Economic Impact Analysis for the 

Mandatory Reporting of Greenhouse 

Gas Emissions Under Subpart W Final 

Rule (GHG Reporting)

PRELIMINARY DRAFT

Final Report

August, 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 Roles...................................................................................... 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 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............................... 1-13

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

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

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

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

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

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

2.1.5 Analysis of Emissions from the Petroleum and Natural Gas 

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

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

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

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

2.3.6 State and Regional Mandatory Programs for Greenhouse Gas 

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

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

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

3.1 Rule Dimensions for 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......................................................................................... 4-8

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

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

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

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

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

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

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

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

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

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

4.5.3 Capital Cost Annualization and O&M Costs......................................... 4-35

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

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

5.1.3 Sensitivity of Subsequent Year Cost Estimates....................................... 5-9
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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 Identify Affected Segments and Entities............................................... 5-12

5.2.2 Develop 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 ...................................................................................... 6-2

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

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

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

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

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

6.7 Executive Order 13045: Protection of Children from Environmental Health 

and Safety Risks..................................................................................................... 6-9

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

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

6.9 National Technology Transfer Advancement Act ............................................... 6-10

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice 

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

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

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

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

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

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

7.2.1 Estimated Costs and Impacts of the Mandatory GHG Reporting 

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

7.2.2 Summary of Qualitative Benefits Assessment......................................... 7-2
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7.3 What Did We Learn through This Analysis? ......................................................... 7-4

Section 8 References .................................................................................................................. 8-1
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LIST OF FIGURES

Page

Figure 5-1 Average and Marginal Cost per Metric Ton of Emissions Reported by Threshold ...... 5-7

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

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LIST OF TABLES

Page

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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 Emissions Coverage and Entities Reporting for Field Level Facility Definition 

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

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

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

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

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

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

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

Table 5-14 Establishment Sales Tests by Industry and Enterprisea

5-19

Size: Subsequent Year 

Costs .......................................................................................................................
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SECTION 1

INTRODUCTION AND BACKGROUND

1.1 Background

On December 26, 2007, President Bush signed the FY2008 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 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 emission resulting 

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

Administrator deems it appropriate. The Administrator shall determine 

appropriate thresholds of emissions 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 Reporting Rule (40 CFR Part 98) on September 22, 

2009, which was published in the October 30, 2009 Federal Register (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 emissions data from two 

additional segments in the petroleum and natural gas source category. EPA also released an 

Economic Impact Analysis (EIA) in April, 2010 that assessed the proposed rulemaking’s costs 

and benefits.

1

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

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

equivalent (CO2e) process emissions, or on average $0.16/metric ton CO2e. This compares with 

the estimate of $0.38/metric ton under the April, 2009 proposal.

2

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

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

underground storage, LNG storage and LNG import & 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 emissions 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 several key changes in today’s final rule that affect the compliance cost 

estimates. First, the final rule provides floors on several emissions sources. Reporters will use a 

simple population based emissions factors for sources below the floor. Second, EPA has

. There are also some sources that would use population based 

factors—often referred to as default factors—primarily for inaccessible sources or relatively 

small leaking sources. Consistent with the April, 2010 proposed rulemaking and the Technical 

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

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

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

production platforms. This leverages an existing GHG data collection process and minimizes

burden.

 2 For the final rule, 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 emissions reporting by reporters. The April, 2009 analysis did not 

include a burden estimate for non-reporters to make a threshold determination. 3 Leaker factors are developed by actual measurement of leaks from a large population of common fugitive or 

vented sources; the emissions quantification requires actual detection of a leak before application of a factor. This 

provides a truer assessment of actual emissions than “population” emissions 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.
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simplified the required for sampling of gas and emissions for many of the emissions sources, 

thus considerably reducing burden.

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

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

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

emissions costs for reporters changed from $0.36/metric ton CO2e in the April, 2009 proposed

rule to $0.28/metric ton CO2e in the April, 2010 proposal, and to $0.33/metric ton CO2e in the 

final rulemaking, based on average “first year” costs. 4,5 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/metric ton CO2e in the first year, which is less than the first year cost of 

$0.21/metric ton CO2e in the April 2010 proposed rulemaking. 

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

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

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

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

threshold in the absence of Subpart W. However, those that meet the emissions threshold under 

Subpart W 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 MRR to result in the reporting of additional combustion emissions under 

Subpart C, referred to as “incremental combustion emissions” in this document. Of the 162.2 

million metric tons CO2e expected to be reported under Subpart C, 83.5 million metric tons

CO2e are the combustion emissions from petroleum and natural gas facilities that would not have 

reported in the absence of Subpart W. The incremental combustion emissions reporting is $3.3 

million per year of the total combustion emissions cost, or $0.04/metric ton CO2

Year one costs for Subpart W vented and equipment leak emissions are significantly 

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

leaks and vented emissions determination, decreasing to $15.1 million in subsequent years. The 

higher burden is due to start-up costs in the first year. For example, the rule requires the 

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

e. 

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

5 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 IPCC. Also, subsequent year costs are the average of costs subsequent to 

year one costs, and thereby represent a “steady-state” time period.
1-4

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 CH4 and/or 

CO2

2) equipment leaks, which are defined to include those emissions which are 

unintentional and could not reasonably pass through a stack, chimney, vent, or 

other functionally-equivalent opening; and 

containing natural gas or hydrocarbon gas (not including stationary 

combustion flue gas) from emissions sources including, but not limited to, 

open ended lines, gas pneumatic powered valves and pumps, equipment 

depressuring to the atmosphere and compressor shaft seals; 

3) flare combustion emissions, which include CH4, CO2 and N2

1.2 Role of the Economic Impact Analysis in the Rulemaking Process

O emissions 

resulting from combustion of gas in flares.

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 FY08 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)6

 6 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.

of the CAA authorizes the Administrator to, inter alia, require certain 

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

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

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

operates an emission source, (ii) manufactures control or process equipment, (iii) the 
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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 1297

, determining if any 

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

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)8

• Final rulemaking with DOT to limit greenhouse gas emissions from light-duty 

vehicles, “Light-Duty Vehicle Greenhouse Gas Emission Standards and 

Corporate Average Fuel Economy Standards,” (75 FR 25324, May 7, 2010); 

.

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: 

• 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); and 

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

 7 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.” 8 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. 
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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 MRR and this final rulemaking do not indicate 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 economy-wide data on facilitylevel (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 our understanding of the factors that influence GHG 

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

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

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

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

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

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

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

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

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

associated with a range of reporting thresholds.

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

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

may result when the mandatory reporting program is implemented.

1.2.2 Role of Statutory and Executive Orders

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

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

executive orders is presented in Section 6.
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EPA presents this Economic Impact Analysis for Subpart W—Petroleum and Natural 

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

Budget (OMB) Circular A-4, and EPA’s Economic Guidelines9

1.2.3 Illustrative Nature of the Analysis

. 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 Economic Impact Analysis 

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

of the program. Section 5 also qualitatively describes the benefits of the final rulemaking. 

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 Baseline and Years of Analysis

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

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

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

circulars/a004/a-4.pdf. 
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emissions monitoring, and reporting activities for this industry. While EPA recognizes that 

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

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

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

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

as a proxy for conditions 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 over 484 significant and detailed comments (over 

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 see how these programs treat emissions from the petroleum

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

that, to the extent possible and appropriate, is consistent with existing GHG emission estimation 

and reporting methodologies in order to reduce the burden of reporting for all parties involved. 

The TSD documents our review of GHG monitoring protocols for each segment identified by 

Subpart W that is used by federal, state, regional, and international voluntary and mandatory 

GHG programs, and our 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 identification of anthropogenic sources in 

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

would require reporting of CO2 and CH4 equipment leak and vented emissions, and combustionrelated emissions10 of CO2 and CH4 and N2O as defined in the rule. The IPCC focuses on CO2, 

CH4 and N2

 10 It must be noted that only flaring emissions are required for reporting under this Subpart of the MRR. All other 

combustion related emissions are to be reported under Subpart C of the finalized MRR.

O for both scientific assessments and emissions inventory purposes because these 

are long-lived, well-mixed GHGs not controlled by the Montreal Protocol on Substances that 

Deplete the Ozone Layer. These GHGs are directly emitted by human activities, are reported 
1-9

annually in EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks, and are the common 

focus of the climate change research community.

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

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

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

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

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

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

measurement and reporting methods for this final rulemaking.

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

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

the list of source categories included in the proposal:

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

minimizing the number of reporters; and 

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

Source categories that would be required to report were identified. Sources were then 

screened 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, possible reporting methodologies for the selected sources were developed. The 

reporting methodologies identified fall into several categories, including continuous emissions 

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

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

of continuous emissions monitoring and calculations based on site-specific information.

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

detection and direct spot measurement11

 11 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” as it is not 

continuous.

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

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

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

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

emissions quantification is through effective but less burdensome use of engineering estimates 

and leak detection with use of leaker factors and component population count and population 

(default) emission factors.

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

different rule options across the following dimensions:

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

o 1,000 metric tons CO2

o 10,000 metric tons CO

e/year;

2

o 25,000 metric tons CO

e/year;

2

o 100,000 metric tons CO

e/year; and

2

– Methodology for measuring emissions;

e/year.

o Direct spot measurement;

o Facility-specific calculation methods; and

o Leaker and default emissions 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 April, 2009 Proposed Rulemaking to April, 2010 

Proposed Rulemaking

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

rulemaking for all subparts; over 1,200 pages of those comments focused on Subpart W. EPA 

held two public hearings and conducted an unprecedented level of outreach between signature of 

the proposal and the close of the public comment period. Below 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 was used, in others leak detection coupled with 

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

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

“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 

was minimized.

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

GOADS emissions results for offshore platforms in Federal Gulf of Mexico 

(GoM) waters to avoid redundancy of reporting efforts.

12

 12 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 The Minerals Management Service (MMS). The 

MMS mandated that all 2525 offshore operators in the Gulf of Mexico conduct annual surveys (in 2000 and 2005) 

of their GHG and other hazardous pollutants. The MMS collects activity data from each platform that is then used 

to estimate emissions. The usual cycle for this data collection effort has been once in every three to four years.

We also required that

facilities not covered by GOADS (State waters and Federal non-GoM platforms) 

use data collection and emissions calculation methods in accordance with the 

MMS GOADS program to reduce burden and make emissions reporting 

consistent across the segment.
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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 metric tons of CO2

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

less than 15,000 metric tons of CO

e for 5 years to cease annual reporting to 

EPA.

2

– 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.

e for 3 years to cease annual reporting to 

EPA.

– Added a provision in 40 CFR 98.3 for submittal of revised annual GHG reports to 

correct errors.

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

flow meters.

– Excluded 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 (ARP regulations).

– Changed record retention to 3 years instead of 5 years for most records (40 CFR 

98.3).

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

monitoring plan (called the 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 

emissions spot measurements.
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1.3.2.2 Summary of the Major Changes from April, 2010 Proposed Rulemaking to 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 a floor for compressors, separators, and dehydrators such that sources 

below the floor use a simplified population emissions factor approach and sources 

above the floor use actual monitoring;

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

equipment rather than individual components;

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

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

acceptable; and

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

toxic vapor analyzers, in addition to using infrared devices.

The above changes significantly reduce burden and simplify reporting of emissions.

1.3.3 Evaluating Costs and Benefits

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

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

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

alternative by examining the costs per million metric ton of CO2 equivalent (MMtCO2

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative

e) 

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

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

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 emissions 

coverage.
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– Threshold: 25,000 metric tons CO2

– The thresholds for the finalized MRR fall generally into three groups: 

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

facility that emits 25,000 metric tons CO

e/year

2

– Subpart W facilities determine their applicability by comparing their 

emissions to a threshold of 25,000 metric tons CO

e/year or more reports all sources 

for which there are methods specified in the Rule.

2

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

and equipment leaks and stationary combustion-based emissions.

e/year.

– 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 emissions 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 emissions data that can be 

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

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

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

supplement rather than duplicate other U.S. government GHG programs. We outline EPA’s 

overall rulemaking approach, sources considered, and summarize our 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 our review of state mandatory GHG 

rules below. For example, the monitoring and GHG calculation methodologies for many of the 

petroleum and natural gas systems are the same as, or similar to, the methodologies contained in 

state reporting programs. The remainder of the section provides an overview of related existing 

programs and discusses their relevance in the development of this rule.

