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

PRELIMINARY DRAFT Final Report

August , 20 10i 

### TABLE OF CON T ENTS

Page

Se ction 1 Introduction and Background

................................ ................................ ..................... 1

- 1

1.1 Background

................................ ................................ ................................ ............ 1

- 1

1.2 Role of the Economic Impact Analysis in the Rulemaking Process

...................... 1

- 4
1.2.1 Legislative Roles

................................ ................................ ...................... 1

- 4
1.2.2 Role of Statutory and Executive Orders

................................ .................. 1

- 6
1.2.3 Illustrative Nature of the Analysis

................................ ........................... 1

- 7

1.3 Overview and Design of the Economic Impact Analysis

................................ ...... 1

- 7
1.3.1 Baseline and Years of Analysis

................................ ............................... 1

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

................................ ................................ ...... 1

- 8
1.3.3 Evaluating Costs and Benefits

................................ ............................... 1

- 13

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative

............................... 1

- 13

Section 2 Regulatory Background

................................ ................................ .............................. 2

- 1

2.1 EPA’s Overall Rulemaking Approach

................................ ................................ ... 2

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

............ 2

- 1
2.1.2 Developing the Rule

................................ ................................ ................ 2

- 2
2.1.3 Evaluation of Existing Greenhouse Gas Reporting Programs

................. 2

- 2
2.1. 4 Stakeholder Outreach to Identify Reporting Issues

................................ . 2

- 3
2.1.5 Analysis of Emissions from the Petroleum and Natural Gas Industry

................................ ................................ ................................ .... 2

- 4

2.2 Sources Considered

................................ ................................ ................................ 2

- 5

2.3 How the Mandatory GHG Reporting Program Is Different from the Federal and State Programs EPA Reviewed

................................ ................................ ....... 2

- 6

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

........................ 2

- 7
2.3.2 Federal Voluntary Greenh ouse Gas Programs

................................ ......... 2

- 9
2.3.3 Federal Mandatory Reporting Programs

................................ ................ 2

- 10
2.3.4 Other EPA Emissions Inventories

................................ ......................... 2

- 11ii 2.3.5 State and Regional Voluntary Programs for Green house Gas Emissions Reporting

................................ ................................ .............. 2

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

................................ .......................... 2

- 12
2.3.7 State Mandatory Greenhouse Gas Reporting Rules

............................... 2

- 14

Section 3 Development of the Mandatory Reporting Rule

................................ ........................ 3

- 1

3.1 Rule Dimensions for Which Options Were Identified

................................ ........... 3

- 1
3.1.1 Thresholds

................................ ................................ ................................ 3

- 2
3 .1.2 Measurement Methodology

................................ ................................ ..... 3

- 3

3.2 Selected Option

................................ ................................ ................................ ...... 3

- 4

3.3 Alternative Scenarios Evaluated

................................ ................................ ............ 3

- 5

3.4 Data Quality for This Analysis

................................ ................................ ............... 3

- 6

Section 4 Engineering Cost Analysis

................................ ................................ ......................... 4

- 8

4.1 Introduction

................................ ................................ ................................ ............ 4

- 8

4.2 Overview of Cost Analysis

................................ ................................ .................... 4

- 9
4.2.1 Baseline Reporting

................................ ................................ ................... 4

- 9
4.2.2 Repor ting Costs

................................ ................................ ........................ 4

- 9

4.3 Subpart W

— Petroleum and Natural Gas Systems

................................ ............... 4

- 11

4.4 Summary Results: Subpart W

— Petroleum and Natural Gas Systems

................ 4

- 18

4.5 Detailed Cost Assumption s: Subpart W

— Petroleum and Natural Gas Systems

................................ ................................ ................................ ................. 4

- 22

4.5.1 Determining Labor Categories

................................ ............................... 4

- 28
4.5.2 Allocating Responsibilities

................................ ................................ .... 4

- 29
4.5.3 Capital Cost Annualization an d O&M Costs

................................ ......... 4

- 35

Section 5 Subpart W Analysis of Reporting Rule Options

................................ ........................ 5

- 1

5.1 Evaluating Alternative Options for Implementation of the Rule

........................... 5

- 4
5.1.1 Analysis of A lternative Threshold Options

................................ ............. 5

- 4
5.1.2 Analysis of Alternative Monitoring Method Options

.............................. 5

- 8
5.1.3 Sensitivity of Subsequent Year Cost Estimates

................................ ....... 5

- 9iii 5.1.4 Summary of Alternative Options for Onshore Facility Definition

........ 5

- 10

5.2 Assessing Economic Impacts on Small Entities

................................ .................. 5

- 12
5.2.1 Identify Affected Segments and Entities

................................ ............... 5

- 12
5.2. 2 Develop Small Entity Economic Impact Measures

............................... 5

- 17
5.2.3 Results of Screening Analysis

................................ ............................... 5

- 20

5.3 Synopsis of Benefits

................................ ................................ ............................. 5

- 21

Section 6 Statutory and Executive Order R eviews

................................ ................................ ..... 6

- 1

6.1 Executive Order 12866: Regulatory Planning and Review

................................ .... 6

- 1

6.2 Paperwork Reduction Act

................................ ................................ ...................... 6

- 2

6.3 Regulatory Flexibility Act

................................ ................................ ...................... 6

- 3

6.4 Unfunded Mandates Reform Act

................................ ................................ ........... 6

- 6

6.5 Executive Order 13132: Federalism

................................ ................................ ....... 6

- 7

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

................................ ................................ ................................ .......... 6

- 7

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

................................ ................................ ................................ ..... 6

- 9

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

................................ ................................ ................................ 6

- 9

6.9 National Technology Transfer Advancement Act

................................ ............... 6

- 10

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

- Income Populations

................................ ....... 6

- 10

Section 7 Conclusions and Implications

................................ ................................ ..................... 7

- 1

7.1 Discussion of Results

................................ ................................ ............................. 7

- 1
7.1.1 Development of the Proposed Rule

................................ ......................... 7

- 1
7.1.2 Affected Source Categories

................................ ................................ ..... 7

- 2

7.2 Assessment of Costs and Benefits of the Mandatory GHG Reporting Rule

.......... 7

- 2
7.2.1 Estimated Costs and Impacts of the Mandatory GHG Reporting Program

................................ ................................ ................................ .... 7

- 2
7.2.2 Summary of Qualit ative Benefits Assessment

................................ ......... 7

- 2iv 7.3 What Did We Learn through This Analysis?

................................ ......................... 7

- 4

Section 8 References

................................ ................................ ................................ .................. 8

- 1v 

### LIST OF FIGURES

Page

Figure 5

- 1 Average and Marginal Cost per Metric Ton of Emissions Reported by Threshold

...... 5

- 7 Figure 5

- 2 Summary of Basin vs. Field Decision

................................ ................................ .... 5

- 11vii 

### LIST OF TABLES

Page

Table 2

- 1 Sources of GHG Emissions Considered

................................ ................................ ... 2

- 5

Table 2

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

........... 2

- 6

Table 3

- 1 Options Considered in Developing Scenarios for Regulation under Subpart W (Final Option Indicated by Shading)

................................ ................................ ........ 3

- 2

Table 4

- 1 Selected Reporting Thresholds and Reporting Requirements

................................ .. 4

- 8

Table 4

- 2 Number of Facilities Reporting by Threshold and Industry Segment

.................... 4

- 13

Table 4

- 3 Subpart W Petroleum and Natural Gas Systems: Labor Costs 1 4

- 17 (2006$)

................ Table 4

- 4 Subpart W Petroleum a nd Natural Gas Systems: Capital and O&M Costs 2
4

- 17 (2006$)

................................ ................................ ................................ .................... Table 4

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

....... 4

- 18

Table 4

- 6 Subpart W Facilities and Emissions Covere d by Final Rule

................................ .. 4

- 18

Table 4

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

.................. 4

- 20

Table 4

- 8 Summary of Reporting Determination Costs per Segment by Threshold

.............. 4

- 22

Table 4

- 9 Allocation of Facilities to Model Types

................................ ................................ . 4

- 27

Table 4

- 10 Labor Categories and Hourly Rates

................................ ................................ ........ 4

- 28

Table 4

- 11 Loaded Hourly Rates for Goods Producing Private Establishments

...................... 4

- 29

Table 4

- 12 Responsibilities for Regulation Compliance by Labor Category

........................... 4

- 29

Table 4

- 13 Responsibilities for Monitoring and Allocation of Labor Hours

............................ 4

- 30

Table 4

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

......................... 4

- 36

Table 5

- 1 National Cost Estimates for Petroleum and Natural Gas Systems

........................... 5

- 2

Table 5

- 2 Equipment Leaks and Vented Emissions Costs , Petroleum and Natural Gas Systems, First Year Estimates

................................ ................................ .................. 5

- 3

Table 5

- 3 Equipment Leaks and Vented Emissions Costs, Petroleum and Natural Gas Systems, Subsequent Year Estimates

................................ ................................ ....... 5

- 3

Table 5

- 4 Summa ry of Threshold Cost

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

- 5 e

................................ .............................. Table 5

- 5 Summary of Threshold Cost

- Effectiveness Analysis (Subsequent Years)

............... 5

- 5

Ta ble 5

- 6 Subpart W Cost Estimates by Threshold

................................ ................................ .. 5

- 6viii Table 5

- 7 Analysis of Alternative Monitoring Methods

................................ ........................... 5

- 9

Table 5

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

................................ ................................ .............................. 5

- 11

Table 5

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

................................ ............................... 5

- 11

Table 5

- 10 Number of Establishments by Aff ected Industry and Enterprise a 5

- 14 Size: 2002

........ Table 5

- 11 Number of Employees by Affected Industry and Enterprise a 5

- 15 Size: 2002

.............. Table 5

- 12 Receipts by Affected Industry and Enterprise a 5

- 16 Size: 20 02

................................ ..... Table 5

- 13 Establishment Sales Tests by Industry and Enterprise a 5

- 18 Size: First Year Costs

...... Table 5

- 14 Establishment Sales Tests by Industry and Enterprise a 5

- 19 Size: Subsequent Year Costs

................................ ................................ ................................ .......................1

- 1 SECTION 1
INTRODUCTION AND BAC KGROUND

1.1 Background
On December 26, 2007, President Bush signed the FY2008 Consolidated Appropriations Amendment, which authorized funding for the U.S. Environmental Protection Agency (EPA) to
develo p and publish a draft r ule 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 month s after the date of enactment of this Act, to require mandatory reporting of GHG emissions above appropriate threshold in all segment s of the economy.

The accompanying explanatory text stated that EPA shall “use its existing authority under the
Clean Air A ct” to develop a mandatory GHG reporting rule.

The agency is further directed to include in its rule reporting of emission resulting from upstream production and downstream sources, to the extent that the Administrator deems it appropriate. The Administrat or shall determine appropriate thresholds of emissions above which reporting is required, and how frequently reports shall be submitted to EPA. The Administrator shall have discretion to use existing reporting requirements for electric generating units und er Section 821 of the Clean Air Act.

EPA signed the final Mandatory Reporting Rule (40 CFR Part 98) on Septem ber 22, 2009, which was published in the October 30, 2009 Federal Register (74 FR 56260). Th is rule did not include Subpart W

, Petroleum and Natur al Gas S ystems due to the extensive number of
comments received on the April 10, 2009, proposal (74 FR 16448)

. Instead, EPA revised the Subpart W proposal based on its review of the comments and updated information about monitoring techniques

. As a resul t, EPA issued a p roposed r ule making on April 1 2 , 2010 (75 FR
18608 ) that would add Subpart W to 40 CFR Part 98 and collect emissions data from two additional segments in the petroleum and natural gas source category

. EPA also released an Economic Impact A n alysis (EIA) in April

, 2010 that assessed the proposed rulemaking’s costs
and benefits

. 1

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

(GHG Reporting), see http://www.epa.gov/c limatechange/emissions/subpart/w.html.1

- 2 This f inal EIA presents revised cost estimates that reflect the changes EPA made to the
final rule based on its consideration of public comments. Overall, these chan ges have resulted in a lower cost per metric ton for industry segments to monitor and report emissions compared to
the April 2010 proposed rulemakin g

. T he estimated total cost for the petroleum and natural gas source category to comply with the final rule is $ 61

. 8 million in the first year

. Of this total, it costs $ 40.1 million to monitor and report about 254 million metric tons carbon dioxide equivalent ( CO 2 e ) process emissions , or on average $ 0. 1 6 /metric ton CO 2 e

. This compares with
the estimate of $0. 3 8 /metric ton under the April, 2009 proposal

. 2

Whereas the methodology proposed in April

, 2009 for Sub part W involved 100 percent
measurement for six segment s ( o ffshore p roduction

, o nshore g as p rocessing

, t ransmission

,

u nderground s torage , LNG s torage and L NG i mport & export ) , the April, 2010 notice proposed hybrid methodologies to quantify GHG emissions from eight segments in the petroleum and natural gas systems subpart (the original six plus onshore production and natural gas distribution)

. T oday’s rule finalizes the hybrid approach for the eight segments. Notably, it us e s limited direct measurement

, i

. e. , only in areas where emissions are known to be significant and not enough reliable data are available to develop emissions factors. The bulk of emissio ns will be quantified using engineering calculation s based on actual facility or field data and us ing leak
detection and “leaker” factors 3

There are severa l key changes in today’s final rule that affect the compliance cost
estimates . First, the final rule provides floors on several emissions sources. Reporters will use a simple population based emissions factors for sources below the floor. Second, EPA has . There are also some sources that w ould u s e population based
factor s

— often referred to as default factors

— primarily f or inaccessible sources or relatively
small leaking sources

. Consistent with the April, 2010 p roposed r ulemaking and the T echnical Support Document (TSD) (EPA

- HQ

- OAR

- 200 9

- 0923

- 0027 ) , the final rule and economic analysis use population based factors. In addition, EPA finalized the proposal to use the MMS Gulfwide Offshore Activity Data System (GOADS) process for collecting data from offshore production platforms. This leverages an existing GHG data collection process and minimize s burden.

2 For the final rule, total cost estimate for the first year includes $18.4 million for non

- reporters to make a threshold

determination and $3.3 million for combustion emissions reporting by reporters. The April, 200 9 analysis did not include a burden estimate for non

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

vented sources; the emissions quantification req uires actual detection of a leak before application of a factor. This provides a truer assessment of actual emissions than “population” emissions factors

, which are based on simple population count . The population count provides an estimate of “potential” emissions because it assume s a percentage of leaking components.1

- 3 simplified the required for sampling of gas and emissions for many of the emissions sources, thus considerably reducing burden.

Overall, th e hybrid methodology finalized in today’s rule results in a significant reduction
in the compliance cost per metric ton of equipment leak and vented GHG emissions reporting relative to the original proposal . For the six original segment s, equipment leak and vented
emissions costs for reporters changed from $0. 3 6 / metric ton CO 2 e in the April, 2009 p roposed

r ule to $0. 28 / metric ton CO 2 e in the April, 2010 p ropos al, and to $ 0. 3 3 /metric ton CO 2 e in the
f inal r ulemaking , based on average “ first year ” costs

. 4 , 5 These estimates do not account for onshore production and natural gas distribution, the two segments added in the Ap ril, 2010 proposal. Under the final rule, EPA estimates it will cost reporters on average , in eight
segments , $0.1 6 /metric ton CO 2 e in the first year, which is less than the first year cost of $0.21/metric ton CO 2 e in the April 2010 proposed rulemaking.

The cost estimates for today’s rule also account for the burden to report combustion
emissions because some reporters that equal or exceed the Subpart W threshold for equipment
leak s and vented emissions would need to report combustion emissions under Subp art C of 40
CFR Part 98

. In those cases, the reporters would not have triggered the Subpart C reporting threshold in the absence of Subpart W. However, those that meet the emissions threshold under Subpart W are required to report combustion emissions un der Subpart C, even if the combustion emissions alone do not exceed the Subpart C threshold. In short, EPA expects the addition of Subpart W to the MRR to result in the reporting of additional combustion emissions under Subpart C , referred to as “incremen tal combustion emissions” in this document

. Of the 162.2
milli on metric tons CO 2 e expected to be reported under Subpart C

, 83 .5 million metric tons
CO 2 e are the combustion emissions from petroleum and natural gas facilities that would not have reported in the absence of Subpart W. Th e incremental combustion emissions reporting is $3. 3 million per year of the total combustion emissions cost, or $0.04/ metric ton CO 2

Year one costs for Subpart W vented and equipment leak emissions are significantly highe r than the “subsequent year” cost s , totaling $ 40.1 mil lion in the first year for equipment
leaks and vented emissions determination , decreasing to $ 15.1 million in subsequent years. The higher burden is due to start

- up costs in the first year. For example , the rule requires the
install ation of ports in vent lines for compressors and well equipment in the first year to enable e

.

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

-

year global warming potential from the IPCC. Also, subsequent year costs are the average of costs subsequent to year one costs, and thereby represent a “steady

- state” time period.1

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

- time cost associated with reporting start

- up ; th e only cost in subsequent years for those sources is to physically take spot measurements.

Today’s rule finalizes the approach in the April, 2010 proposal to defi ne vented emissions separately from fugitive emissions , except that it replaces the term “fugi tive
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) v ented emissions, which include intentional or designed releases of CH 4 and/or
CO 2

2) equipment leaks, which are defined to include those emissions which are unintentional and could not reasonably pass through a stack, chimney, vent, or
other f unctionally

- equivalent opening ; and containing natural gas or hydrocarbon gas (not including stationary combustion flue gas) from emissions sources including, but not limited to, open ended lines, gas pneumati c powered valves and pumps, equipment depressuring to the atmosphere and compressor shaft seals ;

3) flare combustion emissions, which include CH 4 , CO 2 and N 2

1.2 Role of the Economic Impact Analysis in the Rulemaking Process O emissions resulting from combustion of gas in flares

.

1.2.1 Legislative Authority and Context
This repo rt analyzes the estimated economic impacts of the mandatory reporting program that EPA has developed for Subpart W , in accordance with the FY08 Appropriations language, under the authority of Section 1 14 of the Clean Air Act [CAA]. Section 114 provides EPA broad authority to collect data for the purpose of “carrying out any provision” of the Act (except for a provision of Title II with respect to manufacturers of new motor vehicles or new motor vehicle engines). Section 114(a) 6

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

CAA Amendments and was not codified into the CAA itself. of the CAA authorizes the Adm inistrator to, inter alia, require certain persons (see below) on a one

- time, periodic or continuous basis to keep records, make reports, undertake monitoring, sample emissions, or provide such other information as the Administrator may reasonably require. This information may be required of any person who (i) owns or operates an emission source, (ii) manufactures control or process equipment, (iii) the1

- 5 Administrator believes may have information necessary for the purposes set forth in this section, or (iv) is subject to any requirement of the Act (except for manufacturers subject to certain T itle II requirements). The information may be required for the purposes of developing an implementation plan, an emission standard under sections 111, 112 or 129 7 , dete rmining if any person is in violation of any standard or requirement of an implementation plan or emissions standard, or “carrying out any provision” of the Act (except for a provision of T itle II with respect to manufacturers of new motor vehicles or new motor vehicle engines) 8

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

- duty vehicles, “Light

- Duty Vehicle Greenhouse Gas Emission Standards and
Corporate Average Fuel Economy Standards,” (7 5 FR 25324

, May 7, 2010); .
The scope of the persons potentially subject to a section 114(a)(1) information request (e.g., a person “who the Administrator believes may have information necessary for the purposes set forth in” section 114(a)) and the reach of the phrase “carrying out any provision” of the Act are quite broad. EPA’s authority to request information reaches to a source not subject to the CAA, and may be used for purposes relevant to any provision of the Act. Thus, for example, utilizing section 1 14, EPA could gather information relevant to carrying out provisions involving research (e.g., section 103(g)); evaluating and setting standards (e.g., section 111); and endangerment determinations contained in specific provisions of the Act (e.g., 2 02); a s well as other programs.

EPA has recently announced a number of climate change related actions, including :

**•** P roposed Endangerment and Cause or Contribute Findings for Greenhouse Gases
Under Secti on 202(a) of the Clean Air Act (74 FR 18886, April 24, 2009 );

**•** R econsideration of the memo entitled “ EPA’s Interpretation of Regulations that Determine Pollutants Covered By Federal Prevention of Significant Deterioration (PSD) Permit Program” (73 FR 80300, December 31, 2008) ; and

**•** G ranting the C alifornia Waiver (74 FR 32744, July 9, 2009).

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

“hazardous Ai r Pollutants,” and section 129 contains provisions for “solid waste combustion.”
8 Although there are exclusions in section 114(a)(1) regarding certain title II requirements applicable to

manufacturers of new motor vehicle and motor vehicle engines, secti on 208 authorizes the gathering of information related to those areas.1

- 6 These are all separate actions. Some are related to EPA’s response to the U.S. Supreme Court’s decision in Massachusetts v. EPA. 127 S.Ct. 1438 (2007), others are EPA actions to address climate change. Th e MRR and this f inal r ulemaking do not indicate EPA has made any final
decisions on these other actions. However, the mandatory GHG reporting program will provide EPA, other government agencies, and outside stakeholders with economy

- wide data on facility

level (and in some cases corporate

- level) GHG emissions, which cou ld assist in future policy development.

Accurate and timely information on GHG emissions is essential for informing future climate change policy decisions. Although additional data collection (e.g., for other source categories such as indirect emissions or offsets) will no doubt be required as the development of climate policies evolves, the data collected in this rule will provide useful information for a variety of polices. Furthermore, many existing programs collect this type of information and will

cont inue to do so. Through data collected under this rule, EPA, States and the public will gain a better understanding of the relative emissions of the petroleum and natural gas industry , and the
distribution of emissions from individual facilities within diff erent segments of this industry. The facility

- specific data will also improve our understanding of the factors that influence GHG emission rates and actions that facilities are already taking to reduce emissions.

The Agency considered a wide range of dete rmining factors when selecting the
alternative s for this rule. These included the consideration of costs and benefits, which are essential to making efficient, cost

- effective decisions for implementation of these standards. Other important considerations i ncluded the language of the Appropriations Act and the accompanying explanatory statement related to source categories; consistency with other CAA

or state

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

accuracy of different monitoring approaches and the monitoring methods already in use within
the petroleum and natural gas industry ; and the potential burden placed on small businesses
associated with a range of reporting thresholds.

