Economic Impact Analysis for the 

Mandatory Reporting of Greenhouse 

Gas Emissions Under Subpart W 

Supplemental Rule (GHG Reporting) 

Final Report 

December 8, 2009 

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TABLE OF CONTENTS 

Page

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

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

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

1.2.1 Legislative 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.............................................................1-12 

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative ..............................1-12 

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

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

and State Programs EPA Reviewed .....................................................................2-5 

2.3.1 Inventory of U.S. Greenhouse Gas Emissions and Sinks........................2-6 

2.3.2 Federal Voluntary Greenhouse Gas Programs........................................2-8 

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

2.3.4 Other EPA Emissions Inventories........................................................2-10 
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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..............................2-13 

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

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

4.2 Overview of Cost Analysis..................................................................................4-1 

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

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

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

4.4 Summary Results: Subpart W—Petroleum and Natural Gas Systems..................4-9 

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

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

4.5.1 Determining Labor Categories.............................................................4-18 

4.5.2 Allocating Responsibilities..................................................................4-20 

4.5.3 Capital Cost Annualization and O&M Costs........................................4-26 

Section 5 Subpart W Analysis of Reporting Rule Options.......................................................5-1 

5.1 Evaluating Alternative Options for Implementation of the Rule...........................5-3 

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

5.1.2 Analysis of Alternative Monitoring Method Options.............................5-7 

5.1.3 Sensitivity of Subsequent Year Cost Estimates......................................5-8 
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5.1.4 Summary of Alternative Options for Onshore Facility Definition ..........5-9 

5.2 Assessing Economic Impacts on Small Entities.................................................5-11 

5.2.1 Identify Affected Segments and Entities..............................................5-11 

5.2.2 Develop Small Entity Economic Impact Measures ..............................5-16 

5.2.3 Results of Screening Analysis .............................................................5-19 

5.3 Synopsis of Benefits..........................................................................................5-20 

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

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

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

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

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice 

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

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

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

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 ......5-6 

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

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

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

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

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

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

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

Table 4-5 Subpart W Petroleum and Natural Gas Systems: Combustion Costs (2006$) .........4-9 

Table 4-6 Subpart W Facilities and Emissions Covered by Proposed Rule...........................4-10 

Table 4-7 Summary of Costs and Costs per Representative Entity by Threshold (Million 

2006$).................................................................................................................4-12 

Table 4-8 Allocation of Facilities to Model Types...............................................................4-17 

Table 4-9 Labor Categories and Hourly Rates .....................................................................4-18 

Table 4-10 Loaded Hourly Rates for Goods Producing Private Establishments......................4-20 

Table 4-11 Responsibilities for Regulation Compliance by Labor Category ..........................4-20 

Table 4-12 Responsibilities for Onshore Monitoring and Allocation of Labor Hours.............4-21 

Table 4-13 Monitoring Program Compliance Capital Costs and Other O&M.........................4-27 

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

Table 5-2 Vented and Fugitive Emissions Costs, Petroleum and Natural Gas Systems, First 

Year Estimates ......................................................................................................5-2 

Table 5-3 Vented and Fugitive 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.............................................................5-4 

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

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

Table 5-7 Analysis of Alternative Monitoring Methods.........................................................5-8 
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Table 5-8 Emissions Coverage and Entities Reporting for Field Level Facility Definition 

(Onshore Production) ..........................................................................................5-10 

Table 5-9 Fugitive and Vented and Combustion Emissions Cost for Field Level Facility 

Definition (Onshore Production)..........................................................................5-10 

Table 5-10 Number of Establishments by Affected Industry and EnterpriseaSize: 2002 ........5-13 

Table 5-11 Number of Employees by Affected Industry and EnterpriseaSize: 2002 ..............5-14 

Table 5-12 Receipts by Affected Industry and EnterpriseaSize: 2002....................................5-15 

Table 5-13 Establishment Sales Tests by Industry and EnterpriseaSize: First Year Costs......5-17 

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

Costs...................................................................................................................5-18 
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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 (final MRR) on September 22, 2009, 

which was published in the October 30, 2009 Federal Register (74 FR 56260). The final MRR 

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 has issued a supplemental proposed rulemaking today 

that would add Subpart W to the final MRR and collect emissions data from two additional 

segments in the petroleum and natural gas source category. 

This economic impact analysis assesses the costs and benefits of the Subpart W 

supplemental proposed rulemaking and highlights differences from the original proposal. For 

example, the supplemental proposed rulemaking incorporates additional methodologies at lower 

costs per metric ton for the industry segments compared to the original proposal; the 
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supplemental proposal also includes the key onshore production segment as well as natural gas 

distribution. 

The methodology proposed for Subpart W under the original MRR involved 100 percent 

measurement for the six segments covered (offshore production, onshore gas processing, 

transmission, underground storage, LNG storage and LNG import & export). In contrast, today’s 

supplemental rulemaking proposes 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). The proposed hybrid methodologies would use limited 

direct measurement, e.g., only in areas where emissions are known to be significant and 

insufficient reliable data are available to develop emissions factors. The bulk of emissions will 

be quantified using engineering calculation estimates based on actual facility or field data, and 

the use of leak detection and “leaker” factors

1

. There are also some sources that would use 

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

or relatively small fugitive sources. Consistent with the supplemental proposed rulemaking and 

Technical Support Document (TSD) (EPA-HQ-OAR-2009-0923), the economic analysis uses 

population based factors. In addition, EPA is recommending use of the MMS Gulfwide Offshore 

Activity Data System (GOADS) process for collecting data from offshore production platforms. 

This leverages an existing GHG data collection process to minimize burden. 

Overall, the hybrid methodology case results in a significant reduction in the compliance 

cost per metric ton of fugitive and vented GHG emissions reporting relative to the original 

proposal. For the six original segments, fugitive and vented emissions costs decline from 

$0.36/metric ton CO2e in the original proposal to $0.10/tonne CO2e in the supplemental 

proposed rulemaking, based on average “subsequent year” costs. 2 The cost per metric ton for 

onshore production is $0.06/metric ton CO2e and for natural gas distribution reporters is 

$0.04/metric ton CO2e. Overall cost for the entire petroleum and natural gas source category will 

be $21.5 million, or an average of $0.08/metric ton CO2e for about 272 million metric tons CO2e 

process emissions. 

 

1 Leaker factors are factors 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 (which assume a percentage of leaking components, hence they are only “potential” 

emissions). 

2 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. 
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The hybrid monitoring case also accounts for the cost to report combustion emissions 

because some entities that equal or exceed the Subpart W threshold for fugitive and vented 

emissions would need to report combustion emissions under Subpart C of the final MRR. In 

those cases, the entities would not have triggered the Subpart C reporting threshold in the 

absence of Subpart W. However, entities 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. Total 

combustion emissions reported under Subpart C would total about 158.1 million metric tons 

CO2e, and would cost $5.8 million per year, or $0.04/metric ton. Of the 158.1 million metric 

tons, 79.1 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 $3.9 million per year of the total combustion emissions cost, 

or $0.05/metric ton. 

Year one costs for Subpart W vented and fugitive emissions are significantly higher than 

the “subsequent year” costs, totaling $56 million for fugitive and vented emissions determination 

compared to $21.4 million in subsequent years. The higher burden is due to the requirement to 

install ports in vent lines for compressors and well equipment to enable spot measurement of 

emissions using devices such as vane anemometers. The installation of ports results in a high 

first year cost, beyond which the only cost in subsequent years is to physically take spot 

measurements. 

