September 2009
Regulatory Impact Analysis for the
Mandatory Reporting of
Greenhouse Gas Emissions
Final Rule (GHG Reporting)
Final Report
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Regulatory Impact Analysis for the
Mandatory Reporting of
Greenhouse Gas Emissions
Final Rule (GHG Reporting)
Final Report
September 2009
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CONTENTS
Section Page
1 Introduction and Background 1-1
1.1 Background 1-1
1.2 Role of the Regulatory Impact Analysis in the Rulemaking Process 1-1
1.2.1 Legislative Roles 1-1
1.2.2 Role of Statutory and Executive Orders 1-4
1.2.3 Market Failure or Other Social Purpose 1-4
1.2.4 Illustrative Nature of the Analysis 1-5
1.3 Overview and Design of theRIA 1-5
1.3.1 Baseline and Years of Analysis 1-5
1.3.2 Developing the GHG Reporting Rule Considered in ThisRIA 1-5
1.3.3 Evaluating Costs and Benefits 1-9
1.4 Selected Greenhouse Gas Reporting Alternative 1-9
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 by Sector 2-4
2.2 Sources Considered 2-4
2.3 How the Mandatory GHG Reporting Program Is Different from the
Federal and State Programs EPA Reviewed 2-7
2.4 Existing Reporting Programs 2-8
2.4.1 Inventory of U.S. Greenhouse Gas Emissions and Sinks 2-8
2.4.2 Federal Voluntary Greenhouse Gas Programs 2-10
2.4.3 Federal Mandatory Reporting Programs 2-13
2.4.4 Other EPA Emissions Inventories 2-15
2.4.5 State and Regional Voluntary Programs for Greenhouse Gas
Emissions Reporting 2-15
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2.4.6 State and Regional Mandatory Programs for Greenhouse Gas
Emissions Reporting and Control 2-16
2.4.7 State Mandatory Greenhouse Gas Reporting Rules 2-17
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
3.1.3 Reporting Frequency 3-4
3.1.4 Verification 3-4
3.2 Selected Option 3-5
3.3 Alternative Scenarios Evaluated 3-6
3.4 Data Quality for This Analysis 3-7
4 Engineering Cost Analysis 4-1
4.1 Introduction 4-1
4.2 Overview of Cost Analysis 4-1
4.2.1 Baseline Reporting 4-1
4.2.2 Reporting Costs 4-2
4.2.3 Cost Analysis Summary by Subpart 4-5
4.3 Subpart C—General Stationary Fuel Combustion Sources and Subpart
D—Electricity Generation and Other Stationary Combustion Sources 4-5
4.3.1 Labor Costs 4-9
4.3.2 Capital and O&M Costs 4-9
4.3.3 Units Covered 4-14
4.4 SubpartE—Adipic Acid Production 4-14
4.5 Subpart F—Aluminum Production 4-20
4.6 Subpart G—Ammonia Manufacturing 4-22
4.7 Subpart H—Cement Production 4-24
4.8 Subpart K—Ferroalloy Production 4-26
4.9 Subpart N—Glass Production 4-28
4.10 Subpart O—HCFC-22 Production 4-29
4.11 Subpart P—Hydrogen Production 4-31
IV
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4.12 SubpartQ—Iron and Steel Production 4-33
4.13 Subpart R—Lead Production 4-35
4.14 Subpart S—Lime Manufacturing 4-36
4.15 Subpart V—Nitric Acid Production 4-38
4.16 Subpart X—Petrochemical Production 4-41
4.17 Subpart Y—Petroleum Refineries 4-43
4.18 SubpartZ—Phosphoric Acid Production 4-45
4.19 Subpart AA—Pulp and Paper Manufacturing 4-47
4.20 Subpart BB—Silicon Carbide Production 4-49
4.21 Subpart CC—Soda Ash Manufacturing 4-50
4.22 Subpart EE—Titanium Dioxide Production 4-52
4.23 Subpart GG—Zinc Production 4-54
4.24 Subpart HH—Landfills 4-56
4.25 Subpart JJ—Manure Management 4-58
4.26 Subpart MM—Suppliers of Petroleum Products 4-61
4.27 Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids 4-62
4.28 Subpart OO—Suppliers of Industrial Greenhouse Gases 4-65
4.29 Subpart PP—Suppliers of Carbon Dioxide (CO2) 4-68
4.30 Mobile Sources 4-69
4.30.1 Source Description and Baseline Reporting 4-70
4.30.2 Labor Costs: Reporting and Recordkeeping 4-71
4.30.3 Equipment Costs: Test Equipment/Facility Upgrades 4-72
4.30.4 O&M Costs 4-73
4.30.5 Total Aggregate Annualized Costs, and Average Per Manufacturer
and Per Unit Costs 4-73
4.31 Summary 4-75
5 Economy-Wide Analysis of Reporting Rule Options 5-1
5.1 Evaluating Alternative Options for Implementation of the Rule 5-4
5.1.1 Analysis of Alternative Threshold Options 5-5
5.1.2 Analysis of Alternative Monitory Method Options 5-12
5.1.3 EPA Uses Existing Federal Data for Fuel Quantity 5-18
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5.1.4 EPA Uses Default Carbon Content for Fuel Suppliers 5-19
5.1.5 Frequency of Reporting: Quarterly 5-19
5.1.6 Third-Party Verification 5-20
5.1.7 Only Upstream and Downstream Process Reporting 5-23
5.1.8 Sensitivity of Subsequent Year Cost Estimates 5-27
5.1.9 Summary of Alternative Threshold Options 5-28
5.2 Assessing Economic Impacts on Small Entities 5-31
5.2.1 Identify Affected Sectors and Entities 5-32
5.2.2 Develop Small Entity Economic Impact Measures 5-39
5.2.3 Results of Screening Analysis 5-44
6 Benefits Review 6-1
6.1 Synopsis 6-1
6.2 Background 6-1
6.2.1 Background on Existing GHG Reporting Rules 6-1
6.2.2 Benefits Analysis Methodology 6-2
6.3 Discussion of Benefits 6-2
6.3.1 Benefits of a Mandatory Program 6-2
6.3.2 Benefits to the Public 6-3
6.3.3 Benefits to Industry and Investors 6-5
6.3.4 Reducing Uncertainty: Benefits to all Stakeholders 6-6
7 Statutory and Executive Order Reviews 7-1
7.1 Executive Order 12866: Regulatory Planning and Review 7-1
7.2 Paperwork Reduction Act 7-1
7.3 Regulatory Flexibility Act 7-3
7.4 Unfunded Mandates Reform Act 7-5
7.4.1 Authorizing Legislation 7-6
7.4.2 Benefit-Cost Analysis 7-6
7.4.3 Future Costs and Disproportionate Budget Effects 7-9
7.4.4 Impacts on the National Economy 7-10
7.4.5 Consultation with State, Local, and Tribal Governments 7-10
7.4.6 Consideration of Regulatory Alternatives 7-11
7.5 Executive Order 13132: Federalism 7-13
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7.6 Executive Order 13175: Consultation and Coordination with Indian Tribal
Governments 7-14
7.7 Executive Order 13045: Protection of Children from Environmental
Health and Safety Risks 7-14
7.8 Executive Order 13211: Actions that Significantly Affect Energy Supply,
Distribution, or Use 7-15
7.9 National Technology Transfer Advancement Act 7-15
7.10 Executive Order 12898: Federal Actions to Address Environmental Justice
in Minority Populations and Low-Income Populations 7-16
8 Conclusions and Implications 8-1
8.1 Discussion of Results 8-1
8.1.1 Development of the Rule 8-1
8.1.2 Affected Source Categories 8-2
8.2 Assessment of Costs and Benefits of the Mandatory GHG Reporting Rule 8-2
8.2.1 Estimated Costs and Impacts of the Mandatory GHG Reporting
Program 8-2
8.2.2 Summary of Qualitative Benefits Assessment 8-3
