008-

0508-055 for a complete list of Tribal contacts. EPA participated in a conference call with 

Tribal air coordinators in April 2009 and prepared a guidance sheet for Tribal governments on 

the final Part 98. It was posted on the Greenhouse Gas Reporting Program website and 

published in the Tribal Air Newsletter. 

As required by section 7(a), EPA’s Tribal Consultation Official has certified that the 

requirements of the Executive Order have been met in a meaningful and timely manner. A copy 

of the certification is included in the docket for this action. 

6.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks 

 This action is not subject to EO 13045 because it does not establish an environmental 

standard intended to mitigate health or safety risks. Also, this is not an economically significant 

rule under EO 12866, and thus EO 13045 does not apply. 
6-8 

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

Distribution, or Use 

This final rule is not a “significant energy action” as defined in EO 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 concluded that this final rule is not likely to 

have any adverse energy effects. This final rule relates to monitoring, reporting and 

recordkeeping at petroleum and gas facilities that emit over 25,000 mtCO2e and does not impact 

energy supply, distribution or use. Therefore, EPA concludes that this final rule is not likely to 

have any adverse effects on energy supply, distribution, or use. 

6.9 National Technology Transfer and Advancement Act 

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. Voluntary consensus standards are technical standards 

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations when the Agency decides not to use available and 

applicable voluntary consensus standards. 

This rulemaking involves technical standards. EPA provides the flexibility to use any 

one of the voluntary consensus standards from at least seven different voluntary consensus 

standards bodies, including the following: ASTM, ASME, ISO, Gas Processors Association, and 

American Gas Association. These voluntary consensus standards will help facilities monitor, 

report, and keep records of greenhouse gas emissions. No new test methods were developed for 

this final rule. Instead, EPA reviewed existing rules for source categories and voluntary 

greenhouse gas programs and identified existing means of monitoring, reporting, and keeping 

records of greenhouse gas 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. 
6-9 

By incorporating voluntary consensus standards into this final rule, EPA is both meeting 

the requirements of the NTTAA and presenting multiple options and flexibility for measuring 

greenhouse gas emissions. 

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 executive 

policy on environmental justice. Its main provision directs Federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States. 

EPA has determined that this final rule will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income populations because it does 

not affect the level of protection provided to human health or the environment because it is a rule 

addressing information collection and reporting procedures. 

7-1 

SECTION 7

CONCLUSIONS AND IMPLICATIONS 

In this EIA, EPA has examined the regulatory background, the development of the 

mandatory GHG meporting rule for Subpart W, and estimated costs and benefits of 

implementing this subpart. This section presents EPA’s 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 and monitoring methodology—that were 

finalized in today’s rule. The final rule calls for: 

– A threshold of 25,000-MtCO2e threshold for all facilities. 

– A hybrid methodology, including use of limited direct spot measurement, facilityspecific calculation methods, and use of emission factors (leaker and population 

factors). 

Other scenarios evaluated during the development of the proposal included the following: 

1. A 1,000-MtCO2e threshold; selected options for methodology, frequency, and 

verifier. 

2. A 10,000-MtCO2e threshold; selected options for methodology, frequency, and 

verifier. 

3. A 100,000-MtCO2e threshold; selected options for methodology, frequency, and 

verifier. 

4. The measurement variable is changed to direct spot measurement; selected option for 

threshold. 
7-2 

5. The measurement variable is changed to default emission factors; selected option for 

threshold. 

7.1.2 Affected Source Categories 

EPA considered direct emitters of equipment leaks and vented GHGs under Subpart. 

From these emission sources, EPA identified eight segments under the Subpart W source 

category for which costs and impacts were examined. 

7.2 Assessment of Costs and Benefits of the Mandatory Greenhouse Gas Reporting Rule 

7.2.1 Estimated Costs and Impacts of the Mandatory Greenhouse Gas 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 MtCO2e per year. The total annualized costs incurred 

under the rule by these entities would be $61.8 million for the first year and $19.0 million for 

subsequent years. 