The total cost for Subpart W reporting is therefore significant compared to most other 

MRR source categories. The alternative of direct measurement (continuous emissions monitoring 

system, or “CEMS” case) for all Subpart W segments would result in a prohibitive total cost to 

reporting parties. The cost to simply use default emission factors would be lower, but reliable 

default emissions factors are not available for many large onshore production sources and large 

vented sources in other segments. This would make the emissions reported from these emissions 

sources unreliable and inhibit achievement of the MRR’s goal to gather information on actual 

emissions that could inform future policy. 

Finally, the original MRR proposal from April 10, 2009 included both vented and 

fugitive emissions sources, and collectively defined both sources as “fugitive.” EPA received a 

large number of comments from industry stakeholders and others indicating that this definition 

created confusion. Hence we are defining vented emissions separately from fugitives in the 
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supplemental proposed rulemaking. For this supplemental rulemaking, emissions from the 

petroleum and natural gas industry are defined as: 

1) vented emissions, which include intentional or designed releases of CH4 and/or 

CO2 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; 

2) fugitive emissions, 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 

3) flare combustion emissions, which include CH4, CO2 and N2O emissions 

resulting from combustion of gas in flares. 

1.2 Role of the Economic Impact Analysis in the Rulemaking Process 

1.2.1 Legislative Roles 

This report analyzes the estimated regulatory 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)3of the CAA authorizes the 

Administrator to, inter alia, require certain persons (see below) on a one-time, periodic or 

continuous basis to keep records, make reports, undertake monitoring, sample emissions, or 

provide such other information as the Administrator may reasonably require. This information 

may be required of any person who (i) owns or operates an emission source, (ii) manufactures 

control or process equipment, (iii) the Administrator believes may have information necessary 

for the purposes set forth in this section, or (iv) is subject to any requirement of the Act (except 

for manufacturers subject to certain Title II requirements). The information may be required for 

the purposes of developing an implementation plan, an emission standard under sections 111, 

 

3 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. 
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112 or 1294, 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)5. 

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); 

• Joint proposed rulemaking with DOT to limit greenhouse gas emissions from 

light-duty vehicles, “Joint Rulemaking to Establish Vehicle GHG Emissions and 

CAFÉ Standards,” (74 FR 49454, September 28, 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). 

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 supplemental proposed rulemaking do not indicate EPA has 

made any final decisions on these other actions. However, the mandatory GHG reporting 

 

4

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.” 

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

assist in future policy development. 

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

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. 

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 
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Budget (OMB) Circular A-4, and EPA’s Economic Guidelines6. These documents present 

guidelines for EPA to assess 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 supplemental proposed rulemaking; section 5 summarizes the costeffectiveness analysis of the program. Section 5 also qualitatively describes the benefits of the 

supplemental proposed rulemaking. 

1.2.3 Illustrative Nature of the Analysis 

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

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

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

of adjustments to reflect best and most current information from published sources (delineated in 

the TSD). When the reporting program takes effect, actual patterns of economic activity and 

emissions may differ from current conditions. However, these data provide estimates of baseline 

conditions and estimated costs of compliance. 

1.3 Overview and Design of the Economic Impact Analysis 

This Economic Impact Analysis for Subpart W 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 

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

 

6 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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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 80 significant and detailed comments (over 

1,200 plus 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 fugitive 

emission 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 fugitive and vented emissions, and combustion-related 

emissions7of CO2 and CH4 and N2O as defined in the rule. The IPCC focuses on CO2, CH4 and 

N2O for both scientific assessments and emissions inventory purposes because these are longlived, well-mixed GHGs not controlled by the Montreal Protocol on Substances that Deplete the 

Ozone Layer. These GHGs are directly emitted by human activities, are reported annually in 

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

climate change research community. 

 

7

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. 
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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 final MRR 

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 supplemental proposed 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 the final MRR, EPA selected a combination of 

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

For Subpart W, the original rule proposal involved almost exclusive application of 

detection and direct spot measurement8of vented and fugitive emissions for the six segments 

(offshore production, onshore natural gas processing, transmission, underground storage, LNG 

storage and LNG import and export facilities). The supplemental proposed rulemaking includes 

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 

 

8 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. 
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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 CO2e/year; 

o 10,000 metric tons CO2e/year; 

o 25,000 metric tons CO2e/year; 

o 100,000 metric tons CO2e/year; 

– Methodology for measuring emissions; 

o Direct spot measurement; 

o Facility-specific calculation methods; 

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 Since April, 2009 Proposal 

EPA received a total of approximately 16,800 public comments on the proposed 

rulemaking for all subparts. 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. 

Over 1,200 pages of comments were received specific to the original rule proposal Subpart W. 

Below are the major changes reflected in the supplemental proposed rulemaking for Subpart W: 

– Two additional petroleum and natural gas system segments have been added: 

onshore production and natural gas distribution. These segments represent the 

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

for fugitive, vented, and flare emissions in the petroleum and natural gas system 

source category. 

– The original rule proposal for Subpart W reflected costs that were about 19 

percent of total original rule proposal costs, while emissions covered were only 3 
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percent of total emissions covered in the entire initial rule proposal. This in large 

measure was due to the fact that essentially 100 percent of the original rule 

proposal Subpart W emissions were leak detection and direct measurement. In the 

supplemental rule proposal, the percentage of total fugitive and vented emissions 

directly spot measured has been reduced to 6 percent. 

– The methodology selected for individual sources in each of the supplemental rule 

proposal Subpart W 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 is used, in others leak detection 

coupled with use of average leaking component (i.e. leaker) factors is 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 is proposed in several areas, primarily for 

minor fugitive sources and also sources that are inaccessible or excessively 

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

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

GOADS emissions results for offshore platforms in Federal Gulf of Mexico 

(GoM) waters to avoid redundancy of reporting efforts.9 We have 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. 

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

the final MRR 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 CO2e for 5 years to cease annual reporting to EPA. 

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

less than 15,000 metric tons of CO2e for 3 years to cease annual reporting to EPA. 

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

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

annual reporting to EPA. 

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

correct errors. 

 

9 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. 
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– 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 supplemental proposed 

rulemaking for Subpart W and the estimated annual cost of the original proposed rule results 

from the inclusion of new segments in Subpart W and the significant reduction in direct 

emissions spot measurements. 

1.3.3 Evaluating Costs and Benefits 

To assist in the selection of the selected option EPA conducted an Economic Impact 

Analysis across the above dimensions for Subpart W. 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 (MMtCO2e) reported. This costeffectiveness metric was considered in combination with other important factors such as the 

potential impacts on small entities, consistency with other CAA or state-level regulatory 

programs and monitoring methods already in use within the regulated industries. 

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative 

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

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

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

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

coverage. 

– Threshold: 25,000 metric tons CO2e/year 

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

capacity, emissions, or entire source category (“All in”). In Subpart W, a 
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facility that emits 25,000 metric tons CO2e/year or more reports all sources for 

which there are methods specified in the Rule. 

– Subpart W facilities determine their applicability by comparing their 

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

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

and fugitive emissions and stationary combustion-based emissions. 

– Methodology: Combination of direct measurement and source-specific 

calculation methodologies

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

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

estimated volume of emissions and the lack of effective alternative 

methodologies or 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 

fugitive sources 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 supplemental proposed 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. 

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 fugitive GHG emissions 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 

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 
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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, we conducted a proactive communications outreach 

program to inform the public about the rule development effort. We 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. 

– We also met with U.S. Department of Energy (DOE) and U.S. Department of 

Agriculture (USDA), which have programs 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.10

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. 