8.3 What Did We Learn through This Analysis? 8-4
9 References 9-1
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LIST OF FIGURES
Number Page
5-1. Average and Marginal Cost per Ton of Emissions Reported by Threshold 5-10
5-2. Average Cost per Percentage Point of Uncertainty 5-17
Vlll
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LIST OF TABLES
Number Page
2-1. Sources of GHG Emissions Considered 2-5
2-2. GHG Source Categories Included in the Regulatory Analyses 2-6
3-1. Options Considered in Developing Scenarios (Recommended Option
Indicated by Shading) 3-2
4-1. Per Unit Cost Breakdown by Monitoring Category: Stationary Combustion
(2006$) 4-6
4-2a. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS-Add CO2 Analyzer and Flow Meter (2006$) 4-10
4-2b. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS-Add CO2 Analyzer Only (2006$) 4-10
4-2c. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS-Add Flow Monitor Only (2006$) 4-11
4-2d. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS part 75 Appendix G (non-ARP): Add CO2 Data Stream (2006$) 4-11
4-2e. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS part 75 ARP Units—Report Annual CO2, Methane and Nitrous Oxide
(2006$) 4-11
4-2f Detailed Summary of Stationary Combustion Monitoring Category Costs:
Daily Fuel Sampling (2006$) 4-12
4-2g. Detailed Summary of Stationary Combustion Monitoring Category Costs:
Monthly Fuel Sampling (2006$) 4-12
4-2h. Detailed Summary of Stationary Combustion Monitoring Category Costs:
Periodic In-Stack Gas Sampling (2006$) 4-13
4-2i. Detailed Summary of Stationary Combustion Monitoring Category Costs:
Periodic Off-Site Flue Gas Analysis (2006$) 4-13
4-3. Reporting Units by Threshold and Monitoring Category 4-15
4-4. Subpart E Adipic Acid: Labor Costs (2006$) 4-19
4-5. Subpart E Adipic Acid: Capital and O&M Costs (2006$) 4-20
4-6. Subpart F Aluminum Production: Labor Costs (2006$) 4-21
4-7. Subpart F Aluminum Production: Capital and O&M Costs (2006$) 4-21
4-8. Subpart G Ammonia: Labor Costs (2006$) 4-23
4-9. Subpart G Ammonia: Capital and O&M (2006$) 4-23
4-10. Subpart H Cement Manufacturing: Labor Costs (2006$)a 4-25
4-11. Subpart H Cement Manufacturing: Capital and O&M Costs (2006$)a 4-26
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4-12. Subpart K Ferroalloy Production: Labor Costs (2006$) 4-27
4-13. Subpart K Ferroalloy Production: Capital and O&M Costs (2006$) 4-27
4-14. Subpart N Glass: Labor Costs (2006$) 4-29
4-15. Subpart N Glass: Capital and O&M Costs (2006$) 4-29
4-16. Subpart O HCFC-22 Production: Labor Costs (2006$) 4-30
4-17. Subpart O HCFC-22 Production: Capital and O&M Costs (2006$) 4-30
4-18. Subpart P Hydrogen Production: Labor Costs (2006$) 4-32
4-19. Subpart P Hydrogen Production: Capital and O&M Costs (2006$) 4-32
4-20. Subpart Q Iron & Steel: Labor Costs (2006$) 4-34
4-21. Subpart Q Iron & Steel: Capital and O&M Costs (2006$) 4-35
4-22. Subpart R Lead: Labor Costs (2006$) 4-36
4-23. Subpart R Lead: Capital and O&M Costs (2006$) 4-36
4-24. Subpart S Lime Manufacturing: Labor Costs (2006$) 4-38
4-25. Subpart S Lime Manufacturing: Capital and O&M Costs (2006$) 4-38
4-26. Subpart V Nitric Acid: Labor Costs (2006$) 4-40
4-27. Subpart V Nitric Acid: Capital and O&M Costs (2006$) 4-41
4-28. Subpart X Petrochemical Production: Labor Costs (2006$) 4-42
4-29. Subpart X Petrochemical Production: Capital and O&M Costs (2006$) 4-43
4-30. Subpart Y Petroleum Refineries: Labor Costs (2006$) 4-44
4-31. Subpart Y Petroleum Refineries: Capital and O&M Costs (2006$) 4-45
4-32. Subpart Z Phosphoric Acid Production: Labor Costs (2006$) 4-46
4-33. Subpart Z Phosphoric Acid Production: Capital and O&M Costs (2006$) 4-46
4-34. Subpart AA Pulp and Paper: Labor Costs (2006$) 4-48
4-35. Subpart AA Pulp and Paper: Capital and O&M Costs (2006$) 4-49
4-36. SubpartBB Silicon Carbide: Labor Costs (2006$) 4-50
4-37. SubpartBB Silicon Carbide: Capital and O&M Costs (2006$) 4-50
4-38. Subpart CC Soda Ash: Labor Costs (2006$) 4-52
4-39. Subpart CC Soda Ash: Capital and O&M Costs (2006$) 4-52
4-40. Subpart EE Titanium Dioxide: Labor Costs (2006$) 4-54
4-41. Subpart EE Titanium Dioxide: Capital and O&M Costs (2006$) 4-54
4-42. Subpart GG Zinc: Labor Costs (2006$) 4-55
4-43. Subpart GG Zinc: Capital and O&M Costs (2006$) 4-56
4-44. Subpart HH Landfills: Labor Costs (2006$) 4-57
4-45. Subpart HH Landfills: Capital and O&M Costs (2006$) 4-58
4-46. Subpart JJ Manure Management: Labor Costs (2006$) 4-60
4-47. Subpart JJ Manure Management: Capital and O&M Costs (2006$) 4-60
4-48a. Subpart MM Petroleum Suppliers (Refineries): Labor Costs (2006$) 4-61
4-48b. Subpart MM Petroleum Suppliers (Imports/Exporters): Labor Costs (2006$) 4-62
4-49. Subpart MM Petroleum Suppliers: Capital and O&M Costs (2006$) 4-62
4-50a. Subpart NN Natural Gas Suppliers (LDCs): Labor Costs (2006$) 4-64
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4-50b. Subpart NN Natural Gas Suppliers (Natural Gas Liquids Fractionators): Labor
Costs (2006$) 4-64
4-51. Subpart NN Natural Gas Suppliers: Capital and O&M Costs (2006$) 4-65
4-52a. N2O Producers: Labor Costs (2006$) 4-66
4-52b. Anesthetic Producers: Labor Costs (2006$) 4-66
4-52c. Fluorinated Gas Importers (Bulk): Labor Costs (2006$) 4-67
4-52d. Fluorinated Gas Producers (Bulk): Labor Costs (2006$) 4-67
4-53. Subpart OO Suppliers of Industrial Gases: Capital and O&M Costs (2006$) 4-68
4-54. Subpart PP Suppliers of CO2: Labor Costs (2006$) 4-69
4-55. Subpart PP Suppliers of CO2: Capital and O&M Costs (2006$) 4-69
4-56. Mobile Source Heavy-duty Vehicle and Nonroad Engine Categories 4-70
4-57. Mobile Source Vehicle and Engine Reporting/Recordkeeping Costs (2006$) 4-72
4-58. Mobile Source Annualized Equipment/Facility Costs (2006$) 4-73
4-59. Summary of Estimated Annual Mobile Source Costs by Category (2006$) 4-74
4-60. Estimated Mobile Source Vehicle and Engine Annualized Aggregate Costs,
Average Per Manufacturer Costs, and Average Per Unit Costs ($2006) 4-75
4-61. Number and Share of Entities and Emissions Covered by Threshold 4-76
4-62. Summary of Costs and Costs per Representative Entity by Threshold (Million
$2006) 4-81
5-1. Estimates of Emissions (MtCO2e) Reported in 2006 Under the Selected
Option 5-2
5-2. National Cost Estimates by Sector: Selected Option 5-3
5-3. Summary of Threshold Cost-Effectiveness Analysis (First Year): Selected
Hybrid Option is 25,000 tons CO2e 5-5
5-4. Summary of Threshold Cost-Effectiveness Analysis (Subsequent Years) 5-6
