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

Final Report

November 2010i 

### TABLE OF CONTENTS

Page

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

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

1.2 Role of the Economic Impact Analysis in the Rulemaking Process ...................... 1-4 1.2.1 Legislative Authority and Context ........................................................... 1-4 1.2.2 Role of Statutory and Executive Orders .................................................. 1-6 1.2.3 Illustrative Nature of the Analysis ........................................................... 1-7

1.3 Overview and Design of the Ec onomic Impact Analysis ...................................... 1-7 1.3.1 Establishing Baseline and Years of Analysis ........................................... 1-7 1.3.2 Developing the GHG Reporting Ru le Considered in This Economic Impact Analysis ...................................................................... 1-8 1.3.3 Evaluating Costs and Benefits ............................................................... 1-13

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

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

2.1 EPA’s Overall Rulemaking Approach ................................................................... 2-1 2.1.1 Identifying the Goals of the Gr eenhouse Gas Reporting System ............ 2-1 2.1.2 Developing the Rule ................................................................................ 2-2 2.1.3 Evaluating Existing Greenhouse Gas Reporting Programs ..................... 2-2 2.1.4 Conducting Stakeholder Outreach to Identify Reporting Issues .............. 2-3 2.1.5 Considering Public Comments on Key Reporting Issues ........................ 2-4 2.1.6 Analyzing Emissions From the Petroleum and Natural Gas Industry .................................................................................................... 2-4

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

2.3 How the Mandatory GHG Reporting Program Is Different From the Federal and State Programs EPA Reviewed ....................................................................... 2-6

2.3.1 Inventory of U.S. Greenhouse Gas Emissions and Sinks ........................ 2-7 2.3.2 Federal Voluntary Greenhouse Gas Programs ......................................... 2-9 2.3.3 Federal Mandatory Reporting Programs ................................................ 2-10 2.3.4 Other EPA Emission Inventories ........................................................... 2-11ii 2.3.5 State and Regional Voluntar y Programs for Greenhouse Gas Emission Reporting ................................................................................ 2-11 2.3.6 State and Regional Mandator y Programs for Greenhouse Gas Emission Reporting and Control ............................................................ 2-12 2.3.7 State Mandatory Greenhouse Gas Reporting Rules ............................... 2-14

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

3.1 Rule Dimensions for Which Options Were Identified ........................................... 3-1 3.1.1 Thresholds ................................................................................................ 3-2 3.1.2 Measurement Methodology ..................................................................... 3-3

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

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

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

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

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

4.2 Overview of Cost Analysis .................................................................................... 4-2 4.2.1 Baseline Reporting ................................................................................... 4-2 4.2.2 Reporting Costs ........................................................................................ 4-2

4.3 Subpart W—Petroleum and Natural Gas Systems ................................................. 4-4 4.3.1 Overview .................................................................................................. 4-4 4.3.2 Labor Costs .............................................................................................. 4-6 4.3.3 Capital and O&M Costs ........................................................................... 4-7 4.3.4 Combustion Costs .................................................................................... 4-9

4.4 Summary Results: Subpart W—Petrol eum and Natural Gas Systems ................ 4-11 4.4.1 Detailed Threshold Analysis .................................................................. 4-12 4.4.2 Reporting Determination ....................................................................... 4-14

4.5 Detailed Cost Assumptions: Subpart W—Petroleum and Natural Gas Systems ................................................................................................................. 4-16

4.5.1 Determining Labor Categories ............................................................... 4-21 4.5.2 Allocating Responsibilities .................................................................... 4-22 4.5.3 Annualizing Capital Costs and Determining O&M Costs ..................... 4-28iii Section 5 Subpart W Analysis of Reporting Rule Options .................................................... 5-1

5.1 Evaluating Alternative Options for Implementation of the Rule ........................... 5-4 5.1.1 Analysis of Alternative Threshold Options ............................................. 5-5 5.1.2 Analysis of Alternative M onitoring Method Options .............................. 5-8 5.1.3 Sensitivity of Subsequent-Year Cost Estimates ....................................... 5-9 5.1.4 Summary of Alternative Options fo r Onshore Facility Definition ........ 5-10

5.2 Assessing Economic Impacts on Small Entities .................................................. 5-12 5.2.1 Identifying Affected Segments and Entities .......................................... 5-12 5.2.2 Developing Small-Entity Econom ic Impact Measures .......................... 5-17 5.2.3 Results of Screening Analysis ............................................................... 5-20

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

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

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

6.2 Paperwork Reduction Act ...................................................................................... 6-1

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

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

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

6.6 Executive Order 13175: Consultation a nd Coordination with Indian Tribal Governments .......................................................................................................... 6-6

6.7 Executive Order 13045: Protection of Ch ildren from Environmental Health and Safety Risks ..................................................................................................... 6-7

6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use ................................................................................................ 6-8

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

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations ......................................... 6-9

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

7.1 Discussion of Results ............................................................................................. 7-1iv 7.1.1 Development of the Proposed Rule ......................................................... 7-1 7.1.2 Affected Source Categories ..................................................................... 7-2

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

7.2.1 Estimated Costs and Impacts of the Mandatory Greenhouse Gas Reporting Program ................................................................................... 7-2 7.2.2 Summary of Qualitative Benefits Assessment ......................................... 7-2

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

Section 8 Sources Consulted ................................................................................................... .. 8-1v 

### LIST OF FIGURES

Page Figure 5-1 Average Cost and Co st Differential per Metric Ton of Emissions Reported by Threshold .................................................................................................................. 5- 7 Figure 5-2 Summary of Basin vs. Field Decision .................................................................... 5-12vii 

### LIST OF TABLES

Page

Table 2-1 Sources of GHG Emissions Considered ................................................................... 2-5 Table 2-2 Segments Included in the Petroleu m and Natural Gas Regulatory Analyses ........... 2-6 Table 3-1 Options Considered in Developi ng Scenarios for Regulation Under Subpart W (Final Option Indicated by Shading) ........................................................................ 3-2 Table 4-1 Selected Reporting Threshol ds and Reporting Requirements .................................. 4-1
Table 4-2 Number of Faci lities Reporting by Threshold and Industry Segment ...................... 4-5 Table 4-3 Subpart W Petroleum and Natura l Gas Systems: Labor Costs (2006$) ................... 4-7 Table 4-4 Subpart W Petroleum and Natura l Gas Systems: Capital and O&M Costs (2006$) 4-8 Table 4-5 Subpart W Petroleum and Natural Ga s Systems: Combustion Costs (2006$) ....... 4-11 Table 4-6 Subpart W Facilities and Em issions Covered by Final Rule .................................. 4-11 Table 4-7 Summary of National Costs and Costs per Representative Entity by Threshold ... 4-13 Table 4-8 Summary of Reporti ng Determination Costs per Segment by Threshold .............. 4-15 Table 4-9 Allocation of Facilities to Model Types ................................................................. 4-19 Table 4-10 Labor Categories and Hourly Rates ........................................................................ 4-21 Table 4-11 Loaded Hourly Rates for Goods -Producing Private Establishments ...................... 4-21 Table 4-12 Responsibilities for Regula tion Compliance by Labor Category ........................... 4-22 Table 4-13 Responsibilities for Monitori ng and Allocation of Labor Hours ............................ 4-23 Table 4-14 Monitoring Program Complian ce Capital Costs and Other O&M ......................... 4-29
Table 5-1 National Cost Estimates for Pe troleum and Natural Gas Systems ........................... 5-2 Table 5-2 Equipment Leaks and Vented Em ission Costs, Petroleum and Natural Gas Systems, First-Year Estimates .................................................................................. 5-2 Table 5-3 Equipment Leaks and Vented Em ission Costs, Petroleum and Natural Gas Systems, Subsequent-Year Estimates ....................................................................... 5-3 Table 5-4 Summary of Threshol d Cost-Effectiveness Analysis (First Year); Selected Hybrid Option Is 25,000 MtCO 2 e ............................................................................. 5-5 Table 5-5 Summary of Thre shold Cost-Effectiveness Analys is (Subsequent Years) .............. 5-6 Table 5-6 Subpart W Cost Es timates by Threshold .................................................................. 5-6viii Table 5-7 Analysis of Altern ative Monitoring Methods ........................................................... 5-9 Table 5-8 Emission Coverage and Entities Repo rting for Field-Level Facility Definition (Onshore Production) .............................................................................................. 5-11 Table 5-9 Equipment Leaks, Vented, and Combustion Emission Cost for Field-Level Facility Definition (Onshore Production) ............................................................... 5-11 Table 5-10 Number of Establishments by Affe cted Industry and Enterp rise Size: 2002 ......... 5-14 Table 5-11 Number of Employees by Affected Industry and Enterpri se Size: 2002 ................ 5-15 Table 5-12 Receipts by Affected Indu stry and Enterprise Size: 2002 ...................................... 5-16 Table 5-13 Establishment Sales Tests by Industry and Enterprise Size: First-Year Costs ....... 5-18 Table 5-14 Establishment Sales Tests by Indus try and Enterprise Size: Subsequent-Year Costs ....................................................................................................................... 5 -19ix 

### ACRONYMS AND ABBREVIATIONS

API American Petroleum Institute ARP accidental release prevention

BLS Bureau of Labor Statistics BOEMRE Bureau of Ocean Energy Ma nagement, Regulation, and Enforcement

CAA Clean Air Act CARB California Air Resources Board CBI confidential business information CEMS continuous emission monitoring system CCAR California Climate Action Registry CFR Code of Federal Regulations CH 4 methane CMOP Coalbed Methane Outreach Program CO 2 carbon dioxide CO 2 e carbon dioxide-equivalent CRF capital recovery factor ERMR Essential Requirements for Mandatory Reporting
DOD Department of Defense DOE Department of Energy DOT Department of Transportation
EGU electric generating unit EIA Economic Impact Analysis EO executive order EPA U.S. Environmental Protection Agency ERMR Essential Requirements for Mandatory Reporting
FAQ frequently asked questions FERC Federal Energy Regulatory Commission FR Federal Register
GHG greenhouse gas GOADS Gulfwide Offshore Activity Data System GoM Gulf of Mexico GRI Gas Research Institute
HHV high heating value
ICR information collection request IPCC Intergovernmental Panel on Climate Change
LDC local distribution companyx LMOP Landfill Methane Outreach Program LNG liquefied natural gas
M&R metering and regulating MMBtu million British thermal units MMS Minerals Management Service MtCO 2 e metric tons of car bon dioxide-equivalent MW megawatt

NAICS North American Indus try Classification System NEI National Emissions Inventory NESHAP National Emissions Standa rds for Hazardous Air Pollutants NTTAA National Technology Transfer and Advancement Act of 1995
O&M operations and maintenance OECD Organisation for Economic Co-operation and Development OMB Office of Management and Budget
PFC perfluorocarbon PRTR pollutant release and transfer registers PSD Prevention of Significant Deterioration
QAPP Quality Assurance Project Plan QA/QC quality assura nce/quality control OAQPS Office of Air Qualit y Planning and Standards
R&D research and development RFA Regulatory Flexibility Act RGGI Regional Greenhouse Gas Initiative

SBA Small Business Administration SBREFA Small Business Regulatory Enforcement Fairness Act SF 6 sulfur hexafluoride SISNOSE significant impact on a substa ntial number of small entities SUSB Statistics of U.S. Businesses
TCR The Climate Registry TRI Toxics Release Inventory TSD Technical Support Document

UMRA Unfunded Mandates Reform Act UNFCCC United Nations Framework Convention on Climate Change U.S.C. United States Code USDA U.S. Department of Agriculture
WBCSD World Business Council for Sustainable Developmentxi WCI Western Climate Initiative WRI World Resources Institutexii Disclaimer
The Environmental Protection Agency (EPA) regulations cited in this Economic Impact Analysis (EIA) contain legally-binding requirements. Several sections of the EIA offer illustrative examples for complying with the minimum requi rements indicated by the regulations. This is done to provide information that may be helpful to understand the costs associated with reporters’ implementation efforts. Such recommendations are prefaced by the words “may” or “should” and are to be considered advisory. They are not required elements of the regulations cited in this EIA. Therefore, this document does not substitute for the regulations cited in this EIA, nor is it a regulation itself, so it doe s not impose legally-binding requirements on EPA or the regulated community. It may not apply to a pa rticular situation base d upon the circumstances. Mention of trade names or commercial pr oducts does not constitute endorsement or recommendation for use.
While EPA has made every effort to ensure the a ccuracy of the discussion in this document, the obligations of the regulated comm unity are determined by statutes , regulations or other legally binding requirements. In the even t of a conflict between the disc ussion in this document and any statute or regulation, this docum ent would not be controlling.1-1 SECTION 1 INTRODUCTION AND BACKGROUND

1.1 Background On December 26, 2007, President Bush signed the fiscal year (FY) 2008 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 [g reenhouse gas] GHG emissions above appropriate threshold in a ll segments of the economy.
The accompanying explanatory text stated that EP A shall “use its existing authority under the Clean Air Act” to develop a mandatory GHG reporting rule.
The agency is further directed to incl ude in its rule reporting of emissions resulting from upstream production and downs tream sources, to the extent that the Administrator deems it appropriate. The Administrator shall determine appropriate thresholds of emissions a bove which reporting is required, and how frequently reports shall be submitted to EPA. The Administrator shall have discretion to use existing reporting requirements for electric generating units under Section 821 of the Clean Air Act.
EPA signed the final mandatory GHG reporting rule (40 Code of Federal Regulations [CFR] Part 98) on September 22, 2009, which wa s published in the October 30, 2009 Federal Register (FR) (74 FR 56260). This rule did not include Subpart W, Petroleum and Natural Gas Systems, due to the extensive number of commen ts 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 technique s. As a result, EPA issued a proposed rulemaking on April 12, 2010 (75 FR 18608) that w ould add Subpart W to 40 CFR Part 98 and collect emission data from two additional segm ents in the petroleum and natural gas source category. EPA also released an Economic Impact Analysis (EIA) in Ap ril 2010 that assessed the proposed rulemaking’s costs and benefits. 1

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

(GHG Reporting); see www.epa.gov/c limatechange/emissions/subpart/w.html.1-2 This final EIA presents revised cost estimates that reflect the changes EPA made to the final rule based on its considerati on of public comments. Overall, these changes have resulted in a lower cost per metric ton for industry segments to monitor and report emissions compared to the April 2010 proposed rulemaking. The estimated total cost for the petr oleum and natural gas source category to comply with the final rule is $61.8 million in the first year. Of this total, it costs $40.1 million to monitor and report about 254 million metric tons of carbon dioxide equivalent (MtCO 2 e) process emissions, or, on average, $0.16/MtCO 2 e. This cost compares with the estimate of $0.38/ MtCO 2 e under the April 2009 proposal. 2

Whereas the methodology proposed in Apr il 2009 for Subpart W involved 100-percent measurement for six segments (offshore production, onshore gas processing, transmission, underground storage, liquefied natural gas (LNG) storage and LNG import and export), the April 2010 notice proposed hybrid methodologies to quan tify GHG emissions from eight segments in the petroleum and natural gas systems subpart (the original six, pl us onshore production and natural gas distribution). Today’ s rule finalizes the hybrid approach for the eight segments. Notably, it uses limited direct measurement (i.e., only in areas where emissions are known to be significant and not enough reliable data are avai lable to develop emission factors). The bulk of emissions will be quantified using engineering calc ulations based on actual facility or field data and using leak detecti on and “leaker” factors 3 . There are also some sources that would use population-based factors—often refe rred to as default factors—pr imarily for inaccessible sources or relatively small leaking sour ces. Consistent with the Apr il 2010 proposed rulemaking and the Technical Support Document (TSD) (EPA -HQ-OAR-2009-0923-0027), the final rule and economic analysis use population-based factors. In addition, EPA finali zed the proposal to use the MMS 4 Gulfwide Offshore Activity Data System (GOADS) process for collecting data from offshore production platforms. This approach le verages an existing GHG data collection process and minimizes burden.
Today’s final rule includes several key change s that affect compliance cost estimates. First, the final rule provides equipment thres holds on several emission sources. Reporters will

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

threshold determination and $3.3 million for combustion emission reporting by reporters. The April 2009 analysis did not include a burden estimate for non-reporters to make a threshold determination. 3 Leaker factors are developed by actual measurement of leaks from a large population of common fugitive or

vented sources; the emission quantification requires actual det ection of a leak before app lication of a factor. This method provides a truer assessment of actual emissions than “population” emission factors, which are based on simple population count. The population count provides an estimate of “potential” emissions because it assumes a percentage of leaking components. 4 The Minerals Management Service (MMS) has been renamed the Bureau of Ocean Energy Management,

Regulation, and Enforcement (BOEMRE).1-3 use simple population-based emission factors fo r sources below the equipment threshold. Second, EPA has simplified the requirement for sa mpling of gas and emissions for many of the emission sources, thus considerably reducing burden.
Overall, the hybrid methodology fina lized in today’s rule results in a significant reduction in the compliance cost per metric ton of e quipment leak and vent ed GHG emission reporting, relative to the orig inal proposal. For the six original segments, equipment leak and vented emission costs for reporters changed from $0.36/MtCO 2 e in the April 2009 proposed rule to $0.28/MtCO 2 e in the April 2010 prop osal, and to $0.33/MtCO 2 e in the final rulemaking, based on average “first-year” costs. 5 , 6 These estimates do not acc ount for onshore production and natural gas distribution, the two segments added in the April 2010 proposal. Under the final rule, EPA estimates it will cost reporters on average, in eight segments, $0.16/MtCO 2 e in the first year, which is less than th e first year cost of $0.21/MtCO 2 e in the April 2010 proposed rulemaking.
The cost estimates for today’s rule also account for the burden to report combustion emissions because some reporters that equal or exceed the Subpart W threshold for equipment leaks and vented emissions would need to re port combustion emissions under Subpart C of 40 CFR Part 98. In those cases, the reporters woul d not have triggered th e Subpart C reporting threshold in the absence of Subpart W. Those th at meet the emission threshold under Subpart W, however, are required to report combustion emissi ons under Subpart C, even if the combustion emissions alone do not exceed the Subpart C thres hold. In short, EPA expects the addition of Subpart W to the GHG reporting rule to result in the reporting of additional combustion emissions under Subpart C, referred to as “increme ntal combustion emissions” in this document. Of the 162.2 million MtCO 2 e expected to be reported under Subpart C, 83.5 million MtCO 2 e are the combustion emissions from petroleum and natu ral gas facilities that would not have reported in the absence of Subpart W. The incrementa l combustion emission reporting is $3.3 million per year of the total combustion emission cost, or $0.04/MtCO 2 e.
First-year costs for Subpart W vented and equipment leak emissions are significantly higher than the “subsequent-year” costs, tota ling $40.1 million in the first year for equipment leaks and vented emission determination, decreasing to $15.1 million in subsequent years. The higher burden is due to start-up costs in the fi rst year. For example, the rule requires the

5 The $0.28 figure was incorrectly stated as $0.10/metric ton in the April 2010 EIA due to typographical error. 6 Unless otherwise specified, this document reports all costs in 2006 dollars and the emissions as CO 2 e using a 100-

year global warming potential from the Intergovernmental Panel on Climate Change (IPCC). Also, subsequentyear costs are the average of costs subsequent to first-y ear costs and thereby represen t a “steady-state” time period.1-4 installation of ports in vent line s for compressors and well equipment in the first year to enable spot measurement of emissions using devices such as vane anemometers. This is a one-time cost associated with reporting start-up; the only cost in subsequent years fo r those sources is to physically take spot measurements.
Today’s rule finalizes the approach in the Ap ril 2010 proposal to define vented emissions separately from fugitive emissions, except that it replaces the term “fugitive emissions” with “equipment leak.” EPA made this change in response to public comments that “equipment leak” is better understood in the industry. In sum, today’s final rule defines emissions from the petroleum and natural gas industry as follows:

1) Vented emissions, which include intenti onal or designed rele ases of methane (CH 4 ) and/or carbon dioxide (CO 2 ) containing natural gas or hydrocarbon gas (not including stationary combustion flue gas) from emission sources including, but not limited to, open-ende d lines, gas pneumatic-powered valves and pumps, equipment depressuring to the atmosphere, and compressor shaft seals.

2) Equipment leaks, which mean those em issions that could not reasonably pass through a stack, chimney, vent, or othe r functionally equivalent opening.

3) Flare combustion emissions, which include CH 4 , CO 2 , and nitrous oxide (N 2 O) emissions resulting from combustion of gas in flares.

1.2 Role of the Economic Impact Anal ysis in the Rulemaking Process

1.2.1 Legislative Authority and Context This report analyzes the estimated economic impacts of the mandatory reporting program that EPA has developed for Subpart W, in accordance with the FY 2008 Appropriations language, under the authority of Section 114 of the Clean Air Ac t [CAA]. Section 114 provides EPA broad authority to collect data for the pur pose of “carrying out a ny provision” of the Act (except for a provision of Title II with respect to manufacturers of new motor vehicles or new motor vehicle engines). Section 114(a) 7 of the CAA authorizes the Administrator to, inter alia, require certain persons (see below), on a one-time, periodic or continuous ba sis, to keep records, make reports, undertake monitoring, sample emissions , or provide such other information as the Administrator may reasonably requ ire. This information may be required of any person who (i)

7 The joint explanatory statement refers to “Section 821 of the Clean Air Act,” but Section 821 was part of the 1990 CAA Amendments and was not codified into the CAA itself.1-5 owns or operates an emission source, (ii) manufac tures control or process equipment, (iii) the Administrator believes may have information nece ssary for the purposes set forth in this section, or (iv) is subject to any require ment of the Act (except for manuf acturers subject to certain Title II requirements). The information may be required for the purposes of developing an implementation plan, an emission st andard under Sections 111, 112 or 129 8 , determining if any person is in violation of any st andard or requirement of an implementation plan or emission standard, or “carrying out any provision” of the act (except for a provision of Title II with respect to manufacturers of new motor vehicl es or new motor vehicle engines) 9

. The scope of the persons potentially subjec t to a Section 114(a)(1) information request (e.g., a person “who the Administrato r believes may have information necessary for the purposes set forth in” Section 114[a]) and the reach of the phrase “carryi ng 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 inform ation relevant to carrying out provisions involving research (e.g., Section 103[g]); evaluating and settin g standards (e.g., Section 111); and endangerment determinations contained in speci fic provisions of the Act (e.g., 202); as well as other programs.
EPA has recently announced a number of clim ate change related actions, including:

 Final rulemaking with the Department of Transportation (DOT) to limit GHG emissions from light-duty vehicles , “Light-Duty Vehi cle Greenhouse Gas Emission Standards and Corporate Aver age Fuel Economy Standards,” (75 FR 25324, May 7, 2010).

 Proposed Endangerment and Cause or C ontribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (74 FR 18886, April 24, 2009).