2.1 EPA’s Overall Rulemaking Approach

In response to the FY2008 Consolidated Appropriations Amendment, EPA has developed 

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

2.1.1 Identifying the Goals of the Greenhouse Gas Reporting System

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

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

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

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

Because we do not know at this time the specific policies that will be adopted, the data reported 

through the mandatory reporting system should be of sufficient quality to support a range of 

approaches. Also, consistent with the Appropriations Amendment, the reporting rule covers a 

broad range of source categories in the economy; however, this Economic Impact Analysis for 

the final rulemaking is specific to Subpart W, petroleum and natural gas systems.

To these ends, we 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.

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

while minimizing reporting from small emitters. 
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– 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 Evaluation of Existing Greenhouse Gas Reporting Programs

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

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

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

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

Therefore, we performed a comprehensive review of existing voluntary and mandatory GHG 

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

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

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

– U.S. national programs, such as the U.S. GHG inventory, the ARP, DOE 1605(b) 

voluntary registry, and voluntary GHG partnership programs (e.g., Natural Gas 

STAR);

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

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

Mexico, and New Jersey;

– Reporting protocols developed by nongovernmental organizations, such as the

World Resources Institute/World Business Council for Sustainable Development 

(WRI/WBCSD); and

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

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

Gas Industry.

In reviewing these programs, we analyzed the segments covered, thresholds for reporting, 

the monitoring or emission estimating methods used, the measures to assure the quality of the 

reported data, the point of monitoring, data input needs, and information required to be reported 
2-3

and/or retained. We analyzed these provisions for suitability to a mandatory, federal GHG 

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

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

and guidance for all MRR subparts may be found in the docket at EPA-HQ-OAR-2008-0508-

054.

2.1.4 Stakeholder Outreach to Identify Reporting Issues

Early in the development process of the MRR, EPA conducted a proactive 

communications outreach program to inform the public about the rule development effort. EPA

solicited input and maintained an open door policy for those interested in discussing the 

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

including the following:

– trade 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 emissions reporting, 

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

Initiative (WCI); and

– environmental groups and other nongovernmental organizations.

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

GHG emissions.

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

timetable for developing a rule. Stakeholders were encouraged 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 

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.13

 13 For a full list of organizations EPA met with when developing this rule, please see the EPA docket memo, EPAHQ-OAR-2008-0508-055.
2-4

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

public hearings, and received over 16,000 written public comments. The public comment period 

ended on June 9, 2009. Subpart W received comments from over 80 entities with over 1,200 

pages of comments, recommendations and alternatives for consideration.

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

conducted during the development of the proposal. As a result, EPA met with over 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-HQ-OAR2009-0923).

2.1.5 Consideration of Public Comments on Key Reporting Issues

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

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

process EPA held one public hearing and received over 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 preamble of today’s 

final rule for a complete discussion about these changes.

2.1.6 Analysis of 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 

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.
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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 Emission 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 which are unintentional and could not reasonably pass 

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

include leaks from valves and connectors.

Flare combustion: Means 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 emissions sources to be 

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

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

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

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

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

Subpart W.

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

State programs during development of the rule. Documentation of our review of GHG 

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

and mandatory GHG programs, and our 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, CCAR (California Climate Action Registry), 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 emissions 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.
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The intent of this rule is to collect a reasonable estimate of GHG emissions data that can 

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

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

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

gas facilities submitting reports to other programs. However, we also need to be sure the 

mandatory 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, N2

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

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

O, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.

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

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

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

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

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

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

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

methods for its emission estimates.

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

leads an interagency team that includes the DOE, USDA, the Department of Transportation 

(DOT), the Department of Defense (DOD), the State Department, and others. EPA collaborates 

with hundreds of experts representing more than a dozen federal agencies, academic institutions, 

industry associations, consultants, and environmental organizations. The Inventory of U.S. 

Greenhouse Gas Emissions and Sinks is peer-reviewed annually by domestic experts and by 

UNFCCC, and undergoes a 30-day public comment period, and is peer reviewed annually by 

UNFCCC review teams.
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emissions coverage for reporting under the UNFCCC, most GHG emissions in the report are 

calculated via activity data from national-level databases, statistics, and surveys. The use of the 

aggregated national data means that the national emissions estimates are not broken down at the 

geographic or facility level. In contrast, this reporting rule focuses on bottom-up data and 

individual sources above appropriate thresholds. 

The Inventory 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 Institute14 and EPA (GRI/EPA 1996) is 

used as the basis for estimates of CH4 and non-combustion-related CO2

 14 Now the Gas Technology Institute

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 emissions levels. The final rule for Subpart W is estimated to significantly 

increase the level of emissions covered than 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 

website and assumptions based on expert judgment.

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

national inventories for Petroleum 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 emissions 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.
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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

2.3.2.1 Non-CO2 Voluntary Partnership Programs

voluntary programs, and the DOE 1605(b) voluntary GHG registry. Several other federal 

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

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

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

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

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

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

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

segment-specific voluntary methane reduction programs: Natural Gas STAR, Landfill Methane 

Outreach Partnership (LMOP), Coalbed Methane Outreach Programs (CMOP), and Ag STAR. 

In addition, there are segment-specific voluntary emissions reduction partnerships for high global 

warming potential gases. The program specific to those entities that fall under Subpart W is the

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

petroleum industries to adopt practices 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 emissions inventories.

2.3.2.2 1605(b) Voluntary Registry

The DOE Energy Information Administration (EIA) established a voluntary GHG 

registry under Section 1605(b) of the Energy Policy Act of 1992. The program was recently 

enhanced and a final rule containing general reporting guidelines was published on April 21, 

2006 (71 FR 20784); the rule is contained in 10 CFR Part 300. Unlike EPA’s proposal, which 

requires reporting of greenhouse emissions from facilities over a specific threshold, the DOE 

1605(b) registry allows anyone (e.g., a public entity, private company, or an individual) to report 

their emissions and their emissions reduction projects to the registry. Large emitters (e.g., anyone 

that emits over 10,000 metric tons of CO2e per year) who wish to register emissions reductions 

must submit annual company-wide GHG emissions inventories following technical guidelines 
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published by DOE and must calculate and report net GHG emissions reductions. The program 

offers a range of reporting methodologies from stringent direct measurement to simplified 

calculations using default factors and allows the reporters to report using the methodological 

option they choose. For the petroleum and natural gas industry, some methods for estimating 

emissions are outlined, but this petroleum and natural gas section in the 1605(b) Technical 

Guidelines is only meant to serve as a guide. Reporters can use established, published 

authorities’ estimation methods, which must be referenced. In addition, as mentioned above, 

unlike EPA’s proposal, sequestration and offset projects can also be reported under the 1605(b) 

program. There is additional flexibility offered to small sources that can choose to limit annual 

inventories and emissions reduction reports to a single type of activity rather than reporting 

company-wide GHG emissions, but must still follow the technical guidelines. Reported data are 

made available on the Internet in a public use database.

2.3.2.3 Summary

These voluntary programs are different in nature from the mandatory GHG emissions 

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

voluntary. A small number of sources report, compared to the number of facilities that will likely 

be affected by Subpart W of the mandatory GHG reporting rule. Most of the EPA voluntary 

programs do not require reporting of annual emissions data, but are instead intended to 

encourage GHG reduction activities and track partners’ successes in implementing such projects. 

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

mandatory GHG reporting rules. Greenhouse gas emission calculation principles and protocols 

have been developed for various types of emission sources by Climate Leaders, the DOE 

1605(b) program, and some partnerships such as the 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 (TRI)

TRI requires facility-level reporting of annual mass emissions of approximately 650 toxic 

chemicals. If they are above established thresholds, facilities in a wide range of industries report

including manufacturing industries, the petroleum industry, and other industrial segments. 
2-11

Facilities must submit annual reports of total stack and equipment leaks of the listed toxic 

chemicals using a standardized form which can be submitted electronically. No information is 

reported on the processes and emissions points included in the total emissions. The data reported 

to TRI are not directly useful for the GHG rule because TRI does not include GHG emissions 

and does not identify processes or emissions sources. However, the TRI program is similar to the 

GHG reporting rule in that it requires direct emissions reporting from a large number of facilities 

(roughly 23,000) across all major industrial segments. Therefore, EPA reviewed the TRI 

program for ideas regarding program structure and implementation.

2.3.4 Other EPA Emissions Inventories

2.3.4.1 National Emissions Inventory

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

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 source NEI includes over 60,000 facilities. Required point source 

information consists of facility identification information; 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. However, in developing the rule, EPA 

used the NEI to help determine sources that might need to report under Subpart W of the GHG 

reporting rule. We considered the types of facility, process and activity data reported in NEI to 

support the emissions 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 Emissions 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 greenhouse rules, EPA reviewed 

the relevant protocols used by these programs as a starting point. We recognize that these 

programs may have additional monitoring and reporting requirements than those outlined in the 

rule in order to provide distinct program benefits.
2-12

2.3.5.1 California Climate Action Registry

The California Climate Action Registry (CCAR) is a voluntary GHG registry already in 

use in California. CCAR has released several methodology documents, including a general 

reporting protocol, general certification (verification) protocol, and several segment-specific 

protocols. Companies submit emissions reports using a standardized electronic system. Emission 

reports may be aggregated at the company level or reported at the facility level. CCAR is 

transitioning out of entity emissions reporting, and 2009 will be the last year it accepts such 

reporting. Emissions reporting can instead be conduced under CCAR’s sister organization The 

Climate Registry (TCR), which is based off of CCAR’s work. A number of members of CCAR 

have already made the transition over to TCR.

2.3.5.2 The Climate Registry

The Climate Registry (TCR) is a partnership formed by U.S. and Mexican states, 

Canadian provinces, and tribes to develop standard GHG emissions 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. They have also released a general verification protocol, and an 

electronic reporting system. Several industry-specific draft protocols have been released recently 

for public comment including Petroleum & Gas Exploration & Production Protocol and a 

verification protocol for this segment. Founding reporters (companies and other 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 Emissions 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 emissions 

control programs. This section of the preamble 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. We recognize 

that, like the current voluntary regional and State programs, State and regional mandatory 

reporting programs may evolve or develop to include additional monitoring and reporting 
2-13

requirements than those included in the rule. In fact, these programs may be broader in scope or 

more aggressive in implementation because the programs are either components of established 

reduction programs (e.g., cap and trade) or being used to design and inform specific measures 

that indirectly reduce GHG emissions (e.g., energy efficiency).

2.3.6.1 Regional Greenhouse Gas Initiative

The Regional Greenhouse Gas Initiative (RGGI) is a regional cap-and-trade program that 

covers CO2 emissions from EGUs larger than 25 MW in member states in the Mid-Atlantic and 

Northeast. The program goal is to reduce CO2 emissions to 10% 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 emissions15

 15 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. 

,” 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 

development. The WCI is also analyzing alternative or complementary policies other than cap-
2-14

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.16

2.3.7.1 California Mandatory Greenhouse Gas Reporting Rule

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 twelve 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, methane, nitrous oxide, HFCs, PFCs, SF6); others apply only 

to CO2 or a subset of the six gases. Most require reporting at the facility level, or by unit or 

process within a facility.

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

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

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

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

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

The mandatory reporting rule of the California Air Resources Board (CARB) is an 

example of a state rule that covers multiple source categories and contains relatively detailed 

requirements, similar to this proposal developed by EPA. The regulation became effective on 

January 2, 2009. According to CARB, selected facilities (e.g. general stationary combustion 

facilities outside the petroleum-and-gas segment, and electricity generation and cogeneration 

plants not within the operational control of larger facilities and entities) are required to file their 

 16 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

first emissions data reports by April 1, 2009. The rest of the facilities and entities report by June 

1, 2009 (see http://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 metric tons

CO2 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 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 below.

3.1 Rule Dimensions for Which Options Were Identified

Possible designs for Subpart W of the Mandatory GHG Reporting Rule were developed 

by varying options across two dimensions:

1. Thresholds: Based on the discretion in the language of the appropriations bill that 

calls for emissions reporting above appropriate thresholds in all segments of the 

economy, EPA has identified an appropriate threshold above which petroleum and 

natural gas facilities are required to report their GHG emissions. Types of thresholds 

considered were production or productive capacity, and emissions based. 