This Economic Impact Analysis i s intended to inform the public about the selection criteria for this rule, which include, but are not limited to, the potential costs and benefits that may result when the mandatory reporting program is implemented.

1.2.2 Role of Statutory and Executive Orders

S everal statutes and executive orders dictate the manner in which EPA considers rulemaking and apply to any public documentation. The analysis required by these statutes and executive orders is presented in Section 6.1

- 7 EPA presents this Economic Impact Anal ysis f or Subpart W

— Petroleum and Natural Gas System s

— pursuant to Executive Order 12866

, the guidelines of Office of Management and Budget (OMB) Circular A

- 4

, and EPA’s Economic Guidelines 9

1.2.3 Illustrative Nature of the Analysis . These documents contain guidelines for assess ing the benefits and costs of the selected regulatory option, as well as options that are more stringent or less stringent. Section 4 of the Economic Impact Analysis
presents t he costs of the f inal r ulemaking; section 5 summarizes the cost

- effectiveness analysis of the program

. Section 5 also qualitatively describes t he benefits of the f inal r ule making.

Th e analysis illustr ates the types of costs and benefits that may accrue as a result of the program. The estimates of costs reflect existin g production levels in Subpart W for certain petroleum and natural gas systems. E stimates of emissions are based on 2006 data with a number of adjustments to reflect best and most current information from published sources (delineated in
the TSD ) . When the reporting program takes effect, actual patterns of economic activity and emissions may differ from current conditions. However, th ese data provide estimates of baseline conditions and estimated costs of compliance.

1.3 Overview and Design of the Economic Impa ct Analysis

This EIA comprises seven sections. Following this introductory section, Section 2
describes segment s affected by Subpart W provisions and reviews existing reporting programs and how they treat comparable petroleum and natural gas systems . Secti on 3 describes the development of the rule, including control options and analyses of alternative scenarios. Section 4 characterizes baseline conditions and presents engineering estimates of the costs of complying
with Subpart W of the rule. Section 5 pres ents an assessment of the monitoring and reporting

costs for the petroleum and natural gas industry , a qualitative examination of uncertainty related to measurement accuracy of monitoring methods prescribed, and an assessment of potential impacts on small entities. Section 5 also presents a brief qualitative examination of potential
benefits of the rule. Section 6 provides a discussion of the Agency’s compliance with executive orders and other statutes during the development of the rule. Section 7 describe s EPA’s conclusions and findings.

1.3.1 Baseline and Years of Analysis
Data used for the analysis represent the most recent data available on estimates of GHG
emission for the petroleum and natural gas source category , productive capacity, existing

9 U.S. Office of Management and Budget. Circular A

- 4, September 17, 2003 : http://www.whitehouse.gov/omb/

circulars/ a004/a

- 4.pdf

.1

- 8 emissions mon itoring, and reporting activities for this industry . While EPA recognizes that economic growth and changes in the structure of the economy over time will likely result in changes in both emissions and costs for those covered by Subpart W , attempting to pro ject these changes would lead to an increased level of uncertainty without conveying comparable improvements in the assessment. Thus, EPA uses data representing essentially current conditions as a proxy for conditions present when the rule takes effect. Su ch estimates are inherently uncertain because data needed for more precise measurements are not available. The data collected by the rule would greatly enhance future estimates.

1.3.2 Developing the GHG Reporting Rule Considered in This Economic Impact Analysis
In order to ensure a comprehensive consideration of GHG emissions, EPA conducted numerous stakeholder meetings, evaluated over 484 significant and detailed comments ( over 2,700 pages for Subpart W ) and conducted extensive review and analysis of available
i nformation on segment s 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 s ee how these programs treat emissions from the petroleum and natural gas industry . One of EPA’s goal s was to develop a reporting rule for Subpart W units that, to the extent possible and appropriate, is consistent with existing GHG emission estimation
and reporti ng methodologies in order to reduce the burden of reporting for all parties involved.
The TSD document s our review of GHG monitoring protocols for each segment identified by Subpart W that is used by federal, state, regional, and international volun tary and mandatory GHG programs, and our review of state mandatory GHG rules and how they treat equipment
leak emission s from the petroleum and natural gas industry.

EPA’s overall rulemaking approach began with identification of anthropogenic sources in
th e U.S. GHG Inventory and Inter governmental Panel on Climate Change (IPCC). The rule would require reporting of CO 2 and CH 4 equipment leak and vented emissions, and combustion

related emissions 10 of CO 2 and CH 4 and N 2 O as defined in the rule. The IPCC focuse s on CO 2 , CH 4 and N 2

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

combustion related emissions are to be reported under Subpart C of th e finalized MRR. O for both scientific assessments and emissions inventory purposes because these are long

- lived, well

- mixed GHGs not controlled by the Montreal Protocol on Substances that Deplete the Ozone Layer. These GHGs are directly emitted by huma n activities, are reported1

- 9 annually in EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks, and are the common
focus of the cli mate change research community.

EPA then conducted a review of existing methodologies and reporting programs (e.g.,
Califo rnia Air Resources Board [CARB], The Climate Registry [TCR], 1605b of the Energy Policy Act). EPA’s review of existing reporting programs and measurement methodologies employed by existing federal and state programs is described in Section II of the 40 CFR Part 98

p reamble (74 FR 56260, October 30, 2009). A description specific to petroleum and natural gas can be found in Section C of the TSD. EPA used this information to inform its selection of measurement and reporting methods for this f inal r ulemaking.

Once EPA had a complete list of source categories relevant to the U nited States , the Agency systematically reviewed those source categories against the following criteria to develop
the list of source categ ories included in the proposal:

(1) I nclude source categories that emit the most significant amounts of GHG s , while also minimizing the number of reporters ; and

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

Source categories that would be required to report were identified. Sources were then screened by several key criteria, looking at the number of reporters versus the coverage of emissions under various thresholds, relevant and appropriate quantification methodologies, quantification accuracy, and administr ative burden. Based on the source level screening activities, possible reporting methodologies for the selected sources were developed. The reporting methodologies identified fall into several categories

, including continuous emissions monitoring, calculat ing emissions based on site

- specific information, and calculating emissions based on default emissions factors. In general, for 40 CFR Part 98 , EPA selected a combination
of continuous emissions monitoring and calculations based on site

- specific informatio n.

For Subpart W, the April, 2009 p roposed r ule involved almost exclusive application of detection and direct spot measurement 11

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

measurement using a vane anemometer or similar equipment; the measurement is not “CEMS” as it is not continuous. of vented and equipment leak emissions for the six
segment s (offshore production, onshore natural gas processing, transmission, underground storage, LNG storage and LNG import and export facilities). Both the April, 2010 p roposed1

- 10 r ulemaking and f inal r ulemaking include eight segments

— the original six plus onshore petroleum and natural gas production and natural gas distribution

— a nd significantly reduc es the sources that must be directly quantified. While direct spot measurement is still required to develop site or equipment

- specific emissions factors for some major sources, much of the emissions quantification is through effective but less burdensome use of engineering estimates
and leak detection with use of leaker factors and component population count and population (default) emission factors.

Once the Subpart W segments and methodologies had been identified, EPA evaluated
diffe rent rule options across the following dimensions:

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

o 1,000 metric tons CO 2

o 10,000 metric tons CO e/year;

2

o 25,000 metric tons CO e/year;

2

o 100,000 metric tons CO e/year; and

2

– M ethodology for measuring emissions; e/year

.

o Direct spot measurement;

o Facility

- specific calculation methods; and

o Leaker and d efault emissions factors

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

The options and alternatives evaluated are described in detail in Section 3. Section 4 details the engineering cost analysis which outlines the monitoring and reporting activities and
costs for each source under Subpart W that is required to report.

1.3.2.1 Summary of the Maj or Changes from April , 2009 Propo s ed Rule making to April, 2010 Proposed Rule m aking
EPA received approximately 16,800 public comments on the April, 2009 p roposed

r ulemaking for all subparts ; over 1,200 pages of those comments focused on Subpart W

. EPA
hel d two public hearings and conducted an unprecedented level of outreach between signature of the proposal and the close of the public comment period. Below are the major changes reflected
in th e April, 2010 p roposed r ulemaking for Subpart W:1

- 11 – Two additional petroleum and n atural g as system segment s were added: o nshore

p roduction and n atural g as d istribution . These segment s represent the largest ( o nshore p roduction ) and fourth largest ( n atural g as d istribution ) segment s for equipment leak

, vented , and flare d e missions in the petroleum and n atural gas system source category

.

– Under the April, 2009 p roposed r ule for Subpart W

, essentially 100 percent of the
emissions were monitored using leak detection and direct measurement. In the April, 2010 p roposed r ule, the percentage of total equipment leak and vented emissions directly spot measured was reduced to 6 percent

.

– The methodology selected for individual sources in each of the p roposed April,
2010 r ule segment s was determined based on the intent to achieve the mos t cost effective coverage of emissions. Therefore, in some cases accepted engineering estimates based on facility data was used, in others leak detection coupled with
use of average leaking component (i.e. leak er) factors was used (this is more
informative data on actual leaks for long term tracking purposes than emissions

“ population ” factors based on component counts).

– Use of population e mission factors was proposed in several areas, primarily for
minor equipment leak sources and also sources that are ina ccessible or excessively burdensome for leak detection . To the degree possible, use of these

was minimized.

– In the case of o ffshore production, EPA propose d reporting of existing MMS
GOADS emissions results for o ffshore platforms in Federal Gulf of Mexico (GoM) waters to avoid redundancy of reporting effort s

. 12

12 Gulf Offshore Activities Data System (GOADS) is an inventory of air emissions from pla tforms operating in

Federal waters in the Western Gulf of Mexico developed by The Minerals Management Service (MMS). The MMS mandated that all 2525 offshore operators in the Gulf of Mexico conduct annual surveys (in 2000 and 2005) of their GHG and other hazardous pollutants. The MMS collects activity data from each platform that is then used to estimate emissions. The usual cycle for this data collection effort has been once in every three to four years. We also re quired that facilities not covered by GOADS ( State waters and Federal non

- GoM platform s)
use data collection and emissions calculation methods in accordance with the MMS GOADS program to re duce burden and make emissions reporting
consistent across the segment

.1

- 12 In addition to the Subpart W

- specific changes above, the changes affecting all subparts of
40 CFR Part 98 would likewise affect Subpart W reporters. These changes include :

– Added a mec hanism in 40 CFR 98.2 to allow facilities and suppliers that report less than 25,000 metric tons of CO 2

– Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that report
less than 15 ,000 metric to ns of CO e for 5 years to cease annual reporting to
EPA.

2

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

- emitting processes and operations covered by the rule to cease annual reporting to EPA. e for 3 years to cease annual reporting to
EPA.

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

correct errors.

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

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

– Revised the requirements of the Designated Representative in 40 CFR 98.4 to align them with those in 40 CFR 75 (ARP regulations).

– Changed record retention to 3 years instead of 5 years for most records (40 CFR 98.3).

– In the recordkeeping se ction (40 CFR 98.3), clarified the contents of the monitoring plan (called the QAPP at proposal).

– Revised several definitions in 40 CFR part 98, subpart A to address comments.

Overall , the difference between the estimated annual cost of the April, 2010 p ro posed

r ule making for Subpart W and the estimated annual cost of the April, 2009 p roposed r ule
result ed from the addition of two segment s to Subpart W and the significant reduction in direct emissions spot measurements.1

- 13 1.3.2.2 Summary of the Major Changes from Apr il , 2010 Proposed Rulem aking to September, 2010 Final Rule m aking

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

– P rovide a floor for compressors, separators, and dehydrator s such that sources below the floor use a simplified population emissions factor approach and sources above the floor use actual monitoring ;

– For onshore production, population emissions factors will be applied to major equipment rather than individual comp onents ;

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

– Allow the use of leak detection equipment

, such as organic vapor analyz ers and toxic vapor analyzers

, in addition to using infrared devices

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

1.3.3 Evaluating Costs and Benefits

To inform the selection of the option for the final rule

, EPA conducted an Economic Impact Analysis across the dimensions identified above in Section 1.3.2 . EPA estimated the costs of complying with each of the reporting alternatives, and assessed the cost

- effectiveness of each alternative by examining the costs per million me tric ton of CO 2 equivalent (MMtCO 2

1.4 Subpart W Selected Greenhouse Gas Reporting Alternative e) reported. This cost

- effectiveness metric was considered in combination with other important factors such as the potential impacts on small entities and consistency with other CAA or state

level regulatory programs and m onitoring methods already in use w ithin the regulated industries.

The selected option for Subpart W of the mandatory GHG reporting rule is outlined below. Section 5 provides cost comparisons for each alternative evaluated under the following

two dimensions. The selected option strikes a balance between impacts on small entities, consistency with other programs, costs incurred by the reporting en tities, and emissions

coverage.1

- 14 – Threshold : 25,000 metric t ons CO 2

– The thresholds for the finalized MRR fall generally into three groups: capacity, emissions, or entire source category (“All in”). In Subpart W , a facility that emits 25,000 metric tons CO e/year

2

– Subpart W facilities determine their applicability by comparing their emissions to a threshold of 25,000 metric tons CO e/year or more reports all sourc es for which there are methods specified in the Rule.

2

– Subpart W segment s evaluate threshold from an analysis of reported vented and equipment leak s an d stationary combustion

- based emissions. e/year

.

– Methodology : Combination of direct measurement and source

- specific calculation methodologies

– Direct spot measurement of site or equipment specific emission factor s from

sources at facilities that were deemed to be e ssential to collect based on the estimated volume of emissions and the lack of effective alternative methodologies or emissions factors.

– Source

- specific engineering calculation methods using facility

- specific information for other sources at the facility.

– Source

- specific calculation methods for equipment identified to be leaking.

– Source

- specific use of population based emission factors for minor vented and equipment leaks or inaccessible sources.2

- 1 SECTION 2
REGULATORY BACKGROUN D

The intent of this rule is to collec t accurate and timely GHG emissions data that can be used to inform future policies. Although the mandatory GHG rule is unique, EPA carefully considered other federal and state programs during development of the rule , and how these existing programs treat the petroleum and natural gas industry . The reporting program will supplement rather than duplicate other U.S. government GHG programs. We outline EPA ’ s overall rulemaking approach, sources considered, and summarize our review of GHG monitoring protocols f or each petroleum and natural gas system used by federal, state, regional, and international voluntary and mandatory GHG programs, and our review of state mandatory GHG rules below. For example, the monitoring and GHG calculation methodologies for many of the petroleum and natural gas systems are the same as, or similar to, the methodologies contained in state reporting programs. The remainder of the section provides an overview of related existing programs and discusses their relevance in the development o f this rule.

2.1 EPA ’ s Overall Rulemaking Approach
In response to the FY2008 Consolidated Appropriations Amendment, EPA has developed this rulemaking. The components of this development are explained in the following subsections.

2.1.1 Identifying the Goals of the G reenhouse Gas Reporting System
The mandatory reporting program outlined in Subpart W will provide comprehensive and accurate data which will inform future climate change policies. Potential future climate policies include research and development initiativ es, economic incentives, new or expanded voluntary programs, adaptation strategies, emission standards, a carbon tax, or a cap

- and

- trade program. Because we do not know at this time the specific policies that will be adopted, the data reported through the mandatory reporting system should be of sufficient quality to support a range of approaches. Also, consistent with the Appropriations Amendment, the reporting rule covers a broad range of source categories in the economy ; however, this Economic Impact Anal ysis for
the f inal r ulemaking is specific to Subpart W , petroleum and natural gas systems

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

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

ran ge of future climate change policies and regulations.

– Balance the rule coverage to maximize the amount of emissions reported while minimizing reporting from small emitters.2

- 2 – Create reporting requirements that are consistent with existing GHG reporting
prog rams by using existing GHG emission estimation and reporting methodologies to reduce reporting burden, where feasible.

2.1.2 Developing the Rule

For Subpart W

, EPA evaluated the requirements of existing GHG reporting programs, obtained input from stakeholders, analyzed reporting options, and developed the general reporting requirements and specific requirements for each of the GHG emitting processes listed
in Subpart W

. In addition, EPA considered public comments it received on both the original April, 2009 and April, 2010 proposed rulemakings as it determined the reporting requirements issued in today’s final rule.

2.1.3 Evaluation of Existing Greenhouse Gas Reporting Programs

A number of s tate and regional GHG reporting systems currently are in place or under
develo pment. EPA ’ s goal is to develop a reporting rule that, to the extent possible and appropriate, would rely on similar protocols and formats of the existing programs for petroleum and natural gas systems and, therefore, reduce the burden of reporting for all parties involved. Therefore, we performed a comprehensive review of existing voluntary and mandatory GHG reporting programs, as well as guidance documents for quantifying GHG equipment leaks from
the petroleum and natural gas source category . These GHG re porting programs and guidance
documents specifically related to the petroleum and natural gas source category include:

– U.S. national programs, such as the U.S. GHG inventory, the ARP, DOE 1605(b) voluntary registry, and voluntary GHG partnership programs ( e.g., Natural Gas STAR);

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

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

– Reporting protocols developed by nongovernmental organi zations, such as the World Resources Institute/World Business Council for Sustainable Development ( WRI/WBCSD ) ; and

– Programs from industrial trade organizations, such as the American Petroleum Institute ’ s Compendium of GHG Estimation Methodologies for the Petroleum and Gas Industry

.
In reviewing these programs, we analyzed the segment s covered, thresholds for reporting, the monitoring or emission estimating methods used, the measures to assure the quality of the reported data, the point of monitoring, data input needs, and information required to be reported2

- 3 and/or retained. We analyzed these provisions for suitability to a mandatory, f ederal GHG reporting program, and compiled the information. Section 2.3 describes the existing reporting programs exami ned regarding Subpart W . The full review of existing GHG reporting programs and guidance for all MRR subparts may be found in the docket a t EPA

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2.1.4 Stakeholder Outreach to Identify Reporting Issues
Early in the development process of the MRR
, EPA conducted a proactive communications outreach program to inform the public about the rule development effort. EPA solicited input and maintained an open door policy for those interested in discussing the rulemaking. Since January 2008, EPA staff h as held more than 100 meetings with stakeholders, including the following:

– trade associations and firms in potentially affected industries/ segment s;

– state, local, and tribal environmental control agencies and regional air quality planning organizations;

– st ate and regional organizations already involved in GHG emissions reporting, such as TCR, California Air Resources Board ( CARB ) , and Western Climate Initiative (WCI); and

– environmental groups and other nongovernmental organizations.

– EPA also met with U.S. D epartment of Interior , which ha s a program relevant to GHG emissions.

During the meetings, we shared information about the statutory requirements and timetable for developing a rule. Stakeholders were encouraged to provide input on key issues. Examples of topics discussed included existing GHG monitoring and reporting programs and lessons learned, thresholds for reporting, schedules for reporting, scope of reporting, handling of confidential data, data verification, and the role of states in administering t he program. As needed, the EPA technical workgroups followed up with these stakeholder groups on a variety of methodological, technical, and policy issues. EPA staff also provided information to tribes through conference calls with different Indian tribal working groups and organizations at EPA a s well as through individual calls wi th tribal board members of TCR. 13

13 For a full list of organizations EP A met with when developing this rule , please see the EPA docket memo, EPA

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- 4 On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting rule. EPA held two public hearings, and received over 16,000 written public comme nts. The public comment period ended on June 9, 2009. Subpart W received comments from over 80 entities with over 1

, 200 pages of comments, recommendations and alternatives for consideration.

In addition to the public hearings, EPA had an open door policy, similar to the outreach conducted during the development of the proposal. As a result, EPA met with over 4,000 people and 135 groups between proposal signature (March 10, 2009) and the close of the comment period (June 9, 2009). Details of these meetings are available in the docket (EPA

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2.1.5 Consideration of Public Comments on Key Reporting Issues
EPA considered public comments submitted to the docket and those presented at hearings as it finalized the reporting requirements. In the context of the April, 2010 p roposed r ulemaking process EPA held one public hearing and received over 40 substantive written public comments. Most comments supported changes made in the p roposed r ule published on April 9, 2010. However, various commenters expressed concern about t he inclusion of the Onshore Production
and Local Distribution segments and stated that the scope and cost burden of the proposal would
be significantly exceed the costs estimated by EPA. In addition, many commenters suggested changes in met hodology or quantification

, which EPA incorporated into the final rule. For example, consistent with several commenters’ re commendations, EPA has provide d flexibility in
the types of leak detection equipment required to monitor emissions

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

.
2.1.6 Analysis of Emissions from the Petroleum and Natural Gas Industry

For each o f the petroleum and natural gas system segments mentioned in Section 2. 2

, EPA compiled information on current cond itions in the segment , including information about existing monitoring equipment or reporting frameworks, estimated emissions of GHGs, and estimated productive capacity or throughput. Section 4 summarizes the i ncremental costs of measuring vented and equip ment leak GHG emissions and conducting reporting activities for Subpart W facilities

. Section 5 presents cost scenarios that vary the conditions of the reporting
rule for Subpart W with respect to the size of the entity required to report and the type of

m easurement required of the petroleum and natural gas segment . The scenarios specific to Subpart W are listed in Section 3. EPA also reviewed the benefits to stakeholders, including the public, the government, and industry, of a reporting system for petrole um and natural gas
emissions in a qualitative analysis. These benefits are outlined in Section 5

.2

- 5 2.2 Sources Considered
A technical subgroup on vented and equipment leak emissions considered the following sources of emissions from the petroleum and natural ga s industry, as shown in Table 2

- 1

. Using screening criteria based on the feasibility of monitoring, verifying, and measuring these sources, the technical subgroup developed reporting methodologies for the sources in Subpart W
iden tified in Table 2

- 2

.

Table 2

- 1 Sources of GHG Emissions Considered

Source Subpart W: GHG Emission Considered

Downstream

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

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

Equipment leaks : Emissions which are unintentional and could not reasonably pass through a stack, chimney, vent, or other functionally

- equivalent opening

. Examples include leaks from valves and connectors.