 Reconsideration of the memo entitled “EPA ’s Interpretation of Regulations that Determine Pollutants Covered by Federal Prevention of Signifi cant Deterioration (PSD) Permit Program” (73 FR 80300, December 31, 2008).

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

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

“Hazardous Air Pollutants”; and Section 129 contai ns provisions for “solid waste combustion.” 9 Although there are exclusions in Section 114(a)(1) re garding certain Title II requirements applicable to

manufacturers of new motor vehicle and motor vehicle engines, Section 208 authorizes the gathering of information related to those areas.1-6 These are all separate actions. Some are related to EPA’s response to th e U.S. Supreme Court’s decision in Massachusetts v. EPA. 127 S.Ct. 1438 (2007); others are EPA actions to address climate change. The GHG reporting rule and this final rulemaking do not indicate that EPA has made any final decisions on these other actions; however, the mandatory GHG reportingprogram will provide EPA, other government agencies, and outside stakeholders with economywide data on facility-level (and in some cases corporate-le vel) GHG emissions, which could assist in future policy development.
Accurate and timely information on GHG emissi ons is essential for informing future climate change policy decisions. Although additi onal 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 us eful 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 indi vidual facilities within different segments of this industry. The facility-specific data will also improve understa nding of the factors th at 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 d ecisions for implementation of these standards. Other important considerations included the language of the Appr opriations Act and the accompanying explanatory statement related to s ource 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 al ready in use within the petroleum and natural gas industry; and th e potential burden placed on small businesses associated with a range of reporting thresholds.
This EIA is intended to inform the public abou t 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 di ctate the manner in which EPA considers rulemaking and apply to any public documentation. The analysis required by these statutes and executive orders is presented in Section 6.1-7 EPA presents this EIA for Subpart W—Petr oleum and Natural Gas Systems—pursuant to Executive Order 12866, the guidelines of Office of Management a nd Budget (OMB) Circular A4, and EPA’s Economic Guidelines 10 . These documents contain guidelines for assessing the benefits and costs of the selected regulatory option, as well as opti ons that are more stringent or less stringent. Section 4 of the EIA presents the costs of the final rulemaking; Section 5 summarizes the cost-effectiveness analysis of th e program and also qualit atively describes the benefits of the fi nal 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 existi ng 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 mo st current information from published sources (delineated in the TSD). When the reporting pr ogram takes effect, actua l patterns of economic activity and emissions may differ from current co nditions; however, these data provide estimates of baseline conditions and estim ated costs of compliance.

1.3 Overview and Design of the Economic Impact Analysis This EIA comprises seven sections. Follo wing this introductory section, Section 2 describes segments affected by Subpart W provi sions and reviews existing reporting programs and how they treat comparable petroleum and natural gas systems. Section 3 describes the development of the rule, includi ng control options and analyses of alternative scenarios. Section 4 characterizes baseline conditions and presents engineering estimat es 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 presen ts a brief qualitative examination of potential benefits of the rule. Section 6 provides a disc ussion of the Agency’s compliance with executive orders and other statutes dur ing the development of the ru le. Section 7 describes EPA’s conclusions and findings.

1.3.1 Establishing Baseline and Years of Analysis Data used for the analysis represent the mo st recent data available on estimates of GHG emissions for the petroleum and natural gas source category, producti ve capacity, existing

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

circulars/a004/a-4.pdf.1-8 emission monitoring, and reporting activities for this industry. While EPA recognizes that economic growth and changes in the structure of the economy over time will likely result in changes in both emissions and costs for those co vered 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 essen tially current conditions as a proxy for conditions present when the rule takes effect. Such estimates are inherently uncertain because data needed for more precis e measurements are not available. The data collected by the rule would grea tly enhance future estimates.

1.3.2 Developing the GHG Reporting Rule Considered in This Economic Impact Analysis In order to ensure a comprehensive cons ideration of GHG emissions, EPA conducted numerous stakeholder meetings, evaluated more than 484 significant and detailed comments (more than 2,700 pages for Subpart W), and con ducted extensive review and analysis of available information on segments and specific sources.
EPA examined existing GHG reporting programs prior to developing the rule. Although the mandatory GHG rule is unique, EPA carefully considered other federal and state programs during development of the rule to analyze how these programs treat emissions from the petroleum and natural gas industry. One of EPA’ s goals was to develop a reporting rule for Subpart W units that, to the ex tent possible and appropriate, is consistent with existing GHG emission estimation and reporting methodologies, to reduce the burden of reporting for all parties involved. The TSD documents EPA’s review of GHG monitoring protocols for each segment identified by Subpart W that is used by federa l, state, regional, and international voluntary and mandatory GHG programs, and EPA’s review of state mandatory GHG rules and how they treat equipment leak emissions from the petroleum and natural gas industry.
EPA’s overall rulemaking approach began with identifying anthropogenic sources in the U.S. GHG Inventory and Intergovernmental Pane l on Climate Change (IPCC). The rule would require reporting of CO 2 and CH 4 equipment leak and vented emissions, as well as combustionrelated emissions 11 of CO 2 , CH 4 , and N 2 O as defined in the rule. The IPCC focuses on CO 2 , CH 4 , and N 2 O for both scientific assessments and emissi on inventory purposes because these are longlived, well-mixed GHGs not controlled by the Mont real Protocol on Substa nces that Deplete the Ozone Layer. These GHGs are directly emitted by human activities, are reported annually in

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

combustion-related emissions are to be reported under Subpart C of the finalized GHG reporting rule.1-9 EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks, and are the common focus of the climate change research community.

EPA then conducted a review of existi ng methodologies and re porting programs (e.g., California Air Resources Board [CARB], The Climate Registry [TCR], 1605b of the Energy Policy Act). EPA’s review of existing repor ting programs and measurement methodologies employed by existing federal and state programs is described in Section II of the 40 CFR Part 98 preamble (74 FR 56260, October 30, 2009). A descri ption specific to petr oleum and natural gas can be found in Section C of the TSD. EPA used this information to inform its selection of measurement and reporting met hods for this final rulemaking.
Once EPA had a complete list of source cate gories relevant to the United States, the Agency systematically reviewed those source cate gories against the following criteria to develop the list of source categorie s included in the proposal:
(1) Include source categories that emit the most significant amounts of GHGs, while also minimizing the number of reporters.
(2) Include source categories that can be quantified with an ap propriate level of accuracy.
EPA identified source categories that would be required to re port. EPA then screened sources by several key criteria, looking at the nu mber of reporters versus the coverage of emissions under various thresholds, relevant and appropriate quantif ication methodologies, quantification accuracy, and ad ministrative burden. Based on the source-level screening activities, EPA then developed possible report ing methodologies for the selected sources. The reporting methodologies identified fall into seve ral categories, including continuous emission monitoring, calculating emissions based on site-s pecific information, and calculating emissions based on default emission factors. In general, for 40 CFR Part 98, EPA selected a combination of continuous emission monitoring and calculati ons based on site-specific information.
For Subpart W, the April 2009 proposed rule in volved almost exclusive application of detection and direct spot measurement 12 of vented and equipment leak emissions for the six segments (offshore production, onshore natura l gas processing, transmission, underground storage, LNG storage and LNG import and expo rt facilities). Both the April 2010 proposed

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

measurement using a vane anemometer or similar e quipment; the measurement is not “CEMS” (continuous emission monitoring system), as it is not continuous.1-10 rulemaking and final rulemaking include eigh t segments—the original six plus onshore petroleum and natural gas production and natu ral gas distribution—and significantly reduce the sources that must be directly quantified. While direct spot m easurement is still required to develop site or equipment-spec ific emission factors for some major sources, much of the emission quantification is thr ough 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 methodolog ies had been identified, EPA evaluated different rule options acro ss the following dimensions:

– Threshold (level of emissions below whic h entities are not re quired to report):

o 1,000 MtCO 2 e/year

o 10,000 MtCO 2 e/year

o 25,000 MtCO 2 e/year

o 100,000 MtCO 2 e/year

– Methodology for measuring emissions:

o Direct spot measurement

o Facility-specific calculation methods

o Leaker and default emission factors The Agency examined several options for each dimension to identify the selected option for the rule.
The options and alternatives evaluated are described in detail in Section 3. Section 4 details the engineering cost analysis, which out lines the monitoring and reporting activities and costs for each source under Subpart W that is required to report.

1.3.2.1 Summary of the Major Changes From th e April 2009 Proposed Rulemaking to the April 2010 Proposed Rulemaking EPA received approximately 16,800 public comments on the April 2009 proposed rulemaking for all subparts; more than 1,200 page s of those comments focused on Subpart W. EPA held two public hearings and conducted an unprecedented level of outreach between signature of the proposal and the close of the public comment period. The following are the major changes reflected in the April 2010 proposed rulemaking for Subpart W:1-11 – Two additional petroleum and natural gas system segments were added: onshore production and natural gas distribution. Th ese segments repr esent the largest (onshore production) and fourth largest (n atural gas distribution) segments for equipment leak, vented, and flared emi ssions in the petroleum and natural gas system source category.

– Under the April 2009 proposed rule for Subpa rt W, essentially 100 percent of the emissions were monitored using leak dete ction and direct measurement. In the April 2010 proposed rule, the percentage of total equipment leak and vented emissions directly spot measur ed was reduced to 6 percent.

– The methodology selected for individual sources in each of the proposed April 2010 rule segments was determined based on the intent to achieve the most cost effective coverage of emissions. Therefor e, in some cases accepted engineering estimates based on facility data were used; in others, leak detection coupled with use of average leaking component (i.e. l eaker) factors was used (this is more informative data on actual leaks for l ong-term tracking purposes than emission “population” factors based on component counts).

– Use of population emission factors was pr oposed in several areas, primarily for minor equipment leak sources and also sources that are inaccessible or excessively burdensome for leak detecti on. To the degree poss ible, use of these factors was minimized.

– In the case of offshore production, EP A proposed reporting of existing MMS GOADS emission results for offshore platfo rms in federal Gulf of Mexico (GoM) waters to avoid redundancy of reporting efforts. 13 EPA also required that facilities not covered by GOADS (state waters a nd federal non-GoM platforms) use data collection and emission calculation met hods in accordance with the BOEMRE GOADS program to reduce burden and make emission reporting consistent across the segment.

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

federal waters in the Western Gulf of Mexico, developed by MMS (now called BOEMRE). The MMS mandated that all 2,525 offshore operators in the Gulf of Mexico conduct annual surveys (in 2000 and 2005) of their GHG and other hazardous pollutants. MMS collects activity data from each plat form that is then used to estimate emissions. The usual cycle for this data collection effort has been once in every three to four years.1-12 In addition to the Subpart W-specific changes above, the changes affecting all subparts of 40 CFR Part 98 would likewise affect Subpa rt W reporters. These changes include:

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

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

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

– Added a provision in 40 CF R 98.3 for submitting revised annual GHG reports to
correct errors.

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

– Excluded research and development (R &D) activities from reporting under 40 CFR part 98 by adding an exclusion in 40 CFR 98.2.

– Revised the requirements of the designate d representative in 40 CFR 98.4 to align them with those in 40 CFR 75 (accidental release prevention [ARP] regulations).

– Changed record retention to three years in stead of five years for most records (40 CFR 98.3).

– In the recordkeeping section (40 CFR 98.3), clarified the contents of the monitoring plan (called the Quality Assura nce Project Plan [QAPP] at proposal).

– Revised several definitions in 40 CFR Pa rt 98, Subpart A to address comments.

Overall, the difference between the estimated annual cost of the April 2010 proposed rulemaking for Subpart W and the estimated annual cost of the April 2009 proposed rule resulted from the addition of two segments to Subpart W and the significant reduc tion in direct emission spot measurements.1-13 1.3.2.2 Summary of the Major Changes From th e April 2010 Proposed Rulemaking to the September 2010 Final Rulemaking

Based on its consideration of comme nts on the April 2010 proposed rule, EPA incorporated the following changes in the final rule:

– Provide an equipment threshold for sepa rators, and dehydrators such that sources below the equipment threshold use a simplified population emission factor approach and sources above the equipm ent threshold use actual monitoring.

– Onshore production compressors use emi ssion factor approach for estimating process emissions; actual monitoring is not required.

– Use of emissions factors for all pneum atic devices in onshore production. Also, reporters may count the pneumatic devices in their facilities over a period of three years, beyond which only cha nges have to be reported.

– Provide an external combustion equipm ent threshold of 5 mmBtu per hour for onshore production and LDCs. External co mbustion equipment with a rated heat capacity equal to or less than this e quipment threshold only report the type and count of equipment within a facility.

– For onshore production, population emission factors will be applied to major equipment rather than individual components.

– Sampling is not required for estimatin g combustion emissions, determining the composition of natural gas, or assessing tank vapors; best available estimates are acceptable.

– Allow the use of leak detection equipmen t, such as organic vapor analyzers and toxic vapor analyzers, in addi tion to using infrared devices.
These changes significantly reduce burd en and simplify emission reporting.

1.3.3 Evaluating Costs and Benefits To inform the selection of the option for th e final rule, EPA conducted an EIA across the dimensions identified in Section 1.3.2. EPA estimat ed the costs of complying with each of the reporting alternatives and assessed the cost-effec tiveness of each alternative by examining the costs per million MtCO 2 e reported. This cost-effectiveness metric was considered in combination with other important factors such as the potential impacts on small entities and consistency with1-14 other CAA or state-level regulato ry programs and monitoring met hods already in use within the regulated industries.

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative The selected option for Subpart W of th e mandatory GHG reporting rule is outlined below. Section 5 provides cost comparisons fo r each alternative evaluated under the following two dimensions. The selected option strikes a balance between impacts on small entities, consistency with other programs, costs incurred by the reporting entities, and emission coverage.

– Threshold : 25,000 MtCO 2 e/year

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

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

– Subpart W segments evaluate threshold from an analysis of reported vented and equipment leaks and stationa ry combustion-based emissions.

– Methodology : Combination of direct meas urement and source-specific calculation methodologies

– Direct spot measurement of site- or equipment-specific emission factors from sources at facilities that were deemed to be essential to collect based on the estimated volume of emissions and the lack of effective alternative methodologies or emission factors.

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

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

– Source-specific use of population-based em ission factors for minor vented and equipment leaks or inaccessible sources.2-1 SECTION 2 REGULATORY BACKGROUND

The intent of this rule is to collect accu rate and timely GHG emission data that can be used to inform future policies. Although th e 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 na tural gas industry. The reporting program will supplement rather than duplicate other U.S. government GHG programs. EPA outlines the Agency’s overall rulemaking approach, sources considered, and summarize the review of GHG monitoring protocols for each petroleum and natural gas system used by federal, state, regional, and international voluntary and mandatory GHG pr ograms, and EPA’s review of state mandatory GHG rules below. For example, the monitoring and GHG calculation methodologies for many of the petroleum and natural gas systems are the same as, or similar to, the methodologies contained in state reporting programs. Th e remainder of the section provides an overview of related existing programs and discusses their rele vance in the development of this rule.

2.1 EPA’s Overall Rulemaking Approach In response to the FY 2008 Consolidated Appropriations Amendment, EPA has developed this rulemaking. The components of th is development are explained in the following subsections.

2.1.1 Identifying the Goals of the Greenhouse Gas Reporting System The mandatory reporting program outlined in Subpart W will provide comprehensive and accurate data that will inform future climate ch ange policies. Potential future climate policies include research and development initiatives , economic incentives, ne w or expanded voluntary programs, adaptation strategies, emission standard s, a carbon tax, or a cap and trade program. Because EPA does not know at this time the sp ecific policies that will be adopted, the data reported through the mandatory reporting system s hould be of sufficient quality to support a range of approaches. Also, consistent w ith the FY 2008 Consolidated Appropriations Amendment, the GHG reporting rule covers a broa d range of source categories in the economy; however, this EIA for the final rulemaking is spec ific to Subpart W, petroleum and natural gas systems.

To these ends, EPA identified the followi ng 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.2-2 – Balance the rule coverage to maximize the amount of emissions reported while minimizing reporting from small emitters.

– Create reporting requirements that are c onsistent with existing GHG reporting programs by using existing GHG e mission estimation and reporting methodologies to reduce reporti ng burden, where feasible.

2.1.2 Developing the Rule For Subpart W, EPA evaluated the require ments of existing GHG reporting programs, obtained input from stakeholders, analyzed reporting options, and developed the general reporting requirements and specifi c requirements for each of the GHG emitting processes listed in Subpart W. In addition, EPA considered public comments it received on both the original April 2009 and April 2010 proposed rulemakings as it determined the re porting requirements issued in today’s final rule.

2.1.3 Evaluating Existing Greenhouse Gas Reporting Programs A number of state and regional GHG reporting systems currently are in place or under development. EPA’s goal is to develop a repor ting rule that, to the extent possible and appropriate, would rely on sim ilar protocols and formats of the existing programs for petroleum and natural gas systems and, therefore, reduce the burden of reporting for all parties involved. Therefore, EPA performed a comprehensive re view of existing voluntary and mandatory GHG reporting programs, as well as guidance documen ts for quantifying GHG equipment leaks from the petroleum and natural gas source categ ory. These GHG reporting programs and guidance documents specifically related to the petrol eum and natural gas source category include:

– U.S. national programs, such as the U.S. GHG inventory, the ARP, Department of Energy (DOE) 1605(b) voluntary regist ry, and voluntar y 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 (RGG I), and programs in California, New Mexico, and New Jersey.

– Reporting protocols developed by nongovern mental organizations, such as the World Resources Institute/World Busine ss Council for Sustainable Development (WRI/WBCSD).

– Programs from industrial trade organizati ons, such as the American Petroleum Institute’s Compendium of GHG Estima tion Methodologies for the Petroleum and Gas Industry.2-3 In reviewing these programs, EPA analyzed the segments covered, thresholds for reporting, the monitoring or emission estimating methods used, the measures to ensure the quality of the reported data, the point of monitoring, data input needs, and information required to be reported and/or retained. EPA analyzed these provisions for suita bility to a mandatory, federal GHG reporting program, and compiled the in formation. Section 2.3 describes the existing reporting programs examined regarding Subpart W. The full review of existing GHG reportingprograms and guidance for all GHG reporting rule subparts may be found in the docket at EPAHQ-OAR-2008-0508-054.

2.1.4 Conducting Stakeholder Outreach to Identify Reporting Issues Early in the development process of the GHG reporting rule, EPA conducted a proactive communications outreach program to inform the public about the rule development effort. EPA solicited input and maintained an open-door pol icy 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 poten tially affected industries/segments.

– State, local, and tribal environmental c ontrol agencies and regional air quality planning organizations.

– State and regional organizations alre ady involved in GHG emission reporting, such as TCR, California Air Resource s Board (CARB), and Western Climate Initiative (WCI).

– Environmental groups and other nongovernmental organizations.

– U.S. Department of Interior, which ha s a program relevant to GHG emissions.
During the meetings, EPA shared informa tion about the statut ory requirements and timetable for developing a rule and encouraged stakeholders to provide input on key issues. Examples of topics discussed included exis ting GHG monitoring and re porting programs and lessons learned, thresholds for reporting, schedul es 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 tribes2-4 through conference calls with differe nt Indian tribal working groups and organizations at EPA as well as through individual calls wi th tribal board members of TCR. 14

On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting rule. EPA held two public hearings and received more than 16,000 written public comments. The public comment period ended on June 9, 2009. Subpart W received co mments from more than 80 entities with over 1,200 pages of comments, recommendations, and alternatives fo r consideration.
In addition to the public hearings, EPA had an open-door policy, similar to the outreach conducted during the development of the proposal . As a result, EPA met with more than 4,000 people and 135 groups between proposal signat ure (March 10, 2009) and the close of the comment period (June 9, 2009). Deta ils of these meetings are av ailable in the docket (EPA-HQOAR-2009-0923).

2.1.5 Considering Public Commen ts on Key Reporting Issues EPA considered public comments submitted to th e docket and those presented at hearings as it finalized the reporting requirements. In the context of the Apr il 2010 proposed rulemaking process, EPA held one public hearing and rece ived more than 40 substantive written public comments. Most comments supported changes made in the proposed rule published on April 9, 2010; however, various commenter s expressed concern about th e inclusion of the Onshore Production and Local Distribution se gments and stated that the scope and cost burden of the proposal would be significantly exceed the costs estimated by EPA. In addition, many commenters suggested changes in methodology or quantification, wh ich EPA incorporated into the final rule. For example, consistent with several commenters’ recommendations, EPA has provided flexibility in the types of leak detec tion equipment required to monitor emissions. See the preamble of today’s final rule for a complete discussion of these changes.

2.1.6 Analyzing Emissions From the Petr oleum 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 fram eworks, estimated emissions of GHGs, and estimated productive capacity or throughput. Section 4 summarize s the incremental costs of measuring vented and equipment leak GHG emis sions and conducting reporting activities for Subpart W facilities. Section 5 pr esents cost scenarios that vary the conditions of the reporting rule for Subpart W with respect to the size of th e entity required to re port and the type of

14 For a full list of organizations EPA met with when developing this rule, please see the EPA docket memo, EPAHQ-OAR-2008-0508-055.2-5 measurement required of the petroleum and natu ral gas segment. The scenarios specific to Subpart W are listed in Section 3. EPA also revi ewed the benefits to stakeholders, including the public, the government, and industry, of a re porting system for petroleum and natural gas emissions in a qualitative analysis. Th ese benefits are outlined in Section 5.

2.2 Sources Considered A technical subgroup on vented and equipmen t leak emissions considered the following sources of emissions from the petroleum and natural gas industry, as shown in Table 2-1. Using screening criteria based on the feasibility of monitoring, veri fying, and measuring these sources, the technical subgroup developed reporting me thodologies for the sources in Subpart W identified in Table 2-2.

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

Downstream

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

Vented emissions : Intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas) that result from the extraction, processing, storage, an d transport of fossil fuels to the point of final use. Examples include compressor seal vents, storage tank vents, or pneumatic device emissions.

Equipment leaks : Emissions that are unintentional and could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening. Examples include leaks from valves and connectors.