5-5. National Cost Estimates by Sector: 1,000 tCO2e Threshold 5-6
5-6. National Cost Estimates by Sector: 10,000 tCO2e Threshold 5-8
5-7. National Cost Estimates by Sector: 100,000 tCO2e Threshold 5-9
5-8. Analysis of Alternative Monitoring Methods by Sector 5-13
5-9. Uncertainty Estimates by Methodology Option 5-16
5-10. Uncertainty Cost-Effectiveness Analysis (First Year): Selected Option is the
Hybrid Approach 5-17
5-11. Uncertainty Cost-Effectiveness Analysis (Subsequent Year): Selected Option
is the Hybrid Approach 5-17
5-12. Alternative Option 6 5-18
5-13. Alternative Option 7 5-19
5-14. Alternative Option 8 5-20
5-15. Private-Sector Third-Party Verification Costs 5-21
5-16. Alternative Option 9 5-22
5-17. Alternative Option 10 5-24
5-18. Reporting Costs by Upstream and Downstream Source Categories 5-25
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5-19. Extent of Emissions Reported More than Once 5-26
5-20. Estimates of the Share of New Facilities in Subsequent Years and Adjustment
to Subsequent Year Costs 5-28
5-21. Summary of Results by Option 5-29
5-22. Number of Establishments by Affected Industry and Enterprise21 Size: 2002 5-33
5-23. Number of Employees by Affected Industry and Enterprise21 Size: 2002 5-35
5-24. Receipts by Affected Industry and Enterprise21 Size: 2002 5-37
5-25. Establishment Sales Tests by Industry and Enterprise21 Size: First Year Costs 5-40
5-26. Establishment Sales Tests by Industry and Enterprise21 Size: Subsequent Year
Costs 5-42
5-27. Case Studies of Manufacturing Industries to Determine the Likelihood of
Small Businesses Would Be Covered by the Rule 5-48
5-28. Estimated Emissions and Costs by Subpart (2006$) 5-50
7-1. Estimated Private and Government Costs in Selected Sectors (103 $2006) 7-8
7-2. National Cost Estimates for Selected Sectors: Recommended Option
($ million) 7-9
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SECTION 1
INTRODUCTION AND BACKGROUND
1.1 Background
On December 26, 2007, President Bush signed the FY2008 Consolidated Appropriations
Amendment, which authorized funding for the U.S. Environmental Protection Agency (EPA) to
develop and publish a draft rule on an accelerated schedule:
[N]ot less than $3,500,000 shall be provided for activities to develop and publish
a draft rule not later than 9 months after the date of enactment of this Act, and a
final rule not later than 18 months after the date of enactment of this Act, to
require mandatory reporting of GHG emissions above appropriate threshold in all
sectors of the economy.
The accompanying explanatory statement stated that EPA shall "use its existing authority
under the Clean Air Act" to develop a mandatory GHG reporting rule.
The agency is further directed to include in its rule reporting of emission resulting
from upstream production and downstream sources, to the extent that the
Administrator deems it appropriate. The Administrator shall determine
appropriate thresholds of emissions above which reporting is required, and how
frequently reports shall be submitted to EPA. The Administrator shall have
discretion to use existing reporting requirements for electric generating units
under Section 821 of the Clean Air Act.
EPA examined different options for the design of the reporting rule, including options
that have different thresholds above which sources must measure and report their GHG
emissions. The estimated costs and benefits for some alternatives are likely to exceed $100
million. Hence, a regulatory impact analysis (RIA) was developed.
1.2 Role of the Regulatory Impact Analysis in the Rulemaking Process
1.2.1 Legislative Roles
This report analyzes the estimated regulatory impacts of the mandatory reporting
program that EPA has developed, in accordance with the FY08 Appropriations language, under
the authority of Sections 114 and 208 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
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vehicle engines). Section 114(a)J of the CAA authorizes the Administrator to, inter alia, require
certain persons (see below) on a one-time, periodic or continuous basis to keep records, make
reports, undertake monitoring, sample emissions, or provide such other information as the
Administrator may reasonably require. This information may be required of any person who (i)
owns or operates an emission source, (ii) manufactures control or process equipment, (iii) the
Administrator believes may have information necessary for the purposes set forth in this section,
or (iv) is subject to any requirement of the Act (except for manufacturers subject to certain title II
requirements). The information may be required for the purposes of developing an
implementation plan, an emission standard under sections 111, 112 or 129, determining if any
person is in violation of any standard or requirement of an implementation plan or emissions
standard, or "carrying out any provision" of the Act (except for a provision of title II with respect
to manufacturers of new motor vehicles or new motor vehicle engines).2 Section 208 of the CAA
provides EPA with similar broad authority regarding the manufacturers of new motor vehicles or
new motor vehicle engines, and other persons subject to the requirements of parts A and C of
title II.
The scope of the persons potentially subject to a section 114(a)(l) 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 sections 114 and 208, EPA could gather information relevant to carrying out provisions
involving research (e.g., section 103(g)); evaluating and setting standards (e.g., section 111); and
endangerment determinations contained in specific provisions of the Act (e.g., 202); as well as
other programs.
EPA has recently announced a number of climate change related actions, including a
proposed Endangerment finding (74 FR 18886, April 24, 2009 (e.g., "Proposed Endangerment
and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air
Act"), an intent to regulate vehicles, jointly published with DOT (74 FR 24007, May 22, 2009,
"Notice of Upcoming Joint Rulemaking To Establish Vehicle GHG Emissions and CAFE
Standards), a reconsideration of the memo entitled "EPA's Interpretation of Regulations that
1 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.
2Although there are exclusions in section 114(a)(l) regarding certain title II requirements applicable to
manufacturers of new motor vehicle and motor vehicle engines, section 208 authorizes the gathering of
information related to those areas.