 

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

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

2.2 Sources Considered 

A technical subgroup on fugitive and vented 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. 
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Table 2-1 Sources of GHG Emissions Considered 

Source Subpart W: GHG Emission Considered 

Downstream 

Stationary combustion: Sources considered include stationary combustion units 

(e.g., EGUs, boilers, furnaces, turbines, skid mounted portable equipment). 

Vented emissions: Intentional or designed emissions result from the extraction, 

processing, storage, and transport of fossil fuels (coal, petroleum, and natural gas) to 

the point of final use. Examples include compressor seal vents, storage tank vents, or 

pneumatic device emissions. 

Fugitive emissions: 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: Intentional and unintentional emissions result from the 

extraction, processing, storage, and transport of fossil fuels (coal, petroleum, and 

natural gas) to the point of final use. 

Direct emitters 

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 
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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. 

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 fugitive emissions data of 

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

this rule related to petroleum and natural gas fugitive emissions are different from other federal 

and state programs. 

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

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

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

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

CO2, CH4, N2O, hydroflurocarbons, perflurocarbons, and sulfur hexafluroide. 
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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. 

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 

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, fugitive 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 Institute11 and EPA (GRI/EPA 1996) is used as the basis for 

estimates of CH4 and non-combustion-related CO2 emissions from the U.S. natural gas industry 

in the report. 

 

11 Now the Gas Technology Institute 
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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 supplemental proposed 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 supplemental proposed 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. 

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

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

improve the accuracy of future national-level inventories. 

2.3.2 Federal Voluntary Greenhouse Gas Programs 

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

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

voluntary programs encourage 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 supplemental proposed rulemaking. 

2.3.2.1 Non-CO2 Voluntary Partnership Programs 

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

aimed at reducing emissions from GHGs such as 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. 
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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 

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 
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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. 

Facilities must submit annual reports of total stack and fugitive emissions 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 
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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. 

2.3.5.1 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 
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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 an 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, fugitive 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 

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. 
2-13 

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 emissions12,” 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 capand-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.13

The docket for the final MRR (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 

 

12

 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. 

13

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

New Jersey, New Mexico, North Carolina, Oregon, Virginia, Washington, West Virginia, and Wisconsin. 
2-14 

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 the final MRR (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. 

2.3.7.1 California Mandatory Greenhouse Gas Reporting Rule 

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 

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 of measurements 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 a column identifying the options for each 

specific dimension. Shaded boxes represent recommended options. 
3-2 

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

(Recommended Option Indicated by Shading) 

Threshold Methodology 

Capacity-based Direct measurement (CEMS) 

Emissions based 

1,000mtCO2e 

Hybrid: Direct spot 

measurement for major 

emissions sources and 

facility-specific calculations 

for others 

Emissions-based 10,000 

mtCO2e 

Default emissions factors 

from EPA 

Emissions-based 25,000 

mtCO2e 

Emissions-based 100,000 

mtCO2e 

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. 

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 (recommended) 

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

tons of CO2-equivalent emissions (tCO2e). Various levels were considered, ranging from 1,000 

tCO2e to 100,000 tCO2e. Obviously, lower thresholds would require more facilities to participate 

in the reporting program. Given current data availability, an emissions-based threshold will 
3-3 

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 

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 fugitive 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 

fugitive sources is 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 leak 

detection and quantification of emissions by use of calibrated bagging or high volume samplers 

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

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

3.1.2.2 Option 2: Hybrid of direct measurement and facility-specific calculation for 

other sources (recommended) 

EPA’s current recommended measurement methodology option for Subpart W is a hybrid 

of direct measurement and facility-specific calculations, which is considerably less burdensome 
3-4 

than Option 1. Specifically, EPA recommends 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 are used 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 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 preferred or 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 and fugitive emissions sources and stationary 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 

proposed methods. 

– For several segments in Subpart W, it was determined appropriate to develop 

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 proposed rule and owned or 

operated by a single entity, as defined by the holder of a state-issued 

permit, located in a petroleum basin. EPA also analyzed the same 

facility definition, but as applied to a petroleum field, as opposed to a 

petroleum basin. As described in the Preamble, the threshold 
3-5 

determination and cost burden is recommended to be 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, EPA is recommending 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 emissions factors for 

leaking equipment. Use of population count and population emissions factors 

are used for smaller and inaccessible sources. 

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

other sources at the facility subject to Subpart W; 

3.3 Alternative Scenarios Evaluated 

EPA developed alternative reporting scenarios and assessed the costs and emissions 

associated with each. Alternative scenarios were developed by creating the recommended 

scenario (the recommended option for each dimension, as shown in Table 3-1), then varying the 

levels in one dimension while keeping the other three dimensions at the recommended options. 

The alternative reporting scenarios evaluated for Subpart W are listed below: 

1. A 1,000 mtCO2e threshold; recommended options for methodology. 

2. A 10,000 mtCO2e threshold; recommended options for methodology. 

3. A 100,000 mtCO2e threshold; recommended options for methodology. 

4. Direct techniques (CEMS, flow meters) are used to measure emissions; recommended 

option for threshold. 

5. Default emissions factors (simplified methods) are used to measure emissions; 

recommended option for threshold. 

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 recommended 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. 
3-6 

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 rule (to allow only the incremental costs to be estimated). The 

background information for standards development, often collected from petroleum and natural 

gas industry surveys, was supplemented from numerous sources, including industry surveys from 

the U.S. Census Bureau, trade associations, and operating permits. Information on measurements 

that are already made (and thus would not be associated with the rule) was obtained from 

discussions with industry representatives, knowledge gained from previous site visits, and other 

sources. The data collected to characterize the facilities in Subpart W are judged to be of good 

quality and the best that are publicly available. 

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

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

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

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

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

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

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

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

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

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

Information Collection Requests. 
4-1 

SECTION 4

ENGINEERING COST ANALYSIS 

4.1 Introduction 

EPA estimated costs for each facility under Subpart W to comply with the rule and report 

fugitive 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. We present the reporting and verification requirements for 

petroleum and natural gas systems in Table 4-1.

Table 4-1 Selected Reporting Thresholds and Reporting Requirements 

Subpart 

(Source 

Category) Segment Reporting and Verification 

W—Petroleum 

& Natural Gas 

Systems 

(§98.230) 

Production (onshore 

 and offshore) 

Natural gas processing

Natural gas 

 transmission 

 compression 

Natural gas 

 underground 

 storage 

LNG storage 

LNG import and 

 export terminals 

Natural gas 

 distribution 

(a) Annual emissions reported separately for each of the operations listed in (a)(1) 

through (8) of this paragraph. Within each operation, emissions from each source 

type must be reported in the aggregate. 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 

(b) Emissions reported separately for standby equipment; 

(c) Report activity data for each aggregated source type level for which emissions are 

being reported; 

(d) Activity data for each aggregated source type level for which emissions are being 

reported. 

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

paragraphs (a)(1) through (8) of this section; and 

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

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

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. 

4.2 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 costs for 

performing the monitoring, recordkeeping, and reporting activities necessary to comply with 

Subpart W. All costs referred to in this section are reported in 2006 dollars. 
4-2 

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

quantify fugitive 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. Overall costs presented for Subpart W aggregate process and combustion 

emissions above those covered by Subpart C alone. 

We first provide a general overview of baseline reporting (if data are available); 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 fugitive 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 for these sources that we know is performed routinely by all companies in Subpart W is 

that they have 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 

(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. 
4-3 

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 employer

14

.

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

calculate the wage rates: 

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

(1 + Benefits Loading Factor + Overhead Loading Factor). 