Flare combustion : Unburned hydrocarbons, including CH 4 , CO 2 , and N 2 O emissions resulting from the incomplete combustion of gas in flares from the extraction, processing, storage, and transport of fossil fuels to the point of final use.2-6 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 program s EPA reviewed are diverse. They have different thresholds, require diffe rent pollutants and different t ypes of emission sources to be reported, rely on different monitoring protocols, and require different types of data to be reported, depending on the purposes of each progra m. 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. Th e remainder of this section focuses on existing state and federal programs that apply to pe troleum 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 ru le. Documentation of EPA’s review of GHG monitoring protocols for each source category used by federal, state, and international voluntary and mandatory GHG programs, and EPA’s review of state mandatory GHG rules can be found at EPA-HQ-OAR-2008-0508-056. The monitoring and GHG calculation methodologies for many source categories are the same as, or similar to, the methodologies cont ained in state reporting programs such as TCR, the California Climate Action Registry (CCAR), and state mandatory GHG reporting rules and similar to methodologies developed by EPA voluntary programs such as Climate Leaders. Similarity in methods will help maximize the ability of individual reporters to submit the emission calculations to multiple pr ograms, if desired. EPA will continue to work closely with states and state-based groups to ensu re that the data management approach in this rule will lead to efficient submission of petroleum and natural gas data to multiple programs.2-7 The intent of this rule is to collect a r easonable estimate of GHG emission data that can be used to inform future policy decisions. One goal in developing the rule is to be consistent with the GHG protocols and requirements of other state and federal pr ograms, where appropriate, in order to make use of existing cooperative effort s and reduce the burden to petroleum and natural gas facilities submitting reports to other programs. EPA also needs to be sure, however, that the mandatory GHG reporting rule colle cts facility-specific vented a nd equipment leaks data of sufficient quality to achieve the Agency’s objecti ves. Therefore, some re porting requirements of this rule related to petroleum and natural gas equipment leaks are different from other federal and state programs.

2.3.1 Inventory of U.S. Greenhouse Gas Emissions and Sinks The U.S. greenhouse gas inventory, prepared by EPA’s Office of Atmospheric Programs in coordination with the Office of Transportation and Air Quality, is an impartial, policy-neutral report that tracks annual GHG emissions. The annual re port presents historic al U.S. emissions of CO 2 , CH 4 , N 2 O, hydrofluorocarbons (HFCs), perfluorocar bons (PFCs), and sulfur hexafluoride (SF 6 ).

The United States submits the Inventory of U.S. Greenhouse Gas Emissions and Sinks to the Secretariat of the United Nations Framew ork Convention on Climate Change (UNFCCC) as an annual reporting requirement. The UNFCCC treat y, ratified by the United States in 1992, sets an overall framework for intergovernmental effo rts to tackle the cha llenge posed by climate change. The United States has submitted the GHG i nventory to the United Nations every year since 1993. The annual Inventory of U.S. Greenhouse Gas Emissions and Sinks is consistent with national inventory data submitted by other UNFCCC parties and uses internationally accepted methods for its emission estimates.
In preparing the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks , EPA leads an interagency team that includes DOE, th e U.S. Department of Agriculture (USDA), the Department of Transportation (DOT), the De partment of Defense (DOD), and the State Department. EPA collaborates with hundreds of e xperts representing more than a dozen federal agencies, academic institutions, industry as sociations, consultants, and environmental organizations. The Inventory of U.S. Greenhouse Gas Emissions and Sinks is peer-reviewed annually by domestic experts and by UNFCCC, undergoes a 30-day public comment period, and is peer reviewed annuall y by UNFCCC review teams.

The Inventory of U.S. Greenhouse Gas Emissions and Sinks is a comprehensive, topdown national assessment of national GHG emissi ons and uses top-down national energy data2-8 and other national statistics. To achieve the goal of comprehensive national emission coverage for reporting under the UNFCCC, most GHG emissions in the report are ca lculated via activity data from national-level database s, statistics, and surveys. The use of the aggregated national data means that the national emission estimates are not broken down at the geographic or facility level. In contrast, this reporting rule focuse s on bottom-up data and individual sources above appropriate thresholds.
The inventory contains estimates of vented emissions, equipment leaks, and combustion emissions from petroleum systems and from na tural gas systems, which are both IPCC source categories. Regarding the quantification of CH 4 emissions from natural gas systems, reductions achieved through the Natural Gas STAR progr am and National Emissions Standards for Hazardous Air Pollutants (NESHAP) regulations are included (see below for more details on these programs). A detailed study by the Gas Research Institute (GRI) 15 and EPA (GRI/EPA 1996) is used as the basis for estimates of CH 4 and non-combustion-related CO 2 emissions from the U.S. natural gas industry in the report.
For petroleum and natural gas systems, EPA has been aware that there are a number of areas where the 2008 U.S. Greenhouse Gas Invent ory Report assumptions may substantially underestimate actual emission levels. The final rule for Subpart W is estimated to significantly increase the level of emissions covered th an are included in the 2008 U.S. Greenhouse Gas Inventory Report by reflecting improved estimates of emissions from key sources such as well liquid unloadings, well workovers, well completions and compressor wet seal degassing vents. These estimates are based on publicly available information from the EPA Natural Gas STAR Web site and assumptions based on expert judgment.
The final rule for Subpart W will therefore he lp to improve the development of future national inventories for petroleum and natura l gas systems by improving the estimates of emissions and thereby advance the understa nding of emission pro cesses and monitoring methodologies. Facility, unit, and process level G HG emission data for all sources will improve the accuracy of future U.S. Greenhouse Gas Inventory Reports by confirming the national statistics and emission estimation methodologies used to develop the top-down inventory. The results can confirm shortcomings in the national st atistics and identify where adjustments may be needed.

15 Now the Gas Technology Institute2-9 Therefore, although the da ta collected under this rule will not replace the system in place to produce the comprehensive annual national invent ory, it can serve as a us eful tool to better improve the accuracy of future national-level inventories.

2.3.2 Federal Voluntary Greenhouse Gas Programs EPA and other federal agencies operat e a number of voluntary GHG reporting and reduction programs that EPA reviewed when developing this proposal , including several nonCO 2 voluntary programs, and the DOE 1605(b) vol untary GHG registry. Several other federal voluntary programs encourage emission reductions, clean energy, or energy efficiency; this summary does not cover them all (for additional information see Review of Existing Programs
, EPA-HQ-OAR-2008-0508-054). This summary focuse s on programs that include voluntary GHG emission inventories or repo rting of GHG emission reducti on activities for sources that were considered for inclusion in Su bpart W of this final rulemaking.

2.3.2.1 Non-CO 2 Voluntary Partnership Programs Since the 1990s, EPA has ope rated a number of non-CO 2 voluntary partnership programs aimed at reducing emissions from GHGs such as CH 4 , SF 6 , and PFCs. There are four segmentspecific voluntary methane reduction programs: Natural Gas STAR, Landfill Methane Outreach Partnership (LMOP), Coalbed Methane Outreach Programs (CMOP), and Ag STAR. In addition, there are segment-specific voluntary emission re duction partnerships for high-global-warmingpotential gases. The program specific to those en tities that fall under Subpart W is the Natural Gas STAR partnership, which encourages comp anies across the natural gas and petroleum industries to adopt practices that reduce methane emissions. Industr y partners voluntarily provide technical information on projects they undert ake to reduce methane emissions on an annual basis, but they do not submit methane emission inventories.

2.3.2.2 1605(b) Voluntary Registry The DOE Energy Information Administrati on 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 gui delines was published on April 21, 2006 (71 FR 20784); the rule is contained in 10 CFR Pa rt 300. Unlike EPA’s proposal, which requires reporting of GHG emissions from facilities over a specific threshold, the DOE 1605(b) registry allows anyone (e.g., a public enti ty, private company, or an indivi dual) to report their emissions and their emission reduction project s to the registry. Large emitte rs (e.g., anyone that emits over 10,000 MtCO 2 e per year) who wish to register emission reductions must submit annual company-wide GHG emission inventories followi ng technical guidelines published by DOE and2-10 must calculate and report net GHG emission reducti ons. The program offers a range of reporting methodologies from stringent dir ect measurement to simplified cal culations 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 establis hed, published authorities’ estim ation methods, which must be referenced. In addition, as mentioned previousl y, unlike EPA’s proposal, se questration and offset projects can also be reported under the 1605(b) pr ogram. There is additional flexibility offered to small sources, which is that they can choose to limit annual inventories and emission reduction reports to a single type of activ ity rather than reporting comp any-wide GHG emissions, but they must still follow the technical guidelines. Reporte d data are made availabl e on the Internet in a public-use database.

2.3.2.3 Summary These voluntary programs are different in nature from the mandatory GHG reporting rule. Industry participation in the programs and reporting to the programs is entirely voluntary. A small number of sources report, compared to the nu mber of facilities that will likely be affected by Subpart W of the mandatory GHG reporting rule. Most of the EPA voluntary programs do not require reporting of annual emission data, but are instead intended to encourage GHG reduction activities and track partners’ successes in implementing such projects.
At the same time, aspects of the voluntary pr ograms serve as useful starting points for the mandatory GHG reporting rule. GHG emission calcula tion principles and pr otocols have been developed for various types of emission source s by Climate Leaders, the DOE 1605(b) program, and some partnerships such as the SF 6 reduction partnerships and SmartWay. Under these protocols, reporting companies monitor process or operating parameters to estimate greenhouse emissions, report annually, and retain record s to document their GHG estimates. Through the voluntary programs, EPA, DOE, and participati ng companies have gained understanding of processes that emit GHGs and experience in developing and reviewing GHG emission inventories.

2.3.3 Federal Mandatory Reporting Programs

2.3.3.1 Toxics Release Inventory

The Toxics Release Inventor y (TRI) requires facility-lev el reporting of annual mass emissions of approximately 650 toxic chemicals. Wh en facilities—in a wide range of industries, such as manufacturing industries and the pe troleum industry—emit these chemicals above2-11 established thresholds, they re port. Facilities must submit a nnual reports of total stack and equipment leaks of the listed toxic chemicals us ing a standardized form that can be submitted electronically. No information is reported on th e processes and emission points included in the total emissions. The data reported to TRI are not directly useful for the GHG rule because TRI does not include GHG emissions and does not iden tify processes or emi ssion sources. The TRI program is similar, however, to the mandatory GHG reporting rule in that it requires direct emission reporting from a large number of fac ilities (roughly 23,000) acro ss all major industrial segments. Therefore, EPA reviewed the TRI prog ram for ideas regarding program structure and implementation.

2.3.4 Other EPA Emission Inventories

2.3.4.1 National Emissions Inventory EPA compiles the National Emissions Invent ory (NEI), a database of air emission information provided primarily by state and local ai r 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 po int 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 repor t stationary sources that emit amounts below the thresholds for each pollutant. The point sources that NEI includ es number more than 60,000 facilities. Required point source information consists of facility identification information as well as process information detailing the types of air pollution emission sources, air pollution emission estimates (including annual emissions), control devices in place, stack parameters, and location information. The NEI differs from the GHG reporti ng rule in that the NE I contains no GHG data, and the data are reported primarily by state agenci es rather than directly reported by industries. In developing the rule, however, EPA used the NE I to help determine sour ces that might need to report under Subpart W of the GHG reporting rule. EPA considered the types of facility and process and activity data reported in NEI to support the emission data as a possible model for the types of data to be reported under the GHG reporting rule.

2.3.5 State and Regional Voluntary Programs for Greenhouse Gas Emission Reporting

A number of states have de monstrated 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 a ddressing GHG emissions. The following discussion summarizes two prominent voluntary efforts. In developing the GHG rules, EPA reviewed the relevant protocols used by these programs as a starting point. The Agency recognizes that these2-12 programs may have additional monitoring and repor ting requirements than those outlined in the rule in order to provide distinct program benefits.

2.3.5.1 California Climate Action Registry CCAR is a voluntary GHG-registry already in use in California. CCAR has released several methodology documents, including a genera l reporting protocol, general certification (verification) protocol, and several segment- specific protocols. Companies submit emission reports using a standardized el ectronic system. Emission reports may be aggregated at the company level or reported at the facility level. CCAR is transitioning out of entity-emission reporting; 2009 will be the last year it accepts such reporting. Emission reporting can instead be conduced under CCAR’s sister orga nization The Climate Registry (TCR), which is based off of CCAR’s work. A number of member s of CCAR have already made the transition over to TCR.

2.3.5.2 The Climate Registry TCR is a partnership formed by U.S. and Mexi can states, Canadian provinces, and tribes to develop standard GHG emission measurement a nd verification protocols and reporting system capable of supporting mandatory or voluntary GHG emissi on reporting rules and policies for its member states. TCR has released a final General Reporting Protocol that c ontains procedures to measure and calculate GHG emissions from a wi de range of source cate gories. It has also released a general verification protocol and an electronic reporting system. Several industryspecific draft protocols have been released recently for public comment, including Petroleum & Gas Exploration & Production Protocol and a verification protocol for this segment. Founding reporters (companies and other organizations that have agreed to voluntarily report their GHG emissions) implemented a pilot reporting program in 2008. Annual reports will be submitted covering six GHGs. Corporat ions must report facility-specifi c emissions broken out by type of emission source (e.g., stationary combustion, mob ile combustion, process, equipment leak and indirect) and gas (CO 2 , CH 4 , N 2 O, HFCs, PFCs and SF 6 ) within each facility.

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

Several individual states and re gional groups of states have demonstrated leadership and are developing or have developed manda tory GHG reporting programs and GHG emission control programs. This section summarizes two regional cap and trade pr ograms and several state mandatory reporting rules, which cover—or, for those programs still under development, have the potential to cover—the petroleum and natura l gas segment. EPA recognizes that, like the current voluntary regional and state programs, state and regi onal mandatory reporting programs2-13 may evolve or develop to include additional mo nitoring and reporting requirements than those included in the rule. In fact, these programs ma y be broader in scope or more aggressive in implementation because the programs are either components of establ ished reduction programs (e.g., cap and trade) or being used to design and inform specific m easures that indirectly reduce GHG emissions (e.g., energy efficiency).

2.3.6.1 Regional Greenhouse Gas Initiative RGGI is a regional cap and trade program that covers CO 2 emissions from electric generating units (EGUs) larger than 25 megawatts (MW) in member states in the Mid-Atlantic and Northeast. The program goal is to reduce CO 2 emissions to 10 percent below 1990 levels by the year 2020. Certain types of o ffset projects will be allowed, and GHG offset protocols have been developed. The states participating in R GGI have adopted state rules (based on a model rule) to implement RGGI in each state. The RG GI cap and trade program took effect on January 1, 2009. There has been some discussion of regul ating additional sour ces of GHG emissions under the RGGI program in the future.

2.3.6.2 Western Climate Initiative WCI is another regional cap and trade progr am 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 pr ogram design recommendations were made in September 2008. Other elements of the program, such as reporting re quirements, 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 ru les implementing these re porting requirements in place for the 2010 reporting year or shortly ther eafter. 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 fo r inclusion in the cap and trade framework. One such category is “industrial process emission sources, including petroleum and natural gas process emissions” 16 , meaning that sources covered under Subpa rt W of the federal reporting rule may also be regulated under a future WCI pr ogram. The program might be phased in, starting with a few source categories and adding others ov er time. Points of regulation for some source categories, calculation met hodologies, and other reporting program elements are under

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

biological, and other non-combustion processes. These emissions may be deliberate (e.g., vented), fugitive (e.g., leaked), or accidental.2-14 development. WCI is also analyzing alternativ e or complementary polic ies other than cap and trade that could help reach GHG reduction goals. Options for rule implementation and for coordination with other rules and programs such as TCR are being investigated.

2.3.7 State Mandatory Greenhouse Gas Reporting Rules

Seventeen states have de veloped, or are developing, mandatory GHG reporting rules. 17 The docket for 40 CFR Part 98 (74 FR 56260, Oct ober 30, 2009) contains a summary of these state mandatory rules (EPA-HQ-OAR-2008-0508-056). Final rules have not yet been developed by some of the states, so details of some programs are unknown. Reporting requirements have already entered into effect in 12 states as of 2009; the rest will begin between 2010 and 2012. Reporting is typically annual, although some states require quarterly reporting for EGUs, consistent with RGGI.
State rules differ with regard to which f acilities must report and which GHGs must be reported. Some states require a ll facilities that must obtain Title V permits to report GHG emissions. Others require reporting for particul ar segments (e.g., large EGUs, cement plants, refineries). Some state rules apply to any facili ty with stationary combustion sources that emit a threshold level of CO 2 . Some apply to any facility, or to facil ities within listed industries, if their emissions exceed a specified threshold level of CO 2 e. Many of the state rules apply to six GHGs covered by 40 CFR Part 98 (CO 2 , CH 4 , N 2 O, HFCs, PFCs, SF 6 ); others apply only to CO 2 or a subset of the six gases. Most re quire reporting at the facility leve l, or by unit or process within a facility.
The level of specificity regarding GHG mon itoring and calculation methods varies. Some of the states refer to use of protocols establis hed by TCR or CCAR, to i ndustry-specific protocols (such as methods developed by the American Petroleum Institute [API]), to accepted international methodologies such as IPCC, and/or to emission factors in EPA’s Compilation of Air Pollutant Emission Factors (known as AP-42) or other EPA guidance.

2.3.7.1 California Mandatory Greenhouse Gas Reporting Rule The CARB mandatory reporting rule is an example of a state rule that covers multiple source categories and contains relatively detailed requirements, similar to this proposal developed by EPA. The regulation became ef fective on January 2, 2009. According to CARB, selected facilities (e.g. general stationary combustion facilities outside the petroleum-and-gas segment, and electricity generati on and cogeneration plants not w ithin the operational control of

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

Jersey, New Mexico, North Carolina, Oregon, Virginia, Washington, West Virginia, and Wisconsin.2-15 larger facilities and entities) are required to ha ve filed their first emissi on data reports by April 1, 2009. The rest of the facilitie s and entities are to have reported by June 1, 2009 (see www.arb.ca.gov/cc/reporting/ghg-rep/ghgschedadvisory.pdf ). The rule requires facility-level reporting of all GHGs (except PFCs) from ce ment manufacturing plants, electric power generation and retail markets, cogeneration plan ts, petroleum refineries , hydrogen plants, and facilities with stationary combustion sources emitting greater than 25,000 MtCO 2 per year. The California rule does not impact t hose facilities that would be s ubject 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 la rgely consistent with CCAR protocols and also relies on AP I protocols and IPCC/European Un ion protocols for certain types of sources. California continues to participate in other national a nd regional efforts, such as TCR and WCI, to assist with deve loping consistent reporting tools and procedures on a national and regional basis.3-1 SECTION 3 DEVELOPMENT OF THE MAN DATORY GHG REPORTING RULE
To develop Subpart W of the Mandatory GHG Reporting Rule, EPA considered various dimensions of the reporting program and develo ped and evaluated several options for each dimension. After a preliminary evaluation of the options for each dimension, a recommended reporting program alternative was selected. Severa l 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 th en evaluated based on estimated cost, costeffectiveness (cost per metric ton of emissions reported), and estimated impacts on small entities. This process is discussed in greater detail in the following sections.

3.1 Rule Dimensions for Which Options Were Identified Possible designs for Subpart W of the Ma ndatory GHG Reporting Ru le were developed by varying options across two dimensions:

1. Thresholds : Based on the discretion in the language of the appropriations bill that calls for emission reporting above appropria te thresholds in all segments of the economy, EPA has identified an appropriate threshold above which petroleum and natural gas facilities are re quired to report their GHG emi ssions. Types of thresholds considered were production or produc tive capacity, and emissions-based.

2. Measurement Methodology : To be able to report th eir GHG emissions, facilities will be required to measure them using an appropriate methodology. Generally, measurement methodologies may be ba sed on instrumentation and direct measurement, or on calculation methods based on other data available to the facility (e.g., activity data and emission factors).
The options EPA considered for each dimensi on for Subpart W sources are discussed in the following sections and summarized in Tabl e 3-1. The table shows the combinations of options for specific dimensions. EPA conducted cost analysis for the combinations marked by X; the shaded box represents the final option.3-2 Table 3-1 Options Considered in Developing Scenarios for Regulation Under Subpart W (Final Option Indicated by Shading)

Methodology Direct Measurement (CEMS) Hybrid: Direct spot measurement for major emission sources andcalculation methods for nonmajor sources Default emission factors from EPA Threshold Capacity-based
Emissions based 1,000 MtCO 2 e X X X

Emissions-based 10,000 MtCO 2 e X X X

Emissions-based 25,000 MtCO2e X X X

Emissions-based 100,000 MtCO2e X X X Hybrid: 25,000 MtCO 2 e unless already reporting based on capacity under another program

3.1.1 Thresholds Three options were considered in setting the threshold above which reporting of GHG emissions will be required for Subpart W: capacity-based thresholds, emission-based thresholds, or a hybrid of the two. Within each option, various definitions and levels of the threshold were examined. EPA also considered capacity-bas ed and hybrid threshold approaches in the preliminary phases of the analysis but did not include them in the final cost analysis. As explained in the following sections, EPA ruled out these two options based on data limitations and other challenges.

3.1.1.1 Option 1: Capacity-Based Threshold A capacity-based threshold would be define d based on the emitting facility’s throughput, production, or productive capacity. In defining the capacity-based threshold, EPA considered that using a source-level capacity measure for the threshold might be a more straightforward way for facilities to know that they must report their GHG emissions, but the data on source-level capacity are not currently unive rsally available to EPA.3-3 3.1.1.2 Option 2: Emission-Based Threshold (Selected) Option 2 involves the use of actual facil ity-level emissions of GHGs, measured in MtCO 2 e. Various levels were cons idered, ranging from 1,000 MtCO 2 e to 100,000 MtCO 2 e. Obviously, lower thresholds would require more f acilities to participate in the reporting program. Given current data availability, an emission- based threshold will generally focus on larger, emission-intensive sources in the petroleum and natural gas segment for which emission data are readily calculated or measured.

3.1.1.3 Option 3: Hybrid Threshold The hybrid threshold option is a combinat ion of three general groups: capacity, emissions, or entire source category (“all in”). Th e thresholds developed ar e generally equivalent to a facility-wide threshold of 25,000 MtCO 2 e per year of actual emissions. The preference is to establish thresholds for as many source categor ies as possible based on a capacity metric; for example, tons of product produced per year. A capacity-based threshol d is least burdensome because a facility would not have to estimate emissions to determine if the rule applies. EPA faces two key challenges in trying to develop capac ity thresholds, however. First, in most cases, especially involving equipment l eak and vented emissions under S ubpart W, data are insufficient to determine an appropriate cap acity threshold. Second, in many of the petroleum and natural gas segments, the level of emissions from vented and equipment leaks are not related to capacity or throughput. Rather, emissions may be driven by de sign 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 met hodology options, ranging from installing emission monitoring equipment on all sources unde r Subpart W to using default emission factors to estimate emissions. The measurement methodol ogy options considered for Subpart W sources are discussed in the following sections.

3.1.2.1 Option 1: Direct Measur ement for All Reporters This option would apply direct measuremen t requirements to all reporters. It would require facilities subject to S ubpart W to use fuel-flow meters for gaseous fuels and for spot measurement of vented emissions from various equipment. In addition, it would require spot detection and quantification of equipment leak s by use of calibrated bagging or high-volume samplers throughout all segments. This option was the selected option for the proposed rule for Subpart W (74 FR 164888, April 10, 2009).3-4 3.1.2.2 Option 2: Hybrid of Direct Measurement and Facility-Specific Ca lculation for Other Sources (Selected) EPA’s final rule required measurement met hodology option for Subpart W is a hybrid of direct measurement and facility-specific calcula tions, which is considerably less burdensome than Option 1. Specifically, EPA re quires the use of direct spot measurement, where reliable emission factors do not exist, as well as engi neering calculations based on site-specific information to estimate emissions from the la rgest emission sources. Other sources will be quantified through the use of leak detection and applicati on of emission factors for leaking equipment (i.e. “leaker” factors). Use of population count and default population emission factors is required for smaller and inaccessible sources.
The hybrid approach results in a significantly lower cost burden to reporting parties yet provides a much more robust development of GHG emissions. Unlike Option 3, which is described in the section the follo ws, Option 2 will enable EPA to monitor year-to-year changes in emission levels from the petroleu m and natural gas source category.