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Determine Pollutants Covered By Federal Prevention of Significant Deterioration (PSD) Permit
Program" (73 FR 80300, December 31, 2008), and the granting the CA Waiver (74 FR 32744,
July 9, 2009). These are all separate actions. Some are related to EPA's response to the U.S.
Supreme Court's decision in Massachusetts v. EPA. 127 S.Ct. 1438 (2007), others are EPA
actions to address climate change. This rulemaking does not indicate EPA has made any final
decisions on these other actions. In fact 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 could assist in future policy
development.
Accurate and timely information on GHG emissions is essential for informing some
future climate change policy decisions. Although additional data collection (e.g., for other source
categories such as indirect emissions or offsets) will no doubt be required as the development of
climate policies evolves, the data collected in this rule will provide useful information for a
variety of polices. Furthermore, many existing programs collect this type of information and will
continue to do so. Through data collected under this rule, EPA, States and the public will gain a
better understanding of the relative emissions of specific industries, and the distribution of
emissions from individual facilities within those industries. The facility-specific data will also
improve our understanding of the factors that influence GHG emission rates and actions that
facilities are already taking to reduce emissions. In addition, the data collected on some source
categories could also potentially help inform offset program design by providing fundamental
data on current baseline emissions for these categories.
The Agency considered a wide range of determining factors when selecting the selected
alternative for this rule. These included the consideration of costs and benefits, which are
essential to making efficient, cost-effective decisions for implementation of these standards.
Other important considerations included the language of the Appropriations Act and the
accompanying explanatory statement related to source categories; consistency with other CAA
or state-level regulatory programs that typically require facility or unit level data and; the relative
accuracy of different monitoring approaches and the monitoring methods already in use within
the regulated industries; and the potential burden placed on small businesses associated with a
range of reporting thresholds.
This RIA is intended to inform the public about the selection criteria for this rule, which
include, but are not limited to, the potential costs and benefits that may result when the
mandatory reporting program is implemented.
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1.2.2 Role of Statutory and Executive Orders
There are several statutes and executive orders that dictate the manner in which EPA
considers rulemaking and that apply to any public documentation. The analysis required by these
statutes and executive orders is presented in Section 6.
EPA presents this RIA pursuant to Executive Order 12866 and the guidelines of Office of
Management and Budget (OMB) Circular A-4 and EPA's Economic Guidelines.3 These
documents present guidelines for EPA to assess the benefits and costs of the selected regulatory
option, as well as options that are more stringent or less stringent. The costs of the mandatory
reporting program are described in Section 4 of this RIA; the economic impact analysis and cost-
effectiveness analysis of the program are presented in Section 5. The benefits of the rule are
discussed in Section 6.
1.2.3 Market Failure or Other Social Purpose
OMB Circular A-4 indicates that one of the reasons a regulation such as the GHG
reporting rule may be issued is to address market failure. The major categories of market failure
include inadequate or asymmetric information, externalities, and market power. The mandatory
GHG reporting rule seeks to address inadequate or asymmetric information between and among
GHG emitters and various other stakeholders including the public.
While some sectors of the U.S. economy report emissions of GHGs, and there are other
sources of information about GHG emissions, the rule would provide comprehensive data on
emissions from sources throughout the economy. There currently is significant variation in
which sectors of the U.S. economy report GHG emissions and methods used for calculations. As
a result, existing information is inadequate or various stakeholders have very different
information on which to base decisions about GHG emission levels and possible reductions.
An externality occurs when one party's actions impose uncompensated benefits or costs
on another party. Environmental problems are a classic case of externality. Although not its
primary focus of the rule, the GHG reporting program will provide information on for future
climate policies designed to address externalities. Since GHGs are an externality, the lack of
information on their emissions means the information asymmetry leads to an inefficient
outcome, and providing such information is a necessary step to internalize the externality.
3U.S. Office of Management and Budget. Circular A-4, September 17, 2003: http://www.whitehouse.gov/omb/
circulars/a004/a-4 .pdf.
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1.2.4 Illustrative Nature of the A nalysis
This analysis is illustrative of the types of costs and benefits that may accrue as a result of
the program. The estimates of costs reflect existing production levels in each affected sector, and
estimates of emissions are based on 2006 data. When the reporting program takes effect, actual
patterns of economic activity and emissions may differ from current conditions. However, these
data provide estimates of baseline conditions and estimated costs of compliance.
1.3 Overview and Design of the RIA
This RIA comprises seven sections. Following this introductory section, Section 2
describes affected sectors of the economy and reviews existing reporting programs. Section 3
describes the development of the rule, including control options and analyses of alternative
scenarios. Section 4 characterizes baseline conditions and presents engineering estimates of the
costs of complying with the rule. Section 5 presents an assessment of the monitoring and
reporting costs by sector, an examination of uncertainty related to measurement accuracy of
monitoring methods prescribed, and an assessment of potential impacts on small entities. Section
6 presents a qualitative examination of potential benefits of the rule. Section 7 provides a
discussion of the Agency's compliance with executive orders and other statutes during the
development of the rule. Section 8 describes EPA's conclusions and findings.
1.3.1 Baseline and Years of Analysis
Data used for the analysis represent the most recent data available on estimates of GHG
emission by sector, productive capacity, existing emissions monitoring, and reporting activities
by sector. 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 by sector, attempting
to project these changes would lead to an increased level of uncertainty without conveying
comparable improvements in the assessment. Thus, EPA uses data representing essentially
current conditions as a proxy for conditions present when the rule takes effect. Such estimates
are inherently uncertain because data needed for more precise measurements are not available.
The data collected by the rule would greatly enhance future estimates.
1.3.2 Developing the GHG Reporting Rule Considered in This RIA
In order to ensure a comprehensive consideration of GHG emissions, EPA organized the
development of the mandatory GHG reporting rule around seven categories of processes that
emit GHGs: (1) fossil fuel combustion: stationary, (2) fossil fuel combustion: mobile, (3) fuel
suppliers, (4) industrial processes, (5) industrial GHG suppliers, (6) fossil fuel fugitive
emissions, and (7) biological processes. For each category, EPA evaluated the requirements of
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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.
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. One of EPA's goal was to develop a reporting rule that, to the
extent possible and appropriate, is consistent with existing GHG emission estimation and
reporting methodologies in order to reduce the burden of reporting for all parties involved. We
document our review of GHG monitoring protocols for each source category used by federal,
state, regional, and international voluntary and mandatory GHG programs, and our review of
state mandatory GHG rules. The monitoring and GHG calculation methodologies for many
source categories are the same as, or similar to, the methodologies contained in state reporting
programs.