2. Measurement Methodology: To be able to report their GHG emissions, facilities 

will be required to measure them using an appropriate methodology. Generally, 

measurement methodologies may be based on instrumentation and direct 

measurement, or on calculation methods based on other data available to the facility 

(e.g., activity data and emissions factors).

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

below 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 emissions sources and 

calculation methods for non-major 

sources

Default 

emissions 

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, emissions-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 below, 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 is not currently universally available to EPA.

3.1.1.2 Option 2: Emissions-based threshold (Selected)

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

tons of CO2-equivalent emissions (MtCO2e). Various levels were considered, ranging from 1,000 
3-3

MtCO2e to 100,000 MtCO2e. Obviously, lower thresholds would require more facilities to 

participate in the reporting program. Given current data availability, an emissions-based 

threshold will generally focus on larger, emissions-intensive sources in the petroleum and natural 

gas segment for which emissions 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 metric tons of CO2e per year of actual 

emissions. The preference is to establish thresholds for as many source categories as possible 

based on a capacity metric, for example, tons of product produced per year. A capacity-based 

threshold is least burdensome, because a facility would not have to estimate emissions to 

determine if the rule applies. However, EPA faces two key challenges in trying to develop 

capacity thresholds. First, in most cases, especially involving equipment leak and vented 

emissions under Subpart W, data are insufficient to determine an appropriate capacity threshold. 

Secondly, in many of the petroleum and natural gas segments, the level of emissions from vented 

and equipment leaks are not related to capacity or throughput. Rather, emissions may be driven 

by design and operating factors. As an example, pneumatic controls on petroleum and natural gas 

facilities are designed to vent natural gas to drive valve movements. The level of venting is not 

dependent on throughput.

3.1.2 Measurement Methodology

EPA identified three measurement methodology options, ranging from installing 

emissions monitoring equipment on all sources under Subpart W to using default emissions 

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

sources are discussed below.

3.1.2.1 Option 1: Direct measurement for all reporters

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

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

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

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

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

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

emissions factors do not exist and 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 emissions factors for leaking equipment (i.e. “leaker” 

factors). Use of population count and default population emissions 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 below, Option 2 will enable EPA to monitor year-to-year changes in emissions levels 

from the petroleum and natural gas source category.

3.1.2.3 Option 3: Default emissions 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 above, EPA evaluated a variety of options for each dimension of the GHG 

reporting program, and selected a recommended option for each dimension. We summarize the 

recommended option for each dimension below.

– Threshold: Emissions based approach

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

sum of vented emissions and equipment leaks, stationary and portable 

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

covered by the finalized MRR that may be present at the facility. A facility 

that emits 25,000 metric tons CO2e/year or more reports all sources for which 

there are methods in the finalized MRR 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: Combination of direct measurement and source-specific 

calculation methodologies

– For 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 which are 

smaller, or may be inaccessible to direct measurement will be quantified 

through the use of leak detection and application of leaker emissions factors 

for leaking equipment. Population count and population emissions factors will 

be used for smaller and inaccessible sources. 

– Source-specific calculation methods using facility-specific information for 

other sources in the finalized MRR 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 Subpart W final rule are listed below:

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

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

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

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

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

bagging, and high volume sampler) are used to measure emissions.

6. A 25,000 MtCO2e threshold; default emissions factors (simplified methods) are used 

to measure emissions.

The evaluation of the alternative reporting scenarios will allow policy makers, regulated 

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

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

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

Section 4.

3.4 Data Quality for This Analysis

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

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

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

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

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

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

rule. Existing models, such as EPA’s CEMS “continuous emissions monitoring system” cost 

model, were used for Subpart W to ensure consistency of cost inputs and assumptions.

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

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

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 industry 
3-7

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 Subpart W final rule 

are judged to be of good quality and the best that are publicly available.

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

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

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

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

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

taken from the BLS and adjusted to account for overhead. Monitoring costs were generally based 

on cost algorithms or approaches that had been previously developed, reviewed, accepted as 

adequate, and used specifically to estimate the costs associated with various types of

measurements and monitoring. The data quality associated with these elements of the cost 

analysis is analogous to the quality of data used in the development of numerous other 

Information Collection Requests.
4-8

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 emissions sources.

 (2) Type of emissions 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. The facility must assess every source 

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

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

categories that do not exceed the applicable threshold.
4-9

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, etc. The costs include labor and capital 

costs for performing the monitoring, recordkeeping, and reporting activities necessary to comply 

with Subpart W. All costs referred to in the EIA are in 2006 dollars.

There are two major emissions categories for which costs are determined. One is the cost 

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

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

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

aggregate costs for process and combustion emissions above those covered by Subpart C alone.

We first provide a general overview of baseline reporting and the two cost components 

associated with this information collection—labor costs (i.e., the cost of labor by facility staff to 

meet the information collection requirements of the rule) and 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, we 

assume that there will be additional costs for any detection, sampling and testing requirements in 

the methods used to quantify emissions from petroleum and natural gas sources. We are also 

assuming that additional costs will be incurred for preparing monitoring and QA/QC plans, 

performing the calculations, reporting the results, and maintaining records. The only significant 

element that we know reporters subject to Subpart W already gather is the measurements and 

records of consumption of raw materials, such as feedstocks, as part of their routine operation for 

accounting purposes.

4.2.2 Reporting Costs 

Costs for Subpart W were developed based on assessments of all estimated capital and 

operations and maintenance costs to monitor, measure, detect and calculate the emissions sources 

in all segments of Subpart W. Key variables and data fields were clearly defined to ensure that 

each segment developed costs around a standard set of methods and assumptions for Subpart W
4-10

(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 emissions reporting.

Labor Costs. The costs of complying with and administering this rule include the time of 

managers, technical, and administrative staff in both the private segment and the public segment. 

Staff hours are estimated for activities including:

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

systems;

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

it to EPA through electronic systems; and

– 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 emissions 

monitoring activities at the petroleum or natural gas facility to comply with the rulemaking.

For purposes of this study, EPA adopted the methodology used by Rice (2002) to 

calculate the wage rates for the EPA’s Toxics Release Inventory (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 employer17

 17 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.

.

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

calculate the wage rates:
4-11

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, we have assumed the benefits loading factor to remain the same for each labor category 

across all industries in the rule due to a lack of availability of necessary 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 purposes of this analysis, we have also adopted 

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

the overhead loading factor that we used in the wage rate calculations remains the same for all 

labor categories and across all industry types in the rule. The overhead loading factor was 

assumed to be 0.17.

For Subpart W, the combined “Benefits and Overhead Loading Factor” used is 0.67, or 

an overall adjustment of 1.67 times “Basic Wages.”

Capital and O&M Costs. This includes the cost of purchasing and installing monitoring 

equipment or contractor costs associated with providing the required information. Equipment 

costs include both the initial purchase price of monitoring equipment and any facility/process 

modification that may be required. Based on expert judgment, the engineering costs analyses 

annualized capital equipment costs with the appropriate lifetime and interest rate assumptions. 

The equipment life was set at five years for Subpart W sources with one-time capital costs 

amortized at a rate of seven percent.

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

Overview. The relevant reporters covered in this section are offshore petroleum and 

natural gas production, onshore petroleum and natural gas production (including enhanced oil
4-12

recovery, EOR), onshore natural gas processing, onshore natural gas transmission compression, 

onshore natural gas storage, LNG storage, LNG import and export and natural gas distribution.

For each of the industry segments, with the exception of onshore production, operations 

had to be divided into single units or model facilities at three levels; “small,” “medium,” and 

“large.” The monitoring costs were then developed per size level of a model facility. A model 

facility of a given level can be defined as the most convenient and logical unit with appropriate 

emissions source counts that can aggregate to any size company to determine its monitoring 

costs. For example, in natural gas transmission, a compressor station as a facility was modeled at 

the three different model size 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, we

assigned a model facility cost that best fit the facility based on its emissions profile. Next, we 

summed the costs assigned to each facility in the segment to produce the total national cost in 

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

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

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

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

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

Petroleum Geologists. There is much larger 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 below provides a summary of the number of facilities that would have to report under 

the various thresholds analyzed for each of the industry segments covered by the rule.
4-13

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

.

Industry Segment

Threshold

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

Onshore Production 8,169 1,929 981 385

Natural Gas Processing 566 396 289 130

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

Natural Gas Storage 347 200 133 36

Liquefied Natural Gas Storage 54 41 33 4

Liquefied Natural Gas Terminals 5 4 4 4

Offshore Production 1192 184 58 4

Local Distribution Companies 594 203 143 66

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 2 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 1 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 
4-14

created. These were multiplied by the emissions source counts assigned to each of the model 

facilities to determine the required labor hours. Once the labor hours were calculated, by 

category, for each of the cost elements, they were multiplied by the associated labor rates to 

estimate labor costs per facility. For offshore monitoring costs were developed on a per platform 

basis for non-GOADS reporters based on expert judgment. The only remaining facility costs are 

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

emissions monitoring.

Table 4-3 below presents labor cost numbers aggregated across all segments for Subpart 

W. These data are aggregated from individual tables for each segment. Except for onshore 

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

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

equipment-level labor hours, displayed 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 and Table 4-4. However, the average operational and maintenance 

costs for the onshore production segment are shown separately in the bullets below each table.

Capital and O&M Costs. The capital costs related to monitoring emissions and archiving 

of information consist of purchasing equipment for emissions detection (or the portion of 

contractor purchases of equipment is apportioned to all its customers), emissions measurement, 

and information storage. All costs are reported in 2006 U.S. dollars and annualization was 

assumed over an equipment life of five years with a seven percent interest rate. Equipment leak 

monitoring does not have time-tested standards and equipment leak streams typically are not 

clean gas. For example, a centrifugal compressor wet seal degassing vent will contain fine 

droplets of seal petroleum with the gas. A five-year equipment life was chosen to be 

conservative in cost estimates, opposed to the ten-year equipment life associated with longstanding, proven practices of measuring clean fuel streams assumed in the stationary combustion 

section.

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 
4-15

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 assumes that there 

will be no disruption in the operations since the port can be installed when the compressor is 

either in standby mode or under maintenance. Hence no adjustment is made for production or

operational loss. First year labor costs include the labor required for registration, creating a 

monitoring plan, 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.

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. Onshore production 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 small even if there are multiple compressors at the 

facility.

This analysis includes the cost of incremental combustion reporting and combustion 

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

have been reported under Subpart C. The costs to monitor and report incremental combustionrelated emissions were estimated based on the approach used under 40 CFR Part 98, Subpart C.18

The Tier 1 approach bases estimates on a fuel-specific default CO2 emission factor, a 

default high heating value of the fuel, and the annual fuel consumption from company records. 

EPA determined that entities that need to report incremental combustion-related emissions, as 

described above, would use the Tier 1 method as set forth in Subpart C; these entities would 

likely not meet the requirements for the Tier 2 or higher methods. 

 

Specifically, EPA applied the Tier 1 methodology to estimate the costs to monitor combustion 

emissions that became subject to reporting as a result of today’s final rule. 

 18 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).
4-16

EPA based this conclusion on three considerations for applicability of the Tier 2 

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 methodology, (2) the maximum rated heat input capacity of the equipment, and (3) the 

type of fuel being combusted. First, in order to be required to use a Tier 2, units must have a 

rated heat input capacity less than or equal to 250 MMBtu/hr, combust a fuel found in Table C-1, 

and sample the HHV of the fuel consumed at the required frequency in Part 98.34(a). It was 

determined that this minimum required sampling frequency is not currently carried out at these 

smaller units and therefore these units would not be required to use Tier 2 or higher. These units 

will generally follow Tier 1. 

Second, Tier 3 and Tier 4 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 metric tons CO2e; these 

emissions would be subject to reporting under Subpart C even in the absence of Subpart W and 

therefore would not fall in the category of incremental combustion emissions considered in this 

analysis. 

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. Of these fuels, equipment using pipeline quality natural gas, distillate 

fuel, or products recovered from equipment leaks and vents are required to use Tier 2 or higher. 