3.1.2.3 Option 3: Default Emission Factor Calcul ation for Both Combustion and Process Emissions Under Option 3, EPA would require petroleum and natural gas facilities to base their reported emissions on simplified calculations performed at the facility level, based on EPAprovided default population factors combined with the type of process, production rate, and/or the quantity of fuel/c hemical inputs used.

3.2 Selected Option As described previously, EPA evaluated a va riety of options for each dimension of the GHG reporting program and selected a recomme nded option for each dimension. A summary of the recommended option for each dimension is provided as follows:

– Threshold : Emission-based approach

– For Subpart W sources, applicability is based on emissions. Emissions are the sum of vented emissions and equipm ent leaks, stationary and portable combustion emissions, as well as emissions from any other source category covered by the finalized GHG reporting ru le that may be present at the facility. A facility that emits 25,000 MtCO 2 e/year or more reports all sources for which there are methods in the fina lized GHG reporting rule and final rule for Subpart W.3-5 – For several segments in Subpart W, it was determined appr opriate to require the threshold calculation by de fining “facility” differently:

o For onshore petroleum and natural gas production, the facility is defined as the equipment covered in the April 2009 proposed rule and owned or operated by a single entit y, as defined by the holder of a drilling or operating permit, lo cated in a hydrocarbon basin. If a drilling or operating permit is not required, then the reporter is the entity that pays the taxes. EPA also analyzed the same facility definition, but as applied to a hydrocarbon field, as opposed to a hydrocarbon basin. As described in the preamble, the threshold determination and cost burden is required based on the basin level approach.

o For natural gas distri bution, a facility is defined as the local distribution company (LDC). Therefor e, the threshold is based on total company level emissions of the LDC.

– Methodology : A combination of direct measurement and source-specific calculation methodologies

– For the Subpart W final rule, EPA is requiring the use of direct spot measurement and/or engineering calcula tions using site-specific information to estimate emissions from the larges t emission sources. In addition, sources that are smaller, or are inaccessible for direct measurement, will be quantified through the use of leak dete ction and application of l eaker emission factors for leaking equipment. Population count a nd population emission factors will be used for smaller and inaccessible sources.

– EPA also requires source-specific calcul ation methods using facility-specific information for other sources in the finalized GHG reporting rule present at the facility subject to th e Subpart W final rule.

3.3 Alternative Scenarios Evaluated EPA developed alternative reporting scenar ios and assessed the costs and emissions associated with each. As part of the April 2009 proposal, alternative scenarios were developed by creating the recommended scenario (the shaded op tion in Table 3-1), then varying the levels in3-6 one dimension while keeping the other three dimensions at the recommended options. The alternative reporting scenarios evaluated for the Subpart W final rule are listed as follows:
1. A 1,000-MtCO 2 e threshold; hybrid methodology
2. A 10,000-MtCO 2 e threshold; hybr id methodology
3. A 25,000-MtCO 2 e threshold; hybrid methodology
4. A 100,000-MtCO 2 e threshold; hybrid methodology
5. A 25,000-MtCO 2 e threshold; direct techniques (C EMS, flow meters, calibrated bagging, and high volume sampler) used to measure emissions
6. A 25,000-MtCO 2 e threshold; default emission factor s (simplified methods) used to measure emissions
The evaluation of the alternative reporting s cenarios will allow policymakers, regulated entities, and the general public to see the impact of each variation and assess their cost compared to the required option. Total costs, emissions, a nd cost-effectiveness of the alternative reporting scenarios for the petroleum and natural gas i ndustry pursuant to Subpart W are discussed in Section 4.

3.4 Data Quality for This Analysis EPA gathered existing data from EPA, indus try trade associations , states, and publicly available data sources (e.g., labor rates from the Bureau of Labor St atistics [BLS]) to characterize the processes, sources , segments, and facilities affect ed. Costs were estimated based on the data collected and engineer ing analysis and models provid ed by EPA and its contractors. EPA staff and contractors provided engineeri ng expertise, knowledge of existing facility conditions and activities, and an estimate of incremental activities required to comply with the rule. Existing models, such as EPA’s CEMS cost model, were used for Subpart W to ensure consistency of cost inputs and assumptions.

The most important elements affecting the data quality for this analysis include the number of affected facilitie s in each source category, the number and types of production processes that emit GHGs, process inputs and out puts (especially for monitoring procedures that involve a carbon mass balance), and the measuremen ts that are already being made for reasons not associated with the Subpart W final rule (to allow only the incremental costs to be estimated). The background information for st andards development, often collected from petroleum and natural gas industry surveys, was supplemented from numerous sources, including3-7 industry surveys from the U.S. Census Burea u, 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 i ndustry representatives, knowledge gained from previous site visits, and other sources. The data collected to ch aracterize the facilities in the Subpart W final rule are judged to be of good qua lity and the best that are publicly available.
Other elements affecting the quality of th e 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 co sts of monitoring, repor ting, and recordkeeping for other rules; information from the industry ch aracterization on the numbe r of units or process inputs and outputs to be monito red for Subpart W; and engineer ing judgment. Labor costs were taken from BLS and adjusted to account for ove rhead. 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 a ssociated 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 Subpa rt W to comply with the rule and report GHG equipment leaks and vented GHG emissions. EP A used available industry and EPA data to characterize conditions at affect ed sources (i.e., affected fac ilities). Incremental monitoring, recordkeeping, and reporting activities were then identified for each t ype of facility, and the associated costs were estimated for Subpart W. Table 4-1 presents the re porting and verification requirements for petroleum and natural gas systems.
Table 4-1 Selected Reporting Thresholds and Reporting Requirements

Subpart (Source Category) Industry Segment Reporting and Verification
W—Petroleum & Natural Gas Systems (§98.230) (1) Onshore production (2) Offshore production (3) Natural gas processing (4) Natural gas transmission compression station (5) Natural gas underground storage (6) LNG storage (7) LNG import and export terminals (8) Natural gas distribution (a) Report annual emissions sepa rately for each of the industry segment listed in (a)(1) through (8) below. For each segment, report emissions from each source type in the aggregate, unless specified otherwise. For example, an underground natural gas storage facility with multiple reciprocating compressors must report emissions from all reciprocating compressors as an aggregate number. (1) Onshore petroleum a nd natural gas production facilities. (2) Offshore petroleum and natural gas production facilities. (3) Onshore natura l gas processing facilities. (4) Onshore natural gas transmission compression facilities. (5) Underground natural gas storage facilities. (6) Liquefied natu ral gas storage facilities. (7) Liquefied natural gas import and export facilities. (8) Natural gas distribution facilities. Report each source in the aggregate for pipelines and for metering and regulating (M&R) stations. (b) Emissions reported separate ly for standby equipment; (c) Report activity data for each aggregated source type as follows: (1) Count of emission sources. (2) Type of emission sources. (3) Number of specified events per year or reporting period (such as blowdowns, well completions, etc.). (4) Control measures and other equipment. (5) Volume and flow rates. (6) Input parameters for simulation software, if required. (7) Flared/vented/and equipment leak data. (d) Minimum, maximum and average throughput for each operation listed in industry segments (a)(1) through (8) above. (e) For offshore petroleum and natural ga s production faciliti es, the number of connected wells, and whether they ar e producing oil, gas, or both. (f) Report emissions sepa rately for portable equipment fo r the following source types: drilling rigs, dehydrators, compressors, el ectrical generators, steam boilers, and heaters. (1) Aggregate emissions by source type. (2) Report count of each source type.

Note: Many facilities that w ould be affected by the rule emit GHGs from multip le sources. Each facility must assess every source category that could potentially apply to each when determining if a threshold has been exceeded. If the threshold is exceeded for any source category, the facility must report emissions from all source categories, including those source categories that do not exceed the applicable threshold.4-2 4.2 Overview of Cost Analysis The costs of complying with the rule will vary from one facility to another, depending on the types of emissions; the number of affected sources at the facili ty; existing monitoring, recordkeeping, and reporting activities at the faci lity; and other factors. The costs include labor and capital costs for performing the monito ring, recordkeeping, and reporting activities necessary to comply with Subpart W. All co sts referred to in the EIA are in 2006 dollars.
There are two major emission categories for wh ich costs are determined. One is the cost to quantify process emissions (i.e., equipment leak s and vented emissions); the other is the cost to quantify the additional combus tion-related emissions for facili ties that did not exceed the Subpart C threshold with only combustion emissi ons. The total burden estimates presented for Subpart W are comprised of the costs for process and combustion emissions, above those covered by Subpart C alone.
EPA first provides a general overview of ba seline reporting and the two cost components associated with this information collection: 1) labor costs (i.e., the cost of labor by facility staff to meet the information collection requirements of the rule), and 2) capital and operating and maintenance costs (e.g., the cost of purchasing an d installing monitoring e quipment or contractor costs associated with providing the required in formation). Additional details of the data, methods, and assumptions underlying the costs are documented in this section.

4.2.1 Baseline Reporting In general, the Subpart W analysis assumes that none of the facilities in the covered segments are currently reporting equipment leak s and vented emissions and that many of the requirements will result in “new” or “full” co sts to meet reporting requirements. Specifically, EPA assumes that there will be additional co sts for any detection, sampling, and testing requirements in the methods used to quantify emi ssions from petroleum and natural gas sources. EPA also assumes that additional costs will be incurred for preparing monitoring and quality assurance/quality control (QA/QC) plans, perf orming the calculations, reporting the results, and maintaining records. The only significant elemen t that EPA knows reporters subject to Subpart W already gather is the measurements and record s of consumption of ra w materials, such as feedstocks, as part of their rou tine operation for accounting purposes.

4.2.2 Reporting Costs Costs for Subpart W were developed based on assessments of all estimated capital and operations and maintenance (O&M) costs to monito r, measure, detect and calculate the emission sources in all segments of Subpart W. Key vari ables and data fields we re clearly defined to4-3 ensure that each segment developed costs around a standard set of methods and assumptions for Subpart W (e.g., method for annualization of capital co sts, interest rate to be applied to capital). Cost estimates were developed for each threshol d of emissions, based on the number of reporting entities in that threshol d group and estimates of the specific capital and labor costs associated with conducting the emission reporting.

4.2.2.1 Labor Costs The costs of complying with and administeri ng this rule include the time of managers, technical, and administrative staff in the privat e and public segments. Staff hours are estimated for activities such as:

– Monitoring (private): staff hours to ope rate and maintain emission monitoring systems.

– Reporting (private): staff hour s to gather and process av ailable data and reporting it to EPA through electronic systems.

– Assuring and releasing data (public): staff hours to qua lity-assure, analyze, and release reports.

Staff activities and associated labor costs may vary over ti me. 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 cate gories used in this analysis. The labor categories correspond to the job responsibilitie s of the personnel that are likel y to be involved in GHG emission monitoring activities at a petrol eum or natural gas facility to comply with the rulemaking.
For purposes of this study, EPA adopte d the methodology used by Rice (2002) to calculate the wage rates for th e EPA’s TRI program. Thus, the wage rates calculated for different labor categories included the employer costs for employee compensation (comprising the basic wages and the co rresponding benefits) and the overhead costs to the employer 18

. For each labor category applicable to Subpa rt W, the following formula was used to calculate the wage rates:

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

computer hardware and software, telecommunication and other equipments, organizational support, etc.) required for and used by the employee to effectively fulfill his/her job responsibilities. These costs are over and above the employee compensation costs.4-4 Loaded Hourly Labor Rate ($/h r.) = Basic Wages ($/hr.) * (1 + Benefits Loading Factor + Overhead Loading Factor)

The benefits loading factor corresponds to the relative shar e of benefits compensation in the total employee compensation (comprising basi c wages and benefits). Although the benefits factor tends to vary by labor category and by industry (0.37 to 0.50), for purposes of this analysis, EPA has assumed the benefits loading f actor to remain the same for each labor category across all industries in the rule du e 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 tota l employee compensation. For the purposes of this analysis, EPA has also adopted the same overhead loading factor that Rice (2002) used in her wage rate calculations. Thus the overhead loading factor that EPA used in the wage rate calculations remains the same for all labor categories and across all industry types in the rule. The overhead loading factor was assumed to be 0.17.
For Subpart W, the combined “Benefits and Overhead Loading Factor” used is 0.67, or an overall adjustment of 1.67 times “Basic Wages.”

4.2.2.2 Capital and O&M Cost This includes the cost of purchasing and inst alling monitoring equi pment or contractor costs associated with providing th e required information. Equipment costs include both the initial purchase price of monitoring equipment and a ny facility/process modi fication that may be required. Based on expert judgment, the engineer ing costs analyses annua lized 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 ca pital costs amortized at a rate of 7 percent.

4.2.2.3 Other Recordkeeping and Reporting Additional recordkeeping and reporting costs are added to Subpart W sources based on each segment’s estimated requirements. These cost s are included in the “p rocess emissions” total estimated costs.

4.3 Subpart W—Petroleum and Natural Gas Systems

4.3.1 Overview The relevant reporters covered in this section are those for offshore petroleum and natural gas production, onshore petroleum and natural gas production (including e nhanced oil recovery,4-5 EOR), onshore natural gas processing, onshore natural gas transmission compression, onshore natural gas storage, LNG storage, LNG impor t and export and natura l gas distribution.
For each of the industry segments, with the exception of onshore production, operations had to be divided into single units or model facilities at three le vels: small, medium, and large. The monitoring costs were then developed per size level of a model facilit y. A model facility of a given level can be defined as the most conveni ent and logical unit with appropriate emission source counts that can aggregate to any size co mpany to determine its monitoring costs. For example, in natural gas transmission, a compressor station as a facility wa s modeled at the three different model size levels. Any natural gas tr ansmission company can determine its monitoring costs by assigning the model facility costs to its facilities that are closest to the appropriate level of the model facility. To determine the national cost from each segment, EPA assigned a model facility cost that best fit the facility based on its emission profile. Next, EPA summed the costs assigned to each facility in th e segment to produce the total na tional cost in each segment. Section 4.5 of this document describes the calculation in further detail.
Facilities in onshore producti on, however, are defined as “a ll petroleum or natural gas equipment associated with all petroleum or natural gas production wells under common ownership or common control by an onshore pe troleum 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 vari ation in facility equipment by this definition, so developing model “small,” “medium,” and “large” f acilities for monitoring costs is unintuitive and impractical. In this case, non-monitoring cost s were estimated using the model facilities, but equipment monitoring costs were estimated at the national level and then apportioned to individual operators in ba sins by production rates.
Table 4-2 provides a summary of the number of facilities that would ha ve to report under the various thresholds analyzed for each of the industry segments covered by the rule.
Table 4-2 Number of Facilities Report ing by Threshold and Industry Segment

Industry Segment Threshold
1,000 10,000 25,000 100,000

Onshore Production 8,169 1,929 981 385 Natural Gas Processing 566 396 289 1304-6 Industry Segment Threshold
1,000 10,000 25,000 100,000
Transmission Compressor Stations 1,695 1,443 1,145 433 Natural Gas Storage 347 200 133 36 LNG Storage 54 41 33 4
LNG Terminals 5 4 4 4
Offshore Production 1192 184 58 4 Local Distribution Companies 594 203 143 66

4.3.2 Labor Costs To evaluate labor costs, it was necessary not only to determine the amount of time required for all of the tasks associated with m onitoring, but also to dete rmine 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 judgmen t. When assigning hours, the size of the facility and role of the labor categories were taken into consideration.

To estimate labor costs, it was assumed th at all labor will be performed by middle managers, junior engineers, and senior operators . Middle managers are assumed to spend a total of two hours overseeing the monitoring process pe r quarter but are assumed not to perform any of the monitoring. It was assumed that junior en gineers and contracted te chnicians will do all of the monitoring, except in cases where senior oper ators will log any activity data required to estimate emissions over the course of the quarter . Several equipment types are common between different onshore segments and different facility sizes, but the actual monitoring time typically will not change per equipment unit. For example, centrifugal compressor seals are found in all onshore segments, except for natural gas dist ribution and onshore production. Measuring centrifugal compressor seal degassing vents was assumed to take one hour and that will not change by segment or facility size. What cha nges is the number of centrifugal compressors located at facilities of differe nt sizes. Thus, a series of unive rsal assumptions about onshore monitoring times were created. These were mu ltiplied by the emission source counts assigned to each of the model facilities to determine the required labor hours. Once the labor hours were calculated, by category, for each of the cost elements, they were multiplied by the associated labor rates to estimate labor costs per facilit y. For offshore monitoring, costs were developed on a per-platform basis for non-GOADS reporters, ba sed on expert judgment. The only remaining4-7 facility costs are due to the annualized capital costs and travel, lodging, and shipping to conduct the actual emission monitoring.

Error! Reference source not found. Table 4-3 presents labor cost numbers aggregated across all segments for Subpart W. These data are aggregated from individual tables for each segment. Except for onshore production, each se gment has a table for small, medium, and large facilities.
Table 4-3 Subpart W Petroleum and Na tural Gas Systems: Labor Costs a (2006$)

Activity Estimated Labor Hours and Annual Labor Rates Labor Cost per Year per Reporting Unit/Facility Senior Management Middle Management Junior Engineer/ or Technician Senior Operator ($101.31/hr) ($88.79/hr) ($71.03/hr) ($63.89/hr) First Year Subseq. Year First Year Subseq. Year First Year Subseq. Year First Year Subseq. Year First Year Subseq. Year Planning 0.63 0.06 2.85 0.17 46.21 0.58 3.49 0.28 3,821 80 QA/QC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0 0 Recordkeeping 0.15 0.15 0.24 0.23 2.74 2.60 0.52 0.52 264 253 Sampling and analysis

(calculations) 0.00 0.00 1.86 1.86 91.93 6.45 1.05 0.91 6,762 682

Reporting 0.05 0.04 1.24 1.08 4.13 3.73 13.81 13.10 1,291 1,202 Total 0.83 0.25 6.19 3.35 145.01 13.36 18.87 14.80 12,139 2,217

a Estimated onshore production average labor costs per year per reporting unit/facility are $12,099 for the first year and $5,16 8 for the subsequent years.

Unlike the other segments, onshore production la bor costs were estimated by scaling up equipment-level labor hours, disp layed later in this document in Table 4-13, to a national scale and then apportioning them by individual operator production rates. This approach was chosen over categorizing the operators by small, medium, and large because of the variety of operations present between operators in the onshore producti on segment. For this reason, the labor costs are not shown for the onshore production segm ent like in Table 4-3 or Table 4-4 Error! Reference source not found. . The average operational and mainte nance costs for the onshore production segment are shown below each table, however.

4.3.3 Capital and O&M Costs The capital costs related to monitoring emi ssions and archiving information consist of purchasing equipment for emission detection (o r the portion of contractor purchases of4-8 equipment is apportioned to all its customers), emission measurement, and information storage. All costs are reported in 2006 U.S. dollars and annualization was assumed over an equipment life of five years with a 7-percent in terest rate. Equipment leak mon itoring does not have time-tested standards and equipment leak str eams typically are not clean gas. For example, a centrifugal compressor wet seal degassing vent will contain fine droplets of seal petroleum with the gas. A five-year equipment life was chosen to be cons ervative in cost estimates, as opposed to the 10- year equipment life associated with long-stan ding, proven practices of measuring clean fuel streams assumed in the stat ionary combustion section.

Error! Reference source not found. Table 4-4 shows the capital and operation and maintenance costs at the 25,000-metric-ton thresh old 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 installati on on compressor seal degassing vents and reciprocating rod packing vents. This approach assumes that there will be no disruption in the operations because the port can be installed when the compressor is either in standby mode or under maintenance. No adjustment is made, ther efore, for production or operational loss. Firstyear labor costs include the labor required for registration, monitoring plan creation, and general planning procedures that are required only in the first year of compliance. The subsequent-year cost is a truer reflection of actual average costs over time.
Table 4-4 Subpart W Petroleum and Natura l Gas Systems: Capital and O&M Costs a (2006$)

Activity Cost Categories Capital and O&M Cost per Unit/Facility

Capital

Cost Equipment Lifetime (years) Annualized Capital Cost

(per year) O&M Costs (per year) First Year Subseq. Year Equipment (selection,

purchase, installation) $1,676 6 $409 n/a $409 $409 Performance testing b n/a n/a n/a n/a n/a n/a Recordkeeping $78 5 $19 n/a $19 $19 Travel N/A n/a n/a $848 $848 $848 Total $1,754 n/a $428 $848 $1,276 $1,276

a Estimated onshore production average capital and O&M costs pe r unit/facility are $57 for the first year and $57 for the subsequent years. b Performance testing is not requi red under Subpart W, and therefore no costs are entered.4-9 4.3.4 Combustion Costs Combustion emissions occur in petroleum and natural gas systems primarily through natural gas used to drive compressor engines. Ad ditional 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 fo r the purposes of determining if Subpart W thresholds are met; however, combustion emissions are reported separately under Subpart C for all industry segments, except onshore produc tion and LDCs. Onshore production and LDC combustion emissions will be reported under Subpart W.
To estimate combustion emissions from compressor engines—the primary combustion application in Subpart W—only one emission factor was required pe r facility because the natural gas used for combustion is taken from one pipe of common fuel quality. Consequently the cost for monitoring fuel quality is relatively low even if there are multiple compressors at the facility.
This analysis includes the cost of in cremental combustion reporting and combustion emissions above those that exceed the Subpart C threshold alone and would therefore already be have been reported under Subpart C. For purpos es of cost estimation, EPA determined that under the final rule for Subpart W, entities that need to report incremental combustion-related emissions would use either the Tier 1 calculati on methodology as set forth in Subpart C or the calculation methodology as set forth in Subpart W (40 CFR 98.233(z)). EPA determined that the entities reporting incremental em issions under subpart C would likel y not meet the requirements for Tier 2 or higher methods. However, as th ese entities will be reporting combustion emissions under subpart C (except onshore pro duction and LDCs), if a facility did meet the requirements for a tier other than Tier 1, the facility would have to use the required method, as specified in subpart C.
Given that the combustion methodology in 40 CFR 98.233(z) is similar to the Tier 1 calculation methodology, EPA estimated the cost s to monitor and report incremental combustion-related emissions based on the appr oach used under 40 CFR part 98, subpart C. 19 Specifically, EPA applied the Tier 1 calculation methodology to estimate the costs to monitor combustion emissions that became subject to reporti ng as a result of today’s final rule. Table 4-5 presents incremental combustion cost estimates. The Tier 1 approach bases estimates on a fuel-

19 40 CFR Part 98 used the IPCC tier concept to estimate com bustions emissions (74 FR 56260, October 30, 2009). See EPAHQ-OAR-2008-0508-0004, U.S. EPA, Technica l Support Document for Stationary Fuel Combustion Emissions: Proposed Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more info rmation about the IPCC tier methodology (pgs 10-15).4-10 specific default CO 2 emission factor, a default high heating value of the fuel, and the annual fuel consumption from company records.