Flare combustion : Means unburned hydrocar bons 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 S egments

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 i mport & e xport t erminals Natural gas d istribution

2.3 How the Mandatory GHG Reporting Program Is Different from the Federal and State Programs EPA Reviewed
The various existing state and federal programs EPA reviewed are diverse. They have different thresholds, require different pollutants and different types of emissions sources to be reported, rely on different monitoring protocols, and require different types of data to be reported, depending on the purposes of each pr ogram. None of the existing programs require nationwide, mandatory GHG reporting by facilities in a large number of segment s, so EPA ’ s mandatory GHG rule is unique in this regard. The remainder of this section focuses on existing state and federal programs that apply to petroleum and natural gas systems covered under Subpart W

.
Although the mandatory GHG rule is unique, EPA carefully considered other Federal and State programs during development of the rule. Documentation of our review of GHG monitoring pro tocols for each source category used by f ederal, s tate, and international voluntary and mandatory GHG programs, and our review of State mandatory GHG rules can be found at
EPA

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- 056. The monitoring and GHG calculation methodologies for many source categories are the same as, or similar to, the methodologies contained in State reporting programs such as TCR, CCAR (California Climate Action Registry) , and State mandatory GHG reporting rules and similar to methodologies developed by EPA voluntar y programs such as Climate Leaders. Similarity in methods will help maximize the ability of individual reporters to submit the emissions calculations to multiple programs, if desired. EPA will continue to work closely with states and state

- based groups to ensure that the data management approach in this
rule will lead to efficient submission of petroleum and natural gas data to multiple programs.2

- 7 The intent of this rule is to collect a reasonable estimate of GHG emissions data that can
be used to inform fut ure policy decisions. One goal in developing the rule is to be consistent with the GHG protocols and requirements of other state and federal programs, where appropriate, in order to make use of existing cooperative efforts and reduce the burden to petroleu m and natural

gas facilities submitting reports to other programs. However, we also need to be sure the mandatory reporting rule collects facility

- specific vented and equipment leaks data of sufficient quality to achieve the Agency ’ s objectives. Therefore, some reporting requirements of this rule
related to petroleum and natural gas equipment leaks are different from ot her 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 Of fice of Atmospheric Programs in coordination with the Office of Transportation and Air Quality, is an impartial, policy

- neutral report that tracks annual GHG emissions. The annual report presents historical U.S. emissions of
CO 2 , CH 4 , N 2

The Inventory of U.S. Greenhouse Gas Emissions and Sinks is a comprehensive, top

down national assessment of national greenhouse gas emissions, and uses top

- down nati onal energy data and other national statistics. To achieve the goal of comprehensive national O, hydroflu o r o carbo ns , perflu o rocarbons , and sulfur hexaflu o ride

.

The United States submits the Inventory of U.S. Greenhouse Gas Emissions and Sinks to the Secretariat of the United Nations Framework Convention on Climate Change (UNFCCC) as an annual reporting requirement. T he UNFCCC treaty, ratified by the United States in 1992, sets an overall framework for intergovernmental efforts to tackle the challenge posed by climate change. The United States has submitted the GHG inventory to the United Nations every year
since 1993. The annual Inventory of U.S. Greenhouse Gas Emissions and Sinks is consistent with national inventory data submitted by other UNFCCC parties, and uses internationally accepted
methods for its emission estimates.

In preparing the annual Inventory of U.S. G reenhouse Gas Emissions and Sinks , EPA leads an interagency team that includes the DOE, USDA, the Department of Transportation (DOT), the Department of Defense (DOD), the State Department, and others. EPA collaborates with hundreds of experts representing more than a dozen federal agencies, academic institutions, industry associations, consultants, and environmental organizations. The Inventory of U.S.
Greenhouse Gas Emissions and Sinks is peer

- reviewed annually by domestic experts and by UNFCCC, and underg oes a 30

- day public comment period, and is peer reviewed annually by
UNFCCC review teams.2

- 8 emissions coverage for reporting under the UNFCCC, most GHG emissions in the report are calculated via activity data from national

- level databases, statistics, an d surveys. The use of the aggregated national data means that the national emissions estimates are not broken down at the geographic or facility level. In contrast, this reporting rule focuses on bottom

- up data and individual sources above appropriate thre sholds.

The Inventory contains estimates of vented emissions

, equipment leaks, and combustion emissions from petroleum systems and from natural gas systems, which are both IPCC source categories. Regarding the quantification of CH 4 emissions from natural gas systems, reductions achieved through the Natural Gas STAR program and National Emissions Standards for Hazardous Air Pollutants ( NESHAP ) regulations are included (see below for more details on these programs). A detailed study by the Gas Research Insti tute 14 and EPA (GRI/EPA 1996) is
used as the basis for estimates of CH 4 and non

- combustion

- related CO 2

14 Now the Gas Technology Institute emissions from the U.S. natural gas industry in the report.

For Petroleum and Natural Gas systems, EPA has been aware that there are a number of
areas whe re the 2008 U.S. Greenhouse Gas Inventory Report assumptions may substantially
underestimate actual emissions levels. The f inal r ule for Subpart W is estimated to significantly
increase the level of emissions covered than included in the 2008 U.S. Greenhou se 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 fro m the EPA Natural Gas Star website and assumptions based on expert judgment.

The f inal r ule for Subpart W will therefore help to improve the development of future
national inventories for Petroleum and Natural Gas Systems by improving the estimates of
emis sions and thereby advance the understanding of emission processes and monitoring methodologies. Facility, unit, and process level GHG emissions data for all sources will improve the accuracy of future U.S. Greenhouse Gas Inventory Reports by confirming the national statistics and emission estimation methodologies used to develop the top

- down inventory. The results can confirm shortcomings in the national statistics and identify where adjustments may be
needed.2

- 9 Therefore, although the data collected under th is rule will not replace the system in place to produce the comprehensive annual national Inventory, it can serve as a useful tool to better improve the accuracy of future national

- level inventories.

2.3.2 Federal Voluntary Greenhouse Gas Programs

EPA and other federal agencies operate a number of voluntary GHG reporting and reduction programs that EPA reviewed when developing this proposal, including several non

CO 2

2.3.2.1 Non

- CO 2 Voluntary Partnership Programs voluntary programs, and the DOE 1605(b) voluntary GHG registry. Several other federal voluntary programs encourage emissions reductions, clean energy, or energy efficiency; this summary does not cover them all (for additional information see Review of Existing Programs

, EPA

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- 054 ) . This summary focuses on programs that include voluntar y GHG emission inventories or reporting of GHG emissions reduction activities for sources that
were considered for inclusion in Subpart W of this f inal r ulemaking.

Since the 1990s, EPA has operated a number of non

- CO 2 voluntary partnership programs aimed at reducing emissions from GHGs such as methane, SF 6 , and PFCs. There are four
segment

- specific voluntary methane reduction programs: Natural Gas STAR, Landfill Methane Outreach Partnership (LMOP), Coalbed Methane Outr each Programs (CMOP), and Ag STAR. In addition, there are segment

- specific voluntary emissions reduction partnerships for high global warming potential gases. The program specific to those entities that fall under Subpart W is the Natural Gas STAR partners hip , which encourages companies across the natural gas and petroleum industries to adopt practices that reduce methane emissions. Industry partners voluntarily provide technical information on projects they undertake to reduce methane
emissions on an annua l basis, but they do not submit methane emissions inventories.

2.3.2.2 1605(b) Voluntary Registr y

The DOE Energy Information Administration ( EIA ) established a voluntary GHG registry under Section 1605(b) of the Energy Policy Act of 1992. The program was recently enhanced and a final rule containing general reporting guidelines was published on April 21, 2006 (71 FR 20784); the rule is contained in 10 CFR Part 300. Unlike EPA ’ s proposal, which requires reporting of greenhouse emissions from facilities over a specif ic threshold, the DOE 1605(b) registry allows anyone (e.g., a public entity, private company, or an individual) to report their emissions and their emissions reduction projects to the registry. Large emitters (e.g., anyone that emits over 10,000 metric ton s of CO 2 e per year) who wish to register emissions reductions must submit annual company

- wide GHG emissions inventories following technical guidelines2

- 10 published by DOE and must calculate and report net GHG emissions reductions. The program offers a range o f reporting methodologies from stringent direct measurement to simplified calculations using default factors and allows the reporters to report using the methodological option they choose. For the petroleum and natural gas industry, some methods for estima ting emissions are outlined, but this petroleum and natural gas section in the 1605(b) Technical
Guidelines is only meant to serve as a guide. Reporters can use established, published authorities’ estimation methods, which must be referenced. In addition, as mentioned above,
unlike EPA ’ s proposal, sequestration and offset projects can also be reported under the 1605(b) program. There is additional flexibility offered to small sources that can choose to limit annual inventories and emissions reduction report s to a single type of activity rather than reporting

company

- wide GHG emissions, but must still follow the technical guidelines. Reported data are made available on the Internet in a public use database.

2.3.2.3 Summary
These voluntary programs are different in na ture from the mandatory GHG emissions reporting rule. Industry participation in the programs and reporting to the programs is entirely voluntary. A small number of sources report, compared to the number of facilities that will likely be affected by Subpart W of the mandatory GHG reporting rule. Most of the EPA voluntary programs do not require reporting of annual emissions data, but are instead intended to encourage GHG reduction activities and track partners ’ successes in implementing such projects.

At th e same time, aspects of the voluntary programs serve as useful starting points for the mandatory GHG reporting rules. Greenhouse gas emission calculation principles and protocols have been developed for various types of emission sources by Climate Leaders, the DOE 1605(b) program, and some partnerships such as the SF 6 reduction partnerships and SmartWay. Under these protocols, reporting companies monitor process or operating parameters to estimate greenhouse emissions, report annually, and retain records to document their GHG estimates. Through the voluntary programs, EPA, DOE, and participating companies have gained understanding of processes that emit GHGs and experience in developing and reviewing GHG
emission inventories.

2.3.3 Federal Mandatory Reporting Prog rams

2.3.3.1 Toxics Release Inventory (TRI)
TRI requires facility

- level reporting of annual mass emissions of approximately 650 toxic chemicals. If they are above established thresholds, facilities in a wide range of industries report including manufacturing indu stries, the petroleum industry , and other industrial segment s.2

- 11 Facilities must submit annual reports of total stack and equipment leaks of the listed toxic chemicals using a standardized form which can be submitted electronically. No information is
reporte d on the processes and emissions points included in the total emissions. The data reported to TRI are not directly useful for the GHG rule because TRI does not include GHG emissions and does not identify processes or emissions sources. However, the TRI pro gram is similar to the GHG reporting rule in that it requires direct emissions reporting from a large number of facilities (roughly 23,000) across all major industrial segment s. Therefore, EPA reviewed the TRI program for ideas regarding program structure and implementation.

2.3.4 Other EPA Emissions Inventories

2.3.4.1 National Emissions Inventory
EPA compiles the National Emissions Inventory (NEI), a database of air emissions information provided primarily by state and local air agencies and tribes. The database contai ns information on stationary and mobile sources that emit criteria air pollutants and their precursors, as well as hazardous air pollutants. S tationary point source emissions that must be inventoried and reported are those that emit over a threshold amount of at least one criteria pollutant. Many states also inventory and report stationary sources that emit amounts below the thresholds for each pollutant. The point source NEI includes over 60,000 facilities. Required point source
information consists of fac ility identification information; process information detailing the types of air pollution emission sources, air pollution emission estimates (including annual emissions), control devices in place, stack parameters, and location information. The NEI differ s from the GHG reporting rule in that the NEI contains no GHG data, and the data are reported primarily by State agencies rather than directly reported by industries. However, in developing the rule, EPA used the NEI to help determine sources that might ne ed to report under Subpart W of the GHG reporting rule. We considered the types of facility, process and activity data reported in NEI to support the emissions data as a possible model for the types of data to be reporte d under the GHG reporting rule.

2.3.5 Stat e and Regional Voluntary Programs for Greenhouse Gas Emissions Reporting
A number of States have demonstrated leadership and developed corporate voluntary GHG reporting programs individually or joined with other States to develop GHG reporting

programs as part of their approaches to addressing GHG emissions. The following discussion summarizes two prominent voluntary efforts. In developing the greenhouse rules, EPA reviewed the relevant protocols used by these programs as a starting point. We recognize that these programs may have additional monitoring and reporting requirements than those outlined in the rule in order to provide distinct program benefits.2

- 12 2.3.5.1 California Climate Action Registry
The California Climate Action Registry (CCAR) is a voluntary GHG reg istry already in use in California. CCAR has released several methodology documents, including a general reporting protocol, general certification (verification) protocol, and several segment

- specific protocols. Companies submit emissions reports using a s tandardized electronic system. Emission reports may be aggregated at the company level or reported at the facility level. CCAR is transitioning out of entity emissions reporting, and 2009 will be the last year it accepts such reporting. Emissions reporting can instead be conduced under CCAR’s sister organization The Climate Registry (TCR), which is based off of CCAR’s work. A number of members of CCAR have already made the transition over to TCR.

2.3.5.2 The Climate Registry
The Climate Registry (TCR) is a partners hip formed by U.S. and Mexican states, Canadian provinces, and tribes to develop standard GHG emissions measurement and verification protocols and reporting system capable of supporting mandatory or voluntary GHG emission reporting rules and policies for i ts member states. TCR has released a final General Reporting Protocol that contains procedures to measure and calculate GHG emissions from a wide range of source categories. They have also released a general verification protocol, and an electronic reporti ng system. Several industry

- specific draft protocols have been released recently for public comment including Petroleum & Gas Exploration & Production Protocol and a verification protocol for this segment

. Founding reporters (companies and other organizati ons that have agreed to voluntarily report their GHG emissions) implemented a pilot reporting program in 2008. Annual reports will be submitted covering six GHGs. Corporations must report facility

- specific emissions broken out by type of emission source (e .g., stationary combustion, mobile combustion, process, equipment leak and indirect ) and gas (CO 2 , CH 4 , N 2 O, HFCs, PFCs
and SF 6 ) within each facility.

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

Several individu al States and regional groups of States have demonstrated leadership and are developing or have developed mandatory GHG reporting programs and GHG emissions control programs. This section of the preamble summarizes two regional cap

- and

- trade programs
and s everal State mandatory reporting rules , which cover, or for those programs still under development, have the potential to cover the petroleum and natural gas segment . We recognize that, like the current voluntary regional and State programs, State and regi onal mandatory reporting programs may evolve or develop to include additional monitoring and reporting2

- 13 requirements than those included in the rule. In fact, these programs may be broader in scope or more aggressive in implementation because the programs a re either components of established reduction programs (e.g., cap and trade) or being used to design and inform specific measures that indirectly reduce GHG emissions (e.g., energy efficiency).

2.3.6.1 Regional Greenhouse Gas Initiative
The Regional Greenhouse Gas Initiative (RGGI) is a regional cap

- and

- trade program that
covers CO 2 emissions from EGUs larger than 25 MW in member states in the Mid

- Atlantic and Northeast. The program goal is to reduce CO 2 emissions to 10% below 1990 levels by the year
2020. Certain types of offset projects will be allowed, and GHG offset protocols have been developed. The states participating in RGGI have adopted state rules (based on a model rule) to implement RGGI in each state. The RGGI cap

- and

- trade program took effect on January 1, 2009. There has been some discussion of regulating additional sources of GHG emissions under the RGGI program in the future.

2.3.6.2 Western Climate Initiative
WCI is another regional cap

- and

- trade program being developed by a group of Western
States and Canad ian provinces. The goal is to reduce GHG emissions to 15 percent below 2005 levels by the year 2020. Draft options papers and program scope papers were released in early 2008, public comments were reviewed, and final program design recommendations were mad e in September 2008. Other elements of the program, such as reporting requirements, market operations, and offset program development continue

. WCI released its final version of the first group of Essential Requirements for Mandatory Reporting (ERMR) in Ju ly 2009, and it is anticipated that WCI jurisdictions will have rules implementing these reporting requirements in place for the 2010 reporting year or shortly thereafter. Petroleum and natural gas production facilities are not listed in the first reportin g group, although petroleum refiners must report. Several source categories are being considered for inclusion in the cap and trade framework. One such category is “industrial process emission sources, including petroleum and natural gas process emissions 15

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

biological, and oth er non

- combustion processes. These emissions may be deliberate (e.g., vented), fugitive (e.g., leaked), or accidental. ,” meaning that sources covered under Subpart W of the Federal reporting rule may also be regulated under a future WCI program. The program might be phased in, starting with a few source categories and adding others over time. Points of regulation for some source categories, calculation methodologies, and other reporting program elements are under development. The WCI is also analyzing alternative or complementary policies other than cap

-2

- 14 and

- trade that could help reach GHG reduction goals. Options for rule implementation and for coordination with other rules and programs such as TCR are being investigated.

2.3.7 State Mandatory Greenhouse Gas Reporting Rules
Seventeen states have developed, or are developing, mandatory GHG reporting rules. 16

2.3.7.1 California Mandatory Greenhouse Gas Reporting Rule The docket for 40 CFR P art 98 (74 FR 56260, October 30, 2009) contains a summary of these state mandatory rules (EPA

- HQ

- OAR

- 2008

- 0508

- 056). Final rules have not yet been developed by some of the states, so details of some programs are unknown. Reporting requirements have already entered into effect in twelve states as of 2009; the rest will begin between 2010 and 2012. Reporting is typically annual, although some states require quarterly reporting for EGUs,
consistent with RGGI

.
State rules differ with regard to which facilities must report and which GHGs must be reported. Some states require all facilities that must obtain Title V permits to report GHG emissions. Others require reporting for particular segment s (e.g., large EGUs, cement plants, refineries). Some state rules apply to any facility with stationary combustion sources that emit a
threshold level of CO 2 . Some apply to any facility, or to facilities within listed industries, if their emissions exceed a specified threshold level of CO 2 e. Many of the state rules apply to s ix GHGs covered by 40 CFR Part 98 (CO 2 , methane, nitrous oxide, HFCs, PFCs, SF 6 ); others apply only
to CO 2 or a subset of the six gases. Most require reporting at the facility level, or by uni t or process within a facility.

The level of specificity regardi ng GHG monitoring and calculation methods varies. Some of the states refer to use of protocols established by TCR or CCAR, to industry

- specific protocols (such as methods developed by the American Petroleum Institute [API]), to accepted
international metho dologies such as IPCC, and/or to emission factors in EPA ’ s Compilation of
Air Pollutant Emission Factors (known a s AP

- 42) or other EPA guidance.

The mandatory reporting rule of the California Air Resources Board (CARB) is an example of a state rule that covers multiple source categories and contains relatively detailed requirements, similar to this proposal developed by EPA. The regulation became effective on January 2, 2009. According to CARB, selected fac ilities (e.g. general stationary combustion
facilities outside the petroleum

- and

- gas segment , and electricity generation and cogeneration plants not within the operational control of larger facilities and entities) are required to file their

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

New Jersey, New Mexico, North Ca rolina, Oregon, Virginia, Washington, West Virginia, and Wisconsin.2

- 15 first emission s data reports by April 1, 2009. The rest of the facilities and entities report by June 1, 2009 (see http://www.arb.ca.gov/cc/reporting/ghg

- rep/ghgschedadvisory.pdf ). The rule requires facility

- level reporting of all GHGs (except PFCs) from cement manufact uring plants, electric power generation and retail markets, cogeneration plants, petroleum refineries, hydrogen plants, and facilities with stationary combustion sources emitting greater than 25,000 metric tons
CO 2 per year. The California rule does not im pact those facilities that would be subject to reporting under Subpart W of the Federal reporting rule. Part 75 ( Acid Rain Program ) data will be used for EGUs. The regulation contains specific GHG estimation methods that are largely consistent with CCAR p rotocols, and also relies on API protocols and IPCC/European Union protocols for certain types of sources. California continues to participate in other national and regional efforts, such as TCR and WCI, to assist with developing consistent reporting tools and procedures on a national and regio nal basis.3

- 1 SECTION 3
D EVELOPMENT OF THE MA NDATORY REPORTING RU LE

To develop Subpart W of the Mandatory GHG Reporting Rule, EPA considered various dimensions of the reporting program and developed and evaluated several option s for each dimension. After a preliminary evaluation of the options for each dimension, a recommended reporting program alternative was selected. Several possible program alternatives were selected, generally by varying one dimension at a time, while retai ning the recommended option for the other dimensions. These alternatives were then evaluated based on estimated cost, cost

effectiveness (cost per metric ton of emissions reported), and estimated impacts on small entities. This process is discussed in grea ter detail below.

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

1. Thresholds : Based on the discretion in the language of the ap propriations bill that
calls for emissions reporting above appropriate threshold s in all segment s of the

economy , EPA has identified an appropriate threshold above which petroleum and natural gas facilities are required to report their GHG emissions. Types of t hresholds
considered were production or productive capacity, and emissions based.

2. Measurement Methodology : To be able to report their GHG emissions, facilities will be required to measure them using a n appropriate methodology. Generally,

measurem ent methodologies may be based on instrumentation and direct measurement, or on calculation methods based on other data available to the facility (e.g., activity data and emissions factors).

The options EPA considered for each dimension for Subpart W sourc es are discusse d
below and summarized in Table 3

- 1

. The table shows the combinations of options for specific
dimensions. EPA conducted cost analysis for the combinations marked by X ; the shaded box represents the final option

.3

- 2 T able 3

- 1 Options Considered in Developing Scenarios for Regulation under Subpart W ( Final Option Indicated by Shading)

Methodology Direct Measurement (CEMS) Hybrid: Direct spot measurement for major emissions sources and calculation method s for non

- major

sources Default emissions factors from EPA Threshold
Capacity

- based

Emissions based 1,000 MtC O 2 e X X X

Emissions

- based 10,000 M tCO 2 e X X X

Emissions

- based 25,000 M tCO2e X X X

Emissions

- based 100 ,000 M tCO2e X X X
Hybrid: 25,000 M tCO 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, emissions

- based thresholds, or a hybrid of the two. Within each option, various definitions and levels of the threshold were
examined. EPA also considered capacity

- based and hybrid threshold approaches in the preliminary phases of the a nalysis but did not include them in the final cost analysis. As explained below, EPA ruled out these two options based on data limitations and other challenges.

3.1.1.1 Option 1: Capacity

- based threshold
A capacity

- based threshold would be defined based on the em itting 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 mus t report their GHG emissions, but the data on source

- level capacity is not currently universally available to EPA.