As described above, if the unit has a rated heat-input less than or equal to 250 MMBtu/hr, then 

the unit probably does not currently receive HHV at the required frequency for a Tier 2 and 

could use a Tier 1. 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 emissions category 

considered in this analysis. Finally, the use of produced natural gas is predominant in onshore 

petroleum and natural gas production. Under the final rule, reporters are allowed to use methods 

similar to Tier 1 for all combustion emissions sources that use produced natural gas. In sum, the 

use of Tier 1 costs for incremental combustion is a reasonable assumption.
4-17

Table 4-3 Subpart W Petroleum and Natural Gas Systems: Labor Costs1

Activity

(2006$)

Estimated Labor Hours and Annual Labor Rates

Labor Cost per 

Year per 

Reporting 

Unit/Facility

Senior 

Management

Middle 

Management

Junior 

Engineer/ or 

Technician Senior Operator

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

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

First 

Year

Subseq. 

Year

Planning 0.73 0.08 3.29 0.19 55.68 0.67 4.02 0.32 $4,578 $93

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

Recordkeeping 0.16 0.16 0.27 0.26 2.91 2.75 0.56 0.56 $283 $270

Sampling and analysis 

(calculations)

0.00 0.00 1.83 1.83 97.70 6.80 1.11 1.03 $7,173 $711

Reporting 0.06 0.04 1.38 1.19 4.48 3.99 14.77 13.92 $1,390 $1,283

Total 0.95 0.28 6.78 3.48 160.77 14.21 20.46 15.82 $13,424 $2,357

1

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

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.

1

Activity

(2006$)

Cost Categories

Capital and O&M Cost 

per Unit/Facility

Capital 

Cost

Equipment 

Lifetime

(years)

Annualized 

Capital Cost 

(per year)

O&M 

Costs 

(per year)

First 

Year

Subseq. 

Year

Equipment (selection, 

purchase, installation) $1,821 6 $444 n/a $444 $444 

Performance testing n/a 2 n/a n/a n/a n/a n/a

Recordkeeping $86 5 $21 n/a $21 $21 

Travel N/A n/a n/a $825 $825 $825 

Total $1,906 n/a $465 $825 $1,290 $1,290 

1 Estimated Onshore Production average Capital and O&M Cost per Unit/Facility are $57 for the first year and $57 for the 

subsequent years. 2 Performance testing is not required under Subpart W therefore no costs are entered.
4-18

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 emissions reporting as applicable to an 

individual facility: 1,000 metric tons of CO2 equivalent (MtCO2e) per year; 10,000 mtCO2e;

25,000 mtCO2e; and 100,000 mtCO2e. A threshold analysis was then conducted on each segment 

to determine which level of threshold was most suitable for each industry segment. CH4, CO2, 

and N2O emissions from each segment were included in the threshold analysis. 

Table 4-6 shows the number and share of entities and emissions covered by the final rule. 

The table shows that at lower thresholds, a higher number and share of facilities and emissions 

are covered by the rule. As the threshold increases, smaller numbers and shares of facilities and 

emissions are affected. Of significant note, 85 percent of emissions are covered at the selected 

25,000 metric ton CO2e threshold, but only 9 percent of facilities need to report. Further, both 

total emissions and covered emissions include incremental combustion emissions, i.e. those not 

triggered by the threshold of Subpart C alone. 

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

Threshold

Number of 

Entities

Number of 

Facilities 

Covered

Percent of 

Facilities 

Covered

Total 

Emissions 

(Million 

MtCO2e)

Covered 

Emissions 

(Million 

MtCO2e) Percent of 

Emissions 

Year) Year) Covered

1,000 Threshold 30,241 12,622 42% 396 391 99%

10,000 Threshold 30,241 4,400 15% 396 362 91%

25,000 Threshold 30,241 2,786 9% 396 337 85%

100,000 Threshold 30,241 1,062 4% 396 273 69%
4-19

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. However, the emissions estimates for four sources—well venting for liquids 

unloading, gas well venting during well completions, gas well venting during well workovers, 

and centrifugal compressor wet seal degassing venting—from the U.S. GHG Inventory were 

replaced with revised estimates, 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 

emissions factors available from GRI/EPA 1996, back calculating the natural gas consumption in 

engines, and finally applying a CO2 emissions factor to the natural gas consumed as fuel. N2O 

emissions were calculated similarly. In the case of offshore petroleum and natural gas production 

platforms combustion emissions are already available from the GOADS 2000 study analysis and 

hence were directly used for the threshold analysis. In addition to gas engines, combustion 

emissions from reboilers on glycol dehydrators, acid gas removal amine regeneration, diesel 

engines on drilling rigs, and heater-treaters were estimated for onshore production. The volume 

of fuel gas required by regular operation of a glycol dehydrator was calculated per volume of 

dehydrator input; then the API Compendium combustion emission factors for natural gas were 

applied to facilities’ fuel gas use based on their gas production rates. The same assumptions 

were made to calculate combustion emissions from acid gas removal amine regeneration heaters. 

Drilling rigs were assumed to operate two 1,500-horsepower diesel engines per well drilled, and 

assuming it requires 90 days to drill and complete any well. The API Compendium combustion 

emission factors for diesel engines were used to calculate the emissions. The total drilling 

emissions for the nation were calculated based on the number of drilling rigs in service, then 

apportioned to each basin by throughput. 

The threshold analysis for the rule includes equipment leak, vented, and combustion 

emissions and requires estimation of all emissions at a facility level. As a result, the total 

emissions from the threshold analysis do not necessarily match the U.S. GHG Inventory for all 

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 emissions reporting between thresholds is the highest for the lowest incremental 
4-20

increase in number of facilities reporting between the same thresholds. This would ensure 

maximum emissions reporting coverage with minimal burden on the industry. 

Table 4-7 summarizes the national costs and costs per representative entity for each 

threshold. The first five columns report 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$)

Threshold

(MtCO2e/yr)

First Year 

Process 

Costs

Subsequent 

Year Process 

Costs 1

First Year 

Combustion 

Costs 1

Subsequent 

Year 

Combustion 

Costs

First 

Year 

National 

Costs

First Year 

Representative 

Entity Cost

Subsequent 

Year 

National 

Costs

Subsequent 

Year 

Representative 

Entity Cost

1,000 $112.3 $46.4 $23.9 $23.9 $136.2 $0.011 $70.3 $0.006 

10,000 $53.0 $20.9 $6.6 $6.6 $59.6 $0.014 $27.5 $0.006 

25,000 $40.1 $15.1 $3.3 $3.3 $43.4 $0.016 $18.4 $0.007 

100,000 $23.1 $7.7 $0.9 $0.9 $24.0 $0.023 $8.6 $0.008 1

• Initial start-up costs include labor and capital associated with establishing 

modifications to enable ongoing quantification of key emissions sources. This 

includes costs to install measurement ports in compressor and well vents.

Reporting and Record-keeping costs are included in Process Costs.

Note that year one costs are significantly higher than the subsequent year average costs. 

This is due to the following reasons:

• For onshore production, reporting occurs annually but the measurement of key 

sources is updated every two years.

Subsequent year costs are therefore reported as an average of the cost for years two, three, and 

four. As described in Table 4-7 above, at lower thresholds, a larger number of facilities in each 

subpart are covered by the rule, and thus incur costs. For this reason, the total national costs, and 

total costs by cost subset, decline as the threshold increases from 1,000 MtCO2e to 10,000 

MtCO2e, to 25,000 MtCO2e, and finally to 100,000 MtCO2e. Cost per representative entity for a 

particular segment generally declines for Subpart W as the threshold increases. 
4-21

Reporting Determination. While the cost estimates for representative entities are 

assumed to capture the reporting determination burden—i.e., 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 expects most facilities to use them to make a 

reporting determination. As a first step, facilities would enter basic activity data, such as well 

count and drilling activity, into the tool to roughly assess whether they exceed the threshold. The 

screening results should allow most facilities to make their determination. However, some of the 

facilities may have to take steps in addition to the screening tools 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 

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 below.

Planning costs assumed to include: 

• 2.5 hours for regulatory review 

• 2 hours to understand what operations information is required

• 2 hours to gather operations data for screening tool(s)

• 14 hours to conduct preliminary monitoring
4-22

Recordkeeping and reporting costs 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. 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)

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

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

The assumptions below are the basis for the determination of the costs noted in this section.

STEP 1: Model Facility Development

For each of the industry segments, with the exception of onshore production, operations 

had to be divided into single units or model facilities at three levels; “small,” “medium,” and 

“large.” The monitoring costs were then developed per size level of a model facility. A model 

facility of a given level can be defined as the most convenient and logical unit with appropriate 
4-23

emissions source counts that can aggregate to any size company to determine its monitoring 

costs. For example, in onshore natural gas transmission, a compressor station as a facility was 

modeled at the different levels. Any transmission company can determine its monitoring costs by 

assigning model facility 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 emissions 

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, MMS GOADS-2000 data analysis by EPA was used in the same fashion as the 

national inventories. In some cases, the uncertainty estimates were not applicable. For example, 

if the uncertainty is over 100%, it would predict a negative lower bound for emissions source 

counts. For these cases, expert judgment was used. Expert judgment was also used, where 

necessary, to adjust emissions source counts to reflect real world scenarios. Both equipment and 

component counts at facilities by segment and size are presented in the docket (EPA-HQ-OAR2009-0923)

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 below. Additionally, these cost 

elements are considered in two ways: costs associated with start-up and recurring costs. Startup 

costs refer to a one-time cost associated with initiating the reporting process. Subsequent costs 
4-24

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. 

Each cycle, labor will be required to conduct detection and quantification of 

emissions, i.e., perform actual monitoring of emissions. Quantification may take 

place through direct measurement, use of engineering calculations and/or 

software, use of “leaker” emission factors for detected leaks, or use of component 

counts and population emission factors. For companies with multiple facilities, 

travel may be 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.
4-25

b. Recurring reporting costs consist of labor necessary to document collected 

emissions 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, physical storage system such as a file cabinet, and 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 consists of labor required to validate to the EPA results 

from the monitoring of emissions and the follow-up of 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 

To classify the facilities into different sizes, total combustion, equipment leaked, and 

vented CO2, N2O, and CH4 emissions from individual facilities, expressed in CO2e, were rank 

listed in an ascending order. Cumulative emissions for the facilities were calculated by summing 

the emissions of the individual facility to those of the facilities before it in the ascending list. The 

cumulative emissions, in combination with the total emissions from all facilities, were used to 

assign facilities to the small, medium, and large category.





 



 = TotalEmissions

CumulativeEmissions Percentile(%)

The facilities that accounted for the first 33% of the emissions nationally in the ranked 

list were identified as a small facility. The facilities that accounted for national emissions greater 

than 33 percent but less than 67 percent in the ranked list were identified as a medium facility. 

The facilities that accounted for national emissions over 67 percent in the ranked list were 
4-26

identified as a large facility. Table 4-9 indicates the data sources used to apportion total GHG

emissions to individual facilities, and the number of facilities that fall into each category per 

segment.

STEP 4: Assigning Costs to Cost Elements

Assigning costs to each of the cost elements was completed in three steps:

1. Determine labor categories and associated labor rates,

2. Allocate responsibilities to labor categories to estimate labor hours, and

3. Determine annualized capital costs and operation & maintenance (O&M) costs for 

each of the cost elements.