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

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

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

 

14

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

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

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

above the employee compensation costs. 
4-4 

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 facilities, onshore petroleum and natural gas production companies 

(including enhanced oil recovery, EOR), onshore natural gas processing facilities (including 

gathering/boosting stations), onshore natural gas transmission compression facilities, onshore 

natural gas storage facilities, LNG storage facilities, LNG import and export facilities and natural 

gas distribution facilities. 

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 
4-5 

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 onshore natural gas transmission, a compressor station as a facility was 

modeled at the three different model size levels. Any onshore 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 facilities by this definition, so 

developing model “small”, “medium”, and “large” facilities is unintuitive and impractical. In 

this case, equipment activity was estimated at the field-level and aggregated to the national level, 

then apportioned to individual operators in basins by production rates. 

Table 4-2 Number of Facilities Reporting by Threshold and Sector 

. 

Threshold 

Segment 

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

Onshore Production 10,604 2,413 1,232 466 

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 
4-6 

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. 

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

from the loaded labor rates. For these 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 (assuming some gas gathering is operated by producers), except for natural gas 

distribution. Measuring centrifugal compressor seal degassing vents for leaks was assumed to 

take 1 hour onshore, and that will not change by segment or facility size. What changes is the 

number of centrifugal compressors located at facilities of different sizes. Thus, a series of 

universal assumptions about onshore monitoring times were created. These were multiplied by 

the 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. 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; onshore production 

is calculated at the field-level, then apportioned to basin-levels as discussed above. 

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

of information consists 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. Fugitive 

emission monitoring does not have time-tested standards and fugitive emission streams typically 
4-7 

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 

part of normal operations are required to pay for a one-time flow measurement port installation 

on compressor seal degassing 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. 

As mentioned, a different approach was taken to determine labor cost for the onshore 

production segment. Unlike the previous segments, onshore production labor costs were 

estimated by scaling up field-level labor hours, displayed in Table 4-12, to a national scale and 

then apportioned 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. 

Stationary Combustion Costs. Stationary 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. 

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 

reporting under Subpart C. EPA applied the IPCC system Tier 1 methodology, known as 
4-8 

Default Heat Content, to estimate the combustion emissions. The Tier 1 approach bases 

estimates on a fuel-specific default CO2 emission factor, a default heat content, and the annual 

fuel consumption from company records.15 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. 

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

Labor Rates (per hour) 

Senior 

Management 

Middle 

Management 

Junior 

Engineer/ or 

Technician Senior Operator

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

Labor Cost per 

Year per 

Reporting 

Unit/Facility 

Activity 

First 

Year 

Subseq. 

Year 

First 

Year 

Subseq. 

Year 

First 

Year 

Subseq. 

Year 

First 

Year 

Subseq. 

Year 

First 

Year 

Subseq. 

Year 

Planning 0.80 0.08 3.31 0.21 8.82 0.74 4.18 0.35 $1,268 $103 

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

Recordkeeping 0.18 0.18 0.29 0.29 3.05 3.01 0.62 0.62 $301 $296 

Sampling and analysis 

(calculations)

0.00 0.00 2.00 2.00 37.10 30.37 0.00 0.00 $2,813 $2,334 

Reporting 0.06 0.04 1.53 1.32 4.83 4.41 15.92 15.36 $1,502 $1,416 

Total 1.04 0.31 7.12 3.82 53.81 38.52 20.72 16.33 $5,884 $4,150 

Onshore Production Labor Costs per Year per Reporting Unit/Facility: 

• First Year: $21,877 

• Subsequent Years Average: $6,709 

 

15 The final MRR used the IPCC Tier concept to estimate combustions emissions (74 FR 56260, October 30, 2009). 

See EPA-HQ-OAR-2008-0508-0004, U.S. EPA, Technical Support Document for Stationary Fuel Combustion 

Emissions: Proposed Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more information 

about the IPCC Tier methodology (pgs 10-15). 
4-9 

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

(2006$) 

Cost Categories 

Capital and O&M Cost 

per Unit/Facility 

Activity 

Capital 

Cost 

Equipment 

Lifetime 

(years) 

Annualized 

Capital Cost 

(per year) 

O&M 

Costs 

(per year) 

First 

Year 

Subseq. 

Year 

Equipment (selection, 

purchase, installation) $ 12,549 5 $ 8,615 N/A $8,615 $8,615 

Performance testing a a a a a a

Recordkeeping $ 86 5 $21.09 N/A $21 $21 

Travel N/A N/A N/A $837.03 $837 $837 

Total $12,635 N/A $ 8,636 $837.03 $ 9,473 $ 9,473 

a

Performance testing is not required under Subpart W so no costs are entered. 

Onshore Production Capital and O&M Cost per Unit/Facility: 

• First Year: $22,490 

• Subsequent Years Average: $6,982 

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

Cost Categories 

Total Reporting Cost per 

Unit/Facility 

Activity 

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. 
4-10 

Table 4-6 shows the number and share of entities and emissions covered by the Subpart 

W supplemental proposed 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, 83 percent of 

emissions are covered at the selected 25,000 metric ton CO2e threshold. Further, both total 

emissions and covered emissions include incremental combustion emissions not triggered by the 

threshold of Subpart C alone. Again, all combustion emissions are reported under Subpart C, but 

the 25,000 metric ton threshold is determined by all GHG emissions reportable under all 

subparts. 

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

Total 

Emissions 

(Million 

mtCO2e) 

Covered 

Emissions 

(Million 

mtCO2e) 

Threshold 

Number of 

Entities 

Number of 

Facilities 

Covered 

Percent of 

Facilities 

Covered Year) Year) 

Percent of 

Emissions 

Covered 

1,000 Threshold 35,724 15,057 42% 425 415 98%

10,000 Threshold 35,724 4,884 14% 425 380 90%

25,000 Threshold 35,724 3,037 9% 425 351 83%

100,000 Threshold 35,724 1,143 3% 425 273 64%

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 affected facilities. This analysis was conducted considering vented 

and fugitive CH4 and CO2 emissions, and combustion CH4, CO2, and N2O emissions. The vented 

and fugitive emissions 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 
4-11 

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 one unconventional (i.e. those requiring 

hydraulic fracturing) gas well and 30 days to drill and complete one conventional gas or 

petroleum 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 fugitive, 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 

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. 
4-12 

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

Threshold 

First Year 

Process Costs 

Subsequent 

Year Process 

Costs 

First Year 

Combustion 

Costs 

Subsequent Year 

Combustion 

Costs 

Reporting and 

Record-keeping 

Costs* 

First Year 

National 

Costs 

First Year 

Representative 

Entity Cost 

Subsequent 

Year National 

Costs 

Subsequent Year 

Representative 

Entity Cost 

1,000 Threshold $156.6 $66.2 $29.0 $29.0 NA $187.6 $0.01 $97.2 $0.01 

10,000 Threshold $73.0 $29.0 $7.6 $7.6 NA $82.6 $0.02 $38.6 $0.01 

25,000 Threshold $56.0 $21.4 $3.9 $3.9 NA $59.9 $0.02 $25.3 $0.01 

100,000 Threshold $34.3 $11.6 $1.0 $1.0 NA $36.4 $0.03 $13.7 $0.01 

* These costs are included in Process Costs. 
4-13 

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

This is due to the following reasons: 

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

modifications to enable ongoing quantification of key emissions sources. This 

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

purchase equipment. 

• 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 cost for years following year one. 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. 