EPA based its conclusion that entities would likely report in cremental combustion emissions using the Tier 1 method on three cons iderations for applicab ility of the Tier 2 calculation methodology and higher, as specified in Subpart C, to the petr oleum and natural gas industry: 1) availability of hi gh heating values (HHVs) for the fuels combusted at the frequency required by the Tier 2 calculation methodology, 2) the maximum-rated heat input capacity of the equipment, and 3) the type of fuel being combuste d. First, in order to be allowed to use a Tier 2 analysis, units must have a rated heat-input cap acity less than or equal to 250 million British thermal units per hour (MMBtu/hr), combust a fuel found in Table C-1 of subpart C, and sample the HHV of the fuel consumed at the required fre quency in 40 CFR 98.34(a). It was determined that this minimum-required sampling frequency is not currently carried out at these smaller units, and therefore these units would not be required to use Tier 2. These units will generally follow Tier 1 methodology.

Second, Tier 3 and Tier 4 calcu lation methodologies generally apply to equipment with a maximum-rated heat-input capacity greater than 250 MMBtu/hr. A 250-MMBtu/hr rating means that the emissions from that individual unit alone will be greater th an 25,000 MtCO2e; these emissions would be subject to reporting under Subpa rt C even in the absence of Subpart W and therefore would not fall in the ca tegory of incremental combustion emissions considered in this analysis.
Third, the predominant fuels used in the pe troleum and natural ga s industry are produced natural gas, pipeline quality natural gas, dist illate fuel, and any products recovered from equipment leaks and vents. The use of produ ced natural gas is predominant in onshore petroleum and natural gas production. Under the final rule for subpart W, reporters in this segment are allowed to use methods similar to Ti er 1 for all combustion emissions sources that use produced natural gas.
In the remaining segments, equipment using pr oduced natural gas or products recovered from equipment leaks and vents are normally re quired to use Tier 2 methodology or higher. However, as described previously, if the unit ha s a rated heat input less than or equal to 250 MMBtu/hr, then the unit probably does not curr ently receive HHV at the required frequency for a Tier 2 and could use a Tier 1 analysis instead. If the unit has a maximum-rated heat-input capacity greater than 250 MMBtu/hr, then as just noted, emissions from a unit of this size would already be subject to repor ting and would not be included in the incremental combustion4-11 emission category considered in this analysis . In sum, the use of Tier 1 methodology for incremental combustion is a reasonable a ssumption for costing the subpart W rule.

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

Activity Cost Categories Total Reporting Cost per Unit/Facility

Capital

Cost Equipment Lifetime (years) Annualized Capital Cost

(per year) O&M Costs (per year) First Year Subseq. Year Equipment (selection,

purchase, installation) $3,500 10 $500 $1,700 $2,200 $2,200 Total $3,500 $500 $1,700 $2,200 $2,200

4.4 Summary Results: Subpart W—Petro leum and Natural Gas Systems For each segment in the petroleum and natural gas industry identified as amenable to a reporting program, four thresholds were consider ed for emission reporting as applicable to an individual facility: 1,000 MtCO 2 e per year; 10,000 MtCO 2 e per year; 25,000 MtCO 2 e per year; and 100,000 MtCO 2 e per year. A threshold analysis was then conducted on each segment to determine which level of threshold was mo st suitable for each industry segment. CH 4 , CO 2 , and N 2 O emissions from each segment were included in the threshold analysis.

Table 4-6 shows the number and share of entities and emissions covered by the final rule. The table shows that at lower thresholds, a high er number and share of facilities and emissions are covered by the rule. As the th reshold increases, smaller number s and shares of facilities and emissions are affected. Of significant note, 85 per cent of emissions are c overed at the selected 25,000-MtCO 2 e threshold, but only 9 percent of facilities need to report. Furthermore, both total emissions and covered emissions include incr emental combustion emissions (i.e. those not triggered by the threshold of Subpart C alone).
Table 4-6 Subpart W Facilities and Em issions Covered by Final Rule

Threshold Number of Entities Number of Facilities Covered Percent of Facilities Covered Total Emissions (Million MtCO 2 e/Year) Covered Emissions (Million MtCO 2 e/

Year) Percent of Emissions Covered 1,000 MtCO 2 e/yr Threshold 30,241 12,622 42% 396 391 99%4-12 10,000 MtCO 2 e/yr Threshold 30,241 4,400 15% 396 362 91%

25,000 MtCO 2 e/yr Threshold 30,241 2,786 9% 396 337 85%

100,000 MtCO 2 e/yr Threshold 30,241 1,062 4% 396 273 69%

4.4.1 Detailed Threshold Analysis For each segment, a threshold analysis wa s conducted to determine how many of the facilities in the segment exceed the various repor ting thresholds, and the total emissions from these facilities. This analysis was conducte d considering vented and equipment leaked CH 4 and CO 2 emissions, and combustion CH 4 , CO 2 , and N 2 O emissions. The vented emission and equipment leak estimates available from the U.S. GHG Inventory were used in the analysis. The emission estimates for four sources—well ventin g 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 Inventor y were replaced with revised estimates, however, which are described in Appendix B of the TSD.
Combustion emissions from processing, transmission, underground storage, LNG storage, and LNG import and export terminals were estimated using gas engine methane emission factors available from GRI/EPA (1996), back-calculating the natural gas consumption in engines, and finally applying a CO 2 emission factor to the natu ral gas consumed as fuel. N 2 O emissions were calculated similarly. In the case of offshore petroleum and natural gas production platforms, combustion emissions are already av ailable from the GOADS (2000) study analysis and hence were directly used for the threshold an alysis. In addition to gas engines, combustion emissions from reboilers on glycol dehydrators, acid gas removal amine regeneration, diesel engines on drilling rigs, and h eater-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 com bustion 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 combusti on emissions from acid gas removal amine regeneration heaters. Drilling rigs were assumed to operate two 1,500-hor sepower diesel engines per well drilled, and assuming it requires 90 days to drill and comple te any well. The API Compendium combustion emission factors for diesel engines were used to calculate the emissions. The total drilling emissions for the nation were calcu lated based on the number of dr illing rigs in service, then apportioned to each basin by throughput.4-13 The threshold analysis for the rule incl udes equipment leak, vented, and combustion emissions and requires estimation of all emissions at a facility level. As a result, the total emissions from the threshold analysis do not ne cessarily match the U.S. GHG Inventory for all segments of the petroleum and natural gas i ndustry. A detailed discussion on the threshold analysis is available in the TSD (EPA-HQ-OAR-2009-0923).
The general rationale for selec ting a reporting threshold is to identify a level at which the incremental emission reporting between thresholds is the highest for the lowest incremental increase in number of facilities reporting betw een the same thresholds. This approach would ensure maximum emission reporting coverage with minimal burden on the industry.
Table 4-7 summarizes the national costs and costs per representative entity for each threshold. The first five columns report subsets of costs, including costs associated with processes (labor, annualized capita l, 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-ent ity costs for the first year and for subsequent
years. Table 4-7 Summary of National Costs and Cost s per Representative Entity by Threshold (Million 2006$) a

Threshold (MtCO 2 e/yr) First-Year Process Costs b Subseq.- Year Process Costs a First-Year Combustion Costs Subseq.-Year Combustion Costs FirstYear National

Costs First-Year Representative

Entity Cost Subseq.-Year National

Costs Subseq.-Year Representative

Entity Cost 1,000 $112.3 $46.4 $23.9 $23.9 $136.2 $0.011 $70.3 $0.006 10,000 $53.0 $20.9 $6.6 $6.6 $59.6 $0.014 $27.5 $0.006 25,000 $40.1 $15.1 $3.3 $3.3 $43.4 $0.016 $18.4 $0.007 100,000 $23.1 $7.7 $0.9 $0.9 $24.0 $0.023 $8.6 $0.008

a Excludes determination costs for non-reporters; see next section for estimates of these costs. b Reporting and recordkeeping costs are included in process costs.
Note that first-year costs are significantly hi gher than the subsequent-year average costs, due to the following reasons:

 Initial start-up costs include labor and capital associated with establishing modifications to enable o ngoing quantification of key em ission sources. They include costs to install measurement ports in compressor and well vents.

 For onshore production, reporting occurs a nnually, but the measurement of key sources is updated every two years.4-14 4.4.2 Subsequent-year costs are therefore reported as an average of the cost for years two, three, and four. As described in Table 4- 7, at lower thresholds, a larger number of facilities in each subpart are co vered by the rule and thus incur costs. For this reason, the total national costs, and total costs by co st subset, decline as the threshold increases from 1,000 MtCO 2 e to 10,000 MtCO 2 e, to 25,000 MtCO 2 e, and finally to 100,000 MtCO 2 e. Cost per representative entity for a particular segment generally declines for Subpart W as the threshold increases. Reporting Determination While the cost estimates for representative en tities are assumed to capture the reporting determination burden (i.e., the burden of estimati ng emissions to determine whether they exceed the reporting threshold), they do not account for the reporting determinatio ns made by facilities that fall below the threshold. EPA has therefore estimated the burden for reporting determinations made by these facilities in order to better reflect the rule’s total economic burden.
EPA plans to develop screening tools and has assumed that most facilities will use them to make a reporting determination. As a first ste p, facilities would enter ba sic activity data, such as number of compressors and compressor cylinders, into the tool to roughl y assess whether they exceed the threshold. The screening results should allow many facilities to make their threshold determination. Some of the facili ties may have to take steps in addition to the screening tools, however, to determine if they ha ve to report. For example, facilities that estimate emissions close to the reporting threshold ma y want to conduct preliminary monitoring to better determine their emissions. Such facilities may also conduct preliminary mon itoring in subsequent years to determine whether emissions in those year s meet or exceed the reporting threshold.
Of the 30,241 facilities in the petroleum a nd natural gas industry, approximately 2,786 facilities would likely m eet the threshold and have to repo rt. The remaining 27,455 facilities are expected to be below the reporti ng threshold and would likely use th e screening tool to make this reporting determination. In addition, 296 of the 27,455 facilities could have emissions close to the threshold and may supplement the screening t ool analysis with some preliminary monitoring to determine whether or not they need to repor t; these 296 facilities are also assumed to conduct preliminary monitoring to make a reporti ng determination in subsequent years.
Facilities are required to fo llow methodologies in the rule to make a determination. The costs for this activity are outlined as follows:
Planning costs are assumed to include:

 2.5 hours for regulatory review

 2 hours to understand what operations information is required4-15  2 hours to gather operations data for screening tool(s)

 14 hours to conduct preliminary monitoring
Recordkeeping and reporting cost s are assumed to include:

 1 hour to use screening tool(s) and to review and report data
Using the labor costs presented in Section 4.5.1, the cost of the reporting determination would be $573 per facility. The additional cost fo r those entities close to, but not exceeding, the threshold, to conduct preliminary mo nitoring, is $1,034. See the memo, Estimates of Determination Costs , in the docket for complete details about these calcula tions (EPA-HQ-OAR2009-0923). Table 4-8 provides a su mmary of the determination costs by industry segment and threshold level.
Table 4-8 Summary of Reporting Determination Costs per Segment by Threshold (2006$ in thousands) a

Segment Year Thresholds (metric tons) 1,000 10,000 25,000 100,000
Onshore petroleum and natural gas production First Year $9,146 $12,177 $12,496 $12,731 Subsequent year $1,448 $604 $256 $92 Offshore petroleum and natural gas production First Year $1,921 $2,886 $2,972 $2,996 Subsequent year $241 $110 $33 $3 Natural gas transmission First Year $259 $572 $903 $1,167 Subsequent year $9 $114 $165 $6 Natural gas processing First Year $0 $223 $310 $392 Subsequent year $0 $94 $52 $6 Natural gas underground storage First Year $56 $232 $292 $379 Subsequent year $9 $58 $43 $19
LNG storage First Year $4 $17 $26 $55 Subsequent year $2 $2 $2 $2 LNG import & export terminals First Year $13 $55 $68 $140 Subsequent year $0 $0 $0 $0 Natural gas distribution First Year $921 $1,276 $1,330 $1,406 Subsequent year $133 $47 $32 $28

Total First Year $12,320 $17,438 $18,396 $19,267 Subsequent year $1,841 $1,030 $582 $156

a These estimates are conservative and shoul d be viewed as an upper-bound because they were calculated at the facility-level rather than the company-level. For example, for offshore production, determination costs were applied to each of the approximately 3,000 platforms in the Gulf of Mexico rather th an to the roughly 86 operators in that region. See the memo, “Estimates of Determination Costs,” in the docket for comple te details and additional determination cost estimates (EPA-HQOAR-2009-0923).4-16 4.5 Detailed Cost Assumptions: Subpart W—P etroleum and Natural Gas Systems The cost assumptions are the basis for the determ ination of the costs not ed in this section.
STEP 1: Model Facility Development For each of the industry segments, with the exception of onshore production, operations had to be divided into single units or model facilities at three le vels: small, medium, and large. The monitoring costs were then developed per size level of a model facilit y. A model facility of a given level can be defined as the most conveni ent and logical unit with appropriate emission source counts that can aggregate to any size co mpany to determine its monitoring costs. For example, in onshore natural gas transmission, a co mpressor station as a facility was modeled at the different levels. Any transmission compa ny can determine its monitoring costs by assigning model facility costs to its facilitie s that are closest to the appropria te level of the model facility. Facilities in onshore producti on, however, are defined as op erators reporting all equipment covered at the basin-level. There is much la rger variation in facilities’ equipment by this definition, so developing model “small,” “medium, ” and “large” facilities is unintuitive and impractical for estimating monitoring costs. In this case, non-monitoring costs were estimated using the model-facility method and monitoring costs were estimated at the national level and then apportioned to individual operato rs in basins by production rates.
For each of the sources designated for monitoring, both equipment and component counts were determined to define individual model facil ities, except as noted in onshore production. For onshore natural gas processing, onshore natura l gas transmission, underground natural gas storage, LNG storage, import and export facili ties and natural gas distribution, equipment and component counts for medium facilities were assi gned the national average activity factors from the national inventory, or the ne arest reasonable integer value. In some cases, the uncertainty associated with the activity factors were used to determine the lower bound on equipment and component counts, and assigned to a “small” facility. Similarly, the upper bound on emission source counts was assigned to a “large” facilit y. If illogical values, such as in the case of compressors in natural gas transmission comp ressor stations, resulted from the above methodology; expert judgment was used to corr ect the values; bounding th e aggregated activity levels to that of the nationa l inventory. In the case of offshore petroleum and natural gas production, BOEMRE GOADS (2 000) data analysis by EPA was us ed in the same fashion as the national inventories. In some cases, the uncertain ty estimates were not applicable. For example, if the uncertainty is greater than 100 percen t, it would predict a negative lower bound for emission source counts. For these cases, expert judgment was used. Expert judgment was also used, where necessary, to adjust emission source counts to reflect real-w orld scenarios. Both4-17 equipment and component counts at facilities by segment and size are presented in the docket (EPA-HQ-OAR-2009-0923).

STEP 2: Determine Cost Elements The total costs associated with complying with the April 2009 pr oposed rulemaking were broken into five elements, each of which is de scribed in the following information. Additionally, these cost elements are considered in two wa ys: costs associated with start-up, and recurring costs. Startup costs refer to a one-time cost as sociated 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 th e 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 cons ist entirely of labor expenses. Small amounts of time will be required for the co mpany to stay aware of any updates to regulations and to alter the facility info rmation to reflect a ny new equipment or facilities brought into oper ation or taken offline.
2. Monitoring costs
a. Start-up monitoring costs consist of both labor and capital costs. Capital investment will be required for purchas ing monitoring equipment. This capital cost will be accounted as annualized co st, on an annual basis. Labor will be required for product research for monitori ng instruments before actual purchase. Before actual monitoring takes place, la bor 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 la bor, travel, and shipping of equipment. During each cycle, labor will be required to conduct detection and quantification of emissions (i.e., perform actual monito ring of emissions). Quantification may take place through direct measurement, us e of engineering calculations and/or software, use of “leaker” emission factors fo r detected leaks, or use of component counts and population emission factors. Fo r companies with multiple facilities,4-18 travel may be required for the monitoring team and/or the mo nitoring instruments may require shipping to multiple locations.
3. Reporting costs
a. There will be no start-up reporting co sts; reporting costs ar e applied uniformly across segments reporting to the rule.
b. Recurring reporting costs c onsist of labor necessary to document collected emission data from equipment leak monito ring and to submit the official report in each cycle (i.e., annually).
4. Archiving and recordkeeping costs
a. Start-up archiving and reco rdkeeping costs consist of labor and annualized capital purchase of storage space. For archiv ing reports and associated working documents, a physical storage system such as a file cabinet and an electronic storage system such as an external hard drive will be required.
b. Recurring archiving and recordkeeping costs consist entirely of labor necessary to adequately archive each cycle’s report and associated working documents.
5. Auditing costs
a. There is no start-up cost associated with auditing.
b. Recurring auditing costs consis t of labor required to validate the EPA results from emission monitoring and the follow-up from rectifying any weaknesses found through the audit. The EPA audit is assume d to occur once in several years, not on an annual basis.
STEP 3: Analyze Proportion of Faciliti es in Different Model Facility Levels

Facilities were classified and rank-listed in ascending or der based on their sizes, total combustion, equipment leaked, and vented CO 2 , N 2 O, and CH 4 emissions, expressed in CO 2 e. Cumulative emissions for the facilities were calc ulated by adding the emissions of an individual facility to those of the facilities before it in the ascending list. The cumulative emissions, in combination with the total emissions from all fac ilities, were used to assign facilities to the small, medium, and large category.4-19      

 ions TotalEmiss Emissions Cumulative Percentile (%)

The facilities that accounted fo r the first 33 percent of the emissions nationally in the ranked list were identified as small facilities. Th e facilities that accounted for national emissions greater than 33 percent but less than 67 percent in the ranked list were identified as medium facilities. The facilities that accounted for national emissions greater than 67 percent in the ranked list were identified as large facilities. Table 4-9 indicates the data sources used to apportion total GHG emissions to in dividual facilities, a nd the number of facili ties that fall into each category per segment.
STEP 4: Assigning Costs to Cost Elements Assigning costs to each of the cost el ements was completed in three steps:
1. Determine labor categories and associated labor rates.
2. Allocate responsibilities to labo r categories to estimate labor hours.
3. Determine annualized cap ital costs and O&M costs for each of the cost elements.
These steps are described in more detail as follows:
Table 4-9 Allocation of Facilities to Model Types

Segment Data Source Small Facilities Medium Facilities Large Facilities
Offshore Petroleum and Natural Gas Production Facility Percentile BOEMRE, 2000 GOADS Emission Inventory , Lasser, 2006 0–33% 34%–67% 68%–100%

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

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

Facility Count c API, 2008 Impact 486 64 164-20 Segment Data Source Small Facilities Medium Facilities Large Facilities Assessment of Mandatory GHG Control Legislation Operator/Company API, 2008 Impact Assessment of Mandatory GHG Control Legislation 166 28 10

Mean Emissions (MtCO 2 e) This Analysis 36,486 275,823 1,137,595
Onshore Natural Gas Transmission Facility Percentile FERC, 2008 0–33% 34%–67% 68%–100% Facility Count FERC, 2008 1,314 374 255 Operator/Company FERC, 2008 147 46 27 Mean Emissions (MtCO 2 e) This Analysis 21,293 98,738 210,829 Natural Gas Underground Storage Facility Percentile EIA, 2006. Underground Storage Field Level Data 0–33% 34%–67% 68%–100%

Facility Count EIA, 2006. Underground Storage Field Level Data 325 50 22
Operator/Company EIA, 2006. Underground Storage Field Level Data 102 37 17
Mean Emissions (MtCO 2 e) This Analysis 12,404 82,199 183,936 LNG Storage Facility Percentile GTI. 2007. The World Energy Source Book 0–33% 34%–67% 68%–100%

Facility Count GTI. 2007. The World Energy Source Book 141 12 4
Operator/Company GTI. 2007. The World Energy Source Book 141 11 3
Mean Emissions (MtCO 2 e) This Analysis 20,972 55,340 223,275 LNG Import and Export Facility Percentile FERC, 2008 — 0–100% — Facility Count FERC, 2008 — 5 — Operator/Company Not estimated Mean Emissions (MtCO 2 e) This Analysis — 174,643 — Natural Gas Distribution Facility Percentile DOT, 2006 0–33% 34%–67% 68%–100% Facility Count DOT, 2006 1,360 50 17 Operator/Company DOT, 2006 1,268 49 16 Mean Emissions (MtCO 2 e) This Analysis 5,840 167,066 536,719
Notes:

a The BOEMRE 2000 Gulfwide Emissions Inventory reports 2,525 offshore platforms and 86 operators. No data are available

for individual offshore platforms and their respective operators.
b The onshore production burden analysis was conducted using a hybr id approach. Capital costs and some recurring O&M costs

were assigned on a small, medium, and la rge basis; however, the majority of the recurring O&M costs were determined by apportioning nationwide costs by individual operator throughput.

c Assumed one facility per company; no data available for small plants.4-21 4.5.1 Determining Labor Categories To evaluate labor costs, it was necessary to not only determine the amount of time required for all of the tasks associated with mon itoring, but also to dete rmine who will perform each task. For the sake of this analysis, five la bor categories were used, as shown in Table 4-10.
Table 4-10 Labor Categories and Hourly Rates

Labor Category Description Loaded Hourly Rate a 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 em ission 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 compan y to perform basic leak detection activities. $55.20/hour

a Source: U.S. Department of Labor, 2003.
These labor rates originate from an analys is of loaded hourly rates for goods and producing private establishments at the end of 2007, shown in Table 4-11. Since the petroleum and natural gas industry hourly ra tes are high compared to othe r industries, the top four nonlawyer categories were used to be conservative in this approximation. Specifically, the labor rate of senior managers were assumed to be that of refinery mangers; middle manager labor rates were assumed to be that of electricity managers; junior engineer labor ra tes were assumed to be that of industrial managers; senior operator labo r rates were assumed to be that of refinery engineers/technicians; and contract ed technician labor rates were a ssumed to be that of industrial engineer/technician category.
Table 4-11 Loaded Hourly Rates for Goods-Producing Private Establishments