3.1.1.2 Option 2: Emissions

- based threshold ( Selected )
Option 2 involves the use of actual facility

- level emissions of GHGs, measured in metric

tons of CO 2 - equivalent emissions ( M tCO 2 e). Various levels were considered, ranging from 1,0003

- 3 M tCO 2 e to 100,000 M tCO 2 e. Obviously, lower thresholds would require more facilities to participate in the reporting program. Given current data availability, an emiss ions

- based threshold will generally focus on larger, emissions

- intensive sources in the petroleum and natural

gas segment for which emissions data are readily calculate d or measured.

3.1.1.3 Option 3: Hybrid threshold
The hybrid threshold option is a combination o f three general groups: capacity, emissions, or entire source category ( “ All in ” ). The thresholds developed are generally equivalent to a facility

- wide threshold of 25,000 metric tons of CO 2 e per year of actual emissions. The preference is to establish thr esholds for as many source categories as possible based on a capacity metric, for example, tons of product produced per year. A capacity

- based threshold is least burdensome, because a facility would not have to estimate emissions to
determine if the rule a pplies. However, EPA faces two key challenges in trying to develop capacity thresholds. First, in most cases, especially involving equipment leak and vented
emissions under Subpart W

, data are insufficient to determine an appropriate capacity threshold.
Se condly, in many of the petroleum and natural gas segment s, the level of emissions from vented
and equipment leaks are not related to capacity or throughput. Rather, emissions may be driven by design and operating factors. As an example, pneumatic controls on petroleum and natural gas facilities are designed to vent natural gas to drive valve movements. The level of venting is not dependent on throughput.

3.1.2 Measurement Methodology
EPA identified three measurement methodology options, ranging from installing

em issions monitoring equipment on all sources under Subpart W to using default emissions factors to estimate emissions. The measurement methodology options considered for Subpart W

sources are discussed below.

3.1.2.1 Option 1: Direct measurement for all reporters

T his option would apply direct measurement requirements to all reporters. This would require facilities subject to Subpart W to use fuel flow meters for gaseous fuels and for spot measurement of vented emissions from various equipment. In addition, it would require spot detection and quantification of equipment leaks by use of calibrated bagging or high volume samplers throughout all segment s. This option was the selected option for the p roposed r ule for Subpart W (74 FR 164888, April 10, 2009)

.3

- 4 3.1.2.2 Option 2: H ybrid of direct measurement and facility

- specific calculation for other sources ( selecte d )

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

- specific calculations, which is considerably le ss burdensome than Option 1. Specifically, EPA requires the use of direct spot measurement where reliable
emissions factors do not exist and engineering calculations based on site

- specific information to estimate emissions from the largest emission source s. Other sources will be quantified through the use of leak detection and application of emissions factors for leaking equipment (i.e. “leaker” factors). Use of population count and default population emissions factors is required for smaller
and inaccessi ble sources.

Th e hybrid approach results in a significantly lower cost burden to reporting parties yet provides a much more robust development of GHG emissions. Unlike Option 3, which is
described below

, Option 2 will enable EPA to monitor year

- to

- year changes in emissions levels
from th e petroleum and natural gas source category

.
3.1.2.3 Option 3: Default emissions factor calculation for both combustion and process emissions
Under Option 3, EPA would require petroleum and natural gas facilities to base their

r eported emissions on simplified calculations performed at the facility level, based on EPA

provided default population factors combined with the type of process, production rate, and/or the quantit y of fuel/chemical inputs used.

3.2 Selected Option

As describe d above, EPA evaluated a variety of options for each dimension of the GHG reporting program, and selected a recommended o ption for each dimension. We summarize the
recommended option for each dimension below.

– Threshold : Emissions based approach

– For Subpart W sources, applicability is based on emissions. Emissions are the
sum of vented emissions and equipment leaks

, stationary and portable
combustion emissions , as well as emissions from any other source category covered by the finalized MRR that may be prese nt at the facility . A facility that emits 25,000 metric tons CO 2 e/year or more reports all sources for which
there are methods in the finalized MRR and final rule for subpart W

.3

- 5 – For several segment s in Subpart W, it was determined appropriate to require

t he threshold calculation by defining “facility” differently:

o For onshore petroleum and natural gas production , the facility is
defined as the equipment covered in the April, 2009 p roposed r ule and owned or operated by a single entity, as defined by the hol der of a drilling or operating permit, located in a hydrocarbon basin

. If a drilling or operating permit is not required, then the reporter is the entity that pays the taxes. EPA also analyzed the same facility definition, but as applied to a hydrocarbon f ield, as opposed to a hydrocarbon basin. As described in the Preamble, the threshold
determination and cost burden is required based on the basin level approach.

o For natural gas distribution a facility is defined as the local distribution company (LDC). Th erefore the threshold is based on total company
level emissions of the LDC.

– Methodology : Combination of direct measurement and source

- specific calculation methodologies

– For Subpart W final rule

, EPA is requiring the use of direct spot measurement
and/or en gineering calculations using site specific information to estimate emissions from the largest emission sources. In addition, sources which are smaller, or may be inaccessible to direct measurement will be quantified through the use of leak detection and ap plication of leaker emissions factors for leaking equipment. P opulation count and population emissions factors will
be used for smaller and inaccessible sources.

– Source

- specific calculation methods using facility

- specific information for
other sources in the finalized MRR present at the facility subject to the Subpart W final rule

.
3.3 Alternative Scenarios Evaluated
EPA developed alternative reporting scenarios and assessed the costs and emissions
associated with each. As part of the April 2009 proposal a lt ernative scenarios were developed by creating the recommended scenario (the shaded option 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 Subpart W final rule are listed below:

1. A 1,000 M tCO 2 e threshold; hybrid methodology

.
2. A 10,000 M tCO 2 e threshold; hybrid methodology

.
3. A 25 ,000 M tCO 2 e threshold; hybrid methodology

.
4

. A 100,000 M tCO 2 e threshold ; hybrid methodology

.
5

. A 25 ,000 M tCO 2 e threshold; d irect techniques (CEMS, flow meters , calibrated bagging, and high volume sampler ) are used to measure emissions

.

6

. A 25 ,000 M tCO 2 e threshold; d efault emissions factors (simplified methods) are used
to measure emissions

.
The evaluation of the alternative reporting scenarios will allow policy makers, regulated entities, and the general public to see the impact of each variation and assess their cost compared
to the required option. Total costs, emissions, and cost

- effectiveness of the alternative reporting
scenarios for the petroleum and natural gas industry pursuant to Subpart W are discussed in
Section 4.

3.4 Data Quality for This Analysis
EPA gathered existing data from EPA, industry trade associations, sta tes, and publicly available data sources (e.g., labor rates from the Bureau of Labor Statistics [BLS]) to characterize the processes, sources, segment s, and facilities affected. Costs were estimated based on the data collected and engineering analysis and models provided by EPA and its contractors. EPA staff and contractors provided engineering expertise, knowledge of existing facility
conditions and activities

, and an estimate of incremental activities required to comply with the rule. Existing models, suc h as EPA ’ s CEMS “continuous emissions monitoring system” cost model, were used for Subpart W to ensure consistency of cost inputs and assumptions.

The most important elements affecting the data quality for this analysis include the
number of affected faci lities in each source category, the number and types of production processes that emit GHGs, process inputs and outputs (especially for monitoring procedures that involve a carbon mass balance), and the measurements that are already being made for reasons
not associated with the subpart W final rule (to allow only the incremental costs to be estimated). The background information for standards development, often collected from petroleum and natural gas industry surveys, was supplemented from numerous source s, including industry3

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

. Information on measurements that are already made (and thus would not be associated with the rule) was obtained from discussions with industry representat ives, knowledge gained from previous site visits, and other sources. The data collected to characterize the facilities in Subpart W final rule are judged to be of good quality and the best that are publicly available.

Other elements affecting the quality o f the data include estimates of labor hours to perform specific activities, cost of labor, and cost of monitoring equipment. Estimates of labor hours were based on previous analyses of the costs of monitoring, reporting, and recordkeeping for other rules; information from the industry characterization on the number of units or process inputs and outputs to be monitored for Subpart W ; and engineering judgment. Labor costs were taken from the BLS and adjusted to account for overhead. Monitoring costs were gen erally based on cost algorithms or approaches that had been previously developed, reviewed, accepted as adequate, and used specifically to estimate the costs associated with various types of measurements and monitoring. The data quality associated with the se elements of the cost analysis is analogous to the quality of data used in the development of numerous other Information Collection Requests

.4

- 8 SECTION 4
ENGINEERING COST ANA LYSIS

4.1 Introduction

EPA estimated costs for each facility under Subpart W to comply with t he rule and report GHG equipment leaks and vented GHG emission s. EPA used available industry and EPA data to
characterize conditions at affected sources (i.e., affected facilities) . Incremental monitoring, recordkeeping, and reporting activities were then identified for each type of facility, and the
associated costs were estimated for Subpart W

. Table 4

- 1 present s the reporting and verification requirements for petroleum and natural gas systems

.

Table 4

- 1 Selected Reporting Thresholds and Reporting Requirements

Subpart (Source Category) Industry S egment Reporting and Verification

W

— Petroleum & Natural Gas Systems (§98.230) (1) Onshore
p roduction (2) O ffshore production (3) Natural ga s processing (4) Natural gas
t ransmission compression station (5) Natural gas underground storage (6) LNG storage (7) LNG import and export terminals (8) Natural gas distribution (a) Report a nnual emissions separately for each of the industry segment listed in (a)(1) through ( 8 ) below

. For each segment

, report emissions from each source type in the aggregate , unless specified otherwise. For example, an underground natural gas storage facility with multiple reciprocating compressors must report emissions from all reciprocating compressors as an aggregate number. (1) Onshore petroleum and natural gas production facilities; (2) Offshore petroleum and natural gas production facilities; ( 3 ) Onshore natural gas processing facilities ; ( 4 ) Onshore natural gas transmission compression facilities; ( 5 ) Underground natural gas storage facilities; ( 6 ) Liquefied natural gas storage facilities; ( 7) Liquefied natural gas import and export facilities; (8) Natural gas distribution facilities. R eport e ach source in the aggregate for pipelines and for Metering and Regulating (M&R) stations. (b ) Emissions reported separately for standby equipment; (c) Report a ctivity data for each aggregated sourc e type as follows: (1) Count of emissions sources. (2) Type of emissions sources. (3) Number of specified events per year or reporting period (such as blowdowns, well completions, etc.). (4) Control measures and other equipment. ( 5) Volume and flow rates. (6) Input parameters for simulation software , if required

. (7) Flared/vented/and equipment leak data. ( d ) Minimum, maximum and average throughput for each operation listed in industry segments (a)(1) through (8) above. ( e) For offshore petroleum and natural gas production facilities, the number of connected wells, and whether they are producing oil , gas, or both

. (f) Report emissions separately for portable equipment for the following source types: drilling rigs, dehydra tors, compressors, electrical generators, steam boilers, and heaters

. (1) Aggregate emissions by source type. (2) Report count of each source type.

Note: Many facilities that would be affected by the rule emit GHGs from multip le sources. The facility must assess every source category that could potentially apply to each when determining if a threshold has been exceeded. If the threshold is exceed ed for any source category, the facility must report emissions from all source cate gories, including those source categories that do not exceed the applicable threshold.4

- 9 4.2 Overview of Cost Analysis
The costs of complying with the rule will vary from one facility to another, depending on the types of emissions, the number of affected source s at the facility, existing monitoring, recordkeeping, and reporting activities at the facility, etc. The costs include labor and capital costs for performing the monitoring, recordkeeping , and reporting activities necessary to comply
with Subpart W . All c osts referred to in the EIA are in 2006 dollars.

There are two major emissions categories for which costs are determined. One is the cost to quantify process emissions, i.e., equipment leaks and vented emissions ; the other i s the cost to quantify the addit ional combustion

- related emissions for facilities that did not exceed the Subpart C threshold with only combustion emissions

. The total burden estimates presented for Subpart W
aggregate costs for process and combustion emissions above those covered by Sub part C alone.

W e first provide a general overview of baseline reporting and the two cost components
associated with this information collection

— labor costs (i.e., the cost of labor by facility staff to meet the information collection requirements of the ru le) and capital and operating and maintenance costs (e.g., the cost of purchasing and installing monitoring equipment or contractor costs associated with providing the required information). Additional details of the data, methods, and assumptions underlyi ng the costs are documented in this section.

4.2.1 Baseline Reporting

I n general , the Subpart W analysis assum es that none of the facilities in the covered
segments are currently reporting equipment leaks and vented emissions and that many of the requirements w ill result in “new” or “full” costs to meet reporting requirements. Specifically, we

assum e that there will be additional costs for any detection, sampling and testing requirements in
the methods used to quantify emissions from petroleum and natural gas so urces. We are also assuming that additional costs will be incurred for preparing monitoring and QA/QC plans, performing the calculations, reporting the results, and maintaining records. The only significant
element that we know reporters subject to Subpart W already gather is the measurements and records of consumption of raw materials

, such as feedstocks

, as part of their routine operation for accounting purposes.

4.2.2 Reporting Costs
Costs for Subpart W were developed based on assessments of all estimated cap ital and operations and maintenance costs to monitor, measure, detect and calculate the emissions sources
in all segment s of Subpart W. Key variables and data fields were clearly defined to ensure that
each segment developed costs around a standard set of methods and assumptions for Subpart W4

- 10 (e.g., method for annualization of capital costs, interest rate to be applied to capital). Cost estimates were developed for each threshold of emissions base d on the number of reporting entities in that threshold group and estimates of the specific capital and labor costs associated with conducting the emissions reporting.

Labor Costs . The costs of complying with and administering this rule include the time of managers, technical, and administrative staff in both the pr ivate segment and the public segment

. Staff hours are estimated for activities including :

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

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

– assuring and releasing data (public): staff hours to quality assure, analyze, and release reports.

Staff activities and associated labor costs may vary over time. Thus, cost estimates are developed for start

- up, first

- time reporting, and subsequent reporting.

Loaded hourly labor rates (also referred to as “wage rates”) were developed for several labor categories to represent the employer costs to use an hour of employees’ time in each of the manufacturing segm ent labor categories used in this analysis. The labor categories correspond to the job responsibilities of the personnel that are likely to be involved in GHG emissions monitoring activities at the petroleum or natural gas facility to comply with the rulem aking.

For purposes of this study, EPA adopted the methodology used by Rice (2002 ) to calculate the wage rates for the EPA’s Toxics Release Inventory (TRI) Program. Thus, the wage

rates calculated for different labor categories incl uded the employer costs for employee compensation (comprising the basic wages and the corresponding benefits) and the overhead

costs to the employer 17

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

computer hardware and software, telecommunication and other equipments, organ izational support, etc. ) required for and used b y the employee to effectively fulfill his/her job responsibilities. These costs are over and above the employee compensation costs. .
For each labor category applicable to Subpart W , the following formula was used to calculate the wage rat es:4

- 11 Loaded Hourly Labor Rate ($/hr.) = Basic Wages ($/hr.) * (1 + Benefits Loading Factor + Overhead Loading Factor).

The benefits loading factor corresponds to the relative share of benefits compensation in the total employee compensation (comprising bas ic wages and benefits). Although the benefits factor tends to vary by labor category and by industry (0.37 to 0.50), for purposes of this analysis, we have assumed the benefits loading factor to remain the same for each labor category
across all industries in the rule due to a lack of availability of necessary industry

- specific data on benefits paid to employees.

The overhead loading factor corresponds to the share of overhead costs to the employer relative to the total employee compensation. For purposes o f this analysis, we have also adopted the same overhead loading factor tha t Cody Rice (2002) used in her wage rate calculations. Thus the overhead loading factor that we used in the wage rate calculations remains the same for all labor categories and acros s all industry types in the rule . The overhead loading factor was
assumed to be 0.17.

For Subpart W, the combined “ Benefits and Overhead Loading Factor” used is 0.67, or an overall adjustment of 1.67 times “ Basic Wages

. ”

Capital and O&M Costs . This include s the cost of purchasing and installing monitoring equipment or contractor costs associated with providing the required information. Equipment costs include both the initial purchase price of monitoring equipment and any facility/process
modification that may be required. Based on expert judgment, the engineering costs analyses annualized capital equipment costs with the appropriate lifetime and interest rate assumptions.
The equipment life was set at five years for Subpart W sources with one

- time capital c osts
amortized at a rate of seven percent

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

4.3 Subpart W

— Petroleum and Natural Gas Systems

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

, onshore petroleum and natural gas production (including enhanced oil4

- 12 recovery, EO R), onshore natural gas processing, onshore natural gas transmission compression, onshore natural gas storage, LNG storage, LNG import and export and natural gas distribution

.
For each of the industry segments, with the exception of onshore production, ope rations had to be divided into single units or model facilities at three levels; “small,” “medium,” and “large.” The monitoring costs were then developed per size level of a model facility. A model facility of a given level can be defined as the most conve nient and logical unit with appropriate emissions source counts that can aggregate to any size company to determine its monitoring costs. For example, in natural gas transmission, a compressor station as a facility was modeled at
the three different model size levels. Any natural gas transmission company can determine its monitoring costs by assigning the model facility costs to its facilities that are closest to the appropriate level of the model facility. To determine the national cost from each segment, we assigned a model facility cost that best fit the facility based on its emissions profile. Next, we summed the costs assigned to each facility in the segment to produce t he total national cost in each segment

. Section 4.5 of this document describes the c alculation in further detail.

Facilities in onshore production, however, are defined as all petroleum or natural gas equipment associated with all petroleum or natural gas production wells under common ownership or common control by an onshore petroleum and natural gas production owner or operator located in a single hydrocarbon basin

, as defined by the American Association of Petroleum Geologists

. There is much larger variation in facility equipment by this definition, so developing model “small”, “medi um”, and “large” facilities for monitoring costs is unintuitive and impractical. In this case, non

- monitoring costs were estimated using the model facilities, but equipment monitoring costs were estimated at the national level and then apportioned to
indi vidual operators in basins by production rates.

Table 4

- 2 below provides a summary of the number of facilities that w ould have to report under the various thresholds analyzed for each of the industry segments covered by the rule

.4

- 13 Table 4

- 2 Number of Facilities Reporting by Threshold and Industry Se gment

.

Industry Segment Threshold

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

Onshore Production 8,169 1,929 981 385
Natural Gas Processing 566 396 289 130
Transmission Compressor Stations 1,695 1,443 1,145 433
Natural Gas Storage 347 200 133 36
Liquefied Natural Gas Storage 54 41 33 4
Liquefied Natural Gas Terminals 5 4 4 4

Offshore Production 1192 184 58 4
Local Distribution Companies 594 203 143 66

Labor Costs

. To evaluate labor costs, it was necessary not only to determine the amount of time required for all of the tasks associated with monitoring, but also to determine who will perform each task. For the sake of this analysis, four labor categories were used. Assigning labor hours for all cost elements was based on expert judgment. When assigning hours, the size of the facility and role of the labor categories were taken into consideration.

To estimate labor costs , it was assumed that all labor will be performed by middle managers, junior engineers, and senior operators. Middle managers are assumed to spend a total of 2 hours overseeing the monitoring process per quarter, but are assumed not to perform any of the monitoring. It was assumed that junior engineers and contracted technicians will do all of the monitoring, except in cases where senior operators will log any activity data required to estimate emissions over the course of the quarter. Several equipment types are common between diff erent onshore segments and different facility sizes, but the actual monitoring time typically will not change per equipment unit. For example, centrifugal compressor seals are found in all onshore
segments , except for natural gas distribution and onshore p roduction . Measuring centrifugal compressor seal degassing vents was assumed to take 1 hour and that will not change by segment or facility size. What changes is the number of centrif u gal compressors located at facilities of
different sizes . Thus, a series of universal assumptions about onshore monitoring times were4

- 14 created. These were multiplied by the emissions source counts assigned to each of the model facilities to determine the required labor hours. Once the labor hours were calculated, by category, f or each of the cost elements, they were multiplied by the associated labor rates to estimate labor costs per facility. For offshore monitoring costs were developed on a per platform
basis for non

- GOADS reporters based on expert judgment. The only remaining facility costs are due to the annualized capital costs and travel, lodging, and shipping to conduct the actual emissions monitoring.

Table 4

- 3 below presents labor cost numbers aggregated across all segment s for Subpart W. These data are aggregated from individual tables for each segment

. E xcept for onshore production, e ach segment has a table for small, medium and large facilities

.

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

- level labor hours, displayed in

Table 4

- 13

, to a national scale and then apportion ing them by individual operator production rates. This approach was c hosen over categorizing the operators by small, medium, and large because of the variety of operations present between operators in the onshore production segment. For this reason, the labor costs are not shown for the onshore production segment like in Table 4

- 3 and Table 4

- 4 . However, the average operational and maintenance costs for the onshore production segment are shown separately in the bullets below each table.

Capit al and O&M Costs

. The capital costs related to monitoring emissions and archiving of information consist of purchasing equipment for emissions detection (or the portion of contractor purchases of equipment is apportioned to all its customers), emissions me asurement, and information storage. All costs are reported in 2006 U.S. dollars and annualization was assumed over an equipment life of five years with a seven percent interest rate. Equipment leak monitoring does not have time

- tested standards and equipm ent leak streams typically are not clean gas. For example, a centrifugal compressor wet seal degassing vent will contain fine droplets of seal petroleum with the gas. A five

- year equipment life was chosen to be conservative in cost estimates, opposed to the ten

- year equipment life associated with long

standing, proven practices of measuring clean fuel streams assumed in the stationary combustion
section.

Table 4

- 4 shows the capital and operation and maintenance costs at the 25,00 0 metric ton
threshold for the aggregated Subpart W segment s , less onshore production. The disparity in first year capital costs stems from the fact that each of the onshore segments that use compressor s as4

- 15 part of normal operations are required to pay for a one

- time flow measurement port installation on compressor seal degassing vents and reciprocating rod packing vents

. This assumes that there will be no disruption in the operations since the port can be installed when the compressor is either in standby mode or under maintenance. Hence no adjustment is made for production or operational loss. First year labor costs include the labor required for registration, creating a monitoring plan, and general planning procedures that are required only in the first year of compliance. The “subsequent year” cost is a truer reflection of actual average costs over time

.