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

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

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 by the proposed rule at the basin-level. There is much larger variation in 

facilities by this definition, so developing model “small,” “medium,” and “large” facilities is 

unintuitive and impractical. In this case, equipment activity was estimated at the field-level and 
4-14 

aggregated to the national level, 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 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 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 
4-15 

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. 

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

emissions data from fugitive emissions 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 
4-16 

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, fugitive 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 

identified as a large facility. Table 4-8 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. 
4-17 

Table 4-8 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 (tCO2e) This Analysis 1,430 22,733 483,806 

Operator/Company 

2 Not estimated 

Onshore Petroleum and Natural Gas Production3 

Facility Percentile Lasser 2006 0–33% 34%–67% 68%–100%

Facility Count Lasser 2006 10,192 349 63 

Operator/Company Lasser 2006 — — — 

Mean Emissions (tCO2e) This Analysis 3,175 262,247 1,479,683 

Onshore Natural Gas Processing 

Facility Percentile API Processing Report 0–33% 34%–67% 68%–100% 

Facility Count 1 API Processing Report 486 65 15 

Operator/Company API Processing Report 166 28 10 

Mean Emissions (tCO2e) This Analysis 36,531 275,486 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 (tCO2e) This Analysis 22,114 97,050 209,073 

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 (tCO2e) This Analysis 12,386 82,081 183,671 

LNG Storage 

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

Facility Count GTI 141 13 3 

Operator/Company GTI 141** 11 3 

Mean Emissions (tCO2e) This Analysis 17,639 61,135 243,877 

LNG Import and Export 

Facility Percentile FERC — 0–100% — 

Facility Count FERC — 5 — 

Operator/Company Not estimated 

Mean Emissions (tCO2e) This Analysis — 174,643 — 

Natural Gas Distribution 
4-18 

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

Facility Count DOT 1,361 50 16 

Operator/Company DOT 1,268 49 16 

Mean Emissions (tCO2e) This Analysis 5,840 167,066 536,719 

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

3 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. 

4.5.1 Determining Labor Categories 

To evaluate labor costs, it was necessary to not only determine the amount of time 

required for all of the tasks associated with monitoring, but also to determine who will perform 

each task. For the sake of this analysis, five labor categories were used, as shown in Table 4-9. 

Table 4-9 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 All data from U.S. Department of Labor, Bureau of Labor Statistics, National Compensation Survey - Compensation Cost 

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

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

producing private establishments at the end of 2007, shown in 
4-19 

Table 4-10 below. Since the petroleum and natural gas industry pays comparatively high to other 

industries, the top four non-lawyer categories were used to be conservative in this 

approximation. Specifically, the labor rate of senior managers were assumed to be that of 

refinery mangers, middle manager labor rates were assumed to be that of electricity managers, 

junior engineer labor rates were assumed to be that of industrial managers, senior operator labor 

rates were assumed to be that of refinery engineers/technicians, and contracted technician labor 

rates were assumed to be that of industrial engineer/technician category. 
4-20 

Table 4-10 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 4-11 summarizes these roles. 

Table 4-11 Responsibilities for Regulation Compliance by Labor Category 

Cost Element 

Senior 

Management 

Middle 

Management Junior Engineer Senior Operator 

Per Facility/ 

Per Company*

Facility data To review 

reporting 

documentation/ 

systems and 

facility data 

To review 

reporting 

documentation/ 

systems and 

facility data 

To initiate 

reporting process 

and prepare 

facility data 

To prepare and 

review reporting 

process 

documentation 

and facility data 

Per facility 

Regulation 

review 

To review the 

new regulations 

To review the new 

regulations 

To examine and 

identify potential 

new regulations 

To review the new 

regulations 

identified and 

determine their 

applicability 

Per company 

Plan 

development 

To review the 

monitoring plan 

To review the 

monitoring plan 

To develop a 

monitoring plan 

To develop and 

review the 

monitoring plan 

Per company 

Equipment 

purchase 

To approve the 

equipment 

purchase 

To review the 

equipment to be 

purchased 

To identify and 

purchase the 

equipment 

To review the 

equipment to be 

purchased 

Per company 

Start-up/ 

training 

To review training 

plan 

To acquire 

training 

To provide and 

acquire training 

Per facility 

Data 

documentation 

To review the 

reporting 

documentation 

To prepare and 

complete the 

reporting 

documentation 

To prepare 

reporting 

documentation 

To prepare and 

complete 

reporting 

documentation 

Per facility 

Report 

submission 

To ensure the 

completion of the 

reporting 

documentation 

To submit the 

report 

Per Facility 
4-21 

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 

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

facilities of the company. 

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

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

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

responsibilities and associated hours are organized in Table 4-12. 

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 4-12. 

Table 4-12 Responsibilities for Onshore Monitoring and Allocation of Labor Hours 

Onshore Responsibilities by Labor Category and Hours per Responsibility 

Element Detection Quantification Applicable Segments 

Processing Facility Fugitive emissions 

Technician Conduct fugitive emissions 

detection survey (8 hours/ 

small facility, 12 hours/ 

medium facility, or 16 

hours/large facility) 

Processing 

Junior engineer Estimate emissions using 

leaker factors (2 

hours/facility) 

Processing 

Middle 

Management 

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 Fugitive emissions 

Technician Conduct fugitive emissions 

detection survey (17 hours/ 

small facility, 19 hours/ 

Transmission 
4-22 

medium facility, and 19 

hours/large facility) 

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 Fugitive emissions 

Technician Conduct fugitive emissions 

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 Fugitive emissions 

Technician Conduct fugitive emissions 

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 Fugitive emissions 

Technician Conduct fugitive emissions 

detection survey (12 hours/ 

small facility, 19 hours/ 

medium facility, and 24 

hours/large facility) 

LNG Storage 

Junior engineer Estimate emissions using 

leaker factors (2 hours/ small 

facility, 2 hours/ medium 

facility, and 3 hours/ large 

facility) 

LNG Storage 

Middle 

Management 

Oversee part of the detection 

process and review results (1 

Oversee part of the 

measurement process and 

LNG Storage 
4-23 

hour/reporting period) review results (1 hour/ 

reporting period) 

LDC Above Grade M&R Station Fugitive emissions 

Technician Conduct fugitive emissions 

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 Fugitive Emissions 

Technician Check unit for fugitive 

emissions (1 hour/ 

compressor) 

Processing 

Technician Check unit for fugitive 

emissions (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 fugitives 

quantification) 

Processing, Transmission, 

Storage, LNG Storage, LNG 

Import and Export Facilities 

Reciprocating Compressor Rod Packing Emissions 

Technician Check packing open-ended 

lines for emissions (10 

minutes/ compressor) 

Processing, Transmission, 

Storage, LNG Storage, LNG 

Import and Export Facilities 

Junior engineer Measure rod packing 

emissions (1 hour/ 

compressor) 

Onshore Production, 

Processing 

Junior engineer Measure rod packing 

emissions (2 hours/ 

compressor) 

Transmission, Storage, LNG 

Storage, LNG Import and 

Export Facilities 

Centrifugal Compressor Fugitive Emissions 

Technician Check unit for fugitive 

emissions (1 hour/ 

compressor) 

Processing 

Technician Check unit for fugitive 

emissions (2 hours/ 

compressor) 

Storage, LNG Import and 

Export Facilities 

Technician Check unit for fugitive 

emissions (2.5 hours/ 

compressor) 

LNG Storage 

Centrifugal Compressor Seals 

Junior engineer Check unit for fugitive 

emissions (1 hour/ 

compressor) 

Measure degassing vent 

emissions (1 hour/ 

compressor) 