Labor Category Loaded Hourly Rate ($/hour) a Electricity Manager $88.79 Refinery Manager $101.31 Industrial Manager $71.03 Lawyer $101.00 Electricity Engineer/Technician $60.844-22 Refinery Engineer/Technician $63.89 Industrial Engineer/Technician $55.20 Administrative Support $29.65

a Source: U.S. Department of Labor, Bureau of Labor Sta tistics, National Compensation Survey - Compensation Cost Trends,

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

4.5.2 Allocating Responsibilities Assigning labor hours for all cost elements was based on expert judgment. When assigning hours, the size of the facility and ro le of the labor categories were taken into consideration. Table 4-12 summarizes these roles.
Table 4-12 Responsibilities for Regu lation Compliance by Labor Category

Cost Element Senior Management Middle Management Junior Engineer Senior Operator Per Facility/ Per Company a Facility data To review reporting documentation/ systems and facility data To review reporting documentation/ systems and facility data To initiate reporting process and prepare facility data To prepare and review reporting process documentation and facility data Per facility

Regulation review To review the new regulations To review the new regulations To examine and identify potential new regulations To review the new regulations identified and determine their applicability Per company

Plan development To review the monitoring plan To review the monitoring plan To develop a monitoring plan To develop and review the monitoring plan Per company

Equipment purchase To approve the equipment purchase To review the equipment to be purchased To identify and purchase the equipment To review the equipment to be purchased Per company

Start-up/ training To review training plan To acquire training To provide and acquire training Per facility

Data documentation To review the reporting documentation To prepare and complete the reporting documentation To prepare reporting documentation To prepare and complete reporting documentation Per facility

Report submission To ensure the completion of the reporting documentation To submit the report Per Facility

Archiving reports To archive the reporting documentation To archive the reporting documentation Per facility

Audit To review the audit results To review the audit results To assist and provide information on EPA audits Per facility4-23 Cost Element Senior Management Middle Management Junior Engineer Senior Operator Per Facility/ Per Company a Audit follow-up To review the audit follow-up results and approve corrective

measures To review the audit follow-up results and review corrective

measures To determine corrective measures from EPA audit To assist in determining corrective measures from EPA audit Per facility

a Some activities only have to be done at the company le vel, with information and/ or equipment shared among facilities of the company.
The labor costs associated with performing the actual annual monitoring were omitted from Table 4-12. For these costs, it was assu med that all labor will be performed by middle managers, junior engineers, se nior operators, and contracted technicians. The assumed responsibilities and as sociated hours are organized in Table 4-13.
Additionally, several pi eces of equipment are common am ong different onshore segments and different facility sizes, but the actual monitoring time typically will not change per equipment unit. The series of universal assu mptions about onshore monitoring times are also provided in Table 4-13.
Table 4-13 does not include equipment monito ring on offshore petroleum and natural gas production facilities. Offshore produ ction platforms are proposed to use data already collected for BOEMRE GOADS to estimate GHG emissions from their operations. Specifically, the BOEMRE GOADS program requires GHG emission m onitoring from platforms in the Gulf of Mexico federal waters. Facilities under this final rulemaking are required to report the same emission data calculated by the GOADS program ; hence, these platforms have minimal additional reporting burden. The cost burden model assumes that this monitoring requires 30 minutes per platform.
Table 4-13 Responsibilities for Monito ring and Allocation of Labor Hours

Element Onshore Responsibilities by Labor Ca tegory and Hours per Responsibility Detection Quantification Applicable Segments Onshore Facility Equipment Leaks Senior operator Count large, major pieces of equipment (0.5 minutes/equipment) Onshore Production

Processing Facility Equipment Leaks Technician Conduct equipment leak detection survey (8 hours/small facility, 12 hours/medium facility, or 16 Processing4-24 Element Onshore Responsibilities by Labor Ca tegory and Hours per Responsibility Detection Quantification Applicable Segments hours/large facility) Junior engineer Estimate emissions using leaker factors (2 hours/facility) Processing

Middle management Oversee part of the detection process and review results (1 hour/reporting period) Oversee part of the measurement process and review results (1 hour/reporting period) Processing

Transmission Facility Equipment Leak Technician Conduct equipment leak detection survey (17 hours/small facility, 19 hours/medium facility, and 19 hours/large facility) Transmission

Junior engineer Estimate emissions using leaker factors (2 hours/small facility, 2 hours/medium facility, and 3 hours/large facility) Transmission

Middle management Oversee part of the detection process and review results (1 hour/reporting period) Oversee part of the measurement process and review results (1 hour/reporting period) Transmission

Underground Storage Facility Equipment Leak Technician Conduct equipment leak detection survey (47 hours/small facility, 53 hours/medium facility, and 63 hours/large facility) Storage

Junior engineer Estimate emissions using leaker factors (2 hours/small facility, 3 hours/medium facility, and 2 hours/ large facility) Storage

Middle management Oversee part of the detection process and review results (1 hour/reporting period) Oversee part of the measurement process and review results (2 hours/reporting period) Storage

LNG Import/Export Terminal Equipment Leak Technician Conduct equipment leak detection survey (43 hours/facility) LNG Import and Export Facilities

Junior engineer Estimate emissions using leaker factor s (2 hour/ facility) LNG Import and Export Facilities

Middle management Oversee part of the detection process and review results (2 Oversee part of the measurement process and LNG Import and Export Facilities4-25 Element Onshore Responsibilities by Labor Ca tegory and Hours per Responsibility Detection Quantification Applicable Segments hours/reporting period) review results (1 hour/ reporting period) LNG Storage Facility Equipment Leak Technician Conduct equipment leak detection survey (12 hours/small facility, 19 hours/medium facility, and 24 hours/large facility) LNG Storage

Junior engineer Estimate emissions using leaker factors (2 hours/small facility, 2 hours/medium facility, and 3 hours/large facility) LNG Storage

Middle management Oversee part of the detection process and review results (1 hour/reporting period) Oversee part of the measurement process and review results (1 hour/reporting period) LNG Storage

LDC Above Grade M&R Station Equipment Leak Technician Conduct equipment leak detection survey (1 minute/station) Distribution

Junior engineer Estimate emissions using leaker factors (8 hours/reporting period) Distribution

Middle management Oversee part of the detection process and review results (2 hours/reporting period) Oversee part of the measurement process and review results (1 hour/reporting period) Distribution

Reciprocating Compressor Equipment Leak Technician Check unit for equipment leaks (1 hour/compressor) Processing

Technician Check unit for equipment leaks (1.5 hours/compressor) Transmission, Storage, LNG Storage, LNG Import and Export Facilities Junior engineer Apply emission factors or leaker factors (time accounted for by facility equipment leaks quantification) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities

Reciprocating Compressor Rod Packing Emissions
Maintenance team One time labor cost to install port for hotwire anemometer ($1,000 /compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities Technician Check packing open-ended lines for emissions (10 minutes/compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities Technician Measure rod packing emissions (10 Processing, Transmission, Storage, LNG Storage, LNG4-26 Element Onshore Responsibilities by Labor Ca tegory and Hours per Responsibility Detection Quantification Applicable Segments minutes/compressor) Import and Export Facilities Junior engineer Calculate rod packing emissions (30 minutes/compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities Centrifugal Compressor Equipment Leaks Technician Check unit for equipment leaks (1 hour/compressor) Processing

Technician Check unit for equipment leaks (2 hours/compressor) Storage, LNG Import and Export Facilities Technician Check unit for equipment leaks (2.5 hours/compressor) LNG Storage

Centrifugal Compressor Seals
Maintenance team One-time labor cost to install port for hotwire anemometer ($5,000/compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities Technician Measure degassing vent emissions (10 minutes/compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities Junior engineer Calculate degassing vent emissions (30 minutes/compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities Unconventional Well Completion and Workover Junior engineer Measure flowback from completion or workover (8 hours/field) Onshore Production

Conventional Well Completion and Workover Junior engineer Ask completion or workover contractor for time of venting (5 minutes/per completion or workover) Onshore Production

Well Liquid Unloading Junior engineer Measure flow from well blowdown (5 minutes/unloaded well) Onshore Production

Acid Gas Removal Vent Stacks Junior engineer Perform simulation runs (10 minutes/AGR vent) Processing

Kimray Pumps Junior engineer Accounted for in station equipment leaks– certain portion of time is assumed to be for engineering estimation of sources Onshore Production, Processing, Transmission, Storage

Dehydrator Vent Stacks > 400 thousand cubic feet4-27 Element Onshore Responsibilities by Labor Ca tegory and Hours per Responsibility Detection Quantification Applicable Segments Senior operator Collect data collection (10 minutes/dehydrator vent) Onshore Production, Processing Junior engineer Perform simulation runs (15 minutes/dehydrator vent) Onshore Production, Processing Junior engineer Accounted for in station equipment leaks – certain portion of time is assumed to be for engineering estimation of sources Transmission, Storage

Dehydrator Vent Stacks <400 thousand cubic feet Senior operator Count dehydrator (0.5 minutes/dehydrator vent) Onshore Production, Processing Wellhead Equipment Leaks Junior engineer Apply emission factor – accounted for in station equipment leaks Onshore Production, Storage

Storage Tanks > 10 barrels per day Senior operator Collect separator pressure (1 minute/separator) Onshore Production

Junior engineer Collect data and perform simulation runs (30 minutes/ separator) Onshore Production

Storage Tanks < 10 barrels per day Senior operator Count separator (0.5 minutes/separator) Onshore Production

Natural Gas Distribution Pipelines Junior engineer Estimate emissions using population emission factor – time accounted for in station equipment leaks Distribution

Below Grade Metering & Regulating Stations Junior engineer Estimate emissions using population emission factor – time accounted for in station equipment leaks Distribution

Well Testing Junior engineer Perform emissions calculation with GOR measurement (1 hour/ well) Onshore Production

Associated Gas Venting and Flaring Junior engineer Perform emission calculation with gas-to-oil ration (GOR) measurement (1 hour/well) Onshore Production

Natural Gas Pneumatic Bleed Devices4-28 Element Onshore Responsibilities by Labor Ca tegory and Hours per Responsibility Detection Quantification Applicable Segments Junior engineer Determine high bleed or low bleed from manufacturer and apply appropriate population factor (10 minutes/pneumatic device) Onshore Production, Processing, LNG Storage, LNG Import and Export Facilities, Distribution

Junior engineer Check devices and take inventory of brand/models (8 minute/pneumatic device) Determine high bleed or low bleed from manufacturer and apply appropriate population factor (10 minutes/pneumatic device) Transmission, Storage

Flare Stacks Junior engineer Collect data for emission estimate (10 minutes/ station) Estimate emissions using emission factor (10 minutes/ station) Processing

Junior engineer Apply emission factor – accounted for in station equipment leaks Onshore production

Blowdown Vent Stacks Junior engineer Perform emissions calculation (8 minutes/ station) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities Junior engineer Accounted for in station equipment leaks Distribution

For platforms that are in state waters or in federal waters outside the Gulf of Mexico, GHG emissions will have to be estimated using the BOEMRE GOA DS procedures. EPA estimates the reporting cost for non-GOADS platfo rms 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 trav el, lodging, and shipping to conduct the actual emission monitoring.

4.5.3 Annualizing Capital Costs and Determining O&M Costs The capital costs related to monitoring emissi ons and archiving information consists of purchasing equipment for emission detection, em ission measurement, and information storage. All costs are reported in 2006 U.S. dollars, a nd annualization was assumed over an equipment life of five years with a 7-percent interest rate. From these factors, a capita l recovery factor of 24 percent was calculated using th e formula provided as follows:4-29 1 ) 1 ( ) 1 (

  

 n n

r r r CRF

where CRF is the capital recovery f actor, r is the interest rate, and n is the life expectancy in years. Table 4-14 summarizes the annualized capital costs associated with the monitoring program. Additionally, the table describes the annu al costs of travel, lodging, and shipping—the only other non-labor costs rela ted to the monitoring program.
Table 4-14 Monitoring Program Comp liance 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 fr om Office DepotTM ($140), and 1 hard drive for data stor age from SeagateTM ($95) $57

Monitoring Equipment purchase Screening equipment is represented by a nominal $100,000 cost for an infrared camera. It is assumed to be purchased by the contractors who will pass on the costs to as many facilities as they can provide a service each year. $24,389

Equipment purchase Screening equipment in the distribution segment is represented by a nominal $10,000 cost for a laser emission detector. It is assumed to be purchased by the local distribution companies over the infrared camera due to its low cost. $2,439

Measurement Equipment purchase Hotwire anemometers are required for compressor vents. It is assumed that the hotwire anemometer, a vinyl carrying case, an AC adapter, data acquisition software, and anemometer electronic data logger will be purchased. $206

Traveling Cost of traveling for an engineer to a facility from the home facility (therefore n-1 facilities to visit). Assuming travel cost is $0.485/mile, $150/night for overnight stay, $100/shipment for shipping equipment, and $100 per diem. $0–$10,449 a

a Annual travel costs are highly variable de pending on the facility type, proximity, and ownership structure. Annual travel costs are estimated to vary from $0 to $10,449.
As shown in Table 4-14, the equipment l eaks and vented emissi on detection methods vary depending on the size of the company and its f acilities. In the case of companies with small operations and few facilities, the costs passed on by contractors will be spread over many facilities.4-30 Each facility is assumed to purchase an ad equate 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 determin ed, the final step was to divide company capital and O&M costs amongst individual f acilities owned by a typical company.
Step 3, described previously, provided the propor tion 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 eq uipment purchases, the costs per equipment were attributed to the number of facilities that can be serviced (as determined the number of labor hours required to monitor a facility) each year, as shown in the equation as follows:
     
        
  Contractor Serviced Facilities Contractor t ofEquipmen Equipment tal AnnualCapi Facility tal AnnualCapi # $ $

The travel, lodging, and shipping costs asso ciated with monitori ng several facilities spread over large regions were calculated us ing the assumed costs in Table 4-14. Expert judgment based on the number of teams using eq uipment and the necessity of travel versus shipping between facilities was us ed to determine these costs.
STEP 5: Estimate per Facility Costs for Each Threshold Level The total reporting costs acr oss 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 to tal 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 cost s by the number of facilities that exceeded the reporting threshold—small, medium, and large. In the case of onshore production, field-level monitoring costs were aggregated to the total nati onal burden, then distributed to operators at the basin-level based on production rates.5-1 SECTION 5 SUBPART W ANALYSIS OF REPORTING RULE OPTIONS
For petroleum and natural gas systems, Subpart W, as shown in Table 5-1, the total cost of the reporting rule to the private sector is estimated to be $61.8 million in the first year and $19.0 million in subsequent years (2006$). These estimates include costs for reporters to monitor and report emissions and the costs for non-reporter s to make a reporting determination. Of the costs to report emissions meeting or exceedi ng the threshold, equipment leaks and vented emissions are $40.1 million in the first year and $15.1 million in subsequent years. The estimates are based on the selected option for the final rule, which includes an annual emissionbased threshold of 25,000 MtCO 2 e for each facility and a hybrid of direct measurement and source-specific calculation methodol ogies. Section 3.2 provides more details about the selected option.
EPA estimates that for Subpart W, the pub lic-sector burden is about $1.1 million per year. Approximately $0.46 million per year is for verification activities, and about $0.66 million per year is for program implementation and de veloping and maintaini ng the data collection system. Program implementation activities include , but are not limited to, developing guidance and training materials to assist the regulated community, respondi ng to inquires from affected facilities on monitoring and appl icability requirements, and de veloping tools to assist in determining applicability. In addition to tota l national costs for petroleum and natural gas systems, EPA also reports average cost-per-metric-ton to support additional analysis of the mandatory reporting programs. These costs are also shown on Table 5-1.
The first-year costs are higher due to initia l program start-up costs—in particular; the investment to secure equipment and install fl ow measurement ports in vent lines to allow measurement. Initial-year costs are also higher because reporter s are required to quantify various key sources (e.g., well liquids unloadings, well workovers, compre ssor wet seal degassing vents) in the first year; these sources are only required to be estimated bi-annually to mitigate long-term burden. The average cost per metric ton for all reporters is about $0.13/metric ton in the first year, declining to an average of $0. 05/metric ton in subsequent years.5-2 Table 5-1 National Cost Estimates for Petroleum and Natural Gas Systems

First Year Subsequent Years Subpart W – Petroleum and Natural Gas systems NAICS $Million Million MtCO 2 e $/Mt $Million Million MtCO 2 e $/Mt 2006 2006 Process Emissions 211, 486 $40.1 253.9 $0.16 $15.11 253.9 $0.06 Combustion Emissions $3.3 83.5 $0.04 $3.32 83.5 $0.04 Reporting Determination $18.4 n/a n/a $0.58 n/a n/a Private Sector, Total $61.8 337.4 $0.13 a $19.01 337.4 $0.05 a Public Sector, Total $1.1 337.4 $0.003 $1.1 337.4 $0.003 TOTAL $62.9 337.4 $0.13 b $20.11 337.4 $0.05 b Note:

a Excludes reporting determination for non-reporters; based on priv ate sector cost to report pr ocess and combustion emissions ($43 million in first year, $18 million in subsequent years).

b Excludes reporting determination for non-reporte rs; based on public sector cost plus pr ivate sector cost to report process and combustion emissions ($44 million in first year, $19 million in subsequent years).

There is a notable reduction in reporting cost compared to the April 2010 proposal. The cost reduction resulted from changes such as providing equipment thresholds on several emission sources (e.g., tanks and dehydrators); simplifie d requirements for sampling and gas composition analysis; use of alternative leak detection equi pment in some cases; and use of equipment-based emission factors instead of com ponent-based emission factors. A slight decrease in the emissions expected to be reported also accounted for the lower cost estimate. The slight decrease in reported emissions resulted from data corre ctions in the transmission and LNG storage segments and use of different well property databases in onshore production. Table 5-2 summarizes these changes based on year-one cost s for equipment leaks and vented emissions, and Table 5-3 summarizes these changes based on subsequent-year costs for equipment leaks and vented emissions.
Table 5-2 Equipment Leaks and Vented Emi ssion Costs, Petroleum and Natural Gas Systems, First-Year Estimates

Source Covered Emissions Cost Cost (MtCO 2 e) Million (2006$) (2006$/metric ton)
April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule

Original Six Segments a 85 94.3 78.7 $32.5 $26.7 $26. 2 $0.38 $0.28 $0.33

Onshore Production n/a 154.9 152.4 n/a $27.7 $11.9 n/a $0.18 $0.08

Local Distribution n/a 22.7 22.7 n/a $1.6 $2.0 n/a $0.07 $0.095-3 Source Covered Emissions Cost Cost (MtCO 2 e) Million (2006$) (2006$/metric ton)
April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule

Total 85 272 254 $ 32.5 $ 56.0 $40.1 $ 0.38 $ 0.21 $0.16

a Offshore production, natural gas processing, natural gas tran smission, underground natural ga s storage, LNG storage; LNG import/export.
Table 5-3 Equipment Leaks and Vented Emi ssion Costs, Petroleum and Natural Gas Systems, Subsequent-Year Estimates

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

April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule April 2009 Proposed

Rule April 2010 Proposed

Rule Final Rule
Original Six Segments a 85 94.3 78.7 $28.1 $11.8 $8.7 $0.33 $0.13 $0.11

Onshore Production n/a 154.9 152.4 n/a $8.6 $5.1 n/a $0.06 $0.03

Local Distribution n/a 22.7 22.7 n/a $1.0 $1.3 n/a $0.04 $0.06

Total 85 272 254 $28.1 $21.4 $15.1 $0.33 $0.08 $0.06

a Offshore production, natural gas processing, natural gas tran smission, underground natural ga s storage, LNG storage; LNG import/export. In addition, EPA developed a nnualized estimates of the costs. For each segment, EPA calculated the present value of the labor and capit al costs to monitor and report emissions over a 20-year time period using two disc ount rates (3 and 7 percent). The present value included the costs for facilities that do not meet the emissions threshold to make a reporting determination.
EPA then calculated an annual valu e of the present value at discount rates of 3 and 7 percent. Table 5-4 presents the annualized cost estimates for each segment as well as the first-year and subsequent-year estimates.5-4 Table 5-4 Annualized Cost Estimates for Petroleum and Natural Gas Systems (2006$) a

First Year Subsequent Year
Annualized Cost b ($Million) Annualized Cost c ($Million) Segment National Cost ($Million) Cost ($/metric ton) National Cost ($Million) Cost ($/metric ton)

Processing 8.13 0.26 2.10 0.07 2.43 2.57 Transmission 16.87 0.40 6.49 0.15 7.02 7.26 Underground Storage 2.73 0.35 1.02 0.13 1.10 1.14 LNG Storage 0.70 0.41 0.26 0.15 0.28 0.29 LNG import/export 0.14 0.44 0.03 0.09 0.04 0.04 LDC 3.31 0.15 1.35 0.06 1.47 1.52 Onshore Production 26.58 0.12 7.54 0.03 8.61 9.05 Offshore Production 3.33 0.65 0.24 0.05 0.42 0.49 TOTAL (8 Segments) 61.78 0.18 19.01 0.06 21.36 22.34

a Includes determination costs for non-re porters. These estimates are conservativ e and should be viewed as an upperbound because the determination costs were applied at the facility-level rather than the company-level. For example, for offshore production, determination costs were applied to each of the approximately 3,000 platforms in the Gulf of Mexico rather than to the roughly 86 op erators in that region. See the memo, “Estimates of Determination Costs,” in the docket for complete details and additional determination cost estimates (EPA-HQOAR-2009-0923). b The cost to report annualized over 20 years at 3 percent.

c The cost to report annualized over 20 years at 7 percent.

5.1 Evaluating Alternative Options fo r Implementation of the Rule The selected option was evaluated based on a co st-effectiveness analysis. For example, in selecting the emission threshold, EPA compared the incremental emissions reported with the incremental costs (associated with the change in the facilities that woul d be required to report their emissions). Similarly, in selecting th e reporting methodology option, EPA compared the change in uncertainty with the change in costs associated with different emission measurement/estimation techniques. The metrics us ed and the results of the cost-effectiveness analysis are discussed in the following information.

In addition, the final rule re quires the determination of ons hore reporting to be done with the assumption that reporting parties report emi ssions and, for onshore production, that they determine threshold on a basin level. In othe r words, owners or operators in the onshore production segment must report based on total em issions in all petroleum and natural gas production fields in a defined ba sin. EPA also examined an op tion to require onshore production5-5 companies to report on a field-level basis. This alternative would affect the total emissions reported as well as cost, and is evaluated in the following sections.
Six alternative options were therefore eval uated for this analysis. While the Agency believes that these alternatives represent the most likely variations in the selected option, EPA recognizes that, in some cases, particular in terests may wish to evaluate more nuanced alternative options. To maintain transparency in the analysis, data necessary to conduct further alternative option analyses can be fo und in Section 4 of this document.