These steps are described in further detail below.
4-27

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 MMS GOADS Report & 

Lasser 2006

0–33% 34%–67% 68%–100%

Facility Count MMS GOADS Report & 

Lasser 2006

3,036 191 8

Mean Emissions (MtCO2e) This Analysis 1,430 22,733 483,806

Operator/Company 1 Not estimated

Onshore Petroleum and Natural Gas Production2

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 Processing Report 0–33% 34%–67% 68%–100%

Facility Count 3 API Processing Report 486 64 16

Operator/Company API Processing Report 166 28 10

Mean Emissions (MtCO2e) This Analysis 36,486 275,823 1,137,595

Onshore Natural Gas Transmission

Facility Percentile FERC 0–33% 34%–67% 68%–100%

Facility Count FERC 1,314 374 255

Operator/Company FERC 147 46 27

Mean Emissions (MtCO2e) This Analysis 21,293 98,738 210,829

Natural Gas Underground Storage

Facility Percentile EIA 0–33% 34%–67% 68%–100%

Facility Count EIA 325 50 22

Operator/Company EIA 102 37 17

Mean Emissions (MtCO2e) This Analysis 12,404 82,199 183,936

LNG Storage 

Facility Percentile GTI 0–33% 34%–67% 68%–100%

Facility Count GTI 141 12 4

Operator/Company GTI 141 11 3

Mean Emissions (MtCO2e) This Analysis 20,972 55,340 223,275

LNG Import and Export 

Facility Percentile FERC — 0–100% —

Facility Count FERC — 5 —

Operator/Company Not estimated

Mean Emissions (MtCO2e) This Analysis — 174,643 —

Natural Gas Distribution 

Facility Percentile DOT 0–33% 34%–67% 68%–100%

Facility Count DOT 1,360 50 17

Operator/Company DOT 1,268 49 16
4-28

Mean Emissions (MtCO2e) This Analysis 5,840 167,066 536,719

Notes:

1 MMS 2007 statistics reports 3,923 offshore platforms and 139 operators. No data are available for individual offshore 

platforms and their respective operators.

2 The onshore production burden analysis was conducted using a hybrid approach. Capital costs and some recurring O&M costs 

were assigned on a small, medium large basis; however, the majority of the recurring O&M costs were determined by 

apportioning nationwide costs by individual operator throughput. 

3

4.5.1 Determining Labor Categories

Assumed one facility per company; no data available for small plants. 

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 Rate 

Senior Manager Oversees work at a high level. Is the final authority on 

all reporting requirements. 

$101.31/hour

Middle Manager Oversees junior engineer’s progress and reports; also 

interacts with senior manager. Does not gather 

information, write reports, or perform monitoring.

$88.79/hour

Junior Engineer Conducts monitoring of emissions 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

1

These labor rates originate from an analysis of loaded hourly rates for goods and 

producing private establishments at the end of 2007, shown in 

All data from U.S. Department of Labor, Bureau of Labor Statistics, National Compensation Survey - Compensation Cost 

Trends, Employer Cost for Employee Compensation (ECEC), Customized Tables, as of March 11, 2003.

Table 4-11 below. Since the 

petroleum and natural gas industry pays comparatively high 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 
4-29

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)

Electricity Manager $88.79 

Refinery Manager $101.31 

Industrial Manager $71.03 

Lawyer $101.00 

Electricity Engineer/Technician $60.84 

Refinery Engineer/Technician $63.89 

Industrial Engineer/Technician $55.20 

Administrative Support $29.65 

1 All data from U.S. Department of Labor, Bureau of Labor Statistics, National Compensation Survey - Compensation Cost Trends, 

Employer Cost for Employee Compensation (ECEC), Customized Tables, as of March 11, 2003.

4.5.2 Allocating Responsibilities

Assigning labor hours for all cost elements was based on expert judgment. When 

assigning hours, the size of the facility and role of the labor categories were taken into 

consideration. Table 4-12 summarizes these roles.

Table 4-12 Responsibilities for Regulation Compliance by Labor Category

Cost Element

Senior 

Management

Middle 

Management Junior Engineer Senior Operator

Per Facility/ 

Per Company1

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
4-30

Data 

documentation

To review the 

reporting 

documentation

To prepare and 

complete the 

reporting 

documentation

To prepare 

reporting 

documentation

To prepare and 

complete 

reporting 

documentation

Per facility

Report 

submission

To ensure the 

completion of the 

reporting 

documentation

To submit the 

report

Per Facility

Archiving 

reports

To archive the 

reporting 

documentation

To archive the 

reporting 

documentation

Per facility

Audit To review the 

audit results

To review the 

audit results 

To assist and 

provide 

information on 

EPA audits

Per facility

Audit follow-up To review the 

audit follow-up 

results and 

approve 

corrective 

measures

To review the 

audit follow-up 

results and review 

corrective 

measures

To determine 

corrective 

measures from 

EPA audit

To assist in 

determining 

corrective 

measures from 

EPA audit

Per facility

1

The labor costs associated with performing the actual annual monitoring were omitted 

from the table above. For these costs it was assumed that all labor will be performed by middle 

managers, junior engineers, senior operators, and contracted technicians. The assumed 

responsibilities and associated hours are organized in

Some activities only have to be done at the company level, with information and/or equipment shared among 

facilities of the company.

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 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 

hours/large facility)

Processing
4-31

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 hours

reporting period)

Transmission

Underground Storage Facility Equipment Leak

Technician Conduct equipment leak 

detection survey (47 hours/

small facility, 53 hours/ 

medium facility, and 63 

hours/large facility)

Storage

Junior engineer Estimate emissions using 

leaker factors (2 hours/ small 

facility, 3 hours/ medium 

facility, and 2 hours/ large 

facility)

Storage

Middle 

Management

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 

hours/reporting period)

Oversee part of the 

measurement process and 

review results (1 hour/

reporting period)

LNG Import and Export 

Facilities

LNG Storage Facility Equipment Leak

Technician Conduct equipment leak LNG Storage
4-32

detection survey (12 hours/

small facility, 19 hours/ 

medium facility, and 24 

hours/large facility)

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 

($1000 / compressor)

Processing, Transmission, 

Storage, LNG Storage, LNG 

Import and Export Facilities

Technician Check packing open-ended 

lines for emissions (10 

minutes/ compressor)

Processing, Transmission, 

Storage, LNG Storage, LNG 

Import and Export Facilities

Technician Measure rod packing 

emissions (10 minutes/

compressor)

Processing, Transmission, 

Storage, LNG Storage, LNG 

Import and Export Facilities

Junior engineer Calculate rod packing 

emissions (30 minutes/

compressor)

Processing, Transmission, 

Storage, LNG Storage, LNG 

Import and Export Facilities

Centrifugal Compressor Equipment Leaks
4-33

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 

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 Transmission, Storage
4-34

equipment leaks – certain 

portion of time is assumed to 

be for engineering 

estimation of sources

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 emissions 

calculation with GOR 

measurement (1 hour/ well)

Onshore Production

Natural Gas Pneumatic Bleed Devices

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

Transmission, Storage
4-35

minutes/pneumatic device)

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

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 MMS GOADS to estimate greenhouse gas emissions from their operations. Specifically, the 

MMS GOADS program requires the monitoring of GHG emissions from platforms in the Gulf of 

Mexico Federal waters. Facilities under this final rulemaking are required to report the same 

emissions data calculated by the GOADS Program. Hence these platforms have minimal 

additional reporting burden. The cost burden model assumes that this requires 30 minutes per 

platform.

However, platforms that are in State waters or in Federal waters outside the Gulf of 

Mexico, GHG emissions will have to be estimated using the MMS 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 emissions monitoring.

4.5.3 Capital Cost Annualization and O&M Costs

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

purchasing equipment for emissions detection, emissions measurement, and information storage. 

All costs are reported in 2006 U.S. dollars and annualization was assumed over an equipment life 

of 5 years with a 7% interest rate. From these factors, a capital recovery factor of 24% was 

calculated using the formula provided below:
4-36

(1 ) 1

(1 )

+ −

+ = n

n

r

r r CRF

where CRF is the capital recovery factor, r is the interest rate, and n is the life expectancy in 

years. Table 4-14 below summarizes the annualized capital costs associated with the monitoring 

program. Additionally, the table describes the annual costs of travel, lodging, and shipping—the 

only other non-labor costs related to the monitoring program.

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

Element Capital Cost

Annualized 

Capital Cost

Archiving

Capital costs Cost of archiving material per facility assumes cost of 1 file 

cabinet, 4-drawer vertical from Office DepotTM ($140), and 

1 hard drive for data storage from SeagateTM ($95) 

$57

Monitoring

Equipment purchase Screening equipment is represented by a nominal $100,000 

cost for an infrared camera. It is assumed to be purchased 

by the contractors who will pass on the costs to as many 

facilities as they can provide a service each year.

$24,389

Equipment purchase Screening equipment in the distribution segment is 

represented by a nominal $10,000 cost for a laser emissions 

detector. It is assumed to be purchased by the local 

distribution companies over the infrared camera due to its 

low cost. 

$2,439

Measurement

Equipment purchase Hotwire anemometers are required for compressor vents. It 

is assumed that the hotwire anemometer, a vinyl carrying 

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–$10,4491

1

As shown in 

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.

Table 4-14, the equipment leaks and vented emissions 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. 
4-37

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 above provided the proportion of facilities that fall in the small, medium, and large 

categories. By determining the companies that fall in the three categories, the average number of 

“small,” “medium,” and “large” facilities per company was determined. To convert the 

annualized capital costs and equipment purchases, the costs per equipment were attributed to the 

number of facilities that can be serviced (as determined the number of labor hours required to 

monitor a facility) each year, as shown in the equation below:





 





÷













 = ×

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 year one and $15.1 million in subsequent years. The estimates are 

based on the selected option for the final rule, which includes an annual emissions-based 

threshold of 25,000 metric tons CO2e for each facility and a hybrid of direct measurement and 

source-specific calculation methodologies. Section 3.2 provides more details about the selected 

option.

EPA estimates that for Subpart W, the public sector burden is about $1.1 million per year. 

Approximately $0.46 million per year is for verification activities, and about $0.66 million per 

year is for program implementation and developing and maintaining the data collection system. 

Program implementation activities include, but are not limited to, developing guidance and 

training materials to assist the regulated community, responding to inquires from affected 

facilities on monitoring and applicability requirements, and developing tools to assist in 

determining applicability. In addition to total national costs for petroleum and natural gas 

systems, we also report 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 (well liquids unloadings, well workovers, compressor wet seal degassing vents, etc) 

in the first year; these sources are only required to be estimated bi-annually to mitigate long term 

burden. The average cost per metric ton for all reporters is about $0.13/metric ton in the first 

year, declining to an average of $0.05/metric ton in subsequent years.
5-2

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

First Year Subsequent Years

Subpart W – Petroleum

and Natural Gas systems NAICS

$Million Million 

MtCO2e $/Mt

$Million Million 

2006 2006 MtCO2e $/Mt

Process Emissions 211, 486 $40.1 253.9 $0.16 $15.11 253.9 $0.06 

Combustion Emissions $3.3 83.5 $0.04 $3.32 83.5 $0.04 

 Reporting Determination $18.4 n/a n/a $0.58 n/a n/a

Private Sector, Total $61.8 337.4 $0.131 $19.01 337.4 $0.051 

Public Sector, Total2

$1.1 337.4 $0.003 $1.1 337.4 $0.003 

TOTAL $62.9 337.4 $0.133 $20.11 337.4 $0.053 

Note:

1 Excludes reporting determination for non-reporters; based on cost to report process and combustion emissions ($43 million in 

first year, $18 million in subsequent years). 2 Source: EPA 3 

There is a notable reduction in reporting cost compared to the April, 2010 proposal. The 

cost reduction resulted from changes such as providing floors on several emissions sources (e.g.,

tanks, dehydrators, and compressors); simplified requirements for sampling and gas composition 

analysis; use of alternative leak detection equipment in some cases; and use of equipment-based 

emission factors instead of 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. 

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). 

Table 5-2

summarizes these changes based on year 1 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.
5-3

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

Systems, First Year Estimates

Source

Covered Emissions Cost Cost

(MtCO2e) Million (2006$) (2006$/metric ton)

Apr. 

2009 

Proposed

Rule 

Apr. 

2010 

Proposed

Rule 

Final 

Rule

Apr. 

2009 

Proposed

Rule 

Apr. 

2010 

Proposed

Rule 

Final Rule

Apr. 

2009 

Proposed

Rule 

Apr. 

2010 

Proposed

Rule 

Final Rule

Original 

Six 

Segments

85 194.3 78.7 $32.5 $26.7 $26.2 $0.38 $0.28 $0.33

Onshore 

Production n/a 154.9 152.4 n/a $27.7 $11.9 n/a $0.18 $0.08

Local 

Distribution n/a 22.7 22.7 n/a $1.6 $2.0 n/a $0.07 $0.09

Total 85 272 254 $32.5 $56.0 $40.1 $0.38 $0.21 $0.16

1

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

Systems, Subsequent Year Estimates

Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG storage; LNG 

import/export.