EPA's overall rulemaking approach began with identification of anthropogenic sources in
the U.S. GHG Inventory and International Panel on Climate Change (IPCC). The rule would
require reporting of CO2, CH4, N2O, HFCs, PFCs, SFe, and other fluorinated compounds (e.g.,
NF3 and HFEs) as defined in the rule. The IPCC focuses on CO2, CH4, N2O, HFCs,
perfluorocarbons (PFCs), and SFe for both scientific assessments and emissions inventory
purposes because these are long-lived, well-mixed GHGs not controlled by the Montreal
Protocol on Substances that Deplete the Ozone Layer. These GHGs are directly emitted by
human activities, are reported annually in EPA's Inventory of U.S. Greenhouse Gas Emissions
and Sinks, and are the common focus of the climate change research community. The IPCC also
included methods for accounting for emissions from several specified fluorinated gases in the
2006 IPCC Guidelines for National Greenhouse Gas Inventories.4 These gases include
fluorinated ethers, which are used in electronics and anesthetics and as heat transfer fluids. Like
the other six GHGs that must be reported, these fluorinated compounds are long-lived in the
atmosphere and have high global warming potentials (GWPs). In many cases these fluorinated
gases are used in expanding industries (e.g., electronics) or as substitutes for HFCs. As such,
EPA is proposing to include reporting of these gases to ensure that the Agency has an accurate
understanding of the emissions and uses of these gases, particularly as those uses expand.
4The 2006 IPCC Guidelines are found here: http://www.ipcc.ch/ipccreports/methodology-reports.htm. For additional
information on these gases please see Table A-l in proposed 40 CFR part 98, subpart A and the Industrial GHG
Suppliers Technical Support Document (EPA-HQ-OAR-2008-0508-141).
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EPA then conducted a review of existing methodologies and reporting programs (e.g.,
California Air Resources Board [CARS], 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 Preamble to the
Rule. EPA used this information to inform its selection of measurement and reporting methods
for this rulemaking.
Once EPA had a complete list of source categories relevant to the U.S., the Agency
systematically reviewed those source categories against the following criteria to develop the list
to the source categories included in the proposal:
(1) include source categories that emit the most significant amounts of GHG emissions,
while also minimizing the number of reporters, and
(2) include source categories that can be measured 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
measurement methodologies, measurement accuracy, and administrative burden.
Based on the source level screening activities, possible reporting methodologies for
the selected sources were developed. The reporting methodologies identified fall into
several categories including, direct measurement, calculating emissions based on site-
specific information, and calculating emissions based on default emissions factors. In
general, for the rule, EPA selected a combination of direct emission measurement and
calculations based on site-specific information.
Once the source categories and methodologies had been identified, EPA evaluated
different rule options across the following dimensions:
• Threshold (level of emissions below which entities are not required to report);
- 1,000 tons CO2e/year;
- 10,000 tons CO2e/year;
- 25,000 tons CO2e/year;
- 100,000 tons CO2e/year;
— Equivalent capacity based threshold where data exists;
• Methodology for measuring emissions;
— Direct measurement;
- Facility specific calculation methods;
— Default emissions factors;
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• Frequency of reporting: Annually, quarterly, or some other frequency;
• Verification responsibility: EPA, third party, or self-certification without independent
verification?
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 required to report.
1.3.2.1 Summary of the Major Changes Since Proposal
EPA received a total of approximately 16,800 public comments on the proposed
rulemaking. As mentioned earlier in this preamble, we had 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 to the program since the proposal:
• Reduced the number of source categories included in the final rule as we further
consider comments and options on several categories5.
• Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that report less
than 25,000 metric tons of CO2e for 5 years to cease annual reporting to EPA.
• Added a mechanism in 40 CFR 98.2 to allow facilities and suppliers that stop
operating all GHG-emitting processes and operations covered by the rule to cease
annual reporting to EPA.
• Added a provision in 40 CFR 98.3 for submittal of revised annual GHG reports to
correct errors.
• Added provisions in 40 CFR 98.3 to allow use of best available monitoring methods
for part of calendar year 2010.
• 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.
5 See the following sections of the preamble for discussion of source categories not included in today's final rule:
sections III.I (electronics manufacturing), III.J (ethanol production), III.L (fluorinated GHG production), III.M
(food processing), III.T (magnesium production), III.W (oil and natural gas systems), III.DD (SF6 from electrical
equipment), III.FF (underground coal mines), III.HH (industrial landfills are not included in today's rule, but
MSW landfills are covered by the rule), III.II (wastewater treatment), and III.KK (suppliers of coal).
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• Revised the requirements of the Designated Representative in 40 CFR 98.4 to align
them with those in 40 CFR 75 (ARP regulations).
• Changed record retention to 3 years instead of 5 years for most records (40 CFR
98.3).
• In the recordkeeping section (40 CFR 98.3), clarified the contents of the monitoring
plan (called the QAPP at proposal).
• Edited CEMS language in several subparts for consistency and to clarify when CEMS
are used and under what circumstances upgrades are needed.
• Revised several definitions in 40 CFR part 98, subpart A to address comments.
Of these changes, the biggest difference between the estimated annual cost of the final
rule and the estimated annual cost of the proposed rule resulted from the reduction of the number
of source categories covered between the proposed rule and the final rule.
1.3.3 Evaluating Costs and Benefits
To assist in the selection of the selected option EPA conducted an economic impact
analysis across the above dimensions. EPA estimated the costs of complying with each of the
reporting alternatives, and assessed the cost-effectiveness of each alternative by examining the
costs per million metric ton of CC>2 equivalent (MMtCC^e) reported. This cost-effectiveness
metric was considered in combination with other important factors such as the potential impacts
on small entities, consistency with other CAA or state-level regulatory programs and monitoring
methods already in use within the regulated industries.
1.4 Selected Greenhouse Gas Reporting Alternative
The selected option for the mandatory GHG reporting rule is outlined below. Section 5
provides cost comparisons for each alternative evaluated under the following four dimensions.
The selected option strikes a balance between impacts on small entities, consistency with other
programs, costs incurred by the reporting entities, and emissions coverage.
• Threshold: Hybrid approach
- The thresholds fall generally into three groups: capacity, emissions, or entire
source category ("All in"). Typically, a facility that emits 25,000 metric tons
CO2e/year or more reports all sources for which there are methods.
The capacity and "all-in" thresholds are roughly equivalent to 25,000 metric tons
CO2e/year.
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- A facility may be subject to a capacity threshold when already reporting (e.g.,
ARP) or to another type of threshold due to unique issues or where an emissions-
based threshold is not practical (e.g., GHG generation threshold for landfills).
Methodology: Combination of direct measurement and source-specific calculation
methodologies
— Direct measurement of emissions from units at facilities that are already required
to collect and report data using continuous emission monitoring systems under
other Federally enforceable programs, including for other regulatory programs
(e.g., CC>2 emissions from Electricity Generating Units [EGUs] in ARP;
requirements of NSPS, NESHAP, SIP)
- Source-specific calculation methods using facility-specific information for other
sources at the facility
Frequency: Annual
— All reporters would report their emissions annually.
- Exception: those already reporting quarterly for existing mandatory programs
(e.g., Acid Rain Program, Energy Information Administration)
Verification: Self-certification with EPA verification
- A facility would report emissions data and supporting information directly to
EPA; EPA will use the information to verify the data.
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SECTION 2
REGULATORY BACKGROUND
The intent of this rule is to collect accurate and timely GHG emissions data that can be
used to inform future policies. Although the mandatory GHG rule is unique, EPA carefully
considered other federal and state programs during development of the rule. The reporting
program will supplement rather than duplicate other U.S. government GHG programs. We
outline EPA's overall rulemaking approach, sources considered, and summarize our review of
GHG monitoring protocols for each source category 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 source
categories are the same as, or similar to, the methodologies contained in state reporting
programs. The remainder of the section provides an overview of related existing programs and
discusses their relevance in the development of this rule.