5.1.1 Analysis of Alternative Threshold Options

The threshold determines the number of en tities required to report GHG emissions under Subpart W of the rule. The higher the threshold, th e 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 reporti ng entities. The per-unit/en tity costs outlined in Section 4 for Subpart W facilitie s, along with the estimates of numbers of covered entities at various thresholds, form the basi s for this analysis. Two metrics are used to evaluate the costeffectiveness of the emission threshold. The first is the average cost per metric ton of emissions reported. The second metric for evaluating the thre shold option is the marginal cost of additional reported emissions ($/MtCO 2 e) relative to the option adopted in the final rule. To compute this metric, EPA computed the change in emissions reported by lowering or ra ising the threshold and divided this by the change in total reporting costs. Table 5-5 provide s the cost-effectiveness analysis for the various thresholds.
Table 5-5 Summary of Threshold Cost-Effect iveness Analysis (First Year); Selected Hybrid Option Is 25,000 MtCO 2 e

Threshold (MtCO 2 e) Facilities Required to

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

Emissions Reported Average Reporting

Cost a (2006$/Mt) Cost Differential a ,b (2006$/Mt ) 1,000 12,622 $136.35 391 99% $0.35 $1.73 10,000 4,400 $61.57 362 91% $0.17 $0.73 25,000 2,786 $43.39 337 85% $0.13 $0.00 100,000 1,062 $25.06 273 69% $0.09 ($0.28)

a Excludes determination costs for non-reporters. Inclusion of determination costs results in the following average reporting c osts ($/Mt): 1,000 metric tons CO 2 e = $0.38; 10,000 metric tons CO 2 e = $0.22; 25,000 metric tons CO 2 e = $0.18; and 100,000 metric tons CO 2 e = $0.16. b Cost difference relative to 25,000-metric-ton threshold The analysis shows a cost reduction of $0.28 pe r metric ton by moving from the selected threshold of 25,000 MtCO 2 e to a higher threshold (100,000 metric tons); the total emissions covered decrease significantly—about 16 percent. Similarly, by moving the threshold from5-6 25,000 to 10,000, the difference increases by $0.73 per metric ton, and the emissions captured increase by 6 percent. Finally, lowering the threshold from 25, 000 to 1,000 yields the highest increase in cost difference ( $1.73 per metric ton) and increa ses the percentage of covered emissions by approximately 14 percent. Similar data are presented for subsequent years in Table 5-6.
Table 5-6 Summary of Threshold Cost-E ffectiveness Analysis (Subsequent Years)

Threshold (MtCO 2 e) Facilities Required to

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

Emissions Reported Average Reporting

Cost a (2006$/Mt) Cost Differential a ,b (2006$/Mt) 1,000 12,622 $71.60 391 99% $0.18 $0.99 10,000 4,400 $29.48 362 91% $0.08 $0.44 25,000 2,786 $18.43 337 85% $0.05 $0.00 100,000 1,062 $9.61 273 69% $0.03 ($0.14)

a Excludes determination costs for non-reporters . Inclusion of determination costs resu lts in the following average reporting co sts ($/Mt): 1,000 metric tons CO 2 e = $0.19; 10,000 metric tons CO 2 e = $0.08; 25,000 metric tons CO 2 e = $0.06; and 100,000 metric tons CO 2 e = $0.04. b Cost difference relative to 25,000-metric-ton threshold

Table 5-7 summarizes costs to report process and combustion emissions for all segments at four thresholds.
Table 5-7 Subpart W Cost Estimates by Threshold

Threshold First Year Subsequent Years Million 2006$ $/Mt Million 2006$ $/Mt 1,000 MtCO 2 e $136.35 $0.35 $71.60 $0.18 10,000 MtCO 2 e $61.57 $0.17 $29.48 $0.08 25,000 MtCO 2 e $43.39 $0.13 $18.43 $0.05 100,000 MtCO 2 e $25.06 $0.09 $9.61 $0.04

The selection decision weighed the marginal cost of capturi ng additional emissions with the percentage of emissions needed to accurate ly estimate national GHG emissions. This analysis is shown in Figure 5-1, which il lustrates the total average cost per metric ton and the marginal cost per metric ton for Subpart W as a function of the percentage of total emissions reported.5-7 Figure 5-1 Average Cost and Cost Differentia l per Metric Ton of Emissions Reported by Threshold
a. Average Cost

$0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40

55% 60% 65% 70% 75% 80% 85% 90% 95% 100% % of Total Emissions Reported$/tonne First Year Subsequent Years Average 1K Threshold

100K Threshold 10K Threshold

25K Threshold

b. Cost Differential

($0.50) $0.00 $0.50 $1.00 $1.50 $2.00

55% 60% 65% 70% 75% 80% 85% 90% 95% 100% % of Total Emissions Reported$/tonne First Year Subsequent Years Average 1K Threshold

100K Threshold 10K Threshold

25K Threshold5-8 5.1.2 Analysis of Alternative Monitoring Method Options Each monitoring technique for which reporti ng costs were estimated for Subpart W in Section 4 was assumed in the burden analysis to provide the same estimate of total emissions by reporting facility. The methods proposed for mon itoring emissions will differ, however, in their precision in estimating actual emissions. Theref ore, 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 av erage industry parameters (referred to as “population emission factors,” or “default parameters ”) to material inputs or throughputs, to the use of direct measurement techniques. This secti on evaluates the change in cost and the change in accuracy for two alternative monitoring options for Subpart W. Generally speaking, under one of the alternatives, population factor s would be used in lieu of direct measurements and facilitylevel estimates, and in the othe r option, direct measurements ar e required for all sources. EPA uses the terms “direct measurement” and “popu lation factors” as shorthand to describe alternative options. For Subpart W, population emission factors and component count are the basis for “default factors.” Estimated costs for e ach monitoring method are shown in Table 5-8.
For Subpart W, the direct measurement option greatly expands to use direct measurement of all vented and equipment leak sources. Th is is the methodology used in the April 2009 proposed rule. The costs associated with this ca se in the April 2009 proposed rule (which did not include the onshore production and natural gas distribution) resu lted in Subpart W incurring 19 percent of the total cost s in the GHG reporting rule to monitor and measure only 3 percent of the emissions.

These costs were re-estimated for the entire petroleum and natural gas segment in the final rule. These costs involve the use of dir ect measurement techniques, including metering of all vents, calibrated bagging, or use of high- volume samplers to measure equipment leaks and inaccessible leaks, and so on. These costs involv e additional equipment as well as significantly higher labor costs. If the same di rect measurement techniques were re quired 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 measur ement option are about $100 million (annually) higher than the selected option.5-9 Table 5-8 Analysis of Alt ernative Monitoring Methods

Direct Measurement (DM) Selected Option (Hybrid Approach) Population Factors
Segment First Year (million 2006$) Subsequent Years (million 2006$) First Year (million 2006$) Subsequent Years (million 2006$) First Year (million 2006$) Subsequent Years (million 2006$) Subpart W— Petroleum and Natural Gas Systems $294.6 $126.9 $43.39 $18.43 $27.6 $17.4

For the “population factor” option, Subpart W sources were assumed to have emissions quantified entirely by the appli cation of emission factors deve loped by GRI/EPA (1996) as the basis for estimates of CH 4 and non-combustion-related CO 2 emissions. These factors are used with a population count of equipm ent and components to arrive at a “population factor” cost estimate. The reduction in cost from the selected hybrid approach for this option is significant, with first-year costs declining by $15.8 million, and subsequent-year costs declining by $1.0 million.

5.1.2.1 Monitoring Method Uncertainty

The use of direct measurement methods would provide the most certain quantification of Subpart W emissions, assuming that measuremen ts were taken using consistent monitoring protocols across reporters. If emission sources are measured as estimated in the burden analysis, there should be a high certaint y level in the emissions quantified. Based on the analysis, however, the costs to gather and quantify these emissions would be very high.
The use of population-based f actors would result in a si gnificantly lower burden, although the certainty level of the emission dete rmination would be very poor. Population-based factors determine the potential for emissions, assuming a percentage of known components that may leak based on previous (and dated) studies.
The final-rule-required option of using leak de tection as well as a hybrid of spot direct measurement, engineering estimates, leaker emi ssion factors, and populati on-based factors (for inaccessible sources) provides an emission estim ate with significantly more certainty than population based factors at a more reasonable burden.

5.1.3 Sensitivity of Subsequent-Year Cost Estimates

National cost estimates for the final rule were developed based on the current population of entities in the petroleum and natural gas segment. The forward analysis (“subsequent years”) assumes that the number of entities would remain relatively constant. Thus, the analysis assumes5-10 a stable population where a ll entities subject to S ubpart W bear a single fi rst-year cost and then repeated subsequent-year costs.
In reality, however, over time some existing facilities close or go out of business and new facilities come into existence, which is sometimes referred to as entry and exit in an industry. This phenomenon may affect the cost of the rule because as entities “turn over,” the new entrants presumably will bear first-year costs that are slightly higher than subsequent-year costs.
The largest contribution to non-recurring first- year costs for Subpart W compliance is for flow measurement port installation in compressor s eal vent lines. When a company goes out of business and sells its assets to either a new or existing business, these ports will already be installed; much of the first-year compliance costs will not apply to a company acquiring an already-reporting facility . The remainder of first-year costs that do not repeat are due to labor associated with reviewing the regulation and planning accordingly for compliance. These costs will not be necessary when an existing company, which already reports, acquires a reporting facility from a failing business. Only in the ca se of a new business enti ty acquiring an existing or new reporting station will these reviewing and pl anning first-year labor costs be necessary.
The reviewing and planning costs are minimal in comparison to the significant other firstyear costs of reporting for Subpart W; therefor e, the impact of business transitions on rule reporting costs for Subpart W are assumed minimal.

5.1.4 Summary of Alternative Options for Onshore Facility Definition The final rule specifies that onshore petrol eum and natural gas producers will report for each hydrocarbon basin. A basin is as identified by the American Association of Petroleum Geologists’ three-digit Ge ologic Province Code. The reporters wi ll be owners or operators in a basin; however, EPA also considered an alternate op tion 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 aggr egation of emissions by owners or operators at a field-level to apply the thresh old. Table 5-9 and Tabl e 5-10 show a detailed emission coverage and burden to reporter that would have been expected under a field-level facility definition.5-11 Table 5-9 Emission Coverage and Entities Re porting for Field-Level Facility Definition (Onshore Production)

Threshold Level Emissions Covered Facilities Covered Million MtCO 2 e/

year Percent Number Percent

1,000 219.1 83% 22,459 33% 10,000 171.9 65% 2,549 4% 25,000 150.3 57% 1,157 2% 100,000 110.4 42% 306 0.4%

Table 5-10 Equipment Leaks, Vented, and Co mbustion Emission Cost for Field-Level Facility Definition (Onshore Production)

Threshold

Level Equipment Leak and Vented Emission Cost s (2006$) Combustion Emission Costs (2006$) First-Year Costs Subsequent-Year Costs First-Year Costs Subsequent-Year Costs
Annualized Capital Cost O&M Cost Annualized Capital Cost O&M Cost Annualized Capital Cost O&M Cost Annualized Capital Cost O&M Cost
1,000 $57.3 $7,274 $57.3 $3,069 $500 $1,700 $500 $1,700 10,000 $57.3 $8,855 $57.3 $3,834 $500 $1,700 $500 $1,700 25,000 $57.3 $10,334 $57.3 $4,549 $500 $1,700 $500 $1,700 100,000 $57.3 $14,963 $57.3 $6,622 $500 $1,700 $500 $1,700

Figure 5-2 presents a comparison of average costs (years 1, 2, and 3) and emission coverage at different thresholds for the fiel d- and basin-level options. Specifically, it shows that the fieldlevel option would result in a significantly lowe r coverage in emissions reported—57 percent at field-level versus 85 percent at the basin-level for a 25,000-MtCO 2 e threshold. In addition, the cost to report under the field-leve l definition is higher than under the basin-level definition at all thresholds, except at 100,000-MtCO 2 e threshold, at which field-level is lower. Emission coverage at the 100,000-MtCO 2 e threshold under a field-level de finition is very low, however— 42 percent. Finally, the number of entities reporting at a 25,000-MtCO 2 e threshold for basinlevel definition is lower, at 981 in comparison to the 1,157 entities repor ting for a field-level definition.5-12 Figure 5-2 Summary of Ba sin vs. Field Decision

0.13 0.76

0.04 0.07 0.24

0.07 0.05 0.03

- 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

30% 40% 50% 60% 70% 80% 90% 100% 110% Percent of Total Onshore Emissions Reported2006$/metric tons

Field Level Basin Level

5.2 Assessing Economic Impacts on Small Entities The first step in this assessment was to determine whether the rule would have a significant impact on a substantial number of small entities (SISNOSE) under Subpart W. To make this determination, EPA used a screening analysis that allows it to indicate whether the Agency can certify the rule as not having a SIS NOSE. The elements of this analysis included:

– Identifying affected entities under Subpart W.

– Selecting and describing the measures a nd economic impact thresholds used in the analysis.

– Determining a SISNOSE certification category.

5.2.1 Identifying Affected Segments and Entities The affected entities covered by the rule we re identified during the development of the cost analysis for the reporting rule. The Statis tics of U.S. Businesses (SUSB) data provide national information on the distribution of economic variables by the size of entity. These data were developed in cooperation with, and partia lly funded by, the Office of Advocacy of the Small Business Administration (SBA) (SBA, 2008a). The data include the number of establishments (Table 5-11), employment (Table 5-12), and receipts (Table 5-13) and present information on all entities in an industry covered by Subpart W of th e rule; however, many of these entities would not be expect ed to report under the selected option because they would fall5-13 below the 25,000 hybrid threshold. SUSB also provi des this data by enterprise employment size. The census definitions in this data set are as follows:

– Establishment : An establishment is a single phys ical location wh ere business is conducted or where services or i ndustrial operations are performed.

– Employment : Paid employment consists of full- and part-time employees, including salaried officers and executiv es of corporations, who were on the payroll in the pay period including March 12, 2002. Included are employees on sick leave, holidays, and vacations; not included are proprietors and partners of unincorporated businesses.

– Receipts : Receipts (net of taxes) are defined as the revenue for goods produced or distributed, or services provided, including reve nue earned from premiums, commissions and fees, rents, interest, di vidends, and royalties. Receipts exclude all revenue collected for local , state, and federal taxes.

– Enterprise : An enterprise is a business organi zation consisting of one or more domestic establishments that were speci fied 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 payrol l are summed from the a ssociated establishments. Enterprise size designations are determ ined by the summed employment of all associated establishments.
Because the SBA’s business size definitions (SBA , 2008c) apply to an establishment’s “ultimate parent company,” EPA assumes in this analys is that the “enterpris e” definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses, and the terms are used interchangeably. EPA also reports the SBA size standard(s) for each industry group in order to facilitate comparisons a nd different thresholds.5-14Table 5-11 Number of Establishments by Affected Industry and EnterpriseaSize: 2002SBA SizeStandard(effectiveMarch 11,2008)TotalEstablishmentsOwned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees20 to 99Employees100 to 499Employees< 500Employees500 to 749Employees750 to 999Employees1,000 to1,499EmployeesOnshore petroleum andnatural gasproduction; offshorepetroleum and naturalgas production;onshore natural gasprocessing211 Crude Petroleum and NaturalGas Extraction500 7,629 5836 456 292 6,584 60 64 31Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 Pipeline Transportation ofNatural Gasb1,936 81 27 61 169 36 2 20Natural gas distribution 221210 Natural Gas Distribution 500 2,897 483 86 131 700 68 33 73aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified under common ownership or control.The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterpriseemployment and annualpayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment ofall associated establishments.Because the SBA’s business size definitions (www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumesin this analysis that the enterprise definitionabove is consistent with the concept of ultimate parent company thatis typically used for SmallBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts.5-15Table 5-12 Number of Employees byAffected Industry and EnterpriseaSize: 2002SBA SizeStandard(effectiveMarch 11,2008)TotalEmployeesOwned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees20 to 99Employees100 to 499Employees< 500Employees500 to 749Employees750 to 999Employees1,000 to1,499EmployeesOnshore petroleum andnatural gasproduction; offshorepetroleum and naturalgas production;onshore natural gasprocessing211 Crude Petroleum andNatural Gas Extraction500 88,280 19,336 12,113 11,656 43,105 2,421 3,551 1,061Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 Pipeline Transportation ofNatural Gasb37,450 347 157 1,053 1,834cccNatural gas distribution 221210 Natural Gas Distribution500 86,890 1,956 1,899 4,398 8,420 1,960 2,631 5,014aThe Census Bureau defines an enterprise asa business organization consisting of one ormore domestic establishments that werespecified under common ownership or control.The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterpriseemployment and annualpayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment ofall associated establishments.Since the SBA’s business size definitions (www.sba.gov/size) applyto an establishment’s ultimate parent company, EPA assumes in this analysis that the enterprise definitionabove is consistent with the concept of ultimate parent company thatis typically used for SmallBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts.cThe U.S. Census Bureau has missingdata for this employee range.5-16Table 5-13 Receipts by Affected Industry and EnterpriseaSize: 2002SBA SizeStandard(effectiveMarch11, 2008)TotalReceipts($Million)Owned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees($thousands)20 to 99Employees($thousands100 to 499Employees($thousands)< 500Employees($thousands)500 to 749Employees($thousands)750 to 999Employees($thousands)1,000 to1,499Employees($thousands)Onshore petroleum andnatural gas production;offshore petroleumand natural gasproduction; onshorenatural gas processing211 Crude Petroleum andNatural Gas Extraction500 $160,879 $7,573 $6,790 $9,609 $23,972 $4,609 $3,991 $2,805Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 Pipeline Transportationof Natural Gasb$35,897 $1,035 $106c$394c$2,566cccNatural gas distribution 221210 Natural Gas Distribution 500 $67,275 $2,524 $4,642 $2,878 $13,127 $865 $2,116 $3,757aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified under common ownership or control.The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterpriseemployment and annualpayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment ofall associated establishments.Since the SBA’s business size definitions (www.sba.gov/size) applyto an establishment’s ultimate parent company, EPA assumes in this analysis that the enterprise definitionabove is consistent with the concept of ultimate parent company thatis typically used for SmallBusiness 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 1 to 20 range therefore underestimate true value.5-17 5.2.2 Developing Small-Entity Economic Impact Measures Because Subpart W covers businesses, the analysis generated a set of sales tests (represented as cost-to-receipt ratios) 20 for NAICS codes associated with the affected Subpart W segments. Although the appropriate SBA size definiti on should be applied at the parent company (enterprise) level, data limitations allowed EPA only to compute and compare ratios for a model establishment for eight enterprise size ranges (i.e., all categories, enterprises with 1 to 20 employees, 20 to 99 employees, 100 to 499 employees, 500 to 749 employees, less than 500 employees, 750 to 999 employees, and 1,000 to 1,499 employees). This approach allows EPA to account for differences in establishment recei pts between large and small enterprises and differences in small business definitions across affected Subpart W indus tries. It is also a conservative approach because it does not screen out entities that woul d be below the reporting threshold. It is also conservative because an establishment’s parent co mpany (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 es tablishment’s total annualized mandatory reporting costs to the average establishment recei pts for enterprises within several employment categories 21 (first-year costs: Table 5-14; subsequent-y ear costs: Table 5-15). The average entity costs used to compute the sales test are the same across all of these enterpri se 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 lo wer than average entity estimates provided by the engineering cost analysis.

20 Metrics for other small-entity economic impact measures (if applicable) would potentially include:

 Small governments (if applicable): “Rev enue” test; annualized compliance cost as a percentage of annual government

revenues.

 Small non-profits (if applicable): “Expend iture” test; annualized compliance cost as a percentage of annual operating expenses. 21 The ratios for the 1 to 20 employee category are conservative because they include SUB data for enterprises with zero

employees; these enterprises did not operate the entire year. Ex clusion of enterprises with ze ro employees would result in slightly lower cost-to-sales ratios (e.g., 1.22% for NAICS 211).5-18Table 5-14 Establishment Sales Tests by Industry and EnterpriseaSize: First-Year CostsSBA SizeStandard(effectiveMarch 11,2008)AverageCost PerEntity($1,000/entity)AllEnterprisesOwned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees20 to 99Employees100 to 499Employees< 500Employees500 to 749Employees750 to 999Employees1,000 to 1,499EmployeesOnshore petroleum andnatural gas production;offshore petroleum andnatural gas production;onshore natural gasprocessing211 Crude Petroleum andNatural GasExtraction500$17.1 0.08% 1.32% 0.11% 0.05% 0.47% 0.02% 0.03% 0.02%Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 PipelineTransportation ofNatural Gasb$15.70.08% 0.12% 0.40%c0.24%c0.10%cc cNatural gas distribution 221210 Natural GasDistribution500 $13.9 0.06% 0.27% 0.03% 0.06% 0.07% 0.11% 0.02% 0.03%aThe Census Bureau defines an enterprise asa business organization consisting of one ormore domestic establishments that werespecified under common ownership or control. The enterprise and theestablishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterpriseemployment and annual payroll are summed from the associatedestablishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA’s business size definitions(www.sba.gov/size) apply to anestablishment’s ultimate parent company, EPA assumes in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for SmallBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bThe SBA size standard for NAICS 486210 is$7 million in average annual receipts.cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receiptsfor these categories underestimate true value.5-19Table 5-15 Establishment Sales Tests by Industry and EnterpriseaSize: Subsequent-Year CostsaThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified under common ownership or control.The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterpriseemployment and annualpayroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment ofall associated establishments.Since the SBA’s business size definitions (www.sba.gov/size) applyto an establishment’s ultimate parent company, EPA assumes in this analysis that the enterprise definitionabove is consistent with the concept of ultimate parent company thatis typically used for SmallBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts.cThe U.S. Census Bureau has missing data for this employee range; some estimates were possibleusing partial data. The receiptsfor these categories underestimate the true value,which results in conservative estimates of cost-to-sales ratios.SBA SizeStandard(effectiveMarch 11,2008)AverageCost PerEntity($/entity)AllEnterprisesOwned by Enterprises with:Industry NAICS NAICS Description1 to 20Employees20 to 99Employees100 to 499Employees< 500Employees500 to 749Employees750 to 999Employees1,000 to1,499EmployeesOnshore petroleum andnatural gas production;offshore petroleum andnatural gas production;onshore natural gasprocessing211 Crude Petroleum andNatural GasExtraction500$7.5 0.04% 0.58% 0.05% 0.02% 0.21% 0.01% 0.01% 0.01%Onshore natural gastransmission;underground naturalgas storage; LNGstorage; LNG importand export486210 PipelineTransportation ofNatural Gasb $6.90.04% 0.05% 0.18%c0.11%c0.05% c c cNatural gas distribution 221210 Natural GasDistribution500 $9.2 0.04% 0.18% 0.02% 0.04% 0.05% 0.07% 0.01% 0.02%5-20 5.2.3 Results of Screening Analysis The Regulatory Flexibility Act generally re quires 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 agen cy 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 sm all not-for-prof it enterprises.
For the purposes of assessing the impacts of Subpart W of the rule on small entities, EPA defined a small entity as 1) a small business, as defined by SBA’s regul ations 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, inde pendently owned and operated, a nd not dominant in its field.