Combustion Costs

. C ombustion emissions occur in petroleum and natural gas systems primarily through natural gas used to drive compressor engines. Additi onal fuel is used to power drilling rigs (diesel) and for process heaters and boilers, glycol dehydrator s, and some acid gas
removal reboilers . Combustion emissions are included for the purposes of determining if Subpart
W thresholds are met, however combu stion emissions are reported separately under Subpart C for all industry segments, except onshore production

. Onshore production combustion emissions will be reported under Subpart W.

To estimate combustion emissions from compressor engines

— the primary com bustion application in Subpart W

— only one emission factor was required per facility because the natural gas used for combustion is taken from one pipe of common fuel quality. Consequently the cost for monitoring fuel quality is relatively small even if the re are multiple compressors at the facility.

Th is a nalysis includes the cost of incremental combustion reporting and combustion
emissions above those that exceed the Subpart C threshold alone and would therefore already be
have been report ed under Subpart C. The costs to monitor and report incremental combustion

related emissions were estimated based on the approach used under 40 CFR Part 98, Subpart C. 18

The Tier 1 approach bases estimates on a fuel

- specific default CO 2 emission factor, a default high heating value of the fuel, and the annual fuel consumption from company records.
EPA determined that entities that need to report incremental combustion

- related emissions, as
described above, would use the Tier 1 method as set forth in Subpart C; these entities would likely not meet the requirements for the Tier 2 or higher methods. Specifically, EPA applied the Tier 1 methodology to estimate the costs to monitor combustion
emissions that became subject to reporting as a result of today’s final rule.

18 40 CFR Part 98 used the IPCC Tier concept to estimate combustions emission s (74 FR 56260, October 30, 2009). See EPA

HQ

- OAR

- 2008

- 0508

- 0004, U.S. EPA, Technical Support Document for Stationary Fuel Combustion Emissions: Proposed Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more information about the IP CC Tier methodology (pgs 10

- 15).4

- 16 EPA b ased this conclusion on three considerations for applicability of the Tier 2 methodology and higher, as specified in Subpart C, to the petroleum and natural gas industry: (1) availability of high heating values (HHVs) for the fuels combusted at the frequen cy required by the Tier 2 methodology, (2) the maximum rated heat input capacity of the equipment, and (3) the type of fuel being combusted. First, in order to be required to use a Tier 2, units must have a rated heat input capacity less than or equal to 2 50 MMBtu/hr, combust a fuel found in Table C

- 1, and sample the HHV of the fuel consumed at the required frequency in Part 98.34(a). It was determined that this minimum required sampling frequency is not currently carried out at these
smaller units and the refore these units would not be required to use Tier 2 or higher. These units will generally follow Tier 1.

Second, Tier 3 and Tier 4 methodologies generally apply to equipment with a maximum rated heat input capacity greater than 250 MMBtu/hr. A 250 MM Btu/hr rating means that the emissions from that individual unit alone will be greater than 25,000 metric tons CO2e; these emissions would be subject to reporting under Subpart C even in the absence of Subpart W and therefore would not fall in the category of incremental combustion emissions considered in this analysis.

Third, the predominant fuels used in the petroleum and natural gas industry are produced natural gas, pipeline quality natural gas, distillate fuel, and any products recovered from equipmen t leaks and vents. Of these fuels, equipment using pipeline quality natural gas, distillate fuel, or products recovered from equipment leaks and vents are required to use Tier 2 or higher. As described above, if the unit has a rated heat

- input less than o r equal to 250 MMBtu/hr, then the unit probably does not currently receive HHV at the required frequency for a Tier 2 and could use a Tier 1. If the unit has a maximum rated heat input capacity greater than 250 MMBtu/hr, then as just noted, emissions from a unit of this size would already be subject to reporting and would not be included in the incremental combustion emissions category considered in this analysis. Finally, the use of produced natural gas is predominant in onshore petroleum and natural gas production. Under the final rule, reporters are allowed to use methods similar to Tier 1 for all combustion emissions sources that use produced natural gas. In sum, the use of Tier 1 costs for incremental combustion is a reasonable assumption.4

- 17 Table 4

- 3 Subpart W Petroleum and Natural Gas Systems: Labor Costs 1

Activity (2006$)

Estimated Labor Hours and Annual Labor Rates
Labor Cost per Year per Reporting Unit/Facility Senior Management Middle Management Junior Engineer/ or Technician Senior Operator ($101.31/hr) ($88.79/hr) ($71.03/hr) ($63.89/hr)

First Year Subseq. Year First Year Subseq. Year First Year Subseq. Year First Year Subseq. Year First Year Subseq. Year Planning 0.73 0.08 3.29 0.19 55.6 8 0.67 4.02 0.32 $ 4,578 $ 93 QA/QC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0 0 Recordkeeping 0.16 0.16 0.27 0.26 2.91 2.75 0.56 0.56 $ 283 $ 270 Sampling and analysis

(calculations) 0.00 0.00 1.83 1.83 97.70 6.80 1.11 1.03 $ 7,173 $ 711

Reporting 0.06 0.04 1.38 1.19 4.48 3.99 14.77 13.92 $ 1,390 $ 1,283
Total 0.95 0.28 6.78 3.48 160.77 14.21 20.46 15.82 $ 13,424 $ 2,357

1

Table 4

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

Estimated Onshore Production average Labor Costs per Year per Reporting Unit/Facility are $ 1 2

, 099 for the first year and $ 5

, 168 for the s ub sequent years.

1

Activity (2006$)

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

Capital

Cost Equipment Lifetime (years) Annualized Capital Cost

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

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

Performance testing n/a 2 n/a n/a n/a n/a n/a Recordkeeping $86 5 $21 n/a $21 $21

Trave l N/A n/a n/a $825 $825 $825

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

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

s ubsequent y ears. 2 Performance testing is not required under Subpart W therefore no costs are entered.4

- 18 Table 4

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

Activity Cost Categories Total Reporting Cost per Unit/Facility

Capital

Co st Equipment Lifetime (years) Annualized Capital Cost

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

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

Total $3,500 $500 $1,700 $2,200 $2,200

4.4 Summary Results: Subpart W

— Petroleum and Natural Gas Systems
For each segment in the petroleum and natural gas industry identified as amenable to a reporting program, four thresholds were considered for emissions reporting as applicable to an individual facility : 1,000 met ric tons of CO 2 equivalent ( M tCO 2 e) per year ; 10,000 mtCO 2 e ; 25,000 mtCO 2 e ; and 100,000 mtCO 2 e. A threshold analysis was then conducted on each segment to determine which level of threshold was most suitable for each industry segment. CH 4 , CO 2 , and N 2 O emi ssions from each segment were included in the threshold analysis.

Table 4

- 6 shows the number and share of entities and emissions covered by the f inal r ule

. The table shows that a t lower thresholds

, a higher number and share of facilities and emissions are covered by the rule. As the threshold increases, smaller numbers and shares of facilities and
emissions are affected. Of significant note, 8 5 percent of emissions are covered at the selected 25,000 metric ton CO 2 e threshold , bu t only 9 percent of facilities need to report

. Further, both
total emissions and covered emissions include incremental combustion emissions , i.e. those not triggered by the threshold of Subpart C alone.

Table 4

- 6 Subpart W Facilities and Emissions Covered by Final Rule

Threshold Number of Entities Number of Facilities Covered Percent of Facilities Covered Total Emissions (Million M tCO 2 e ) Covered Emissions (Million M tCO 2 e ) Percent of Emissions Covered Ye ar) Year) 1,000 Threshold 30,241 12,622 42% 396 391 99% 10,000 Threshold 30,241 4,400 15% 396 362 91% 25,000 Threshold 30,241 2,786 9% 396 337 85% 100,000 Threshold 30,241 1,062 4% 396 273 69%4

- 19 Detailed Threshold Analysis. For each segment, a thresho ld analysis was conducted to determine how many of the facilities in the segment exceed the various reporting thresholds, and the total emissions from these facilities. This analysis was conducted considering vented and equipment leaked CH 4 and CO 2 emissio ns, 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. However, the emissions estimates for four source s

— well venting for liquids unloading, gas wel l venting during well completions, gas well venting during well workovers, and centrifugal compressor wet seal degassing ventin g

— from the U.S. GHG Inventory were replaced with revised estimates , which are described in Appendix B of the TSD

.

Combustion emi ssions from processing, transmission, underground storage, LNG storage, and LNG import and export terminals were estimated using gas engine methane
emissions factors available from GRI/EPA 1996 , back calculating the natural gas consumption in engines, and finally applying a CO 2 emissions factor to the natural gas consumed as fuel. N 2 O emissions were calculated similarly. In the case of offshore petroleum and natural gas production platforms combustion emissions are already available from the GOADS 2000 stud y analysis and hence were directly used for the threshold analysis. In addition to gas engines, combustion emissions from reboilers on glycol dehydrators, acid gas removal amine regeneration, diesel engines on drilling rigs, and heater

- treaters were estim ated for onshore production. The volume of fuel gas required by regular operation of a glycol dehydrator was calculated per volume of dehydrator input; then the API Compendium combustion emission factors for natural gas were applied to facilities’ fuel ga s use based on their gas production rates. The same assumptions were made to calculate combustion emissions from acid gas removal amine regeneration heaters. Drilling rigs were assumed to operate two 1,500

- horsepower diesel engines per well drilled, and assuming it requires 90 days to drill and complete any well . The API Compendium combustion emission factors for diesel engines were used to calculate the emissions. The total drilling
emissions for the nation were calculated based on the number of drilli ng rigs in service, then apportioned to each basin by throughput.

T he threshold analysis for the rule includes equipment leak , vented, and combustion
emissions and requires estimation of all emissions at a facility level. As a result, the total
emission s from the threshold analysis do not necessarily match the U.S. GHG Inventory for all segments of the petroleum and natural gas industry. A detailed discussion on the threshold analysis is available in the TSD ( EPA

- HQ

- OAR

- 200 9

- 0923 ).

The general rationale for selecting a reporting threshold is to identify a level at which the incremental emissions reporting between thresholds is the highest for the lowest incremental4

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

m aximum emissions reporting coverage with minimal burden on the indust ry.

Table 4

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

t hreshold. The first five columns report subsets of costs, including c osts associated with processes (labor, annualized capital, and operating and maintenance costs), costs associated with stationary combustion , and costs associated with reporting and recordkeeping

. The final four columns report total national costs and tota l per

- entity costs for the first year and for subsequent

years.

T able 4

- 7 S ummary of National Costs and Costs per Representative Entity by Threshold (Million 2006 $ )

Threshold ( M tCO 2 e/yr) First Year Process Costs Subsequent Year Process Costs 1 First Year Combus tion Costs 1 Subsequent Year Combus tion Costs First Year National

Costs First Year Repre sentative

Entity Cost Subsequent Year National

Costs Subsequent Year Representative

Entity Cost 1,000 $112.3 $46. 4 $23.9 $23.9 $136.2 $0.011 $70.3 $0.006 10,000 $53.0 $20.9 $6.6 $6.6 $59.6 $0.014 $27.5 $0.006 25,000 $40.1 $15.1 $3.3 $3.3 $43.4 $0.016 $18.4 $0.007 100,000 $23.1 $7.7 $0.9 $0.9 $24.0 $0.023 $8.6 $0.008

1

**•** Initial start

- up costs include labor and capital associated with establishi ng modifications to enable ongoing quantification of key emissions sources. This includes costs to install measurement ports in compressor and well vents

. Reporting and Record

- keeping c osts are included in Process Costs

. Note that year one costs are significantly higher than the subsequent year average costs. This is due to the following reasons:

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

sources is updated every two years

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

four . As described in Table 4

- 7 above , at lower thresholds, a larger number of facilities in each subpart are covered by the rule, and thus incur costs. For this reason, the total national costs, and total costs by cost subset, decline as the threshold increases from 1,000 M tCO 2 e to 10,000

M tCO 2 e, to 25,000 M tCO 2 e, and finally to 100,000 M tCO 2 e. Cost per representative entity for a particular segment generally declines for Subpart W as the threshold increases.4

- 21 Reporting Determination

. While the cost estimates for representative entities are assumed to capture the reporting determination bur den

— i.e., burden of estimating emissions to determine whether they exceed the reporting threshold

— they do not account for the reporting determinations made by facilities that fall below the threshold. EPA has therefore estimated the burden for reporting d eterminations made by these facilities in order to better reflect the rule’s
total economic burden.

EPA plans to develop screening tools and expects most facilities to use them to make a reporting determination. As a first step, facilities would enter b asic activity data

, such as well count and drilling activity

, into the tool to roughly assess whether they exceed the threshold . The screening results should allow most facilities to make their determination. However, s ome of the facilities may have to t ake steps in addition to the screening tools to determine if they have to
report. For example, facilities that estimate emissions close to the reporting threshold may want to conduct preliminary monitoring to better determine their emissions. Such facilit ies may also
conduct preliminary monitoring in subsequent years to determine whether emissions in those years meet or exceed the reporting threshold

.

Of the 30,241 facilities in the petroleum and natural gas industry, approximately 2,786
facilities would l ikely meet the threshold and have to report. The remaining 27, 455 facilities are expected to be below the reporting threshold and would likely use the screening tool to make this reporting determination. In addition, 296 of the 27, 455 facilities could hav e emissions close to threshold and may supplement the screening tool analysis with some preliminary monitoring to determine whether or not they need to report ; these 296 facilities are also assumed to conduct preliminary monitoring to make a reporting dete rmination in subsequent years.

F acilities are required to follow methodologies in the rule to make a determination. The costs for this activity are outlined below

.
Planning costs assumed to include:

**•** 2.5 hours for regulatory review

**•** 2 hours to understand what operations information is required

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

**•** 14 hours to conduct preliminary monitoring4

- 22 Recordkeeping and reporting costs assumed to include:

**•** 1 hour to use screening tool(s) and to review and repor t data

Using the labor costs presented in Section 4.5.1

, the cost of the reporting determination
would be $ 573 per facility. The additional cost for those entities close to, but not exceeding the
threshold , to conduct preliminary monitoring is $1,034. Table 4

- 8 provides a summary of the
determination costs by industry segment and threshold level

.

Table 4

- 8 Summary of Reporting Determination Costs per Segment by Threshold (2006$ in t housands )

Segment Year Thresh old s (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 Fi rst Year $56 $232 $292 $379 Subsequent year $9 $58 $43 $19

LNG storage First Year $4 $17 $26 $55 Subsequent year $2 $2 $2 $2

LNG import & export terminals First Year $13 $55 $68 $140 Subsequent year $0 $0 $0 $0

Natural gas distribution First Year $921 $1,276 $1,330 $1,406 Subsequent year $133 $47 $32 $28

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

4.5 Detailed Cost Assumptions: Subpart W

— Petroleum and Natural Gas Systems
The assumptions below are the basis for the determination of the costs noted in this s ection

. 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 lev els; “small,” “medium,” and “large.” The monitoring costs were then developed per size level of a model facility. A model facility of a given level can be defined as the most convenient and logical unit with appropriate4

- 23 emissions source counts that can agg regate to any size company to determine its monitoring costs. For example, in onshore natural gas transmission, a compressor station as a facility was modeled at the different levels. Any transmission company can determine its monitoring costs by assigning model facility costs to its facilities that are closest to the appropriate level of the model facility. Facilities in onshore production, however, are defined as operators reporting all equipment covered at the basin

- level. There is much larger variatio n in facilities’ equipment by this definition, so developing model “small,” “medium,” and “large” facilities is unintuitive and impractical for estimating monitoring costs . In this case, non

- monitoring costs were estimated using the model

- facility method and monitoring costs were estimated at the national level and then apportioned to individual operators in basins by production rates.

For each of the sources designated for monitoring, both equipment and component counts
were determined to define individua l model facilities , except as noted in onshore production

. For onshore natural gas processing, onshore natural gas transmission, underground natural gas storage, LNG storage

, import and export facilities and natural gas distribution

, equipment and

componen t counts for medium facilities were assigned the national average activity factors from the National Inventory , or the nearest reasonable integer value

. In some cases, t he uncertainty
associated with the activity factors were used to determine the lower bo und on equipment and
component counts, and assigned to a “small” facility. Similarly, the upper bound on emissions source counts was assigned to a “large” facility. If illogical values, such as in the case of compressors in natural gas transmission compre ssor stations, resulted from the above methodology; expert judgment was used to correct the values; bounding the aggregated activity levels to that of the national inventory. In the case of offshore petroleum and natural gas production, MMS GOADS

- 2000 data analysis by EPA was used in the same fashion as the national inventories. In some cases, the uncertainty estimates were not applicable. For example, if the uncertainty is over 100%, it would predict a negative lower bound for emissions source
counts. For these cases, expert judgment was used. Expert judgment was also used, where necessary, to adjust emissions source counts to reflect real world scenarios. Both equipment and component counts at facilities by segment and size are presented in the docket (EPA

- HQ

- OAR

200 9

- 0923 )

STEP 2: Determine Cost Elements
The total costs associated with complying with the April, 2009 p roposed r ulemaking were broken into five elements, each of which is described below. Additionally, these cost
elements are considered in two ways: costs associated with start

- up and recurring cost s. Startup
costs refer to a one

- time cost associated with initiating the reporting process. Subsequent costs4

- 24 for reporting on an annual basis are less than the startup costs and are referred to as recu rring

costs.

1. Regulation compliance determination costs

a. Start

- up costs consist entirely of the labor necessary to study and review the regulations to assure compliance, gather data on the facility, and fill out any appropriate forms.

b. Recurring cost s will be small and consist entirely of labor expenses. Small amounts of time will be required for the company to stay aware of any updates to regulations and to alter the facility information to reflect any new equipment or facilities brought into operati on or taken offline.

2. Monitoring costs

a. Start

- up monitoring costs consist of both labor and capital costs. Capital investment will be required for purchasing monitoring equipment. This capital cost will be accounted as annualized cost, on an annual bas is. Labor will be required for product research for monitoring instruments before actual purchase. Before actual monitoring takes place, labor will have to be devoted to the development of a monitoring plan that will be used company

- wide. Finally,
selected employees will be trained on how to use the monitoring equipment.

b. Recurring monitoring costs consist of labor, travel, and shipping of equipment. Each cycle, labor will be required to conduct detection and quantification of emissions, i.e., perform act ual monitoring of emissions. Quantification may take place through direct measurement, use of engineering calculations and/or software, use of “leaker” emission factors for detected leaks, or use of component
counts and population emission factors. For com panies with multiple facilities, travel may be required for the monitoring team and/or the monitoring instruments may require shipping to multiple locations.

3. Reporting costs

a. There will be no start

- up reporting costs; reporting costs are applied unifo rmly

across segments reporting to the rule.4

- 25 b. Recurring reporting costs consist of labor necessary to document collected
emissions data from equipment leak monitoring and to submit the official report in each cycle (i.e., annually).

4. Archiving and recor dkeeping costs

a. Start

- up archiving and recordkeeping costs consist of labor and annualized capital purchase of storage space. For archiving reports and associated working documents, physical storage system such as a file cabinet, and electronic storage

s ystem such as an external hard drive, will be required.

b. Recurring archiving and recordkeeping costs consist entirely of labor necessary to adequately archive each cycle’s report and associated working documents.

5. Auditing costs

a. There is no start

- up cost associated with auditing.

b. Recurring auditing costs consists of labor required to validate to the EPA results from the monitoring of emissions and the follow

- up of rectifying any weaknesses found through the audit. The EPA audit is assumed to occur once in several years,
not on an annual basis.

STEP 3: Analyze Proportion of Facilities in Different Model Facility Levels
To classify the facilities into different sizes, total combustion

, equipment leaked, and
vented CO 2 , N 2 O, and CH 4 emissions from i ndividual facilities, expressed in CO 2 e, were rank listed in an ascending order. Cumulative emissions for the facilities were calculated by summing the emissions of the individual facility to those of the facilities before it in the ascending list . The

cum ulative emissions, in combination with the total emissions from all facilities, were used to assign facilities to the small, medium, and large category.

** **  ** **  ** ** 

**=** ions TotalEmiss Emissions Cumulative Percentile (%)

The facilities that accounted for the first 33% of the emissions nationally in the ranked list were identified as a small facility. The facilities that accounted for national emissions greater
than 33 percent but less than 67 percent in the ranked list were identified as a medium facility.
The facilities that accounted for national e missions over 67 percent in the ranked list were4

- 26 identified as a large facility. Table 4

- 9 indicates the data source s used to apportion total GHG
emissions to individual facilities , and the number of facilities that fall into each category per segment.

STEP 4: Assigning Costs to Cost Elements
Assigning costs to each of the cost elements was completed in three steps:

1. Determine labor categories and associated labor rates,

2. Allocate responsibilities to labor categories to estimat e labor hours, and

3. Determine annualized capital costs and operation & maintenance (O&M) costs for each of the cost elements.

These steps are described in further detail below.4

- 27 Table 4

- 9 Allocation of Facil ities to Model Types

Segment Data Source Small Facilities Medium Facilities Large Facilities

Offshore Petroleum and Natural Gas Production Facility Percentile MMS GOADS Report & Lasser 2006 0

– 33% 34%

– 67% 68%

– 100%

Facility Count MMS GOADS Report & La sser 2006 3

, 036 191 8

Mean Emissions ( MtC O 2 e) This Analysis 1

, 430 22,733 483,806 Operator/Company 1 Not estimated

Onshore Petroleum and Natural Gas Production 2
Facility Percentile HPDI 2006 0

– 33% 34%

– 67% 68%

– 100% Facility Count HPDI 2006 22,27 5 19 4 41 Operator/Company HPDI 2006

— — — Mean Emissions ( MtC O 2 e) This Analysis 3,98 8 451, 120 2,17 0

, 820 Onshore Natural Gas Processing Facility Percentile API Processing Report 0

– 33% 34%

– 67% 68%

– 100% Facility Count 3 API Processing Report 486 6 4 1 6 Operator/Company API Processing Report 166 28 10 Mean Emissions ( MtC O 2 e) This Analysis 36, 486 275, 823 1,137,595

Onshore Natural Gas Transmission Facility Percentile FERC 0

– 33% 34%

– 67% 68%

– 100% Facility Count FERC 1,314 374 255 Operator/Company FER C 147 46 27 Mean Emissions ( MtC O 2 e) This Analysis 2 1,293 98,738 210,829 Natural Gas Underground Storage Facility Percentile EIA 0

– 33% 34%

– 67% 68%

– 100% Facility Count EIA 325 50 22 Operator/Company EIA 102 37 17 Mean Emissions ( MtC O 2 e) This Analys is 12, 404 82, 199 183, 936 LNG Storage Facility Percentile GTI 0

– 33% 34%

– 67% 68%

– 100% Facility Count GTI 141 1 2 4 Operator/Company GTI 141 11 3 Mean Emissions ( MtC O 2 e) This Analysis 20,972 55,340 223,275 LNG Import and Export Facility Percenti le FERC

— 0

– 100%

— Facility Count FERC

— 5

— Operator/Company Not estimated Mean Emissions ( MtC O 2 e) This Analysis

— 174,643

— Natural Gas Distribution Facility Percentile DOT 0

– 33% 34%

– 67% 68%

– 100% Facility Count DOT 1,36 0 50 1 7 Operator/Com pany DOT 1,268 49 164

- 28 Mean Emissions ( MtC O 2 e) This Analysis 5,840 167,066 536,719

Notes:

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

platforms and their respective operators.