Processing, Transmission, 

Storage, LNG Storage, LNG 

Import and Export Facilities 
4-24 

Unconventional Well Completion and Workover 

Junior engineer Measure flowback from 

completion or workover (8 

hours/ field) 

Onshore Production 

Well Liquid Unloading 

Junior engineer Measure flow from well 

blowdown (4 hours/ basin) 

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 

fugitive emissions – certain 

portion of time is assumed to 

be for engineering 

estimation of sources 

Onshore Production, 

Processing, Transmission, 

Storage 

Dehydrator Vent Stacks 

Junior engineer Collect data and perform 

simulation runs, accounted 

for in fugitive emission data 

collection (1 hour) 

Onshore Production 

Junior engineer Collect data and perform 

simulation runs (10 

minutes/dehydrator vent) 

Processing 

Junior engineer Accounted for in station 

fugitive emissions – certain 

portion of time is assumed to 

be for engineering 

estimation of sources 

Transmission, Storage 

Wellhead Fugitive Emissions 

Junior engineer Apply emission factor – 

accounted for in station 

fugitives 

Onshore Production, Storage 

Storage Tanks 

Junior engineer Collect data and perform 

simulation runs (1 hour/ 

tank) 

Onshore Production, 

Processing, Transmission 

Coal Bed Methane Water Production 

Junior engineer Water sampling per basin 

four times per year where 

where it is used for EOR – 

time accounted for in 

fugitives data collection 

Onshore Production 

Gathering Pipelines 

Junior engineer Estimate emissions using 

population emission factor – 

time accounted for in station 

fugitives 

Onshore Production, 

Processing, Transmission, 

Distribution 
4-25 

Natural Gas Distribution Pipelines 

Junior engineer Estimate emissions using 

population emission factor – 

time accounted for in station 

fugitives 

Distribution 

Below Grade Metering & Regulating Stations 

Junior engineer Estimate emissions using 

population emission factor – 

time accounted for in station 

fugitives 

Distribution 

Well Testing 

Junior engineer Perform emissions 

calculation with GOR 

measurement (1 hour/ well) 

Onshore Production 

Natural Gas Pneumatic Bleed Devices 

Junior engineer Apply emission factor – 

accounted for in station 

fugitives 

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) 

Calculate bleed rates based 

on use and design (22.5 

minutes/pneumatic device) 

Transmission, Storage 

Flare Stacks 

Junior engineer Collect data for emission 

estimate (10 minutes/ station) 

Estimate emissions using 

emission factor (10 minutes/ 

station) 

Processing 

Junior engineer Apply emission factor – 

accounted for in station 

fugitives 

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 

fugitives 

Distribution 

Table 4-12 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 proposed supplemental 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. 
4-26 

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: 

(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 4-13 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. 
4-27 

Table 4-13 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 

Measurement 

Equipment purchase Hotwire anemometers are required for compressor seal 

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–$10,449* 

* Annual travel costs are highly variable depending on the facility type, proximity, and ownership structure. Annual travel costs 

are estimated to vary from $0 to $10,449. 

As shown in Table 4-13, the fugitive 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. 

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 
4-28 

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 4-13. 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, or 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 $59.9 million in the first year and 

$25.3 million in subsequent years (2006$). These costs include costs for vented and fugitive 

emissions and incremental combustion emissions triggered by the sum of process and 

combustion emissions exceeding the threshold. Fugitive and vented emissions alone are $56.0 

million in year one and $21.4 million in subsequent years. They are based on the selected 

option, 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 $1.2 million per year. 

Approximately $0.5 million per year is for verification activities, and about $0.7 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 initial year costs are higher due to initial program start up costs (primarily investment 

to secure equipment and install flow measurement ports in vent lines to allow measurement), and 

also because the first year requires that a number of key sources (well liquids unloadings, well 

workovers, compressor wet seal degassing vents, etc) be quantified. These sources are only 

required to be estimated bi-annually to mitigate long term burden. The cost per metric ton is 

about $0.17/metric ton in the first year, declining to an average of $0.07/metric ton in subsequent 

years. 
5-2 

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

First Year Subsequent Years 

$Million $Million Subpart W – Petroleum 

and Natural Gas systems NAICS 2006 

Million 

MtCO2e $/Mt 2006 

Million 

MtCO2e $/Mt 

Process Emissions 211, 486 $56.0 272.0 $0.21 $21.4 272.0 $0.08 

Combustion Emissions $3.9 79.1 $0.05 $3.9 79.1 $0.05 

Private Sector, Total $59.9 351.1 $0.17 $25.3 351.1 $0.07 

Public Sector, Total $1.2 351.1 $0.003 $1.2 351.1 $0.003 

TOTAL $61.1 351.1 $0.17 $61.1 351.1 $0.07 

While the cost of the program is significant, there is in fact a large reduction in cost 

compared to the initial proposal stemming from the decision to use a hybrid approach to 

proposed measurement methodologies instead of direct measurement, which was the basis for 

the initial proposal for quantification of Subpart W emissions. In addition, the inclusion of 

onshore production and natural gas distribution into this segment significantly raises the total 

emissions which are covered in this analysis. Table 5-2 summarizes these changes based on year 

1 costs for fugitive and vented emissions and Table 5-3 summarizes these changes based on 

subsequent year costs for fugitive and vented emissions. 

Table 5-2 Vented and Fugitive Emissions Costs, Petroleum and Natural Gas Systems, First 

Year Estimates 

Source Emissions Million $/Mt 

Category MtCO2e 2006$ 

Original Revised Original Revised Original Revised 

Original Six Segments* 85 94.3 $32.5 $26.7 $0.38 $0.28 

Onshore Production NA 154.9 NA $27.7 NA $0.18 

Local Distribution NA 22.7 NA $1.6 NA $0.07 

Total 85 272.0 $32.5 $56.0 $0.38 $0.21 

* Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG 

storage; LNG import/export. 
5-3 

Table 5-3 Vented and Fugitive Emissions Costs, Petroleum and Natural Gas Systems, 

Subsequent Year Estimates 

Source Emissions Million $/Mt 

Category MtCO2e 2006$ 

Original Revised Original Revised Original Revised 

Original Six Segments* 85 94.3 $28.1 $11.8 $0.33 $0.13 

Onshore Production NA 154.9 NA $8.6 NA $0.06 

Local Distribution NA 22.7 NA $1.0 NA $0.04 

Total 85 272.0 $28.1 $21.4 $0.33 $0.08 

* Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG 

storage; LNG import/export. 

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 supplemental proposed rule requires the determination of onshore 

reporting to be done assuming that reporting parties report emissions and determine threshold on 

a basin level. In other words, owners or operators 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 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. 
5-4 

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 5-4Table 5-11 provides the 

cost-effectiveness analysis for the various thresholds. 

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

Hybrid Option is 25,000 metric tons CO2e 

Threshold (MtCO2e) 

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) 

Marginal 

Cost 

(2006$/Mt ) 

1,000 15,057 $187.61 415 98% $0.45 $2.01 

10,000 4,884 $82.59 380 90% $0.22 $0.78 

25,000 3,037 $59.90 351 83% $0.17 $0.00 

100,000 1,143 $36.38 273 64% $0.13 ($0.30) 

The analysis also shows a marginal cost reduction of $0.30 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 19 percent. Similarly, the 

marginal cost of moving the threshold from 25,000 to 10,000 increases $0.78 per metric ton and 

the emissions captured by increase 7 percent. Finally, the marginal cost of lowering the threshold 

from 25,000 to 1,000 yields the highest increase in marginal cost ($2.01 per metric ton), and 

increases the percentage of covered emissions by approximately 15 percent. Similar data is 

presented for subsequent years in Table 5-5. 
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 

(MtCO2e) 

Percentage of 

Total 

Downstream 

Emissions 

Reported 

Average 

Reporting 

Cost 

(2006$/Mt) 

Marginal 

Cost 

(2006$/Mt)

1,000 15,057 $97.18 415 98% $0.23 $1.13 

10,000 4,884 $38.62 380 90% $0.10 $0.46 

25,000 3,037 $25.30 351 83% $0.07 $0.00 

100,000 1,143 $13.66 273 64% $0.05 ($0.15) 

Information on how costs are distributed across segments at each threshold is provided in 

Table 5-6 for thresholds of 1,000, 10,000, 25,000, and 100,000 metric tons CO2e. 