2.1 EPA's Overall Rulemaking Approach
In response to the FY2008 Consolidated Appropriations Amendment, EPA has developed
this rulemaking. The components of this development are explained in the following subsections.
2.1.1 Identifying the Goals of the Greenhouse Gas Reporting System
The mandatory reporting program will provide comprehensive and accurate data which
will inform future climate change policies. Potential future climate policies include research and
development initiatives, economic incentives, new or expanded voluntary programs, adaptation
strategies, emission standards, a carbon tax, or a cap-and-trade program. Because we do not
know at this time the specific policies that will be adopted, the data reported through the
mandatory reporting system should be of sufficient quality to support a range of approaches.
Also, consistent with the Appropriations Amendment, the reporting rule covers a broad range of
sectors of the economy.
To these ends, we identified the following goals of the mandatory reporting system:
• Obtain data that is of sufficient quality that it can be used to support a range of future
climate change policies and regulations.
• Balance the rule coverage to maximize the amount of emissions reported while
excluding small emitters.
• Create reporting requirements that are consistent with existing GHG reporting
programs by using existing GHG emission estimation and reporting methodologies to
reduce reporting burden, where feasible.
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2.1.2 Developing the Rule
In order to ensure a comprehensive consideration of GHG emissions, EPA organized the
development of the rule around seven categories of processes that emit GHGs: (1) fossil fuel
combustion: stationary, (2) fossil fuel combustion: mobile, (3) fuel suppliers, (4) industrial
processes, (5) industrial GHG suppliers, (6) fossil fuel fugitive emissions, and (7) biological
processes. For each category, 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.
2.1.3 Evaluation of Existing Greenhouse Gas Reporting Programs
A number of State and regional GHG reporting systems currently are in place or under
development. EPA's goal is to develop a reporting rule that, to the extent possible and
appropriate, would rely on similar protocols and formats of the existing programs and, therefore,
reduce the burden of reporting for all parties involved. Therefore, each of the work groups
performed a comprehensive review of existing voluntary and mandatory GHG reporting
programs, as well as guidance documents for quantifying GHG emissions from specific sources.
These GHG reporting programs and guidance documents included the following:
• International programs, including the IPCC, the EU Emissions Trading System, and
the Environment Canada reporting rule;
• 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 TCR, RGGI, and programs in
California, New Mexico, and New Jersey;
• Reporting protocols developed by nongovernmental organizations, such as
WRI/WBCSD; and
• Programs from industrial trade organizations, such as the American Petroleum
Institute's Compendium of GHG Estimation Methodologies for the Oil and Gas
Industry and the Cement Sustainability Initiative's CO2 Accounting and Reporting
Standard for the Cement Industry, developed by WBCSD.
In reviewing these programs, we analyzed the sectors covered, thresholds for reporting,
approach to indirect emissions reporting, the monitoring or emission estimating methods used,
the measures to assure the quality of the reported data, the point of monitoring, data input needs,
and information required to be reported and/or retained. We analyzed these provisions for
suitability to a mandatory, Federal GHG reporting program, and compiled the information. A
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summary of existing reporting programs examined is provided in Section 2.4. The full review of
existing GHG reporting programs and guidance may be found in the docket at EPA-HQ-OAR-
2008-0508-054.
2.1.4 Stakeholder Outreach to Identify Reporting Issues
Early in the development process, we conducted a proactive communications outreach
program to inform the public about the rule development effort. We solicited input and
maintained an open door policy for those interested in discussing the rulemaking. Since January
2008, EPA staff have held more than 100 meetings with stakeholders, including the following:
• trade associations and firms in potentially affected industries/sectors;
• state, local, and tribal environmental control agencies and regional air quality
planning organizations;
• state and regional organizations already involved in GHG emissions reporting, such
as TCR, CARS, and Western Climate Initiative (WCI); and
• environmental groups and other nongovernmental organizations.
• We also met with U.S. Department of Energy (DOE) and U.S. Department of
Agriculture (USDA), which have programs relevant to GHG emissions.
During the meetings, we shared information about the statutory requirements and
timetable for developing a rule. Stakeholders were encouraged to provide input on key issues.
Examples of topics discussed included existing GHG monitoring and reporting programs and
lessons learned, thresholds for reporting, schedules for reporting, scope of reporting, handling of
confidential data, data verification, and the role of states in administering the program. As
needed, the EPA technical workgroups followed up with these stakeholder groups on a variety of
methodological, technical, and policy issues. EPA staff also provided information to tribes
through conference calls with different Indian tribal working groups and organizations at EPA
and through individual calls with tribal board members of TCR.
For a full list of organizations EPA met with when developing this rule please see the
memo found at EPA-HQ-OAR-2008-0508-055.
On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting rule. EPA held two
public hearings, and received over 16,000 written public comments. The public comment period
ended on June 9, 2009.
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
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and 135 groups between proposal signature (March 10, 2009) and the close of the comment
period (June 9, 2009). Details of these meetings are available in the docket (EPA-HQ-OAR-
2008-0508)
2.1.5 Analysis of Emissions by Sector
For each of the source categories mentioned in Section 2.4, EPA compiled information
on current conditions in the category, including information about existing monitoring equipment
or reporting frameworks, estimated emissions of GHGs, and estimated productive capacity or
throughput. Incremental costs of measuring GHG emissions and conducting reporting activities
were estimated under each scenario. The scenarios vary the conditions of the reporting rule with
respect to the size of the entity required to report, the frequency of reporting, who verifies
emissions, and the type of measurement required by sector. The scenarios are listed in Section 3.
EPA also reviewed the benefits to stakeholders, including the public, the government, and
industry, of a reporting system in a qualitative analysis. These benefits are outlined in Section 5.
2.2 Sources Considered
Seven technical subgroups at EPA considered emissions sources from several broad
categories, as shown in Table 2-1. Using screening criteria based on the feasibility of monitoring,
verifying, and measuring these sources, the technical subgroups developed reporting
methodologies for the sources in Table 2-2.
Some source categories were excluded as a result of this screening step, such as direct
emissions from land use changes and agricultural soils, fugitive emissions from selected oil and
gas operations, and vehicle fleets. Vehicle fleet emissions are covered by reporting from fuel
suppliers as part of the oil and gas production. Other emissions sources were excluded due to the
large uncertainty associated with measuring, monitoring, and verifying the emissions. Further
detail regarding the rationale for the exclusion of sources can be found in Section II of the
Preamble for the final rule and Section IV of the Preamble for the proposed rule.
Consistent with the appropriations language regarding reporting of emissions from
"downstream sources," EPA is proposing reporting requirements from facilities that directly emit
GHGs above a certain threshold as a result of combustion of fuel or processes. The majority of
the direct emitters included in this proposal are large facilities in the electricity generation or
industrial sectors. In addition, many of the electricity generation facilities are already reporting
their CC>2 emissions to EPA under existing regulations. As such, these facilities have only a
minimal increase in the amount of data they have to provide EPA on their CH4 and N2O
emissions. The typical industrial facilities that are required to report under this proposal have
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Table 2-1. Sources of GHG Emissions Considered
Source
GHG Emission Considered
Downstream
Direct emitters
Upstream
Fuel suppliers
Industrial gas suppliers
Mobile Sources
Mobile combustion
Stationary combustion: Sources that may be considered include stationary
combustion units (e.g., EGUs, boilers, furnaces, turbines, kilns).