EPA believes the selected thresholds maximize the rule coverage w ith 85 percent of all U.S. petroleum and natural gas systems emissi ons reported by approximately 2,786 reporters, while keeping reporting burden to a minimum and excluding small emitters. Furthermore, many Subpart W industry stakeholders with whom EPA met expressed support for a 25,000-MtCO 2 e threshold because it sufficiently captures the ma jority of GHG emissions in the United States while excluding smaller facilities and sources. After considering the economic impact of the final rule on small entities, EPA has concluded that this action will not have a significant economic impact on a substantial number of small entitie s. As shown in Table 5-14 and Table 5-15, the average ratio of annualized repo rting 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 th e reporting program.
The only exception to this is the ratio for 1 to 20 employee range for crude petroleum and natural gas extraction, which is greater than 1 percent but less than 2 percent. As previously noted, the small business analysis does not screen out entities that would be below the reporting threshold. Based on further anal ysis of production data in HPDI , EPA estimates that in most cases, the small enterprises have very small ope rations (such as a single family owning a few production wells) that are highly unlikely to cross the 25,000-MtCO 2 e reporting threshold.
In other cases, a small enterprise (less th an 20 employees) may own large operations but conduct nearly all of its operations through service providers, so th at it has few employees of its own. Such enterprises, however, tend to ha ve higher annual revenues than those with small operations and therefore have lower cost-to-sa les ratios. The review of production data by5-21 operator in HPDI shows a ratio of less than one percent for the ope rators expected to meet the reporting threshold.

5.3 Synopsis of Benefits Under the Mandatory GHG Reporting Rule, EP A requires the collection and verification of emission data from Subpart W facilities. Th is section reviews the benefits of a mandatory reporting program for Subpart W facilities based on previous experience with emission inventory programs in the United States and abroad.
Recent policy discussions have highlighted poten tial benefits to society of the mandatory GHG reporting program (Pew, 2008). Benefits to the public include: build ing public confidence through clear and transparent em ission measures and reports a nd making petroleum and natural gas facilities accountab le for their equipment leaks and vented emissions. A GHG reporting system will also have the benefit of providing policymakers and analysts with a data set that is comprehensive for the petroleum and natural gas industry if reporti ng is conducted under Subpart W and other applicable subparts. Benefi ts to the industry incl ude: identifying costeffective GHG reduction opportunities and disclosi ng information, which provides firms with incentives to reduce emissions voluntarily and prov ides emission data to service industries, such as insurance and financial markets. Availabi lity of emission information to the public, consumers, investors, corporations, and governme nt regulators provides a sound basis for future policy analysis, which benefits society as a w hole. Accurate and transparent information is necessary for the implementation of efficient appr oaches that meet environmental goals with the lowest cost to the economy.6-1 SECTION 6 STATUTORY AND EXECUT IVE ORDER REVIEWS

This section describes EPA’s compliance with applicable executive orders and statutes during the development of Subpart W of the Mandatory GHG Reporting Rule.

6.1 Executive Order 12866: Regula tory Planning and Review
Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a "significant regulatory ac tion” because it raises novel legal or policy issues arising out of legal mandates, the President’s priorities, or the prin ciples set forth in the EO. Accordingly, EPA submitted this action to the Office of Manage ment and Budget (OMB) for review under EO
12866.

6.2 Paperwork Reduction Act

The information collection requirements in th is final rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act
, 44 U.S.C. 3501 et seq . The Information Collection Reque st (ICR) document prepared by EPA has been assigned EPA ICR number 2376.02.

EPA plans to collect complete and accura te facility-level GHG emissions from the petroleum and natural gas industry. Accura te and timely information on GHG emissions is essential for informing future climate change pol icy decisions. Through da ta collected under this rule, EPA will gain a better unders tanding of the relative emissions of different segments of the petroleum and natural gas industry and the distribu tion of emissions from individual facilities within those industries. The facility-specific data will also improve our understanding of the
factors that influence GHG emission rates and actions that faciliti es are already taking to reduce emissions. Additionally, EPA will be able to trac k the trend of emissions from facilities within the petroleum and natural gas industry over time , particularly in re sponse to policies and potential regulations. The data collected by this rule will improve EPA’s ability to formulate climate change policy options a nd to assess which segments of the petroleum and gas industry would be affected, and how these segments would be affected by the options.6-2 This information collection is mandatory and will be carried out under CAA section 114.
Information identified and marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Howe ver, emissions data collected under CAA section 114 cannot generally be claimed as CBI and will be made public.

The projected cost and hour burden for non-Federal respondents is $27.7 million and 396,474 hours per year. The estimated average burden per response is 90.71 hours; the frequency of response is annual for all respondent s that must comply with the final rule’s reporting requirements; and the estimated aver age number of likely respondents per year is 2,786. The cost burden to respondents resulting from the collection of information includes the total capital cost annualized ove r the equipment’s expected useful life (averaging $0.74 million), a total operation and maintenance component (ave raging $1.7 million per year), and a labor cost component (averaging $25.3 million per year) 22

.

Burden is defined at 5 CFR 1320.3(b). Th ese cost numbers differ from those shown elsewhere in the EIA for these subparts because the information collection request (ICR) costs represent the average cost over the first three ye ars of the rule, but cost s are reported elsewhere in the EIA for the subparts for the first year of th e rule and for subsequent years of the rule. In addition, the ICR focuses on respondent burde n, while the EIA includes both national compliance costs and the burden for EPA to implement the rule.

An agency may not conduct or sponsor, a nd 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 ar e listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a te chnical amendment to 40 CFR part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in this final rule.

22 Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown elsewhere in the Economic

Analysis because the ICR costs represent the average cost over the first three years of the proposed rule, but costs are reported elsewhere in the Economic Analysis for the first year of the proposed rule and for subsequent years of the proposed rule. In addition, the ICR focuses on resp ondent burden, while the Economic Analysis includes EPA Agency costs.6-3 6.3 Regulatory Flexibility Act The RFA generally requires an agency to prep are a regulatory flexibil ity analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifie s that the rule will not have a significant economic impact on a substantial number of sm all entities. Small en tities include small businesses, small organizations, a nd small governmental jurisdictions.

For purposes of assessing the impacts of this final rule on small entities, small entity is defined as: (1) A small business as defined by th e Small Business Administration’s regulations at 13 CFR 121.201; (2) a small governmental jurisdic tion that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise that is independently owned and operated and is
not dominant in its field.

After considering the economic impacts of this final action on small entities, I certify that this action will not have a significant economic im pact on a substantial number of small entities.

The small entities directly regulated by this final rule include small businesses in the petroleum and gas industry, small governmental jurisdictions and small non-profits. EPA has
determined that some small businesses will be affected because their production processes emit GHGs exceeding the reporting threshold.

For affected small entities, EPA conduc ted a screening assessment comparing compliance costs for affected industry segments to petroleum and gas-specific data on revenues
for small businesses. This ratio constitutes a “sales” test that computes the annualized compliance costs of this final rule as a percen tage of sales and determines whether the ratio exceeds some level (e.g., 1 percent or 3 percent). The cost-to-sales ratios were constructed at the establishment level (average compliance cost for the establishment/ average establishment revenues).6-4 As shown in Table 5-14, the average ratio of annualized reporting program costs to receipts of establishments owned by model small enterprises was less than 1 percent for industries presumed likely to have small busines ses covered by the repo rting program. It is important to note that this analys is does not screen out entities that would be below the reporting threshold. Although the costs to receipts for entities in onshore production with 1-20 employees is slightly over 1 percent, most of these facilities would likely not exceed the 25,000 mtCO 2 e threshold, a threshold supported by many stakehol ders as one that sufficiently captures the majority of GHG emissions while excluding small facilities.

EPA also concluded that the final rulemaking would not affect a small organization that is any not-for-profit enterprise that is independently owned and operated and is not dominant in its field. Specifically, the data listing entities in each segment of the petroleum and natural gas industry did not include any non-profit entities.

In addition, EPA determined that the fi nal 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 gove rnments affected by the final rulemaking. A comparison of the compliance costs to the reve nue of potentially affect ed small governmental jurisdictions revealed that the costs of the rule are less than 1 percent of revenues.

Although this final rule will not have a si gnificant economic impact on a substantial number of small entities, EPA nonetheless took seve ral steps to re duce the impact of this final rule on small entities. For example, EPA dete rmined appropriate thre sholds that reduce the number of small businesses repor ting. In addition, EPA allows different monitoring methods for different emissions sources, requ iring direct measurement only fo r selected sources. Also, EPA intends to provide a screeni ng tool that will help small businesses make a reporting determination (see Section II.F.6 of the preamble). Finally, EPA is establishing annual instead of more frequent reporting.

Through comprehensive outreach activities prior to proposal of the initial rule, EPA held approximately 100 meetings and/or conference calls with representatives of the primary audience6-5 groups, including numerous trade associations and industries in the petroleum and gas industry
that include small business members. EPA’s outr each activities prior to proposal of the initial rule are documented in the memorandum, Summ ary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule, located in Docket No. EPA-HQ-OAR-2008-0508-053. After the initial proposal, EPA posted a guide for small businesses on the EPA GHG reporting rule website, along with a gene ral fact sheet for the rule, in formation sheets for every source category, and an FAQ document. EPA also ope rated a hotline to answer questions about the
final rule. EPA continued to meet with stake holders and entered documen tation of all meetings
into the docket.

During rule implementation, EPA would mainta in an “open door” policy for stakeholders to ask questions about the final rule or provide suggestions to EPA about the types of compliance
assistance that would be useful to small businesses. EPA in tends to develop a range of compliance assistance tools and materials and co nduct extensive outreach for the final rule.

EPA has therefore concluded that this fina l action will not have a significant economic impact on a substantial number of small entities.

6.4 Unfunded Mandates Reform Act This rule does not contain a Federal manda te that may result in expenditures of $100 million or more for State, local, and Tribal governmen ts, in the aggregate, or the private sector in any one year. EPA estimated the cost to individual facilities that may have to report to this final rule using actual facili ty characteristics such as throughput and size. EPA also determined the costs to non-reporters for determination to report. The sum of these costs for the entire industry has been estimated to be less than $100 million. T hus, this rule is not subject to the requirements
of sections 202 or 205 of UMRA.

This rule is also not subject to the requi rements of section 203 of UMRA because it contains no regulatory require ments that might significantly or uniquely affect small governments. Based on EPA’s analysis of the ru le’s impact on small entities, the Agency determined that natural gas distribution is the only industry segment that would potentially have small governments affected by the rule. In this segment, however, the facilities owned or6-6 operated by small governments are e xpected to be too small to trigger the 25,000 metric tons
CO 2 e reporting threshold.

6.5 Executive Order 13132: Federalism

This action does not have federalism implicatio ns. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in EO 13132. This regu lation applies directly to petrol eum and natural gas facilities that emit greenhouse gases. Few, if any, State or local government facilities would be affected. This regulation also does not limit the power of St ates or localities to collect GHG data and/or regulate GHG emissions. Thus, EO 13132 doe s not apply to this action.

6.6 Executive Order 13175: Consultation a nd Coordination with Indian Tribal Governments EPA has concluded that this action may have tr ibal implications. However, it will neither impose substantial direct compliance costs on trib al governments, nor preempt Tribal law. EPA conducted an analysis to determine potential impact of this action on tribes that own or operate petroleum and natural gas systems (EPA- HQ-OAR-2009-0923-XXX). First, EPA analyzed a comprehensive listing of all operato rs of petroleum and natural gas systems in the United States in conducting the threshold analysis. In a separa te analysis, EPA researched additional available data to determine which tribal entities may own or operate petroleum and natural gas systems that could be impacted by this final action. As a result of those analysis, EPA found one tribe that may potentially be impacted by this final acti on. Finally, during the comment period for the April 2010 proposal, EPA received comment from one tribe, Southern Ute, which were specific to the proposed reporting methodologies.

As further discussed in the 2009 final rule that established the Greenhouse Gas reporting program, EPA believes that there are minimal impacts to tribes. Tribes could be required to submit an annual GHG report for any facility they ow n or operate that is subject to the rule. Specifically, tribes that own or operate oil a nd gas operations could be required to report emissions under this rulemaking. It should be note d that the owner or oper ator of any privately
owned sources located on a reservation would be required to report for any applicable facility.6-7 EPA sought opportunities to provide information to tribal governments and representatives during rule development. As stated in IV.F of the preamble, Executive Order 13175:
Consultation and Coordination with Indian Tr ibal Governments of 40 CFR part 98, and in
consultation with EPA’s American Indian Envi ronment Office, EPA’s outreach plan for the Greenhouse Gas Reporting Rule included tribes. EPA conducted several conference calls with Tribal organizations during the proposal phase of Part 98. For example, EPA staff provided information to tribes through conference calls with multiple Indian working groups and organizations at EPA that intera ct with tribes and through indivi dual calls with two Tribal board members of The Climate Registry (TCR).

In addition, EPA prepared a short article on the Greenhous e Gas Reporting Program that appeared on the front page of a Tribal newsle tter—Tribal Air News—tha t was distributed to EPA/OAQPS’s network of Tribal organizations. EPA gave a pr esentation on various climate efforts, including the Greenhouse Gas Reporting Program, at the National Tribal Conference on Environmental Management on June 24-26, 2008. In addition, EPA distributed copies of a short information sheet at a meeting of the Nationa l Tribal Caucus. See the Summary of EPA
Outreach Activities for Devel oping the GHG reporting rule, in Docket No. EPA-HQ-OAR-2008- 0508-055 for a complete list of Tribal contacts. EPA participated in a conference call with Tribal air coordinators in Ap ril 2009 and prepared a guidance sheet for Tribal governments on the final Part 98. It was posted on the Greenhouse Gas Reporting Program website and published in the Tribal Air Newsletter.

As required by section 7(a), EPA’s Tribal C onsultation Official ha s certified that the requirements of the Executive Order have been me t in a meaningful and timely manner. A copy
of the certification is included in the docket for this action.

6.7 Executive Order 13045: Protection of Ch ildren from Environmental Health Risks and Safety Risks This action is not subject to EO 13045 becau se it does not establish an environmental standard intended to mitigate health or safety risk s. Also, this is not an economically significant rule under EO 12866, and thus EO 13045 does not apply.6-8 6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use

This final rule is not a “s ignificant energy action” as de fined in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to ha ve a significant adverse effect on the supply, distribution, or use of energy. Further, EPA has concluded that th is final rule is not likely to have any adverse energy effects. This fina l rule relates to monitoring, reporting and recordkeeping at petroleum and gas facilities that emit over 25,000 mtCO 2 e and does not impact energy supply, distribution or use. Therefore, EPA concludes that this final rule is not likely to have any adverse effects on energy supply, distribution, or use.

6.9 National Technology Transfer and Advancement Act

Section 12(d) of the Nati onal 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 regul atory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Volunt ary consensus standards are technical standards (e.g., materials specifications, test methods, samp ling procedures, and busi ness practices) that are developed or adopted by voluntary consensus st andards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when th e Agency decides not to use available and applicable voluntary consensus standards.

This rulemaking involves techni cal standards. EPA provides the flexibility to use any one of the voluntary consensus standards from at least seven different voluntary consensus standards bodies, including the fo llowing: ASTM, ASME, ISO, Gas Processors Association, and American Gas Association. These voluntary cons ensus standards will help facilities monitor, report, and keep records of gr eenhouse gas emissions. No new test methods were developed for this final rule. Instead, EPA reviewed ex isting rules for source categories and voluntary greenhouse gas programs and identified existing m eans of monitoring, re porting, and keeping records of greenhouse gas emissions. The existi ng methods (voluntary consensus standards) include a broad range of measurement technique s, including many for co mbustion sources such as methods to analyze fuel and measure its heati ng value; methods to measure gas or liquid flow; and methods to gauge and measure pe troleum and petroleum products.6-9 By incorporating voluntary consensus standard s into this final rule, EPA is both meeting the requirements of the NTTAA and presenting multiple options and flexibility for measuring greenhouse gas emissions.

6.10 Executive Order 12898: Federal Actions to Address Environm ental 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 provi sion directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as a ppropriate, disproportio nately high and adverse human health or environmental effects of their programs, policie s, and activities on minority populations and lowincome populations in the United States.

EPA has determined that this final rule will not have disproportionately high and adverse
human health or environmental effects on minor ity or low-income populations because it does not affect the level of protection provided to huma n health or the environm ent because it is a rule addressing information collecti on and reporting procedures.7-1 SECTION 7 CONCLUSIONS AND IMPLICATIONS
In this EIA, EPA has examined the regulatory background, the development of the mandatory GHG meporting rule for Subpart W, and estimated costs and benefits of implementing this subpart. This secti on presents EPA’s overall conclusions.

7.1 Discussion of Results EPA has developed this final rule in re sponse to language contained in the FY 2008 Consolidated Appropriations amendment (Decem ber 26, 2007), which authorized funding for EPA to publish the rule on an acce lerated schedule. The major market failure that the rule is designed to address is one of in adequate or asymmetric information: while existing state and federal programs collect similar data, the resultin g data are neither comprehensive nor consistent for Subpart W sources. As such, they are an inad equate 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—thres hold and monitoring methodology—that were finalized in today’s rule. The final rule calls for:

– A threshold of 25,000-MtCO 2 e threshold for all facilities.

– A hybrid methodology, including use of limited direct spot measurement, facilityspecific calculation methods, and use of emission factors (leaker and population factors).

Other scenarios evaluated duri ng the development of the prop osal included the following:
1. A 1,000-MtCO 2 e threshold; selected options for methodology, frequency, and verifier.
2. A 10,000-MtCO 2 e threshold; selected options for methodology, frequency, and verifier.
3. A 100,000-MtCO 2 e threshold; selected options for methodology, frequency, and verifier.
4. The measurement variable is changed to direct spot measurement; selected option for threshold.7-2 5. The measurement variable is changed to default emission factors; selected option for threshold.

7.1.2 Affected Source Categories EPA considered direct emitters of equipm ent leaks and vented GHGs under Subpart. From these emission sources, EPA identified eight segments under the Subpart W source category for which costs and impacts were examined.

7.2 Assessment of Costs and Benefits of the Mandatory Greenhouse Gas Reporting Rule

7.2.1 Estimated Costs and Impacts of the Man datory Greenhouse Gas Reporting Program
Under the final rule, EPA estimates that 2, 786 entities would be covered by Subpart W of the rule, directly emitting 337 million MtCO 2 e per year. The total annualized costs incurred under the rule by these entities would be $61.8 m illion for the first year and $19.0 million for subsequent years.
Overall, economic impacts on industry segmen ts are measured by comparing per-entity costs with average per entity receipts. These co st-to-sales ratios are less than 1 percent for establishments owned by small businesses that EP A considers most likely to be covered by the reporting program (e.g., establishments owned by a business with 20 or more employees) and small government entities. This analysis enables EPA to determine that the final rule will not have a significant economic impact on a substantial number of sma ll entities. Overall, Subpart W of the rule will impose national costs exceeding $61.8 million in the first year and $19.0 million in subsequent years; the costs will be widely dispersed throu ghout the economy and relatively low on a per-entity basis. The estimated nationa l costs represent less than 0.001 percent of 2007 gross domestic product. Thus, EPA does not estimate that there will be significant impacts on the economy in general or on individual segmen ts or small entities within Subpart W.

7.2.2 Summary of Qualitative Benefits Assessment EPA did not quantify the estimated benefits of the final rule. Instead, a qualitative assessment was performed, based on informati on from the literature and previous benefits assessments of existing emission inventory programs.
Recent policy discussions have highlighted potential bene fits to society of the GHG reporting program (Pew, 2008). Benefits to the public include buildi ng public confidence through clear and transparent em ission measures and reports a nd making facilities accountable for their emissions. Benefits to petroleum and natural gas in dustry include identifying GHG reduction opportunities and disclosing informati on, which provides firms with incentives to7-3 reduce emissions voluntarily and provides emission data to service industries, such as insurance and financial markets. A GHG reporting system will also have the benefit of providing policymakers and analysts with a comparable da ta set that is comprehensive and reduces the potential for policy bias. In addi tion, a mandatory reporting system is a key element to an overall GHG policy; no effort ca n succeed without it.
Studies published by the Or ganization for Economic Co-operation and Development (OECD) (2005) and U.S.EPA (2003) have docum ented benefits to various stakeholders, including the public, industry, investors, and government, of existing pollutant release and transfer registers (PRTRs). Thes e benefits are likely similar to the benefits that would be experienced as a result of the mandatory GHG repor ting rule, and thus they provide a basis for a qualitative characterization of t hose benefits. The studies examin ed in Section 5 of this EIA describe the following types of benefits:

– Public

– More information will lead to increase d levels of trust towards government and industry where there are right-t o-know laws concerning emissions.

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

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

– Industry

– Public relations: Having independent, veri fiable data to present to the public would demonstrate appropriate environmental stewardship.

– Standardization: Uniform industry st andards would reduce the cost of reporting relative to non-uniform, jurisdic tion-specific, and allow facilities to benchmark their performance against other similar facilities.

– Potential cost savings: Mandatory monitoring may uncover previously unmeasured wasteful processes, yielding cost-saving conservation opportunities that would offset some of the costs of monitoring.7-4 – Potential customer data for servic e industries: Information about GHGemitting firms will be useful for firms that market emission-reduction technologies, and to insurance companies for assessing risk.

– Investors

– Information about emissions will enable investors to implement socially responsible investing using GHG emissi on information if they so choose.

– Government

– Policy development: The greatest bene fit to government of mandatory GHG reporting is the comprehensive, consiste nt data it would provide, enabling government to develop accurate , informed future GHG policy.

– Comparability: A mandatory system woul d reduce the difficulties associated with comparing across different reporting standards across states or programs.

– Compliance and policy evaluation: Pub licly 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 cost s and benefits of the provi sions in Subpart W of the mandatory GHG reporting rule revealed that th e final rule will impose an estimated $30.9 million (based on average of first-year and subsequent-year costs) in monitoring, recordkeeping, and reporting costs on emitters of GHGs that ar e widely distributed throughout the U.S. economy. Impacts of the costs on individual segmen ts and entities are exp ected to be generally small, comprising less than 1 percent of entity receipts and approximately 0.001 percent of 2007 gross domestic product. Thus, despite the overall national costs, macroeconomic impacts are not anticipated, and EPA does not believe that th e final rule will impose significant economic impacts on a substantial number of small entities.7-5 A review of the literature enabled EPA to ch aracterize the expected types of benefits, which will be experienced by stakeholders, incl uding the public, industry, investors, and government. Based on this qualitative assessment and evidence from other existing programs, EPA expects the benefits of the final rule to be substantial.8-1 SECTION 8 SOURCES CONSULTED
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