Table 5-6 Subpart W Cost Estimates by Threshold 

First Year Subsequent Years 

Threshold 

Million 

2006$ $/Mt Million 2006$ $/Mt 

1,000 tCO2e $188 $0.45 $97.18 $0.23 

10,000 tCO2e $82.59 $0.22 $38.62 $0.10 

25,000 tCO2e $59.90 $0.17 $25.30 $0.07 

100,000 tCO2e $36.38 $0.13 $13.66 $0.05 

The selection decision weighed the marginal cost of capturing additional emissions with 

the percentage of emissions needed to accurately estimate the U.S. GHG emissions nationally 

and by segment. 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. 
5-6 

Figure 5-1 Average and Marginal Cost 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

$0.45

$0.50

55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

% of Total Emissions Reported

$/metric tons

First Year Subsequent Years Average 1K Threshold

100K Threshold

10K Threshold

25K Threshold

b. Marginal Cost Relative to Final Rule 

($0.50)

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

% of Total Emissions Reported

$/m

etric tons

First Year Subsequent Years Average 1K Threshold

100K Threshold

10K Threshold

25K Threshold
5-7 

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 – as estimated in the analysis by the U.S. Inventory as amended with additional 

methods discussed earlier in this document. 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 facility-level 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 fugitive sources. This is the methodology used in the initial rule proposal. The 

costs associated with this case in the original rule proposal (which did not include the added 

segments of 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 

revised rule proposal. These costs involve the use of direct measurement techniques, including 

metering of all vents, calibrated bagging or use of high volume samplers to measure fugitive 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 proposed 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. 
5-8 

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 $59.9 $25.3 $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 $32.3 million, and 

subsequent year costs declining by $7.9 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 recommended 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 Subpart W proposed rule option 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, 
5-9 

the analysis assumes a stable population where all entities subject to Subpart W bear a single 

first-year cost and then repeated subsequent-year costs. 

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 proposal 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 a 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 from the potential adoption of a field level facility 

definition. 
5-10 

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

(Onshore Production) 

Emissions Covered Facilities Covered Threshold 

Level Metric tons 

CO2e/year 

Percent Number Percent 

1,000 242,621,431 92% 39,652 48%

10,000 169,160,462 64% 2,846 3% 

25,000 144,547,282 55% 1,253 2% 

100,000 99,776,033 38% 305 0% 

Table 5-9 Fugitive and Vented and Combustion Emissions Cost for Field Level Facility 

Definition (Onshore Production) 

Fugitive and Vented Emission Costs Combustion Emission Costs 

Year 1 Costs Year 1 Costs Year 1 Costs Year 2 Costs Threshold 

Level2 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 $325 $6,748 $270 $2,473 $500 $1,700 $500 $1,700 

10,000 $1,035 $9,904 $270 $3,856 $500 $1,700 $500 $1,700 

25,000 $1,270 $11,001 $270 $4,357 $500 $1,700 $500 $1,700 

100,000 $1,270 $11,388 $270 $4,672 $500 $1,700 $500 $1,700 

Figure 5-2 shows a comparison of average costs (years 1, 2, and 3) and emissions 

coverage at different thresholds for the field and basin level options. It can be observed that the 

field level option would result in a significantly lower coverage in emissions reported at 55 

percent in comparison to the basin level coverage of 81 percent for a 25,000 metric tons CO2e 

threshold. In addition, the field level definition cost to report is higher than the basin level 

definition at all thresholds, except at 100,000 metric tons CO2e threshold, where field level is 

lower. But at the 100,000 CO2e threshold the coverage from field level definition is very low at 

38 percent. Finally, the number of entities reporting at a 25,000 metric tons CO2e threshold for 

basin level definition is lower at 1,181 in comparison to the 1,253 entities reporting for a field 

level definition. 
5-11 

Figure 5-2 Summary of Basin vs. Field Decision 

$2.40

$0.37

$0.03

$0.13

$0.25

$0.13

$0.10 $0.07

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

30% 40% 50% 60% 70% 80% 90% 100%

% of Total Onshore Emissions Reported

$/ton

Onshore Field Level Onshore 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 
5-12 

information on all entities in an industry covered by Subpart W of the rule; however, many of 

these entities would not be expected to report under the selected option because they would fall 

below the 25,000 hybrid threshold. SUSB also provides this data by enterprise employment size. 

The census definitions in this data set are as follows: 

– Establishment: An establishment is a single physical location where business is 

conducted or where services or industrial operations are performed. 

– Employment: Paid employment consists of full- and part-time employees, 

including salaried officers and executives of corporations, who were on the 

payroll in the pay period including March 12, 2002. Included are employees on 

sick leave, holidays, and vacations; not included are proprietors and partners of 

unincorporated businesses. 

– Receipts: Receipts (net of taxes) are defined as the revenue for goods produced, 

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. 
5-13 

Table 5-10 Number of Establishments by Affected Industry and EnterpriseaSize: 2002 

Owned by Enterprises with:

Industry NAICS NAICS Description 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total 

Establishments

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; LNG 

storage; LNG import 

and export. 

211 Crude Petroleum and Natural 

Gas Extraction 

500 7,629 5836 456 292 60 6,584 64 31 

Onshore natural gas 

processing; onshore 

natural gas 

transmission; 

underground natural 

gas storage 

486210 Pipeline Transportation of 

Natural Gas 

b 1,936 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. 

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts.
5-14 

Table 5-11 Number of Employees by Affected Industry and EnterpriseaSize: 2002 

Owned by Enterprises with:

Industry NAICS NAICS Description 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total 

Employees

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; LNG 

storage; LNG import 

and export 

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 

processing; onshore 

natural gas 

transmission; 

underground natural 

gas storage 

486210 Pipeline Transportation of 

Natural Gas 

b

37,450 347 157 1,053 c1,934 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. 

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. 

cThe U.S. Census Bureau has missing data for this employee range. 
5-15 

Table 5-12 Receipts by Affected Industry and EnterpriseaSize: 2002 

Owned by Enterprises with:

Industry NAICS NAICS Description 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Total 

Receipts 

($Million)

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; LNG 

storage; LNG import 

and export 

211 Crude Petroleum and 

Natural Gas Extraction 

500 $160,879 $7,573 $6,789 $9,608 $4,608 $23,972 $3,991 $2,805 

Onshore natural gas 

processing; onshore 

natural gas 

transmission; 

underground natural 

gas storage 

486210 Pipeline Transportation 

of Natural Gas 

b

$35,897 $1,035 $106c$394c c$2,566 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. 

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. 

cThe U.S. Census Bureau has missing data for this employee range. The receipts for the one to 20 range therefore underestimate true value. 
5-16 

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)16 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. 

These sales tests examine the average establishment’s total annualized mandatory 

reporting costs to the average establishment receipts for enterprises within several employment 

categories17 (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. 