Source

Covered Emissions Cost Cost

(MtCO2e) Million (2006$) ($/metric ton)

Apr. 

2009 

Proposed

Rule 

Apr. 

2010 

Proposed

Rule 

Final 

Rule

Apr. 

2009 

Proposed

Rule 

Apr. 

2010 

Proposed

Rule 

Final Rule

Apr. 

2009 

Proposed

Rule 

Apr. 

2010 

Proposed

Rule 

Final 

Rule

Original 

Six 

Segments

85 1

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

1 Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG storage; LNG 

import/export.
5-4

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 emissions threshold, we 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, we 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 below.

In addition, the final rule requires the determination of onshore reporting to be done 

assuming that reporting parties report emissions and for onshore production, determine threshold 

on a basin level. In other words, owners or operators in the onshore production segment must 

report based on total emissions in all petroleum and natural gas production fields in a defined 

basin. EPA also examined an option to require onshore production companies to report on a field 

level basis. This alternative would affect the total emissions reported as well as cost, and is 

evaluated below.

Six alternative options were therefore evaluated for this analysis. While we believe these 

alternatives represent the most likely variations in the selected option, we recognize that in some 

cases particular interests may wish to evaluate more nuanced alternative options. To maintain 

transparency in the analysis, data necessary to conduct further alternative option analyses can be 

found in Section 4 of this document.

5.1.1 Analysis of Alternative Threshold Options

The threshold determines the number of entities required to report GHG emissions under

Subpart W of the rule. The higher the threshold, the more entities that are excluded. It is assumed 

that the per-unit/entity cost does not change at 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 emissions 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 ($/metric ton CO2e) relative to the option adopted in the final rule. To 

compute this metric, we compute the change in emissions reported by lowering or raising the 

threshold and divide this by the change in total reporting costs. Table 5-4 provides the costeffectiveness analysis for the various thresholds.
5-5

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

Hybrid Option is 25,000 metric tons CO2e

Threshold (MtCO2e)

1

Facilities 

Required to 

Report

Total 

Costs

(Million 

2006$)

Downstream 

Emissions 

Reported 

(Million 

MtCO2e/ year)

Percentage of 

Total 

Downstream 

Emissions 

Reported

Average 

Reporting 

Cost 

(2006$/Mt)

Cost 

Differential1

(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) 1

The analysis shows a cost reduction of $0.28 per metric ton by moving from the selected 

threshold of 25,000 metric tons CO2e to a higher threshold (100,000 metric tons); the total 

emissions covered decrease significantly—about 16 percent. Similarly, moving the threshold 

from 25,000 to 10,000 the difference increases $0.73 per metric ton and the emissions captured 

by increase 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 is presented for subsequent years in

Cost difference relative to 25,000 metric ton threshold

Table 

5-5.

Table 5-5 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 

Cost 

(2006$/Mt)

Cost 

Differential1

(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)

1 Cost difference relative to 25,000 metric ton threshold 

Table 5-6 summarizes costs to report process and combustion emissions for all segments 

at four thresholds. 
5-6

Table 5-6 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 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. However, the methods proposed for monitoring emissions will differ 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. In this section, we evaluate the change in cost and 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. We use 

the term direct measurement and “population factors” as shorthand to describe alternative 

options. For Subpart W, population emission factors and component count is the basis for 

“default factors”. Estimated costs for each monitoring method are shown in Table 5-7.

For Subpart W, the direct measurement option greatly expands to use direct measurement 

of all vented and equipment leak sources. This is the methodology used in the April, 2009 

proposed rule. The costs associated with this case in the April, 2009 proposed rule (which did not 

include the onshore production and natural gas distribution) resulted in Subpart W incurring 19% 

of the total costs in the MRR to monitor and measure only 3% 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 5-7 Analysis of Alternative Monitoring Methods

Direct Measurement (DM) Selected Option (Hybrid Approach) Population Factors

Segment First Year

(million 2006$)

Subsequent Years

(million 2006$)

First Year

(million 2006$)

Subsequent Years

(million 2006$)

First Year

(million 2006$)

Subsequent Years

(million 2006$)

Subpart W—

Petroleum and 

Natural Gas 

Systems

$294.6 $126.9 $43.39 $18.43 $27.6 $17.4

For the “population factor” option, Subpart W sources were assumed to have emissions 

quantified entirely by the application of emissions factors developed by the Gas Research 

Institute and EPA (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. However, based on the analysis 

above, the costs to gather and quantify these emissions would be very high. 

The use of population based factors would result in a significantly lower burden, although 

the certainty level of the emissions determination would be very poor. Population-based factors 

determine the potential for emissions assuming a percentage of known components which may 

leak based on previous (and dated) studies. 

The final rule required option of using leak detection and a hybrid of spot direct 

measurement, engineering estimates, leaker emission factors, and population based factors (for 

inaccessible sources) provides an emissions estimate with significantly more certainty than 

population based factors at a more reasonable burden.

5.1.3 Sensitivity of Subsequent Year Cost Estimates

National cost estimates for the final rule were developed based on the current population 

of entities in the petroleum and natural gas segment. The forward analysis (“subsequent years”)

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.

However, in reality, over time some existing facilities close or go out of business and 

new facilities come into existence. This is sometimes referred to as entry and exit in an industry. 

This may affect the cost of the rule because as entities “turn over” the new entrants presumably 

will bear first-year costs that are slightly higher than subsequent year costs. 

The largest contribution to non-recurring first-year costs for Subpart W compliance is for 

flow measurement port installation in compressor seal vent lines. When a company goes out of 

business and sells its assets to either a new or existing business, these ports will already be 

installed; so much of the first-year compliance costs will not apply to a company acquiring an 

already-reporting facility. The remainder of first-year costs that do not repeat is 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 first 

year costs of reporting for Subpart W, therefore the impact of business transitions on rule 

reporting costs for Subpart W are assumed minimal.

5.1.4 Summary of Alternative Options for Onshore Facility Definition

The final rule specifies that onshore 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 5-8 and Table 5-9 below show a detailed 

emissions coverage and burden to reporter that would have been expected under a field-level 

facility definition. 
5-11

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

(Onshore Production)

Threshold 

Level

Emissions Covered Facilities Covered

Million

Metric tons 

CO2e/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 5-9 Equipment Leaks, Vented, and Combustion Emissions Cost for Field Level 

Facility Definition (Onshore Production)

Threshold 

Level

Equipment Leak and Vented Emission Costs (2006$) Combustion Emission Costs (2006$)

Year 1 Costs Subsequent Year Costs Year 1 Costs Subsequent Year Costs

Annualized 

Capital Cost

O&M 

Cost

Annualized 

Capital Cost O&M Cost Annualized 

Capital Cost

O&M 

Cost

Annualized 

Capital Cost

O&M 

Cost

1,000 $57.3 $7,274 $57.3 $3,069 $500 $1,700 $500 $1,700 

10,000 $57.3 $8,855 $57.3 $3,834 $500 $1,700 $500 $1,700 

25,000 $57.3 $10,334 $57.3 $4,549 $500 $1,700 $500 $1,700 

100,000 $57.3 $14,963 $57.3 $6,622 $500 $1,700 $500 $1,700 

Figure 5-2 presents a comparison of average costs (years 1, 2, and 3) and emissions 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 metric tons CO2e threshold. In 

addition, the cost to report under the field-level definition is higher than under the basin-level 

definition at all thresholds, except at 100,000 metric tons CO2e threshold, at which field-level is 

lower. However, emissions coverage at the 100,000 CO2e threshold under a field-level definition 

is very low—42 percent. Finally, the number of entities reporting at a 25,000 metric tons CO2e 

threshold for basin level definition is lower at 981 in comparison to the 1,157 entities reporting 

for a field-level definition.

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

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 will have a significant 

impact on a substantial number of small entities (SISNOSE) under Subpart W. To make this 

determination, EPA used a screening analysis that allows us to indicate whether EPA 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, and

– determining SISNOSE certification category.

5.2.1 Identify Affected Segments and Entities

The affected entities covered by the rule were identified during the development of the 

cost analysis for the reporting rule. The Statistics of U.S. Businesses (SUSB) data provides

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 5-10), employment (Table 5-11), and receipts (Table 5-12) and present 

information on all entities in an industry covered by Subpart W of the rule; however, many of 

these entities would not be expected to report under the selected option because they would fall 
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, 

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,” we assume in this analysis that the “enterprise” definition above is consistent 

with the concept of ultimate parent company that is typically used for Small Business Regulatory 

Enforcement Fairness Act (SBREFA) screening analyses and the terms are used interchangeably. 

We also report the SBA size standard(s) for each industry group in order to facilitate 

comparisons and different thresholds.
5-14

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

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total

Establishments

Owned by Enterprises with:

Industry NAICS NAICS Description

1 to 20 

Employees

20 to 99 

Employees

100 to 499 

Employees

500 to 749 

Employees

< 500

Employees

750 to 999 

Employees

1,000 to 

1,499 

Employees

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 60 6,584 64 31

Onshore natural gas 

transmission; 

underground natural 

gas storage; LNG 

storage; LNG import 

and export

486210 Pipeline Transportation of 

Natural Gas

1,936 b 81 27 61 36 169 2 20

Natural gas distribution 221210 Natural Gas Distribution 500 2,897 483 86 131 68 700 33 73

a

The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. 

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual 

payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. b

The SBA size standard for NAICS 486210 is $7 million in average annual receipts.
5-15

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

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total 

Employees

Owned by Enterprises with:

Industry NAICS NAICS Description

1 to 20 

Employees

20 to 99 

Employees

100 to 499 

Employees

500 to 749 

Employees

< 500

Employees

750 to 999 

Employees

1,000 to 

1,499 

Employees

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 2,421 43,105 3,551 1,061

Onshore natural gas 

transmission; 

underground natural 

gas storage; LNG 

storage; LNG import 

and export

486210 Pipeline Transportation of 

Natural Gas

37,450 b 347 157 1,053 1,934 c c c

Natural gas distribution 221210 Natural Gas Distribution 500 86,890 1,956 1,899 4,398 1,960 8,420 2,631 5,014

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. 

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual 

payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. b

The 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.
5-16

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

SBA Size 

Standard 

(effective 

March 

11, 2008)

Total 

Receipts

($Million)

Owned by Enterprises with:

Industry NAICS NAICS Description

1 to 20 

Employees

($ 

thousands)

20 to 99 

Employees

($ 

thousands

100 to 499 

Employees

($ 

thousands)

500 to 749 

Employees

($ 

thousands)

< 500

Employees

($ 

thousands)

750 to 999 

Employees

($ 

thousands)

1,000 to 

1,499 

Employees

($ 

thousands)

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 $4,609 $23,972 $3,991 $2,805

Onshore natural gas 

transmission; 

underground natural 

gas storage; LNG 

storage; LNG import 

and export

486210 Pipeline Transportation 

of Natural Gas

$35,897 b $1,035 $106 $394 c c $2,566 c c c

Natural gas distribution 221210 Natural Gas Distribution 500 $67,275 $2,524 $4,642 $2,878 $865 $13,127 $2,116 $3,757

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. 

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual 

payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. b

The 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 one to 20 range therefore underestimate true value.
5-17

5.2.2 Develop Small Entity Economic Impact Measures

Because Subpart W covers businesses, the analysis generated a set of sales tests 

(represented as cost-to-receipt ratios)19

These sales tests examine the average establishment’s total annualized mandatory 

reporting costs to the average establishment receipts for enterprises within several employment 

categories

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 us only to compute and compare ratios for a model 

establishment for eight enterprise size ranges (i.e., all categories, enterprises with 1 to 20 

employees, 20 to 99 employees, 100 to 499 employees, 500 to 749 employees, less than 500 

employees, 750 to 999 employees, and 1,000 to 1,499 employees). This approach allows us 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 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.

20 (first year costs: Table 5-13; subsequent year costs: Table 5-14). The average entity 

costs used to compute the sales test are the same across all of these enterprise size categories. As a 

result, the sales-test will overstate the cost-to-receipt ratio for establishments owned by small 

businesses, because the reporting costs are likely lower than average entity estimates provided by 

the engineering cost analysis.

 19The following metrics for other small entity economic impact measures (if applicable) would potentially include

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

revenues.