Overall, economic impacts on industry segments are measured by comparing per-entity 

costs with average per entity receipts. These cost-to-sales ratios are less than 1 percent for 

establishments owned by small businesses that EPA considers most likely to be covered by the 

reporting program (e.g., establishments owned by a business with 20 or more employees) and 

small government entities. This analysis enables EPA to determine that the final rule will not 

have a significant economic impact on a substantial number of small entities. Overall, Subpart W 

of the rule will impose national costs exceeding $61.8 million in the first year and $19.0 million 

in subsequent years; the costs will be widely dispersed throughout the economy and relatively 

low on a per-entity basis. The estimated national costs represent less than 0.001 percent of 2007 

gross domestic product. Thus, EPA does not estimate that there will be significant impacts on the 

economy in general or on individual segments or small entities within Subpart W. 

7.2.2 Summary of Qualitative Benefits Assessment 

EPA did not quantify the estimated benefits of the final rule. Instead, a qualitative 

assessment was performed, based on information from the literature and previous benefits 

assessments of existing emission inventory programs. 

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 facilities accountable 

for their emissions. Benefits to petroleum and natural gas industry include identifying GHG 

reduction opportunities and disclosing information, which provides firms with incentives to 
7-3 

reduce emissions voluntarily and provides emission data to service industries, such as insurance 

and financial markets. A GHG reporting system will also have the benefit of providing 

policymakers 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 

describe the following types of benefits: 

– Public 

– More information will lead to increased levels of trust towards government 

and industry where there are right-to-know laws concerning emissions. 

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

– More information will enable environmentally aware consumers to alter their 

consumption habits based on GHG emissions of producers. 

– Industry 

– Public relations: Having independent, verifiable data to present to the public 

would demonstrate appropriate environmental stewardship. 

– Standardization: Uniform industry standards would reduce the cost of 

reporting relative to non-uniform, jurisdiction-specific, and allow facilities to 

benchmark their performance against other similar facilities. 

– Potential cost savings: Mandatory monitoring may uncover previously 

unmeasured wasteful processes, yielding cost-saving conservation 

opportunities that would offset some of the costs of monitoring. 
7-4 

– Potential customer data for service industries: Information about GHGemitting firms will be useful for firms that market emission-reduction 

technologies, and to insurance companies for assessing risk. 

– Investors 

– Information about emissions will enable investors to implement socially 

responsible investing using GHG emission information if they so choose. 

– Government 

– Policy development: The greatest benefit to government of mandatory GHG 

reporting is the comprehensive, consistent data it would provide, enabling 

government to develop accurate, informed future GHG policy. 

– Comparability: A mandatory system would reduce the difficulties associated 

with comparing across different reporting standards across states or programs. 

– Compliance and policy evaluation: Publicly available nationwide data on 

GHG emissions will enable government to develop and robustly evaluate 

environmental policies, and to ensure compliance with the policies once 

implemented. 

7.3 What Did We Learn through This Analysis? 

EPA’s examination of the costs and benefits of the provisions in Subpart W of the 

mandatory GHG reporting rule revealed that the final rule will impose an estimated $30.9 

million (based on average of first-year and subsequent-year costs) in monitoring, recordkeeping, 

and reporting costs on emitters of GHGs that are widely distributed throughout the U.S. 

economy. Impacts of the costs on individual segments and entities are expected to be generally 

small, comprising less than 1 percent of entity receipts and approximately 0.001 percent of 2007 

gross domestic product. Thus, despite the overall national costs, macroeconomic impacts are not 

anticipated, and EPA does not believe that the final rule will impose significant economic 

impacts on a substantial number of small entities. 
7-5 

A review of the literature enabled EPA to characterize the expected types of benefits, 

which will be experienced by stakeholders, including the public, industry, investors, and 

government. Based on this qualitative assessment and evidence from other existing programs, 

EPA expects the benefits of the final rule to be substantial. 

8-1 

SECTION 8

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