 

16The 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. 

17For the one to 20 employee category, we exclude SUSB data for enterprises with zero employees. These enterprises did not 

operate the entire year. 
5-17

Table 5-13 Establishment Sales Tests by Industry and EnterpriseaSize: First Year Costs 

Owned by Enterprises with:

Industry NAICS NAICS Description 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($1,000/ 

entity) 

All 

Enterprises 

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; 

LNG storage; LNG 

import and export 

211 Crude Petroleum and 

Natural Gas 

Extraction 

500 $24 0.11% 1.83% 0.16% 0.07% 0.03% 0.65% 0.04% 0.03% 

Onshore natural gas 

processing; onshore 

natural gas 

transmission; 

underground natural 

gas storage 

486210 Pipeline 

Transportation of 

Natural Gas 

b

$18 0.10% 0.14% 0.47%c

0.28%c c

0.12% c c

Natural gas distribution 221210 Natural Gas 

Distribution 500 $11 0.05% 0.22% 0.02% 0.05% 0.09% 0.06% 0.02% 0.02% 

aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the 

establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated 

establishments. Enterprise size designations are determined by the summed employment of all associated establishments. 

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent 

with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. 

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. 

cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate true value. 
5-18

Table 5-14 Establishment Sales Tests by Industry and EnterpriseaSize: 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. 

bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. 

cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate the true value, which results in 

conservative estimates of cost-to-sales ratios. 

Owned by Enterprises with:

Industry NAICS NAICS Description 

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($/entity)

All 

Enterprises 

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; 

LNG storage; LNG 

import and export 

211 Crude Petroleum and 

Natural Gas 

Extraction 

500 $9 0.04% 0.69% 0.06% 0.03% 0.01% 0.25% 0.01% 0.01% 

Onshore natural gas 

processing; onshore 

natural gas 

transmission; 

underground natural 

gas storage 

486210 Pipeline 

Transportation of 

Natural Gas 

b

$9 0.05% 0.07% 0.23%c

0.14%c c

0.06% c c

Natural gas distribution 221210 Natural Gas 

Distribution 500 

$7 

0.03% 0.13% 0.01% 0.03% 0.05% 0.04% 0.01% 0.01% 
5-19 

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 83% of all U.S. 

petroleum and natural gas systems emissions reported by approximately 3,037 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 proposed 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. The petroleum and 

natural gas industry has a large number of enterprises, the majority of them in the 1-20 employee 

range. However, a large fraction of production comes from large corporations and not the small 

with less than 20 employee enterprises. The smaller enterprises in most cases deal with small 

operations (such as a singly family owning a few production wells) that are unlikely to cross 

even the 25,000 metric tons CO2e threshold considered for the rule. An exception to such a 

scenario is a small (less than 20 employee) enterprise owning large operations but conducting 

nearly all of its operations through contractors. This is not an uncommon practice in the onshore 

petroleum and natural gas production segment. Such enterprises, however, are a very small group 
5-20 

among the over 19,000 enterprises in the less than 20 employee category and EPA proposes to 

cover them in the proposed rule. 

5.3 Synopsis of Benefits 

Under the mandatory GHG reporting rule EPA proposes 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 vented and fugitive 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. 
6-1 

SECTION 6

STATUTORY AND EXECUTIVE ORDER REVIEWS 

This section describes EPA’s compliance with several 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 proposed 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. 
6-2 

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 will be approximately 

$60 million during the first year of the program and $25 million in subsequent years (not 

including $1.2 million of programmatic costs to the Agency). 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, 
6-3 

emissions information collected under CAA Sections 114 and 208 generally cannot be claimed 

as CBI and will be made public18. 

The projected cost and hour respondent burden in the ICR is $37.8 million and 478,774 

hours per year. The estimated average burden per response is 98.2 hours; the frequency of 

response is annual for all respondents that must comply with the rule’s reporting requirements. 

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 $5.3 

million per year) a total operation and maintenance component (averaging $1.6 million per year), 

and a labor cost component (averaging $30.9 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. 

6.3 Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the agency 

certifies that the rule will not have a significant economic impact on a substantial number of 

small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions. 

 

18Although 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 Final MRR 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 
6-4 

For purposes of assessing the impacts of this proposed 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 83 percent of 

all U.S. petroleum and natural gas systems emissions reported by approximately 3,037 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 industries presumed likely to have small businesses covered by the reporting 

program. 
6-5 

Second, EPA determined that the supplemental proposed 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 

supplemental proposed 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 supplemental proposed 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 proposed 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 

proposed 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 proposed rule. We continued to meet with stakeholders and entered documentation of 

all meetings into the docket. 

During rule implementation, EPA would maintain an “open door” policy for stakeholders 

to ask questions about the proposed 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 proposed 

rule. 
6-6 

We have therefore concluded that today's proposed rule will relieve regulatory burden for 

all affected small entities. We continue to be interested in the potential impacts of the proposed 

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 
6-7 

the aggregate in any year. Thus, today's rule is not subject to the requirements of sections 202 

and 205 of UMRA. 

This rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments. 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 

proposed 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 proposed 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 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 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.” 

This supplemental proposed rule may have tribal implications, as specified in Executive 

Order 13175. This regulation would apply to facilities that directly emit GHGs from petroleum 

and natural gas systems. Although few facilities that would be subject to the rule are likely to be 

owned by tribal governments, EPA has sought opportunities to provide information to tribal 

governments and representatives during rule development. 

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 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, 
6-9 

distribution, or use of energy. Further, we have concluded that this 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 rule is not likely to have any adverse effects 

on energy supply, distribution, or use. 

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 rulemaking involves technical standards. EPA proposes to use consensus standards 

bodies. These voluntary consensus standards will help facilities monitor, report, and keep records 

of GHG emissions. No new test methods were developed for this 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 supplemental proposed rulemaking 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 
6-10 

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 rule will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income populations because it does 

not affect the level of protection provided to human health or the environment; it is a rule 

addressing information collection and reporting procedures. 
7-1 

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 proposed 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. The proposed 

regulatory alternative for Subpart W calls for: 

– a threshold of 25,000 tCO2e threshold for all facilities, and 

– a hybrid methodology, including use of direct spot measurement, facility-specific 

calculation methods, and use of emission factors (leaker and population factors) 

Other scenarios evaluated included the following: 

1. A 1,000 tCO2e threshold; selected options for methodology, frequency, and verifier. 

2. A 10,000 tCO2e threshold; selected options for methodology, frequency, and verifier. 

3. A 100,000 tCO2e threshold; selected options for methodology, frequency, and 

verifier. 

4. The measurement variable is changed to direct spot measurement; selected option for 

threshold. 

5. The measurement variable is changed to default emissions factors; selected option for 

threshold. 
7-2 

7.1.2 Affected Source Categories 

EPA considered direct emitters of fugitive 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 rule, EPA estimates that 3,037 entities would be covered by Subpart W of the 

rule, directly emitting 351 Million mtCO2e per year. The total annualized costs incurred under 

the rule by these entities would be $59.9 million for the first year and $25.3 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 proposed 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 $59.9 million in the first year and 

$25.3 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 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 

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 
7-3 

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. 

– 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. 
7-4 

– 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 proposed rule will impose an estimated $34 

million (based on average costs over the first four years) 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% of entity receipts and approximately 0.001% of 2007 GDP. Thus, 

despite the overall national costs, macroeconomic impacts are not anticipated, and EPA does not 

believe that the proposed 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 proposed rule to be substantial. 
8-1 

SECTION 8

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