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

were assigned on a small, medium large basis; however, the majority of the recurring O&M costs were determined by apportioning natio nwide costs by individual operator throughput.

3

4.5.1 Determining Labor Categories

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

To evaluate labor costs, it was necessary to not only determine the amount of time required for all of t he tasks associated with monitoring, but also to determine who will perform each task. For the sake of this analysis, five labor categories were used, as shown in Table 4

- 10

.

Table 4

- 10 Labor Categories and Hourly Rates

Labor Category Description Loaded Hourly Rate Senior Manager Oversees work at a high level. Is the final authority on all reporting requirements. $101.31/hour

Middle Manager Oversees j unior e ngineer’s progress and reports; also interacts with s enior m anager . Does not gather information, write reports, or perform monitoring. $88.79/hour

Junior Engineer Conducts monitoring of emissions sources. Interfaces between middle m anager and s enior o perator to collect informat ion and complete reports. $71.03/hour

Senior Operator Primarily interfaces with j unior e ngineer to collect facility information and assist with initiating the reporting process and reporting. Sometimes logs data used in the monitoring process. $63.89/hour

Technician Contracted by the company to perform basic leak detection activities. $ 55.20 /hour

1

These labor rates originate from an analysis of loaded hourly rates for goods and producing private establishments at the end of 2007, shown in

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

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

Table 4

- 11 below . Since the petroleum and natural gas industry pays comparatively high to other industries, the top four non

lawyer categories were used to be conservative in this approximation. Specifically, the labor rate of senior managers were assumed to be that of refinery mangers, middle manager labor rates were assumed to be that of electricity managers, junior engineer labor rates were assumed to be that of industrial managers, senior operator labor rates were assumed to be that of refinery4

- 29 engineer s/technicians , and contracted technician labor rates were assumed to be that of industrial engineer/technician category

.

Table 4

- 11 Loaded Hourly Rates for Goods Producing Private Establishments

Labor Categor y Loaded Hourly Rate ($/hour) Electricity Manager $88.79 Refinery Manager $101.31 Industrial Manager $71.03 Lawyer $101.00 Electricity Engineer/Technician $60.84 Refinery Engineer/Technician $63.89 Industrial Engineer/Technician $55.20 Administrative Support $29.65

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

- Compensation Cost Trends,

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

4.5.2 Al locating Responsibilities
Assigning labor hours for all cost elements was based on expert judgment. When assigning hours, the size of the facility and role of the labor categories were taken into
consideration. Table 4

- 12 summariz es these roles

.

Table 4

- 12 Responsibilities for Regulation Compliance by Labor Category

Cost Element Senior Management Middle Management Junior Engineer Senior Operator Per Facility/ Per Company 1
Facility da ta 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 P er 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 revie w 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 t he 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 facility4

- 30 Data documentation To review the reporting documentation To prepare and comple te 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 report s To archive the reporting documentation To archive the reporting documentation Per facility

Audit To review the audit results To review the audit results To assist and provide information on EPA audits Per facility

Audit follow

- up To review the audi t follow

- up results and
approve corrective

measures To review the audit follow

- up results and review corrective

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

1

The labor costs associated with performing the actual annual monitoring were omitted
from the table above. For these costs it was ass umed that all labor will be performed by middle managers, junior engineers, senior operators , and contracted technicians

. The assumed responsibilities and associated hours are organized in Some activit ies only have to be done at the company level, with information and/or equipment shared among facilities of the company.

Table 4

- 13

. Additionall y, s everal pieces of equipment are common among different onshore segments and different facility sizes, but the actual monitoring time typically will not change per equipment unit. The series of universal assumptions about onshore monitoring times are als o provided in

Table 4

- 13 Responsibilities for Monitoring and Allocation of Labor Hours

Element Onshore Responsibilities by Labor Category and Hours per Responsibility
Detection Quantification Applicable Se gments Onshore Facility Equipment Leaks Senior Operator Count large, major pieces of equipment (0.5 minutes / equipment) Onshore Production

Processing Facility Equipment Leaks
Technician Conduct equipment leak detection survey (8 hours/ small facility , 12 hours/ medium facility, or 16 hours/large facility) Processing4

- 31 Junior engineer Estimate emissions using leaker factors (2 hours/facility) Processing

Middle Management Oversee part of the detection process and review results (1 hour/reporting perio d) 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 resu lts (1 hour/reporting period) Oversee part of the measurement process and review results (1 hours reporting period) Transmission

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

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

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

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

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

Middle Management Oversee part of the detection process and review results (2 hours/reporting period ) Oversee part of the measurement process and review results (1 hour/ reporting period) LNG Import and Export Facilities

LNG Storage Facility Equipment Leak
Technician Conduct equipment leak LNG Storage4

- 32 detection survey (12 hours/ small facility, 19 hours/ medium fa cility, and 24 hours/large facility) Junior engineer Estimate emissions using leaker factors (2 hours/ small facility, 2 hours/ medium facility, and 3 hours/ large facility) LNG Storage

Middle Management Oversee part of the detection
proce ss 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/
sta tion) 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 pr ocess 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) Transm ission, Storage, LNG Storage, LNG Import and Export Facilities Junior engineer Apply emission factors or leaker factors (time accounted for by facility equipment leaks quantification) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities

Reciprocating Compressor Rod Packing Emissions

Maintenance Team One time labor cost to install port for hotwire anemometer ($1000 / compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities
Technician Check packing open

- ended lines for emissions (10 minutes/ compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities
Technician Measure rod packing emissions ( 10 minutes / compressor) Processing, Transmission, Storage, LNG St orage, LNG Import and Export Facilities Junior engineer Calculate rod packing emissions ( 30 minutes / compressor) Processing, Transmission, Storage, LNG Storage, LNG Import and Export Facilities Centrifugal Compressor Equipment Leaks4

- 33 Technician Check un it for equipment leak s (1 hour/ compressor) Processing

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

Technician Check unit for equipment leak s (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

U nconventional Well Completion and Workover Junior engineer Measure flowback from completion or workover (8 hours/ field) Onshore Production

C onventional Well Completion and Workover Junior engineer Ask completion or workover contractor for time of ven ting (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 (1 0 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 S tacks > 400 thousand cubic feet Senior operator Collect data collection ( 10 minutes/dehydrator vent ) Onshore Production

, Processing Junior engineer P erform simulation runs (1 5 minutes/dehydrator vent) Onshore Production

, Processing Junior engineer A ccounted for in station Transmission, Storage4

- 34 equipment leak s

– certain portion of time is assumed to be for engineering estimation of sources Dehydrator Vent Stacks <400 thousand cubic feet Senior operator Count dehydrator ( 0.5 minutes/dehydrator vent ) Onshore Production

, Processing
Wellhead Equipment Leaks Junior engineer Apply emission factor

– accounted for in station equipment leaks Onshore Production, Storage

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

Junior engineer Collect dat a 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

N atural 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
popu lation emission factor

– time accounted for in station equipment leaks Distribution

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

Associated Gas Venting and Flaring Junior engineer Perform emissions calculation with GOR measurement (1 hour/ well) Onshore Production

Natural Gas Pneumatic Bleed Devices Junior engineer Determine high bleed or low bleed from manufacturer and apply appropriate population factor ( 10 minutes/pneumatic de vice) 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 ap propriate population factor ( 10 Transmission, Storage4

- 35 minutes/pneumatic device)

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

Junior engin eer Apply emission factor

– accounted for in station equipment leak s Onshore production

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

Table 4

- 13 does not include equipment monitoring on offshore petroleum and natural gas production facilities. Offshore production pla tforms are proposed to use data already collected for MMS GOADS to estimate greenhouse gas emissions from their operations. Specifically, the MMS GOADS program requires the monitoring of GHG emissions from platforms in the Gulf of
Mexico Federal waters

. Facilities under this f inal r ulemaking are required to report the same emissions data calculated by the GOADS Program. Hence these platforms have minimal additional reporting burden. The cost burden model assumes that this requires 30 minutes per platform

.
However, platforms that are in State waters or in Federal waters outside the Gulf of Mexico, GHG emissions will have to be estimated using the MMS GOADS procedures. EPA estimates the reporting cost for non

- GOADS platforms to be $5,000 for first year of reporting.

Once the labor hours were calculated, by category, for each of the cost elements, they were multiplied by the associated labor rates to estimate labor costs per facility. The only remaining facility costs are due to the annualized capital costs and travel, lodging, and shipping to conduct the actual emissions monitoring.

4.5.3 Capital Cost Annualization and O&M Costs
The capital costs related to monitoring emissions and archiving of information consists of purchasing equipment for emissions detection, emissions measurement, and information storage. All costs are reported in 2006 U.S. dollars and annualization was assumed over an equipment life of 5 years with a 7% interest rate. From these factors, a capital recovery factor of 24% was calculated using the formula provided below:4

- 36 1 ) 1 ( ) 1 (

**− +**  **+**

**=** n n

r r r CRF

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

years. Table 4

- 14 below summarizes the annualized capital costs associated with the monitoring program. Additionally, the table describes the annual costs of travel, lodging, and shipping

— the only other non

- labor costs related to the monitoring program.

Table 4

- 14 Monitoring Program 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 from Office DepotTM ($140), and 1 hard drive for data storag e from SeagateTM ($95) $57

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

Equipment purchase Screening equipment in the distribution segment is represented by a nominal $10,000 cost for a laser emissions detector . It is assumed to be purchased by the local distribution companies over t he 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

anemome ter 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 1

1

As shown in Annual travel costs are highly variable depending on the facility type, proximity, and ownership structure. Annual travel cos ts are estimated to vary from $0 to $ 10

, 449

.

Table 4

- 14 , the equipment leaks and vented emissions detection methods vary depending on the size of the company and its facilities. In the case of companies with small operations and few facilities, the costs passed on by contractors will be spread over many facilities

.4

- 37 Each facility is assumed to purchase an adequate flow meter to measure the emission rates from compressor seal vents either at the pipe end

, if accessible, or a flow measurement port installed at a suitable location capturing all ve nt emissions

.
With the equipment costs per company determined, the final step was to divide company capital and O&M costs amongst individual facilities owned by a typical company.

Step 3 above provided the proportion of facilities that fall in the small, medium, and large categories. By determining the companies that fall in the three categories, the average number of “small,” “medium,” and “large” facilities per company was determined. To convert the annualized capital costs and equipment purchases, the c osts per equipment were attributed to the number of facilities that can be serviced (as determined the number of labor hours required to monitor a facility) each year , as shown in the equation below:

** **  ** **  ** ** 

**÷ **  ** **  ** **  ** **  ****

**× =**  Contractor Serviced Facilities
Contractor t ofEquipmen Equipment tal AnnualCapi Facility tal AnnualCapi # $ $

The travel, lodging, and shippin g costs associated with monitoring several facilities spread over large regions were calculated using the assumed costs in Table 4

- 14 . Expert judgment based on the number of teams using equipment and the necessity of travel versus shipping between facilities was used to determine these costs.

STEP 5: Estimate per Facility Costs for Each Threshold Level
The total reporting costs across each segment were determined by assigning model facility costs (small, medium, and large) to indiv idual facilities in the respective industry
segments based on relative size and determining total costs from the entire segment. This was done for only those facilities that exceeded the reporting threshold. Average cost per facility was then determined by dividing the total segment costs by the number of facilities that exceeded the reporting threshold

— small, medium, and large . In the case of onshore production, field

- level monitoring costs were aggregated to the total national burden, then distributed t o operators at the
basin

- level based on production rates.5

- 1 SECTION 5
SUBPART W ANALYSIS OF REPORTIN G RULE OPTIONS

For petroleum and natural g as systems, Subpart W , as shown in Table 5

- 1 , the total cost of the reporting rule to the privat e s ector is estimated to be $ 61

. 8 million in the first year and $ 19.0 million in subsequent years (2006$). These estimates inclu de costs for reporters to monitor and report emissions and the costs for non

- reporters to make a reporting determination. Of the costs to report emissions meeting or exceeding the threshold, e quipment leaks and vented
emissions are $ 40.1 million in year one and $ 15.1 million in subsequent years. The estimates are based on the selected option for the final rule , which includes an a nnual emissions

- based threshold of 25,000 metric tons CO 2 e for each facility and a hybrid of direct measurement and

source

- specific calculation methodologies. Section 3.2 provides more details about the selected option.

EPA estimates that for Subpart W, t he public sector burden is about $ 1. 1 million per year. Approximately $ 0. 46 million per year is f or verification activities, and about $ 0. 66 million per year is for program implementation and developing and maintaining the data collection system. Program i mplementation activities include, but are not limited to, developing guidance and training materials to assist the regulated community, responding to inquires from affected facilities on monitoring and applicability requirements, and developing tools to as sist in determining applicability. In addition to total national costs for petroleum and natural g as systems, we also report average cost per metric ton to support additional analysis of the mandatory reporting programs. These cost s are also shown on Table 5

- 1

.

The first year costs are higher due to initial program start

- up costs , in particular the investment to secure equipment and inst all flow measurement ports in vent lines to allow

measurement

. Initial year costs are also high er because reporters are required to quantify various key sources (well liquids unloadings, well workovers, compressor wet seal degassing vents, etc) in the first year ; t hese sources are only required to be estimated bi

- annually to mitigate long term
burde n. 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 M tCO 2 e $/Mt $Million Million M tCO 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 1 $19.01 337.4 $0.05 1 Public Sector, Total 2 $1.1 337.4 $0.003 $1.1 337.4 $ 0.003 TOTAL $62.9 337.4 $0.1 3 3 $20.11 337.4 $0.0 5 3
Note:
1 Excludes reporting determination for non

- reporters; b ased on cost to report process and combustion emissions ( $43 million in first year, $18 million in subsequent years ).
2 Source: EPA
3

T here is a notable reduction in rep orting cost compared to the April, 2010 proposal . The cost reduction resulted from changes such as provid ing floors on several emissions sources (e.g., tanks, dehydrators, and compressors ) ; simplified requirements for sampling and gas composition analysis ; use of alternative leak detection equipment in some cases ; and use of equipment

- based
emission factors instead of component

- based emission factors

. A slight decrease in the emissions expected to be reported also accounted for the lower cost estimate. Th e slight decrease in reported emissions resulted from data corrections in the transmission and LNG storage
segments and use of different well property databases in onshore production.

Excludes reporting determination for non

- reporters; based on public sector cost plus private sector cost to report process and combustion emissions ($44 million in first year, $19 million in subsequent years).

Table 5

- 2
summarizes these c hanges based on year 1 costs for equipment leaks and vented emissions and
Table 5

- 3 summarizes these changes based on subsequent year costs for equipment leaks and
vented emissions.5

- 3 Table 5

- 2 Equipment Leaks and Vented Emissions Costs, Petroleum and Natural Gas Systems , First Year Estimates

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

Apr. 2009 Proposed

Rule Apr. 2010 Proposed

Rule Final Rule Apr. 2009 Proposed

Rule Apr. 2010 Proposed

Rule Final Rule Apr. 2009 Proposed

Rule Apr. 2010 Proposed

Rule Final Rule

Original Six Segments 85
1 94.3 78.7 $32.5 $26.7 $ 26.2 $0.38 $0.28 $0.33

Onshore Production n/a 154.9 152 .4 n/a $27.7 $ 11.9 n/a $0.18 $0.08

Local Distribution n/a 22.7 22.7 n/a $1.6 $ 2.0 n/a $0.07 $0.09

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

1

Table 5

- 3 Equipment Leaks and Vented Emissions Costs, Petroleum and Natural Gas Systems , Subsequent Year Estimates Offshore production, natural gas processing, natural gas transmission, underground natural gas stora ge, LNG storage; LNG import/export.

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

Apr. 2009 Proposed

Rule Apr. 2010 Proposed

Rule Final Rule Apr. 2009 Proposed

Rule Apr. 2010 Proposed

Rule Final Rule Apr. 2009 Proposed

Rule Apr. 2010 Proposed

Rule Final Rule

Original Six Segments 85
1 94.3 78.7 $28.1 $11.8 $8.7 $0.33 $0.13 $0.11

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

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

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

1 Offshore production, natural gas processing, natural gas transmission, underground natural gas storage, LNG storage; LNG import/export.5

- 4 5.1 Evaluating Alternative Options for Implementation of the Rule
The selected option was evaluated based on a cost

- effectiveness analysis. For example, in selecting the emissions threshold, we compared the incremental emissions reported with the incremental costs (associated with the change in the facilities that would be required to report their emissions). Similarly, in selecting the reporting methodology option, we compared the change in uncertainty with the change in costs associated with different emission measurement/estimation techniques. The metrics used and the results of the cost

- effectivenes s analysis are discussed below.

In addition, the f inal r ul e requires the determination of onshore reporting to be done assuming that reporting parties report emissions and for onshore production, determine threshold on a basin level. In other words, owners or operators in the onshore production segment must

repor t based on total emissions in all petroleum and natural gas production fields in a defined basin. EPA also examined an option to require onshore production companies to report on a field level basis. This alternative would affect the total emissions report ed as well as cost, and is
evaluated below.

Six alternative options were therefore evaluated for this analysis. While we believe these alternatives represent the most likely variations in the selected option, we recognize that in some cases particular inte rests may wish to evaluate more nuanced alternative options. To maintain transparency in the analysis, data necessary to conduct further alternative option analyses can be
found in Section 4 of this document.

5.1.1 Analysis of Alternative Threshold Options

The t hreshold determines the number of entities required to report GHG emissions under Subpart W of the rule. The higher the threshold, the more entities that are excluded. It is assumed that the per

- unit/entity cost does not change at different thresholds so t hat changes in the national cost estimates are driven by the number of reporting entities. The per

- unit/entity costs outlined in
Section 4 for Subpart W facilities , along with the estimates of numbers of covered entities at various thresholds, form the bas is for this analysis. Two metrics are used to evaluate the cost

effectiveness of the emissions threshold. The first is the average cost per metric ton of emissions reported. The second metric for evaluating the threshold option is the marginal cost of addi tional reported emissions ($/ metric ton CO 2 e ) relative to the option adopted in the f inal r ule. To compute this metric, we compute the change in emissions reported by lowering or raising the threshold and divide this by the change in total reporting costs. Table 5

- 4 provides the cost

effectiveness analy sis for the various thresholds.5

- 5 Table 5

- 4 Summary of Threshold Cost

- Effectiveness Analysis (First Year): Selected Hybrid Option is 25,0 00 metric tons CO 2 e

Threshold (Mt CO 2 e) 1

Facilities Required to

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

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

1
The an alysis shows a cost reduction of $ 0.28 per metric ton by moving from the selected threshold of 25,000 metric ton s CO 2 e to a higher threshold (100,000 metric ton s) ; the total emissions covered decrease significantly

— about 1 6 percent. Similarly, moving the threshold from 25,000 to 10,000 the difference increases $0.73 per metric ton and the emissions captured by increase 6 percent . Finally, lowering the threshold from 25,000 to 1,000 yields the highest
increase in cost difference ( $1. 73 per metric ton ), and increases the percentage of covered emissions by approximately 1 4 percent . Si milar data is pre sented for subsequent years in

Cost difference relative to 25,000 metric ton threshold

Table
5

- 5

.

Table 5

- 5 Summary of Threshold Cost

- Effectiv eness Analysis (Subsequent Years)

Threshold (Mt CO 2 e) Facilities Required to

Report Total Costs (million 2006 $ / year) Downstream Emissions Reported ( M illion M tCO 2 e ) Percentage of Total Downstream

Emissions Reported Average Reporting Cost (2006 $/Mt ) Cost Differential 1 (2006 $/Mt ) 1,000 12,622 $71.60 391 99% $0.18 $0.99 10,000 4,400 $29.48 362 91% $0.08 $0.44 25,000 2,786 $18.43 337 85% $0.05 $0.00 100,000 1,062 $9.61 273 69% $0.03 ($0.14) 1 Cost difference relative to 25,000 metric ton thre shold

Table 5

- 6 summarizes costs to report process and combustion emissions for all segment s

at four thresholds.5

- 6 Table 5

- 6 Subpart W Cost Estimates by Threshold

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

The select ion decision weighed the marginal cost of capturing additional emissions with the percentage of emissions needed to accurately estimate national GHG emissions. This is
shown in Figure 5

- 1 , which illustrates the total average cost per metric ton and the marginal cost

per metric ton for Subpart W as a function of the percentage of total emissions reported.5

- 7 Figure 5

- 1 Average Cost and Cost Differential per Metric Ton of Emissions Report ed 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 Monitor ing Method Options
Each monitoring technique for which reporting costs were estimated for Subpart W in
Section 4 was assumed in the burden analysis to provid e the same estimate of total emissions by reporting facility. However, the methods proposed for monitoring emissions will differ in their precision in estimating actual emissions. Therefore, the gain from increasing the cost of monitoring is to have more p recise estimates of facility emissions. The methods considered for determining emissions ranged from applying average industry parameters (referred to as “population emission factors,” or “default parameters”) to material inputs or throughputs, to the

use of direct measurement techniques . In this section, we evaluate the change in cost and change in accuracy for two alternative monitoring options for Subpart W . Generally speaking, under one of the alternatives, population factors would be used in lieu of di rect measurements and facility

level estimates, and in the other option, direct measurements are required for all sources. We use
the term direct measurement and “ population factors ” as shorthand to describe alternative options. For Subpart W, population e mission factors and component count is the basis for
“default factors”. Estimated costs for each monitoring method are shown in Table 5

- 7

.