Industrial processes: Emissions result from the physical or chemical
transformation of materials in the mineral (e.g., cement, lime, glass), metal
(e.g., iron, steel, ferroalloy, aluminum) and chemical (e.g., HCFC-22
production, nitric acid, petrochemical) industries.
Fugitive emissions1: Intentional and unintentional emissions result from the
extraction, processing, storage, and transport of fossil fuels (coal, oil, and
gas) to the point of final use.
Biological processes: Sources that may be considered include emissions
from sources in the waste, agricultural, and forestry sectors (e.g., landfills,
waste water treatment, and manure management operations).
Producers/refiners/importers: Reporting from fuel providers and importers
(e.g., petroleum refiners and importers, coal mines, gas processing plants,
LNG importers).
Producers/importers: Reporting from producers and importers from
industrial gases (e.g., HFC, PFC, SF6, CO2, and N2O).
Emissions from vehicles and engines in use: Reporting from vehicle
manufacturers and heavy duty and nonroad engine manufacturers. Sources
include passenger cars, large/heavy duty truck cabs and chassis, light and
medium duty trucks and vans, motorcycles, and other miscellaneous vehicles
and engines.
1 This definition of fugitive emissions is derived from the definition of fugitives outlined in the 2006 Intergovernmental Panel
on Climate Change Guidelines for National Greenhouse Gas Inventories, and is consistent with the use of the term in the
development of GHG inventories. In non-GHG related reporting efforts, fugitives are more narrowly defined to be emissions
which could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening.
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Table 2-2. GHG Source Categories Included in the Regulatory Analyses
Source Categories
Electricity generators
Other large stationary combustion equipment (e.g., boilers, furnaces,
engines)
Mobile combustion (e.g., vehicle and heavy duty equipment
manufacturers)
Petroleum refineries
Gas processors
Industrial gas suppliers/importers
LNG terminals
Liquid/solid/gaseous fuel importers
HCFC-22 production
Ammonia manufacture
Nitric acid production
Adipic acid production
Hydrogen production
Semiconductor
Petrochemical production
Titanium dioxide
Soda ash manufacture
Phosphoric acid production
Iron and steel
Aluminum production
Ferroalloy production
Zinc production
Lead production
Cement manufacturing
Lime manufacturing
Limestone/dolomite-FGD
Limestone/dolomite-glass
Silicon carbide production/consumption
Pulp & paper
Natural gas systems
Petroleum systems
Landfills
Manure management
emissions that are substantially higher than the thresholds and are already doing many of the
measurements and quantifications of emissions required by this proposal through existing
business practices, voluntary programs, or mandatory state-level GHG reporting programs.
For more information about the thresholds included in the proposal please refer to
Section IV.C of the preamble and for more information about the requirements for specific
sources refer to Section V of the preamble for the rule.
Consistent with the appropriations language regarding reporting of emissions from
"upstream production," EPA is proposing reporting requirements from upstream suppliers of
fossil fuel and industrial GHGs. In the context of GHG reporting, "upstream emissions" refers to
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the GHG emissions potential of a quantity of industrial gas, fossil fuel, or substance whose use
directly leads to the emissions of a GHG that is supplied into the economy. For fossil fuels, the
emissions potential is the amount of CC>2 that would be produced from complete combustion or
oxidation of the carbon in the fuel. In many cases, the fossil fuels and industrial GHGs supplied
by producers and importers are used and ultimately emitted by a large number of small sources,
particularly in the commercial and residential sectors (e.g., HFCs emitted from home A/C units
or GHG emissions from individual motor vehicles). To cover these direct emissions would
require reporting by hundreds or thousands of small facilities. To avoid this impact, the rule does
not include all of those emitters, but instead requires reporting by the suppliers of industrial gases
and suppliers of fossil fuels. Because the GHGs in these products are almost always fully emitted
during use, reporting these supply data will provide an estimate of national emissions while
substantially reducing the number of reporters. For this reason, the rule requires reporting by
suppliers of products, petroleum products, natural gas and natural gas liquids (NGLs), CC>2 gas,
and other industrial GHGs.
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 apply to
different industries, have different thresholds, require different pollutants and different types of
emissions sources to be reported, rely on different monitoring protocols, and require different
types of data to be reported, depending on the purposes of each program. None of the existing
programs require nationwide, mandatory GHG reporting by facilities in a large number of
sectors, so EPA's mandatory GHG rule is unique in this regard.
Although the mandatory GHG rule is unique, EPA carefully considered other Federal and
State programs during development of the rule. Documentation of our review of GHG
monitoring protocols for each source category used by Federal, State, and international voluntary
and mandatory GHG programs, and our review of State mandatory GHG rules can be found at
EPA-HQ-OAR-2008-0508-056. The monitoring and GHG calculation methodologies for many
source categories are the same as, or similar to, the methodologies contained in State reporting
programs such as TCR, CCAR, and State mandatory GHG reporting rules and similar to
methodologies developed by EPA voluntary programs such as Climate Leaders. The reporting
requirements set forth in 40 CFR part 75 are also being used for this rule. 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
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groups to ensure that the data management approach in this rule will lead to efficient submission
of data to multiple programs.
The intent of this rule is to collect a reasonable estimate of GHG emissions data that can
be used to inform future policy decisions. One goal in developing the rule is to be consistent with
the GHG protocols and requirements of other state and federal programs, where appropriate, in
order to make use of existing cooperative efforts and reduce the burden to facilities submitting
reports to other programs. However, we also need to be sure the mandatory reporting rule
collects facility-specific data of sufficient quality to achieve the Agency's objectives for this rule.
Therefore, some reporting requirements of this rule are different from other federal and state
programs.
2.4 Existing Reporting Programs
A number of voluntary and mandatory GHG programs already exist or are being
developed at the State, regional, and Federal levels. These programs have different scopes and
purposes. Many focus on GHG emission reduction, whereas others are purely reporting
programs. In addition to the GHG programs, other Federal emission reporting programs and
emission inventories are relevant to the GHG reporting rule. Several of these programs are
summarized in this section.
In developing the rule, we carefully reviewed the existing reporting programs,
particularly with respect to emissions sources covered, thresholds, monitoring methods,
frequency of reporting and verification. States may have, or intend to develop, reporting
programs that are broader in scope or are more aggressive in implementation because those
programs are either components of established reduction programs (e.g., cap and trade) or being
used to design and inform measures that reduced GHGs indirectly (e.g., energy efficiency).
Where possible, we built upon concepts in existing Federal and State programs in developing the
mandatory GHG reporting rule.
2.4.1 Inventory of U.S. Greenhouse Gas Emissions and Sinks
The U.S. greenhouse gas inventory, prepared by EPA's Office of Atmospheric Programs
in coordination with the Office of Transportation and Air Quality, is an impartial, policy-neutral
report that tracks annual GHG emissions. The annual report presents historical U.S. emissions of
CO2, CH4, N2O, HFCs, PFCs, and SF6.