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

expenses. 20For the one to 20 employee category, we exclude SUSB data for enterprises with zero employees. These enterprises did not 

operate the entire year.
5-18

Table 5-13 Establishment Sales Tests by Industry and Enterprisea Size: First Year Costs

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($1,000/

entity)

All 

Enterprises

Owned by Enterprises with:

Industry NAICS NAICS Description

1 to 20 

Employees

20 to 99 

Employees

100 to 499 

Employees

500 to 749 

Employees

< 500

Employees

750 to 999 

Employees

1,000 to 1,499 

Employees

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% 0.02% 0.47% 0.03% 0.02%

Onshore natural gas 

transmission; 

underground natural 

gas storage; LNG 

storage; LNG import 

and export

486210 Pipeline 

Transportation of 

Natural Gas

b $15.7 0.08% 0.12% 0.40% 0.24% c c c 0.10% c c

Natural gas distribution 221210 Natural Gas 

Distribution

500 $13.9 0.06% 0.27% 0.03% 0.06% 0.11% 0.07% 0.02% 0.03%

a

The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the

establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated 

establishments. Enterprise size designations are determined by the summed employment of all associated establishments.

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent 

with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. b

The 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; some estimates were possible using partial data. The receipts for these categories underestimate true value.
5-19

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

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the 

establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated 

establishments. Enterprise size designations are determined by the summed employment of all associated establishments.

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent 

with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. b

The 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; some estimates were possible using partial data. The receipts for these categories underestimate the true value, which results in 

conservative estimates of cost-to-sales ratios. 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($/entity)

All 

Enterprises

Owned by Enterprises with:

Industry NAICS NAICS Description

1 to 20 

Employees

20 to 99 

Employees

100 to 499 

Employees

500 to 749 

Employees

< 500

Employees 750 to 999 

Employees

1,000 to 

1,499 

Employees

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% 0.01% 0.21% 0.01% 0.01%

Onshore natural gas 

transmission; 

underground natural 

gas storage; LNG

storage; LNG import 

and export

486210 Pipeline 

Transportation of 

Natural Gas

b $6.9 0.04% 0.05% 0.18% 0.11% c c c 0.05% c c

Natural gas distribution 221210 Natural Gas 

Distribution

500 $9.2 0.04% 0.18% 0.02% 0.04% 0.07% 0.05% 0.01% 0.02%
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, we 

defined a small entity as (1) a small business, as defined by SBA’s regulations at 13 CFR Part 

121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, 

school district, or special district with a population of less than 50,000; or (3) a small 

organization that is any not-for-profit enterprise that is independently owned and operated and is 

not dominant in its field.

EPA believes the selected thresholds maximize the rule coverage with 85% of all U.S. 

petroleum and natural gas systems emissions reported by approximately 2,786 reporters, while 

keeping reporting burden to a minimum and excluding small emitters. Furthermore, many 

Subpart W industry stakeholders with whom EPA met expressed support for a 25,000 metric ton 

of CO2e threshold because it sufficiently captures the majority of GHG emissions in the United 

States while excluding smaller facilities and sources. After considering the economic 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 5-13 and Table 

5-14, the average ratio of annualized reporting program costs to receipts of establishments owned 

by model small enterprises was less than 1% for industries presumed likely to have small 

businesses covered by the reporting program.

The only exception to this is the ratio for 1-20 employee range for crude petroleum and 

natural gas extraction, which is greater than 1 percent but less than 2 percent. While a majority of 

the enterprises in the petroleum and natural gas industry fall in the 1-20 employee range, most of 

the production, and therefore emissions, comes from large corporations. In fact, the top 20 large 

corporations in the U.S. account for 85 percent of the total oil and 77 percent of the total gas 

produced in the country. In most cases, the small enterprises have very small operations (such as 

a singly family owning a few production wells) that are highly unlikely to cross the 25,000 

metric tons CO2e reporting threshold. 
5-21

In other cases, a small enterprise (less than 20 employees) may own large operations but 

conduct nearly all of its operations through contractors. Such enterprises, however, tend to have 

higher annual revenues than those with small operations. In addition, these enterprises constitute 

a small fraction of the over 19,000 enterprises in the less than 20 employee category subject to 

the final rule. 

5.3 Synopsis of Benefits

Under the mandatory GHG reporting rule EPA requires to collect and verify emissions 

data from Subpart W facilities. This section reviews the benefits of a mandatory reporting 

program for Subpart W facilities based on previous experience with emissions 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 the ability of the public to make 

petroleum and natural gas facilities accountable for their equipment leaks and vented emissions. 

A GHG reporting system will also have the benefit of providing policy makers and analysts with

a data set that is comprehensive for the petroleum and natural gas industry if reporting is 

conducted under Subpart W and other applicable subparts. Benefits to the industry include the 

identification of cost-effective GHG reduction opportunities and disclosure that provides firms 

with incentives to reduce emissions voluntarily, and provides emissions data to service 

industries, such as insurance and financial markets. Availability of emissions information to the 

public, consumers, investors, corporations and government regulators provides a sound basis for 

future policy analysis. This benefits society as a whole. Accurate and transparent information is 

necessary for the implementation of efficient approaches that meet environmental goals with the 

lowest cost to the economy.

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SECTION 6

STATUTORY AND EXECUTIVE ORDER REVIEWS

This section describes EPA’s compliance with applicable executive orders and statutes 

during the development of Subpart W of the mandatory GHG reporting rule.

6.1 Executive Order 12866: Regulatory Planning and Review

Under EO 12866, (58 Federal Register (FR) 51735, October 4, 1993) the Agency must

determine whether the regulatory action is “significant” and therefore subject to Office of

Management and Budget (OMB) review and the requirements of the EO. The Order defines

“significant regulatory action” as one that is likely to result in a rule that may:

1. Have an annual effect on the economy of $100 million or more or adversely affect in a 

material way the economy, a sector of the economy, productivity, competition, jobs, the 

environment, public health or safety, or State, local, or Tribal governments or 

communities;

2. Create a serious inconsistency or otherwise interfere with an action taken or planned by 

another agency;

3. Materially alter the budgetary impact of entitlement, grants, user fees, or loan programs 

or the rights and obligations of recipients thereof; or

4. Raise novel legal or policy issues arising out of legal mandates, the President’s priorities, 

or the principles set forth in the EO.

Pursuant to the terms of Executive Order 12866, it has been determined that this final rule is a 

“significant regulatory action” because it raises novel legal or policy issues arising out of legal 

mandates, the President’s priorities, or the principles set forth in the EO. Accordingly, EPA 

submitted this action to the Office of Management and Budget (OMB) for review under 

Executive Order 12866.
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However, this action is not an “economically significant regulatory action” under EO 

12866 because it is unlikely to have an annual economic effect of $100 million or more. 

Nonetheless, EPA has prepared this analysis of the potential costs and benefits associated with 

this action. 

In the economic analysis, EPA has identified the regulatory options considered, their 

costs, and the emissions that would likely be reported under each option, and explained the 

selection of the option chosen for the rule. The cost analysis, presented in Section 4, estimates 

that under the regulatory option, the total annualized cost of Subpart W for the private sector will 

be approximately 62 million during the first year of the program and 19 million in subsequent 

years. The analysis also estimates about $1.1 million of annual programmatic costs for EPA.. In 

addition, EPA has conducted a qualitative assessment of the benefits of the rule, which are 

reported in Section 5. Overall, EPA has concluded that the costs of the proposed mandatory 

GHG reporting rule for Subpart W are outweighed by the potential benefits of more 

comprehensive information about GHG emissions.

6.2 Paperwork Reduction Act

The information collection requirements in this 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 requirements are not enforceable until OMB approves 

them.

EPA plans to collect complete and accurate economy-wide data on facility-level GHG 

emissions. 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 petroleum and gas systems, and the distribution of 

emissions from individual facilities within those systems. The facility-specific data will also 

improve our understanding of the factors that influence GHG emission rates and the actions that 

facilities are already taking to reduce emissions. Additionally, EPA will be able to track the trend 

of emissions from petroleum and gas systems 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 petroleum and gas systems would be affected, 

and how these systems would be affected by the options.

This information collection is mandatory and will be carried out under CAA Sections 114 

and 208. Information identified and marked as Confidential Business Information (CBI) will not 

be disclosed except in accordance with procedures set forth in 40 CFR Part 2. However, 
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emissions information collected under CAA Sections 114 and 208 generally cannot be claimed

as CBI and will be made public21

6.3 Regulatory Flexibility Act

.

The projected cost and hour respondent burden in the ICR is $27.7 million and 396,474

hours per year. The estimated average burden per response is 90.71 hours; the frequency of 

response is annual for all respondents that must comply with the rule’s reporting requirements; 

and the estimated average number of likely respondents per year is 2,786. The cost burden to 

respondents resulting from the collection of information includes the total capital and start-up 

cost annualized over the equipment’s expected useful life (averaging $0.74 million per year) a 

total operation and maintenance component (averaging $1.7 million per year), and a labor cost 

component (averaging $25.3 million per year). Burden is defined at 5 CFR Part 1320.3(b). These 

cost numbers differ from those shown elsewhere in the Economic Impact Analysis because ICR 

costs represent the average cost over the first three years of the rule, but costs are reported 

elsewhere in the Economic Impact Analysis for the first year of the rule and for subsequent years 

of the rule. Also, the total cost estimate of the rule in the Economic Impact Analysis includes the 

cost to the Agency to administer the program. The ICR differentiates between respondent burden 

and cost to the Agency.

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it 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 the final rule.

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the agency 

certifies that the rule will not have a significant economic impact on a substantial number of 

small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions.

 21Although CBI determinations are usually made on a case-by-case basis, EPA has issued guidance in an earlier 

Federal Register notice on what constitutes emissions data that cannot be considered CBI (956 FR 7042 – 7043, 

February 21, 1991). As discussed in Section II.R of the 40 CFR Part 98 final rule preamble, EPA is initiating a 

separate notice and comment process to make CBI determinations for the data collected under this rulemaking. 

EPA intends to issue this notice in early 2010, and will include in the notice the data proposed for collection in this 

rulemaking
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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 which is independently owned and operated and 

is not dominant in its field.

First, EPA examined the effect of Subpart W on small businesses using data collected by 

SUSB and SBA on the number of establishments, enterprises, employees, and receipts of 

businesses to allocate first-year and subsequent year costs to small businesses and assess the 

impact. Data limitations allowed EPA to only to compute and compare ratios for a model 

establishment for six enterprise size ranges (i.e., all categories, enterprises with 1 to 20 

employees, 20 to 99 employees, 100 to 499 employees, 500 to 749 employees, less than 500 

employees, 750 to 999 employees, and 1,000 to 1,499 employees). This approach is conservative

because an establishment’s parent company (the “enterprise”) may have other economic 

resources that could be used to cover the costs of the reporting program. Section 5.2 provides 

further description of these methods.

These sales tests examine the average establishment’s total annualized mandatory 

reporting costs to the average establishment receipts for enterprises within several employment 

categories. The average entity costs used to compute the sales test are the same across all of 

these enterprise size categories. As a result, the sales-test will overstate the cost-to-receipt ratio 

for establishments owned by small businesses, because the reporting costs are likely lower than 

average entity estimates provided by the engineering cost analysis.

EPA believes the selected thresholds maximize the rule coverage with over 85 percent of 

all U.S. petroleum and natural gas systems emissions reported by approximately 2,786 reporters, 

while keeping reporting burden to a minimum and excluding small emitters. Furthermore, many 

Subpart W industry stakeholders with whom EPA met expressed support for a 25,000 metric ton 

of CO2e threshold because it sufficiently captures the majority of GHG emissions in the United 

States while excluding smaller facilities and sources. After considering the economic impact of 

the rule on small entities, EPA has concluded that this action will not have a significant 

economic impact on a substantial number of small entities. The average ratio of annualized 

reporting program costs to receipts of establishments owned by model small enterprises was less 

than 1 percent for the segments that may be likely to have small businesses covered by Subpart 

W in the reporting program.
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Second, 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% of revenues. 

Third, EPA concluded that the final rulemaking would not affect a small organization that 

is any not-for-profit enterprise which is independently owned and operated and is not dominant 

in its field. Specifically, the data listing entities in each segment of the petroleum and natural gas 

industry did not include any non-profit entities. 