For Subpart W

, the di rect measurement option greatly expands to use direct measurement
of a ll vented and equipment leak sources. This is the methodology used in the April, 2009

p roposed r ule . The costs associated with this case in the April, 2009 p roposed r ule (which did not include the onshore production and natural gas distribution ) resulted i n Subpart W incurring 19%
of the total costs in the MRR to monitor and measure only 3% of the emissions.

These costs were re

- estimated for the entire petroleum and natural gas segment in the
final rule. These costs involve the use of direct measurement tec hniques, including metering of all vents, calibrated bagging or use of high volume samplers to measure equipment leaks and inaccessible leaks, and so on. These costs involve additional equipment as well as significantly higher labor costs. If the same dire ct measurement techniques were required in this rule, the costs would be particularly high for the new onshore production and natural gas distribution segments.

The overall costs for the direct measurement option are about $100 million (annually) higher th an the selected option.5

- 9 Table 5

- 7 Analysis of Alternative Monitoring Methods

Direct Measurement (DM) Selected Option (Hybrid Approach) Population Factors

Segment First Year (million 2006 $ ) Subsequent Years (million 2006 $ ) First Year (million 2006 $ ) Subsequent Years (million 2006 $ ) First Year (million 2006 $ ) Subsequent Years (million 2006 $ ) Subpart W

— Petroleum and Natural Gas Systems $294.6 $126.9 $43.39 $18.43 $27.6 $17.4

For the “population facto r” option, Subpart W sources were assumed to have emissions quantified entirely by the application of emissions factors developed by the Gas Research Institute and EPA (GRI/EPA 1996) as the basis for estimates of CH 4 and non

- combustion

- related
CO 2 emission s. These factors are used with a population count of equipment and components to
arrive at a “ population factor ” cost estimate. The reduction in cost from the selected Hybrid Approach for this option is significant, with first year costs declini ng by $ 15

. 8 million, and subsequent year costs declining by $ 1.0 million.

5.1.2.1 Monitoring Method Uncertainty

The use of direct measure ment methods would provide the most certain quantific ation of Subpart W emissions , assuming that measurements were taken using consistent monitoring protocols across reporters

. If emission sources are measured as estimated in the burden analysis, there should be a high certainty level in the emissions quantified. However, b ased on the analysis above, the costs to gather and quantify these em issions would be very high.

The use of population based factors would result in a significantly lower burden, although the certainty level of the emissions determination would be very poor. Population

- based factors
determine the potential for emissions as suming a percentage of known components which may leak based on previous (and dated) studies.

The final rule required option of using leak detection and a hybrid of spot direct measurement, engineering estimates, leaker emission factors, and population ba sed factors (for inaccessible sources) provides an emissions estimate with significantly more certainty than population based factors at a more reasonable burden.

5.1.3 Sensitivity of Subsequent Year Cost Estimates

National cost estimates for the f inal r ule 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 all entities subject to Subpart W bear a single first

- year cost and then repeated subsequent

- year costs.

However, in reality, over time some existing facilities close or go out of business and

new facilities come into existence. This is sometimes ref erred to as entry and exit in an industry.
This may affect the cost of the rule because as entities “turn over” the new entrants presumably
will bear first

- year costs that are slightly higher than subsequent year costs.

The largest contribution to non

- rec urring first

- year costs for Subpart W compliance is for
flow measurement port installation in compressor seal vent lines. When a company goes out of business and sells its assets to either a new or existing business, these ports will already be installed; so much of the first

- year compliance costs will not apply to a company acquiring an already

- reporting facility. The remainder of first

- year costs that do not repeat is due to labor associated with reviewing the regulation and planning accordingly for com pliance. These costs will not be necessary when an existing company, which already reports, acquires a reporting facility from a failing business. Only in the case of a new business entity acquiring an existing

or new reporting station will these reviewi ng and planning first

- year labor costs be necessary.

The reviewing and planning costs are minimal in comparison to the significant other first year costs of reporting for Subpart W, therefore the impact of business transitions on rule reporting costs for Subpart W are assumed minimal.

5.1.4 Summary of Alternative Options for Onshore Facility Definition

The final rule specifies that onshore petroleum and natural gas producers will report for
each hydrocarbon basin. A basin is as identified by the American Associ ation of Petroleum Geologists three

- digit Geologic Province Code. The reporters will be owners or operators in a basin. However, EPA also considered an alternate option to define a facility at a field level. One such definition is available from the Energy Information Administration Petroleum and Gas
Field Code Master. The f ield

- level option would require aggregation of emissions by owners or operators at a field

- level to apply the threshold. Table 5

- 8 and Table 5

- 9 below show a detailed emissions coverage and burden to reporter that would have been expected under a fiel d

- level facility definition.5

- 11 Table 5

- 8 Emissions C over age and E ntities R eporting for F ield L evel F acility D efinition (Onshore Production)

Threshold Level Emissions Covered Facilities Covered
M illion Metric ton s CO 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

- 9 Equipment Leaks, Vented , and C ombustion E missions C ost for F ield L evel F acility D efinition (Onshore Production)

Threshold

Level Equipment Leak and Vented Emission Costs (2006$) Combustion Emission Costs (2006$)

Year 1 Costs Subsequent Year Costs Year 1 Costs Subsequent Year Costs

Annualized Capital Cost O&M Cost Annualized Capital Cost O&M Cost Annualized Capital Cost O&M Cost Annualized Capital Cost O&M Cost

1,000 $57.3 $7,274 $57.3 $3,069 $500 $1,700 $500 $1,700
10,000 $57.3 $8,855 $57.3 $3,834 $500 $1,700 $500 $1,700
25,000 $57.3 $10,334 $57.3 $4,549 $500 $1,700 $500 $1,700
100,000 $57.3 $14,963 $57.3 $6,622 $50 0 $1,700 $500 $1,700

Figure 5

- 2 presents a comparison of average costs (years 1, 2, and 3) and emissions coverage at
different thresholds for the field

- and basin

- level options. Specifically, it shows that the field

level option would result in a significantly lower coverage in emissions reported

— 57 percent at
field

- level versus 85 percent at the basin

- level for a 25,000 metric tons CO 2 e threshold. In addition, the cost to report under the field

- level definition is higher t han under the basin

- level definition at all thresholds, except at 100,000 metric tons C O 2 e threshold, at which field

- level is
lower. However, emissions coverage at the 100,000 CO 2 e threshold under a field

- level definition is very low

— 42 percent. Finally, t he number of entities reporting at a 25,000 metric tons CO 2 e threshold for basin level definition is lower at 9 81 in comparison to the 1

, 157 entities reporting
for a field

- level definition.

Figure 5

- 2 Summar y of Basin vs

. Field Decision5

- 12 0.13 0.76

0.04 0.07 0.24

0.07 0.05 0.03

- 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

30% 40% 50% 60% 70% 80% 90% 100% 110% Percent of Total Onshore Emissions 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 will have a significant impact on a substantial number of small entities (SISNOSE) u nder Subpart W . To m ake this determination, EPA used a screening analysis that allows us to indicate whether EPA can certify the rule as not having a SISNOSE. The elements of this analysis included

– identifying affected entities under Subpart W

,

– selecting and describing the me asures and economic impact thresholds used in the analysis, and

– determining SISNOSE certification category.

5.2.1 Identify Affected Segment s and Entities

The affected entities covered by the rule were identified during the development of the cost analysis for th e reporting rule. The Statistics of U.S. Businesses ( SUSB ) data provide s national information on the distribution of economic variables by the size of entity

. These data were developed in cooperation with, and partially funded by, the Office of Advocacy of the Small Business Administration (SBA) (SBA, 2008a). The data include the number of
establishments ( Table 5

- 10 ), employment ( Table 5

- 11 ), and receipts ( Table 5

- 12 ) and present
information on all entities in an industry covered by Subpart W of the rule; however, many of these entities would not be expected to report under the selected option because they would fall5

- 13 below the 25,000 hybrid threshold. SUSB also provides this data b y enterprise employment size.
The census definitions in this data set are as follows:

– Establishment : An establishment is a single physical location where business is conducted or where services or industrial operations are perfo rmed.

– Employment : Paid emplo yment consists of full

- and part

- time employees, including salaried officers and executives of corporations, who were on the payroll in the pay period including March 12, 2002. Included are employees on sick leave, holidays, and vacations; not included are proprietors and partners of unincorporated businesses.

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

– Enterprise : An enterprise is a business organization consisting of one or more domestic establishments that were specified under common ownership or control.
T he enterprise and the establishment are the same for single

- establishment firms.
Each multi

- establishment company forms one enterprise

— the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all
associated establishments.

Because the SBA’s business size definitions (SBA, 2008c) apply to an establishment’s “ultimate parent company,” we assume in this analysis that the “enterprise” definition above is c onsistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses and the terms are used interchangeably. We also report the SBA size standard(s) for each industr y group in order to facilitate

compar isons and different thresholds.5

- 14 Table 5

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

SBA Size Standard (effective March 11,

2008) Total Estab

lish

ments Owned by Enterprises with:

Industry NAICS NAICS Description 1 to 20 Employees 20 to 99 Employees 100 to 499 Employees 500 to 749 Employees < 500 Employees 750 to 999 Employees 1,000 to 1,499 Employees

Onshore petroleum and

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 211 Crude Petroleum and Natural Gas Extraction 500 7,629 5836 456 292 60 6,584 64 31

O nshore natural gas

transmission; underground natural gas storage ; LNG storage; LNG import and export 486210 Pipeline Transportation of Natural Gas 1

, 936 b 81 27 61 36 169 2 20

Natural gas distribution 221210 Natural Gas Distribution 500 2

, 897 483 86 131 68 700 33 73

a The Census Bureau defines an enterprise as a business organizati on consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single

- establishment firms. Each multi

- establishment company forms one enterprise

— the enterpri se employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment o f all associated establishments. Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcem ent Fairness Act (SBREFA) screening analyses.

b The SBA size standard for NAICS 486210 is $7 million in average annual receipts.5

- 15 Table 5

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

SBA Size Stan dard (effective March 11,

2008) Total Employees Owned by Enterprises with:

Industry NAICS NAICS Description 1 to 20 Employees 20 to 99 Employees 100 to 499 Employees 500 to 749 Employees < 500 Employees 750 to 999 Employees 1,000 to 1,499 Employees

Ons hore petroleum and

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 211 Crude Petroleum and Natural Gas Extraction 500 88

, 280 19

, 336 12

, 113 11

, 656 2

, 421 43

, 105 3

, 551 1

, 061

Onshore natural gas

transmissi on; underground natural gas storage; LNG storage; LNG import and export 486210 Pipeline Transportation of Natural Gas 37

, 450 b 347 157 1

, 053 1

, 934 c c c

Natural gas distribution 221210 Natural Gas Distribution 500 86

, 890 1

, 956 1

, 899 4

, 398 1

, 960 8

, 420 2

, 63 1 5

, 014

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that wer e specified under common ownership or control. The enterprise and the establishment are the same for single

- establishmen t firms. Each multi

- establishment company forms one enterprise

— the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment o f all associated establishments

. Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we a ssume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typ ically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.

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

c The U.S. Census Bureau has missing data for this employee range.5

- 16 Ta ble 5

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

SBA Size Standard (effective March 11, 2008) Total Receipts ( $M illion) Owned by Enterprises with:

Industry NAICS NAICS Description 1 to 20 Employees ($ thousands) 20 to 99 Employees ($ thousands 100 to 499 Employees ($ thousands) 500 to 749 Employees ($ thousands) < 500 Employees ($ thousands) 750 to 999 Employees ($ thousands) 1,000 to 1,499 Employees ($ thousands)

Onshore petroleum and

natural gas production; offshore petroleum and natural gas production; onshore natural gas processing 211 Crude Petroleum and Natural Gas Extraction 500 $ 160,879 $ 7,573 $ 6,7 90 $ 9,60 9 $ 4,60 9 $ 23,972 $ 3,991 $ 2,805

Onshore natural gas

transmission; undergro und natural gas storage; LNG storage; LNG import and export 486210 Pipeline Transportation of Natural Gas $ 35,897 b $ 1,035 $ 106 $ 394 c c $ 2,566 c c c

Natural gas distribution 221210 Natural Gas Distribution 500 $ 67,275 $ 2,524 $ 4,642 $ 2,878 $ 865 $ 13,127 $ 2,1 16 $ 3,757

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that wer e specified under common ownership or control. The enterprise and the establishment are the same for single

- establishm ent firms. Each multi

- establishment company forms one enterprise

— the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment o f all associated establishmen ts. Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we a ssume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is t ypically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.

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

c The U.S. Census Bureau has missing data for this employee range. The recei pts for the one to 20 range therefore underestimate true value.5

- 17 5.2.2 Develop Small Entity Economic Impact Measures

Because Subpart W covers businesses, the analysis generated a set of sales tests (represented as cost

- to

- receipt ratios) 19

These sales tests examine the average establishment’s total annualized mandatory reporting costs to the average establishment receipts for enterprises within several employment categories for NAICS codes associa ted with the affected Subpart W segment s. Although the appropriate SBA size definition should be applied at the parent company (enterprise) level, data limitations allowed us only to compute and compare ratios for a model establishment for eight enterprise size ranges (i.e., all categories, enterprises with 1 to 20 employees, 20 to 99 employees, 100 to 499 employees, 500 to 749 employees, less than 500 employees, 750 to 999 employees, and 1,000 to 1,499 employees ) . This approach allows us to account for dif ferences in establishment receipts between large and small enterprises and differences in small business definitions across affected Subpart W industries. It is also a conservative approach, because an establishment’s parent company (the “enterprise”) may have other economic resources that could be used to cover the costs of the reporting program. It must be noted that the 1,000 to 1,499 employee category does not belong to the small business category. However, the category has been included to provide a co mparison with small business

cost

- to

- receipt ratios.

20 Table 5

- 13

(first year co sts: ; subsequent year costs: Table 5

- 14 ). The average entity costs used to compute the sales test are the same across all of these enterprise size categories. As a result, the sales

- test will o verstate the cost

- to

- receipt ratio for establishments owned by small businesses, because the reporting costs are likely lower than average entity estimates provided by the engineering c ost analysis.

19 The following metrics for other small entity economic impact measures (if applicable) would potentially include

 Small governments (if applicable): “Revenue” test; annualized compliance cost as a percentage of annual govern ment

revenues

.

 Small non

- profits (if applicable): “Expenditure” test; annualized compliance cost as a percentage of annual operating

expenses

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

operate the entire year.5-18 Table 5

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

SBA Size Standard (effective March 11,

2008) Average Cost Per Entity ($1,000/ entity) All Enter

prises Owned by Enterprises with:

Industry NAICS NAICS Description 1 t o 20 Employees 20 to 99 Employees 100 to 499 Employees 500 to 749 Employees < 500 Employees 750 to 999 Employees 1,000 to 1,499 Employees Onshore petroleum and

natural gas production; offshore petroleum and natural gas production; onshore natural gas
pro cessing 211 Crude Petroleum and Natural Gas Extraction 500 $17.1 0.08% 1.32% 0.11% 0.05% 0.02% 0.47% 0.03% 0.02%

Onshore natural gas

transmission; underground natural gas storage; LNG storage; LNG import and export 486210 Pipeline Transportation of N atural Gas b $ 1 5

. 7 0. 08 % 0.1 2 % 0. 40 % 0.2 4 % c c c 0. 10 % c c

Natural gas distribution 221210 Natural Gas Distribution 500 $13.9 0.06% 0.27% 0.03% 0.06% 0.11% 0.07% 0.02% 0.03%

a The Census Bureau defines an enterprise as a business organization consi sting of one or more domestic establishments that were specified und er 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 emplo yment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an e stablishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SB REFA) screeni ng analyses.
b The SBA size standard for NAICS 486210 is $7 million in average annual receipts.

c The U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipt s for these categories underestimat e true value.5-19 Table 5

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

a The Census Bu reau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified u nder common ownership or control. The enterprise and the establishment are the same for single

- establishment firms. Each multi

- esta blishment company forms one enterprise

— the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA’s busine ss size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Bu siness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
b The SBA size standard for NAICS 486210 is $7 million in average annual receipts.

c The U.S. Census Bureau has missing data for this employee range; some estimates were possible using p artial data. The receipts for these categories underestimate the true value, which results in conservative estimates of cost

- to

- sales ratios. SBA Size Standard (effective March 11,

2008) Average Cost Per Entity ($/entity) All Enter

prise s Owned by Enterprises with:

Industry NAICS NAICS Description 1 to 20 Employees 20 to 99 Employees 100 to 499 Employees 500 to 749 Employees < 500 Employees 750 to 999 Employees 1,000 to 1,499 Employees Onshore petroleum and

natural gas production; of

fshore petroleum and natural gas production; onshore natural gas processing 211 Crude Petroleum and Natural Gas Extraction 500 $7.5 0.04% 0.58% 0.05% 0.02% 0.01% 0.21% 0.01% 0.01%

Onshore natural gas

transmission; underground natural gas storage; LNG storage; LNG import and export 486210 Pipeline Transportation of Natural Gas b $ 6.9 0.0 4 % 0.0 5 % 0. 18 % 0.1 1 % c c c 0.0 5 % c c

Natural gas distribution 221210 Natural Gas Distribution 500 $9.2 0.04% 0.18% 0.02% 0.04% 0.07% 0.05% 0.01% 0.02%5

- 20 5.2.3 Results of Screening Analysis
The Regulatory Flexibility Act generally requires an agency to prepare a regulat ory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial n umber of small entities. Small entities include small businesses, small govern mental jurisdictions, and small not

- for

- profit enterprises.

For the purposes of assessing the impacts of Subpart W of the rule on small entities, we defined a small entity as (1) a small business, as defined by SBA’s regulations at 13 CFR Part 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; or (3) a small organi zation that is any not

- for

- profit enterprise that is independently owned and operated and is
not dominant in its field.

EPA believes the selected thresholds maximize the rule coverage wit h 85 % of all U.S. petroleum and natural gas systems emissions reporte d by approximately 2, 786 reporters, while keeping reporting burden to a minimum and excluding small emitters. Furthermore, many Subpart W industry stakeholders with whom EPA met expressed support for a 25,000 metric ton
of CO 2 e threshold because it suffici ently captures the majority of GHG emissions in the United States while excluding smaller facilities and sources. After considering the economic impact of
the final r ule on small entities, EPA has concluded that this action will not have a significant

econ omic impact on a substantial number of small entities. As shown in Table 5

- 13 and Table
5

- 14 , the average ratio of annualized reporting program costs to receipts of establishments owned by model small ent erprises was less than 1% for industries presumed likely to have small businesses covered by the reporting program.

The only exception to this is the ratio for 1

- 20 employee range for crude petroleum and natural gas extraction, which is greater than 1 per cent but less than 2 percent. While a majority of the enterprises in the petroleum and natural gas industry fall in the 1

- 20 employee range , most of the production, and therefore emissions, comes from large corporations

. In fact, the top 20 large corporati ons in the U.S. account for 85 percent of the total oil and 77 percent of the total gas produced in the country. In most cases, the small enterprises have very small operations (such as a singly family owning a few production wells) that are highly unlike ly to cross the 25,000
metric tons CO 2 e reporting threshold.5

- 21 In other cases, a small enterprise (less than 20 employee s ) may own large operations but
conduct nearly all of its operations through contractors. Such enterprises, however, tend to have higher annual revenues than those with small operations. In addition, these enterprises constitute
a small fraction of the over 19,000 enterprises in the less than 20 employee category subject to
the final rule.

5.3 Synopsis of Benefits

Under the mandatory GHG rep orting rule EPA requires to collect and verify emissions
data from Subpart W facilities

. This section reviews the benefits of a mandatory reporting

program for Subpart W facilities based on previous experience with emissions inventory programs in the Unit ed States and abroad.

Recent policy discussions have highlighted potential benefits to society of the mandatory GHG reporting program (Pew, 2008 ). Benefits to the public include building public confidence through clear and transparent emi ssion measures and reports and the ability of the public to make petroleum and natural gas facilities accountable for their equipment leaks and ve nted emissions. A GHG reporting system will also have the benefit of providing policy makers and analysts with a data set that is comprehensive for the petroleum and natural gas industry if reporting is
conducted under Subpart W and other applicable subparts. Benefits to the industry include the
identification of cost

- effective GHG reduction opportunities and dis closure that provides firms with incentives to reduce emissions voluntarily, and provides emissions data to service industries, such as insurance and financial markets. Availability of emissions information to the public, consumers, investors, corporations and government regulators provides a sound basis for future policy analysis. This benefits society as a whole. Accurate and transparent information is necessary for the implementation of efficient approaches that meet environmental goals with the
lowest c ost to the economy.6

- 1 SECTION 6
STATUTORY AND EXECUT IVE ORDER R EVIEWS

This section describes EPA’s compliance with applicable executive orders and statutes during the development of Subpart W of the mandatory GHG reporting rule.

6.1 Executive Order 12866: Regulatory P lanning and Review Under EO 12866, (58 Federal Register (FR) 51735, October 4, 1993) the Agency must determine whether the regulatory action is “significant” and therefore subject to Office of Management and Budget (OMB) review and the requirements of the EO. The Order defines “significant regulatory action” as one that is likely to result in a rule that may:

1. Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity , competition, jobs, the environment, public health or safety, or State, local, or Tribal governments or
communities;

2. Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;

3. Materially alter the budgetary impact of entitlement, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or

4. Raise novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles set forth in the EO.

Pursua nt to the terms of Executive Order 12866, it has been determined that this f inal r ule is a “significant regulatory action” because it raises novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles set forth in the EO. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for rev iew under

Executive Order 12866.6

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

In the economic analysis , EPA has identified the regulatory options considered, their

co sts, and the emissions that would likely be reported under each option, and explained the selection of the option chosen for the rule. The cost analysis, presented in Section 4, estimates that under the regulatory option, the total annualized cost of Subpa rt W for the private sector will be approximately 6 2 million during the first year of the program and 19 mi llion in subsequent

years . The analysis also estimates about $ 1. 1 million of annual programmatic costs for EPA.

. In addition, EPA has conducted a q ualitative assessment of the benefits of the rule, which are reported in Section 5 . Overall, EPA has concluded that the costs of the proposed mandatory GHG reporting rule for Subpart W are outweighed by the potential benefits of more comprehensive informat ion about GHG emissions.

6.2 Paperwork Reduction Act
The information collection requirements in this rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The information co llection requirements are not enforceable until OMB approves
them.

EPA plans to collect complete and accurate economy

- wide data on facility

- level GHG emissions. Accurate and timely information on GHG emissions is essential for informing future
climate chan ge policy decisions. Through data collected under this rule, EPA will gain a better understanding of the relative emissions of petroleum and gas systems , and the distribution of
emissions from individual facilities within those systems . The facility

- specif ic data will also improve our understanding of the factors that influence GHG emission rates and the actions that facilities are already taking to reduce emissions. Additionally, EPA will be able to track the trend
of emissions from petroleum and gas syste ms over time, particularly in response to policies and potential regulations. The data collected by this rule will improve EPA’s ability to formulate climate change policy options and to assess which petroleum and gas systems would be affected,
and how the se systems wo uld be affected by the options.

This information collection is mandatory and will be carried out under CAA Sections 114 and 208. Information identified and marked as Confidential Business Information (CBI) will not be disclosed except in accor dance with procedures set forth in 40 CFR Part 2. However,6

- 3 emissions information collected under CAA Sections 114 and 208 generally cannot be claimed as CBI and will be made public 21

6.3 Regulatory Flexibility Act . The projected cost and hour respondent burden in the ICR is $27. 7 million and 3 9 6
, 474 hours per year. The estimated average burden per response is 90.71 hours; the frequency of response is annual for all respondents that must comply with the rule’s reporting requirements ; and the estimated average number of likely respondents p er year is 2,786 . The cost burden to respondents resulting from the collection of information includes the total capital and start

- up cost annualized over the equipment’s expected useful life (averaging $ 0.7 4 million per year) a total operation and mainten ance component (averaging $1. 7 million per year), and a labor cost component (averaging $ 25. 3 million per year). Burden is defined at 5 CFR Part 1320.3(b). These
cost numbers differ from those shown elsewhere in the Economic Impact Analysis because ICR

cos ts represent the average cost over the first three years of the rule, but costs are reported
elsewhere in the Economic Impact Analysis for the first year of the rule and for subsequent years of the rule. Also, the total cost estimate of the rule in the Eco nomic Impact Analysis includes the cost to the Agency to administer the program. The ICR differentiates between respondent burden and cost to the Agency.

An agency may not conduct or sponsor, and a person is not required to respond to, a
collection of info rmation unless it displays a currently valid OMB control number. The OMB control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR Part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR P art 9 in the
Fe deral Register to display the OMB control number for the approved information collection requirements contained in the final rule.

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory 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 certifies that the rule will not have a significant economic impact on a substantial number of
smal l entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.

21 Although CBI determinations are usually made on a case

- by

- case basis, EPA has issued guidance in an earlier

Federal Register notice on what constitutes emissions data that cannot be considered CBI (956 FR 7042

– 7043, Feb ruary 21, 1991). As discussed in Section II.R of the 40 CFR Part 98 final rule preamble, EPA is initiating a separate notice and comment process to make CBI determinations for the data collected under this rulemaking. EPA intends to issue this notice in early 2010, and will include in the notice the data proposed for collection in this rulemaking6

- 4 For purposes of assessing the impacts of this f inal r ule on small entities, small entity is defined as: (1) a small business as defined by the Small Business Administration’s regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not

- for

- profit enterprise which is independently owned and operated and
is not dominant in its field.

First, EPA examined the effect of Subpart W on small businesses using data collected by SUSB and SBA on the number of establishments, enterprises, employees, and receipts of
businesses to allocate first

- year and subsequent year costs to small businesses and assess the impact. Data limitations allowed EPA to only to compute and compare ratios for a model
establishment for six enterprise size ranges ( i.e., all categories, enterprises with 1 to 20 employees, 20 to 99 employees, 100 to 499 employees, 500 to 749 employees, less than 500 employees, 750 to 999 employees, and 1,000 to 1,499 employees )

. This approach is conservative
because an establishment’s parent company (the “enterprise”) may have other economic resources that could be used to cover the costs of the reporting program. Section 5.2 provides further description of these methods.

These sales tests examine the average establishment’s total an nualized mandatory reporting costs to the average establishment receipts for enterprises within several employment categories

. The average entity costs used to compute the sales test are the same across all of these enterprise size categories. As a result , the sales

- test will overstate the cost

- to

- receipt ratio for establishments owned by small businesses, because the reporting costs are likely lower than average entity estimates provided by the engineering c ost analysis.

EPA believes the selected threshol ds maximi ze the rule coverage with o ver 85 percent of all U.S. petroleum and natural gas systems emissions reported by approximately 2, 786 reporters, while keeping reporting burden to a minimum and excluding small emitters. Furth ermore, many Subpart W indu stry stakeholders with whom EPA met expressed support for a 25,000 metric ton
of CO 2 e threshold because it sufficiently captures the majority of GHG emissions in the United States while excluding smaller facilities and sources. After considering the econom ic impact of the rule on small entities, EPA has concluded that this action will not have a significant economic impact on a substantial number of small entities. The average ratio of annualized reporting program costs to receipts of establishments owned b y model small enterprises was less
than 1 percent for the se gments that may be likely to have small businesses covered by Subpart
W in the reporting program.6

- 5 Second, EPA determined that the f inal r ulemaking would not have a significant impact on small gov ernmental jurisdictions. EPA determined that one segment of the petroleum and natural gas industry might include small governments affected by the f inal r ulemaking. A comparison of the compliance costs to the revenue of potentially affected small governm ental jurisdictions revealed that the costs of the rule are less than 1% of revenues.

Third, EPA concluded that the f inal r ulemaking would not affect a small organization that is any not

- for

- profit enterprise which is independently owned and operated and is not dominant in its field. Specifically, the data listing entities in each segment of the petroleum and natural gas industry did not include any non

- profit entities.

Although this f inal r ule will not have a significant economic impact on a substanti al number of small entities, EPA nonetheless took several steps to reduce the impact of this f inal

r ule on small entities. For example, EPA determined appropriate thresholds that reduce the number of small businesses reporting. In addition, EPA is propos ing different monitoring methods for different emissions sources, requiring direct measurement only for selected sources. Also, EPA is proposing annual instead of more frequent reporting.

Through comprehensive outreach activities prior to proposal of the original MRR, EPA held approximately 100 meetings and/or conference calls with representatives of the primary audience groups, including numerous trade associations and industries in the petroleum and gas industry that include small business members. EPA’ s outreach activities prior to proposal of the initial rule are documented in the memorandum, “Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule,” located in Docket No. EPA

- HQ

- OAR

- 2008

- 0508

- 055. After the original proposa l, EPA posted a guide for small businesses on the EPA GHG reporting rule Web site, along with a general fact sheet for the rule, information sheets for every source category, and an FAQ document. EPA also operated a hotline to answer questions
about the A pril, 2010 proposed r ule. We continued to meet with stakeholders and entered documentation of all meetings into the docket.

During rule implementation, EPA will maintain an “open door” policy for stakeholders to ask questions about the f inal r ule or pro vide suggestions to EPA about the types of compliance assistance that would be useful to small businesses. EPA intends to develop a range of compliance assistance tools and materials and conduct extensive outreach for the f inal r ule

.6

- 6 We have therefore c oncluded that this action will not have a significant economic impact
on a substantial number of small entities. We continue to be interested in the potential impacts of
the f inal r ule on small entities and welcome comments on issues related to such impact s.

6.4 Unfunded Mandates Reform Act
The UMRA seeks to protect State, local, and Tribal governments from the imposition of unfunded Federal mandates. In addition, the Act seeks to strengthen the partnership between the Federal government and State, local, and T ribal governments and ensure that the Federal government covers the costs incurred during compliance with Federal mandates. Title II of the UMRA of 1995, Public Law 104

- 4, establishes requirements for Federal agencies to assess the effects of their regulat ory actions on State, local, and tribal governments and the private segment. Under section 202 of UMRA, EPA generally must prepare a written statement, including a cost

- benefit analysis, for proposed and final rules with Federal mandates that may result in expenditures to State, local, and Tribal governments, in the aggregate, or to the private segment, of $100 million or more in any one year.

Before promulgating an EPA rule for which a written statement is needed, section 205 of UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost

- effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are
inco nsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost

- effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative w as not adopted.

Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including T ribal governments, it must have developed under section 203 of UMRA a small government agency plan. The plan must pro vide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informin g, educating, and advising small governments on compliance with the regulatory requirements.

EPA has determined that the Subpart W rule does not contain a Federal mandate that may
result in expenditures of $100 million or more for State, local, and T ribal governments, in the
aggregate, or the private segment in any one year. Expenditures associated with compliance,
defined as the incremental costs beyond the existing regulations will not surpass $100 million in6

- 7 the aggregate in any year. Thus, today's f inal r ule is not subject to the requirements of sections
202 and 205 of UMRA.

This f inal r ule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small

govern ments. This regulation applies to facilities that directly emit greenhouses gases. It does not apply to governmental entities unless the government entity owns a facility in the petroleum and gas industry that directly emits greenhouse gases above thresh old levels. In addition, this
f inal r ule does not impose any implementation responsibilities on State, local, or Tribal governments and it is not expected to increase the cost of existing regulatory programs managed by those governments. Thus, the impact on governments affected by the f inal r ule is expected to
be minimal.

6.5 Executive Order 13132: Federalism
Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and t imely input by state and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the executive order to include regulations that
have “substantial direct effec ts on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government.”

This f inal r ule does not have F ederalism implications. It will not have subs tantial 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

spec ified in Executive Order 13132.

This regulation ap plies to public

- or private

- segment facilities that directly emit GHGs from petroleum and natural gas systems . Relatively few government facilities would be affected. This regulation also does not limit the power of states or localities to collect GHG data and/or regulate GHG emissions. Thus, Executive Order 13132 does not apply to this f inal r ule

.

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

Executive Order 13175, entitled “Consultation and Coordination with Indian Tr ibal Governments” (59 FR 22951, November 6, 2000), requires EPA to develop an accountable6

- 8 process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.”

EPA has concluded that th is action may have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). However, it will neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law.

EPA conducted an analysis t o determine potential impact of this action on tribes that own or operate petroleum and natural gas systems (EPA

- HQ

- OAR

- 2009

- 0923

- XXX). First, when conducting an emissions reporting threshold analysis, EPA analyzed a comprehensive listing of all operators of petroleum and natural gas systems in the United States. In a separate analysis, EPA researched additional available data to determine which tribal entities may own or operate petroleum and natural gas systems that could be impacted by this final acti on. As a result of those analyse s, EPA found one tribe that may potentially be impacted by this final action. Finally, during the comment period for the April 2010 proposal, EPA received comment from one tribe, Southern Ute, which were specific to the propose d reporting methodologies.

As discussed in the 2009 final rule, which established 40 CFR part 98 , EPA believes that there are minimal impacts to tribes. Tribes could be required to submit an annual GHG report for any facility that they own or operate that is subject to 40 CFR part 98 . Landfills and stationary combustion equipment are the types of facilities owned or operated by tribes that would most likely trigger applicability. Tribes that own or operate large industrial emission sources such as cement pl ants, coal mines, or oil and gas operations could also be required to report emissions under this rulemaking. It should be noted that the owner or operator of any privately owned sources located on a reservation would be required to report for any applicab le facility. The rule would apply to all types of stationary combustion equipment (except for emergency generators and portable equipment) if the aggregate maximum rated heat input capacity of all stationary fuel combustion units at a facility is 30 millio n British thermal units per hour (mmBtu/hr) or greater, and the facility emits 25,000 metric tons of CO2e or more per year from all stationary fuel
combustion sources.

In addition, EPA sought opportunities to provide information to tribal governments an d representatives during rule development. Specifically, EPA consulted with tribal officials early in the process of developing the Mandatory Reporting Program to permit them to have meaningful and timely input into its development. First, EPA sought opp ortunities to provide information to Tribal governments and representatives during development of 40 CFR Part 986

- 9 that was proposed in April 2009 and finalized in September 2009. Today’s action is a supplement to that rule.

In consultation with EPA’s Ameri can Indian Environment Office, EPA’s outreach plan included tribes. During the initial rule proposal phase, EPA staff provided information to tribes through conference calls with multiple Indian working groups and organizations at EPA that
interact with tr ibes and through individual calls with two tribal board members of TCR. In addition, EPA prepared a short article on the GHG reporting rule that appeared on the front page
of a tribal newsletter

— Tribal Air News

— that was distributed to EPA/OAQPS’s network o f tribal organizations. EPA gave a presentation on various climate efforts, including the mandatory reporting rule, at the National Tribal Conference on Environmental Management in June, 2008. In addition, EPA had copies of a short information sheet distri buted at a meeting of the National Tribal Caucus. EPA participated in a conference call with tribal air coordinators in April 2009 and prepared a guidance sheet for Tribal governments on the p roposed r ule. It was posted on the MRR website and published in the Tribal Air Newsletter. For a complete list of tribal contacts, see the “Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule,” in the Docket for this rulemak ing (EPA

- HQ

- OAR

- 2008

- 0508

- 055).

6.7 Executive Order 13045: Protectio n of Children from Environmental Health and Safety Risks
EPA interprets Executive Order 13045 (62 F.R. 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required
under Section 5

- 501 of the executive order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it does not establish an environmental standard intended to mitigate health or safety risks.

6.8 Executive Order 13211: Action s that Significantly Affect Energy Supply, Distribution, or Use

This f inal r ule is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply , distribution, or use of energy. Further, we have concluded that this f inal r ule is not likely
to h ave any adverse energy effects.

This proposal relates to monitoring, reporting, and recordkeeping at facilities that directly
emit GHGs from petroleum and n atural gas systems ; it does not impact energy supply, distribution or use. Therefore, we conclude that this f inal r ule is not likely to have any adverse effects on energy supply, distribution, or use.6

- 10 6.9 National Technology Transfer Advancement Act

Section 12 (d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104

- 113 (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA direct s EPA to provide Congress, through OMB, with explanations when the Agency decides not to use available and applicable voluntary consensus standards.

This f inal r ulemaking provides the option of using technical standards from consensus based standards organ izations

. These voluntary consensus standards will help facilities monitor, report, and keep records of GHG emissions. No new test methods were developed for this f inal

r ule . Instead, from existing rules for source categories and voluntary GHG programs, EP A identified existing means of monitoring, reporting, and keeping records of GHG emissions

. The existing methods (voluntary consensus standards) include a broad range of measurement techniques, such as methods to analyze fuel

, methods to measure gas or li quid flow, and methods to gauge and measure petroleum and petroleum products. The test methods are incorporated by reference into the rule and are available as specified in Section 98. 7 of subpart A. Additional methods that would be incorporated under thi s f inal r ule are GlyCalc and E&P tanks.

By incorporating voluntary consensus standards into this rule, EPA is both meeting the requirements of the NTTAA and presenting multiple options and flexibility for measuring
GHGs.

6.10 Executive Order 12898: Federal Act ions to Address Environmental Justice in Minority Populations and Low

- Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to th e greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, an d activities on minority populations and low

income populations in the United States

.

EPA has determined that this f inal r ule will not have disproportionately high and adverse human health or environmental effects on minority or low

- income populations beca use it does6

- 11 not affect the level of protection provided to human health or the environment; it is a rule addressing information collection and reporting procedures.7

- 1 SECTION 7
CONCLUSIONS AND IMPL ICATIONS

In this E conomic Impact Analysis , EPA has examined the regu latory background, the development of the mandatory GHG reporting rule for Subpart W , and estimated the costs and
benefits of implementing this subpart . This section pr esents our overall conclusions.

7.1 Discussion of Results
EPA has developed this f inal r ule in response to language contained in the FY 2008 Consolidated Appropriations amendment (December 26, 2007), which authorized funding for EPA to publish the rule on an accelerated schedule. The major market failure that the rule is designed to address is on e of inadequate or asymmetric information: while existing state and federal programs collect similar data, the resulting data are neither comprehensive nor consistent
for Subpart W sources . As such, they are an inadequate basis for the formation or evaluat ion of future climate policy that will impact the petroleum and natural gas segment s

.
7.1.1 Development of the Proposed Rule
EPA examined several regulatory alternative scenarios that were developed by varying options across two program dimensions

— Threshold and Monitoring Methodology

— that were finalized in today’s rule . The final rule calls for:

– a threshold of 25,000 MtC O 2 e threshold for all facilities , and

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

specific calculation metho ds, and use of emission factors (leaker and population factors)

Other scenarios evaluated during the development of the proposal included the following:

1. A 1,000 MtC O 2 e threshold; selected options for methodology, frequency, and verifier.

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

3. A 100,000 MtC O 2 e threshold; selected options for method ology, frequency, and verifier.

4. The measurement variable is changed to direct spot measurement; selected option for thre shold.7

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

7.1.2 Affected Source Categories

EPA considered direct emitters of equipment leaks and vented GHGs under Subpart

. From these emission sources, EPA identif ied eight s egment s under the Subpart W source category for which costs and impacts were examined.

7.2 Assessment of Costs and Benefits of the Mandatory GHG Reporting Rule

7.2.1 Estimated Costs and Impacts of the Mandatory GHG Reporting Program

Under the f inal r ule

, EPA estimates tha t 2, 786 entities would be covered by Subpart W of the rule, directly emitting 3 37 Million MtC O 2 e per year

. The total annualized costs incurred under the rule by these entities would be 61

. 8 million for the first year and 19.0 million f or

s ubsequent years.

Overall, economic impacts on industry segment s are measured by comparing per

- entity costs with average per entity receipts. These cost

- to

- sales ratios are less than 1% for establishments owned by small businesses that EPA considers most l ikely 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 f inal r ule will not have a significant economic impact on a sub stantial number of small entities. Overall, Subpart W
of the rule will impo se national costs exceedi ng 61

. 8 million in the first year and 19.0 million in subsequent years; the costs will be wide ly dispersed throughout the economy and relatively low

on a pe r

- entity basis. The estimated national costs represent less than 0.001% of 2007 g ross d omestic p roduct. Thus, EPA does not estimate that there will be significant impacts on the economy in general or on individual se gments or small entities within Subpart W

.
7.2.2 Summary of Qualitative Benefits Assessment

EPA did not quantify the estimated benefits of the f inal r ule . Instead, a qualitative assessment was performed, based on information from the literature and previous benefits
assessments of existin g emissions i nventory programs.

Recent policy discussions have highlighted potential benefits to society of the GHG reporting program (Pew, 2008 ). Benefits to the public include building public confidence through clear and transparent emission measure s and reports and the ability of the public to make
facilities accountable for their emissions. Benefits to petroleum and natural gas industry include the identification of GHG reduction opportunities and disclosure, which provides firms with7

- 3 incentives to reduce emissions voluntarily, and provides emissions data to service industries, such as insurance and financial markets. A GHG reporting system will also have the benefit of providing policy makers and analysts with a comparable data set that is comprehe nsive and reduces the potential for policy bias. In addition, a mandatory reporting system is a key element to an overall GHG policy; no effort can succeed without it.

Studies published by OECD (2005) and EPA (2003) have documented benefits to various
stak eholders, including the public, industry, investors, and government, of existing pollutant release and transfer registers ( PRTRs ) These benefits are likely similar to the benefits that would be experienced as a result of the mandatory GHG reporting rule, a nd thus they provide a basis for a qualitative characterization of those benefits. The studies examined in Section 5 of this economic impact analysis describe the following types of benefits:

– Public

– increased levels of trust towards government and industry where there are right

- to

- know laws concerning emissions;

– information to enable citizens to negotiate directly with polluters; and

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

– Industry

– Public relations: having independent, verifiable data to present to the public would demonstrate appropriate environmental stewardship.

– Standardization: uniform industry standards would reduce the cost of reporting relative to non

- uniform, jurisdi ction

- 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 wo uld offset some of the costs of monitoring.

– Potential customer data for service industries: information about GHG

emitting firms will be useful for firms that market emissions

- reduction technologies, and to insurance companies for assessing risk.7

- 4 – Investors

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

– Government

– Policy development: The greatest benefit to government of mandatory GHG reporting is the comprehensi ve, consistent data it would provide, enabling government to develop accurate, informed futur e GHG policy.

– Comparabil ity: A mandatory system would reduce the difficulties associated with comparing across different reporting stand ards across states or progr ams.

– Compliance and policy evaluation: Publicly available nationwide data on GHG emissions will enable government to develop and robustly evaluate environmental policies, and to ensure compliance with the policies once implemented.

7.3 What Did We Learn throug h This Analysis?
EPA’s examination of the costs and benefits of the provisions in Subpart W of the mandatory GHG reporting rule revealed that the f inal r ule will impose an estimated $ 30. 9 million (based on average of first year and subsequent year costs ) i n monitoring, recordkeeping, and reporting costs on emitters of GHGs that are widely distributed throughout the U.S. economy. Impacts of the costs on individual segment s and entities are expected to be generally small, comprising less than 1 percent of ent ity receipts and approximately 0.001 percent of 2007 GDP. Thus, despite the overall national costs, macroeconomic impacts are not anticipated, and
EPA does not believe that the f inal r ule will impose significant economic impacts on a
substantial number of small entities.

A review of the literature enabled us to characterize the expected types of benefits, which will be experienced by stakeholders, including the public, industry, investors, and government. Based on this qualitative assessment and evidence fr om other existing programs, EPA expects
the benefits of the f inal r ule to be substantial.8

- 1 SECTION 8
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Beierle, T. C. 2003. “The Benefits and Costs of Envi ronmental Information Disclosure: What Do We Know About Right

- to

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. <http://www.ipcc

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OGJ (2006) EOR/ Heavy Oil Survey

.
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