Although this final rule will not have a significant economic impact on a substantial 

number of small entities, EPA nonetheless took several steps to reduce the impact of this final 

rule on small entities. For example, EPA determined appropriate thresholds that reduce the 

number of small businesses reporting. In addition, EPA is proposing different monitoring 

methods for different emissions sources, requiring direct measurement only for selected sources. 

Also, EPA is proposing annual instead of more frequent reporting.

Through comprehensive outreach activities prior to proposal of the original MRR, EPA 

held approximately 100 meetings and/or conference calls with representatives of the primary 

audience groups, including numerous trade associations and industries in the petroleum and gas 

industry that include small business members. EPA’s outreach activities prior to proposal of the 

initial rule are documented in the memorandum, “Summary of EPA Outreach Activities for 

Developing the Greenhouse Gas Reporting Rule,” located in Docket No. EPA-HQ-OAR-2008-

0508-055. After the original proposal, EPA posted a guide for small businesses on the EPA 

GHG reporting rule Web site, along with a general fact sheet for the rule, information sheets for 

every source category, and an FAQ document. EPA also operated a hotline to answer questions 

about the April, 2010 proposed rule. We continued to meet with stakeholders and entered 

documentation of all meetings into the docket. 

During rule implementation, EPA will maintain an “open door” policy for stakeholders to 

ask questions about the final rule or provide suggestions to EPA about the types of compliance 

assistance that 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. 
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We have therefore concluded that this action will not have a significant economic impact 

on a substantial number of small entities. We continue to be interested in the potential impacts of 

the final rule on small entities and welcome comments on issues related to such impacts.

6.4 Unfunded Mandates Reform Act

The UMRA seeks to protect State, local, and Tribal governments from the imposition of 

unfunded Federal mandates. In addition, the Act seeks to strengthen the partnership between the 

Federal government and State, local, and Tribal governments and ensure that the Federal 

government covers the costs incurred during compliance with Federal mandates.

Title II of the UMRA of 1995, Public Law 104-4, establishes requirements for Federal 

agencies to assess the effects of their regulatory actions on State, local, and tribal governments 

and the private segment. Under section 202 of UMRA, EPA generally must prepare a written 

statement, including a cost-benefit analysis, for proposed and final rules with Federal mandates 

that may result in expenditures to State, local, and Tribal governments, in the aggregate, or to the 

private segment, of $100 million or more in any one year.

Before promulgating an EPA rule for which a written statement is needed, section 205 of 

UMRA generally requires EPA to identify and consider a reasonable number of regulatory 

alternatives and adopt the least costly, most cost-effective or least burdensome alternative that

achieves the objectives of the rule. The provisions of section 205 do not apply when they are

inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other

than the least costly, most cost-effective or least burdensome alternative if the Administrator

publishes with the final rule an explanation why that alternative was not adopted.

Before EPA establishes any regulatory requirements that may significantly or uniquely

affect small governments, including Tribal governments, it must have developed under section

203 of UMRA a small government agency plan. The plan must provide for notifying potentially

affected small governments, enabling officials of affected small governments to have meaningful

and timely input in the development of EPA regulatory proposals with significant Federal

intergovernmental mandates, and informing, educating, and advising small governments on

compliance with the regulatory requirements.

EPA has determined that the Subpart W rule does not contain a Federal mandate that may 

result in expenditures of $100 million or more for State, local, and Tribal governments, in the 

aggregate, or the private segment in any one year. Expenditures associated with compliance, 

defined as the incremental costs beyond the existing regulations will not surpass $100 million in 
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the aggregate in any year. Thus, today's final rule is not subject to the requirements of sections 

202 and 205 of UMRA.

This final rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments. This regulation applies to facilities that directly emit greenhouses gases. It does 

not apply to governmental entities unless the government entity owns a facility in the petroleum

and gas industry that directly emits greenhouse gases above threshold levels. In addition, this 

final rule does not impose any implementation responsibilities on State, local, or Tribal 

governments and it is not expected to increase the cost of existing regulatory programs managed 

by those governments. Thus, the impact on governments affected by the final rule is expected to 

be minimal.

6.5 Executive Order 13132: Federalism

Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires 

EPA to develop an accountable process to ensure “meaningful and timely input by state and local 

officials in the development of regulatory policies that have federalism implications.” “Policies 

that have federalism implications” is defined in the executive order to include regulations that 

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.”

This final rule does not have Federalism implications. It will not have substantial direct 

effects on the states, on the relationship between the national government and the states, or on 

the distribution of power and responsibilities among the various levels of government, as 

specified in Executive Order 13132.

This regulation applies to public- or private-segment facilities that directly emit GHGs 

from petroleum and natural gas systems. Relatively few 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, Executive Order 13132 does not apply to this final rule.

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments

Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal 

Governments” (59 FR 22951, November 6, 2000), requires EPA to develop an accountable 
6-8

process to ensure “meaningful and timely input by tribal officials in the development of 

regulatory policies that have tribal implications.”

EPA has concluded that this action may have tribal implications, as specified in 

Executive Order 13175 (65 FR 67249, November 9, 2000). However, it will neither impose 

substantial direct compliance costs on tribal governments, nor preempt Tribal law. 

EPA conducted an analysis to determine potential impact of this action on tribes that own 

or operate petroleum and natural gas systems (EPA-HQ-OAR-2009-0923-XXX). First, when 

conducting an emissions reporting threshold analysis, EPA analyzed a comprehensive listing of 

all operators of petroleum and natural gas systems in the United States. 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 analyses, 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 discussed in the 2009 final rule, which established 40 CFR part 98, EPA believes that 

there are minimal impacts to tribes. Tribes could be required to submit an annual GHG report for 

any facility that they own or operate that is subject to 40 CFR part 98. Landfills and stationary 

combustion equipment are the types of facilities owned or operated by tribes that would most 

likely trigger applicability. Tribes that own or operate large industrial emission sources such as 

cement plants, coal mines, or oil and gas operations could also be required to report emissions 

under this rulemaking. It should be noted that the owner or operator of any privately owned 

sources located on a reservation would be required to report for any applicable facility. The rule 

would apply to all types of stationary combustion equipment (except for emergency generators 

and portable equipment) if the aggregate maximum rated heat input capacity of all stationary fuel 

combustion units at a facility is 30 million British thermal units per hour (mmBtu/hr) or greater, 

and the facility emits 25,000 metric tons of CO2e or more per year from all stationary fuel 

combustion sources. 

In addition, EPA sought opportunities to provide information to tribal governments and 

representatives during rule development. Specifically, EPA consulted with tribal officials early 

in the process of developing the Mandatory Reporting Program to permit them to have 

meaningful and timely input into its development. First, EPA sought opportunities to provide 

information to Tribal governments and representatives during development of 40 CFR Part 98 
6-9

that was proposed in April 2009 and finalized in September 2009. Today’s action is a 

supplement to that rule.

In consultation with EPA’s American Indian Environment Office, EPA’s outreach plan 

included tribes. During the initial rule proposal phase, 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 TCR. In 

addition, EPA prepared a short article on the GHG reporting rule that appeared on the front page 

of a tribal newsletter—Tribal Air News—that was distributed to EPA/OAQPS’s network of tribal 

organizations. EPA gave a presentation on various climate efforts, including the mandatory 

reporting rule, at the National Tribal Conference on Environmental Management in June, 2008. 

In addition, EPA had copies of a short information sheet distributed at a meeting of the National 

Tribal Caucus. EPA participated in a conference call with tribal air coordinators in April 2009 

and prepared a guidance sheet for Tribal governments on the proposed rule. It was posted on the 

MRR website and published in the Tribal Air Newsletter. For a complete list of tribal contacts, 

see the “Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting 

Rule,” in the Docket for this rulemaking (EPA-HQ-OAR-2008-0508-055).

6.7 Executive Order 13045: Protection of Children from Environmental Health and 

Safety Risks

EPA interprets Executive Order 13045 (62 F.R. 19885, April 23, 1997) as applying only 

to those regulatory actions that concern health or safety risks, such that the analysis required 

under Section 5-501 of the executive order has the potential to influence the regulation. This 

action is not subject to Executive Order 13045 because it does not establish an environmental 

standard intended to mitigate health or safety risks.

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 Executive Order 13211 

(66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. Further, we have concluded that this final rule is not likely 

to have any adverse energy effects.

This proposal relates to monitoring, reporting, and recordkeeping at facilities that directly 

emit GHGs from petroleum and natural gas systems; it does not impact energy supply, 

distribution or use. Therefore, we conclude that this final rule is not likely to have any adverse 

effects on energy supply, distribution, or use.
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6.9 National Technology Transfer Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. Voluntary consensus standards are technical standards 

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide 

Congress, through OMB, with explanations when the Agency decides not to use available and 

applicable voluntary consensus standards.

This final rulemaking provides the option of using technical standards from consensus 

based standards organizations. These voluntary consensus standards will help facilities monitor, 

report, and keep records of GHG emissions. No new test methods were developed for this final 

rule. Instead, from existing rules for source categories and voluntary GHG programs, EPA 

identified existing means of monitoring, reporting, and keeping records of GHG emissions. The 

existing methods (voluntary consensus standards) include a broad range of measurement 

techniques, such as methods to analyze fuel, methods to measure gas or liquid flow, and methods 

to gauge and measure petroleum and petroleum products. The test methods are incorporated by 

reference into the rule and are available as specified in Section 98.7 of subpart A. Additional 

methods that would be incorporated under this final rule are GlyCalc and E&P tanks. 

By incorporating voluntary consensus standards into this rule, EPA is both meeting the 

requirements of the NTTAA and presenting multiple options and flexibility for measuring 

GHGs.

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal 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 
6-11

not affect the level of protection provided to human health or the environment; it is a rule 

addressing information collection and reporting procedures.

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SECTION 7

CONCLUSIONS AND IMPLICATIONS

In this Economic Impact Analysis, EPA has examined the regulatory background, the 

development of the mandatory GHG reporting rule for Subpart W, and estimated the costs and 

benefits of implementing this subpart. This section presents our overall conclusions.

7.1 Discussion of Results

EPA has developed this final rule in response to language contained in the FY 2008 

Consolidated Appropriations amendment (December 26, 2007), which authorized funding for 

EPA to publish the rule on an accelerated schedule. The major market failure that the rule is 

designed to address is one of inadequate or asymmetric information: while existing state and 

federal programs collect similar data, the resulting data are neither comprehensive nor consistent

for Subpart W sources. As such, they are an inadequate basis for the formation or evaluation of 

future climate policy that will impact the petroleum and natural gas segments.

7.1.1 Development of the Proposed Rule

EPA examined several regulatory alternative scenarios that were developed by varying 

options across two program dimensions—Threshold 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, and

– 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.
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5. The measurement variable is changed to default emissions 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 GHG Reporting Rule

7.2.1 Estimated Costs and Impacts of the Mandatory GHG Reporting Program

Under the final rule, EPA estimates that 2,786 entities would be covered by Subpart W of 

the rule, directly emitting 337 Million 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% 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% 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 emissions 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 the ability of the public to make 

facilities accountable for their emissions. Benefits to petroleum and natural gas industry include 

the identification of GHG reduction opportunities and disclosure, which provides firms with 
7-3

incentives to reduce emissions voluntarily, and provides emissions data to service industries, 

such as insurance and financial markets. A GHG reporting system will also have the benefit of 

providing policy makers and analysts with a comparable data set that is comprehensive and 

reduces the potential for policy bias. In addition, a mandatory reporting system is a key element 

to an overall GHG policy; no effort can succeed without it.

Studies published by OECD (2005) and 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 

economic impact analysis describe the following types of benefits:

– Public

– increased levels of trust towards government and industry where there are 

right-to-know laws concerning emissions;

– information to enable citizens to negotiate directly with polluters; and

– information to 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.

– Potential customer data for service industries: information about GHGemitting firms will be useful for firms that market emissions-reduction 

technologies, and to insurance companies for assessing risk.
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– 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 

GDP. Thus, despite the overall national costs, macroeconomic impacts are not anticipated, and 

EPA does not believe that the final rule will impose significant economic impacts on a 

substantial number of small entities.

A review of the literature enabled us 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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