The United States submits the Inventory of U.S. Greenhouse Gas Emissions and Sinks to
the Secretariat of the United Nations Framework Convention on Climate Change (UNFCCC) as
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an annual reporting requirement. The UNFCCC treaty, ratified by the United States in 1992, sets
an overall framework for intergovernmental efforts to tackle the challenge posed by climate
change. The United States has submitted the GHG inventory to the United Nations every year
since 1993. The annual Inventory of U.S. Greenhouse Gas Emissions and Sinks is consistent with
national inventory data submitted by other UNFCCC parties, and uses internationally accepted
methods for its emission estimates.
In preparing the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks., EPA
leads an interagency team that includes the DOE, USD A, the Department of Transportation
(DOT), the Department of Defense (DOD), the State Department, and others. EPA collaborates
with hundreds of experts representing more than a dozen federal agencies, academic institutions,
industry associations, consultants, and environmental organizations. The Inventory of U.S.
Greenhouse Gas Emissions and Sinks is peer-reviewed annually by domestic experts and by
UNFCCC, and undergoes a 30-day public comment period, and is peer reviewed annually by
UNFCCC review teams.
The Inventory of U.S. Greenhouse Gas Emissions and Sinks is a comprehensive, top-
down national assessment of national greenhouse gas emissions, and uses top-down national
energy data and other national statistics (e.g., on agriculture). To achieve the goal of
comprehensive national emissions coverage for reporting under the UNFCCC, most GHG
emissions in the report are calculated via activity data from national-level databases, statistics,
and surveys. The use of the aggregated national data means that the national emissions estimates
are not broken down at the geographic or facility level. In contrast, this reporting rule focuses on
bottom-up data and individual sources above appropriate thresholds. Although it will provide
more specific data, it will not provide full coverage of total annual U.S. GHG emissions, as is
required in the development of the Inventory in reporting to the UNFCCC.
The mandatory GHG reporting rule will help to improve the development of future
national inventories for particular source categories or sectors by advancing the understanding of
emission processes and monitoring methodologies. Facility, unit, and process level GHG
emissions data for industrial sources will improve the accuracy of the Inventory by confirming
the national statistics and emission estimation methodologies used to develop the top-down
inventory. The results can indicate shortcomings in the national statistics and identify where
adjustments may be needed.
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Therefore, although the data collected under this rule will not replace the system in place
to produce the comprehensive annual national Inventory, it can serve as a useful tool to better
improve the accuracy of future national-level inventories.
2.4.2 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 Climate
Leaders, several non-CC>2 voluntary programs, the Combined Heat and Power (CHP)
partnership, the SmartWay Transport Partnership program, the National Environmental
Performance Track Partnership, and the DOE 1605(b) voluntary GHG registry. Several other
federal voluntary programs encourage emissions reductions, clean energy, or energy efficiency;
this summary does not cover them all (for additional information see Review of Existing
Programs, EPA-HQ-OAR-2008-0508-054). This summary focuses on programs that include
voluntary GHG emission inventories or reporting of GHG emissions reduction activities for
sectors that were considered for inclusion in this rulemaking.
2.4.2.1 Climate Leaders
Climate Leaders is an EPA partnership program that works with companies to develop
GHG reduction strategies. Over 250 industry partners in a wide range of sectors have joined this
program. Partner companies complete a corporate-wide inventory of GHG emissions and
develop an inventory management plan using Climate Leaders protocols. Each company sets
GHG reductions goals and submits to EPA an annual GHG emissions inventory documenting
their progress. The annual reporting form provides corporate-wide emissions by type of
emissions source.
2.4.2.1 Non-CO2 Voluntary Partnership Programs
Since the 1990s, EPA has operated a number of non-CO2 voluntary partnership programs
aimed at reducing emissions from GHGs such as methane, SF6, and PFCs. There are four sector-
specific voluntary methane reduction programs: Natural Gas STAR, Landfill Methane Outreach
Partnership (LMOP), Coalbed Methane Outreach Programs (CMOP), and Ag STAR. In addition,
there are sector-specific voluntary emissions reduction partnerships for high global warming
potential gases. The Natural Gas STAR partnership encourages companies across the natural gas
and oil industries to adopt practices that reduce methane emissions. LMOP and CMOP
encourage voluntary capture and use landfill and coal mine methane, respectively, to generate
electricity or other useful energy. These partnerships focus on achieving methane reductions.
Industry partners voluntarily provide technical information on projects they undertake to reduce
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methane emissions on an annual basis, but they do not submit methane emissions inventories.
AgSTAR encourages beneficial use of agricultural methane from manure management systems
but does not have partner reporting requirements.
There are two sector-specific partnerships to reduce SFe emissions: the SFe Emission
Reduction Partnership for Electric Power Systems, with over 80 participating utilities, and the
SFe Emission Reduction Partnership for the Magnesium Industry. Partners in these programs
implement practices to reduce SF6 emissions and prepare corporate-wide annual inventories of
SFe emissions using protocols and reporting tools developed by EPA. There are also two
partnerships focused on PFCs: The Voluntary Aluminum Industrial Partnership (VAIP) promotes
technically feasible and cost-effective actions to reduce PFC emissions; industry partners track
and report PFC emissions reductions. Similarly, the Semiconductor Industry Association and
EPA formed a partnership to reduce PFC emissions in which a third party compiles data from
participating semiconductor companies and submits an aggregate (not company-specific) annual
PFC emissions report.
2.4.2.2 Combined Heat and Power Partnership
The Combined Heat and Power partnership is an EPA partnership that cuts across sectors.
It encourages use of CHP technologies to generate electricity and heat from the same fuel source,
thereby increasing energy efficiency and reducing GHG emissions from fuel combustion.
Corporate and institutional partners provide data on existing and new CHP projects but do not
submit emissions inventories.
2.4.2.3 SmartWay Transport Partnership
The SmartWay Transport Partnership program is a voluntary partnership between freight
industry stakeholders and EPA to promote fuel efficiency improvements and GHG emissions
reductions. Over 900 companies have joined including freight carriers (railroads and trucking
fleets) and shipping companies. Carrier and shipping companies commit to measuring and
improving the efficiency of their freight operations using EPA-developed tools that quantify the
benefits of a number of fuel-saving strategies. Companies report progress annually. The GHG
data that carrier companies report to EPA is discussed further in Section V.QQ.4b of the
preamble.
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2.4.2.4 National Environmental Performance Track Partnership6
The Performance Track Partnership is a voluntary partnership that recognizes and
rewards private and public facilities that demonstrate strong environmental performance beyond
current requirements. Performance Track is designed to augment the existing regulatory system
by creating incentives for facilities to achieve environmental results beyond those required by
law. To qualify, applicants must have implemented an independently-assessed environmental
management system, have a record of sustained compliance with environmental laws and
regulations, commit to achieving measurable environmental results that go beyond compliance,
and provide information to the local community on their environmental activities. Members are
subject to the same legal requirements as other regulated facilities. In some cases, EPA and states
have reduced routine reporting or given some flexibility to program members in how they meet
regulatory requirements. This approach is recognized by more than 20 states that have adopted
similar performance-based leadership programs.
2.4.2.5 1605(b) Voluntary Registry
The DOE EIA established a voluntary GHG registry under Section 1605(b) of the Energy
Policy Act of 1992. The program was recently enhanced and a final rule containing general
reporting guidelines was published on April 21, 2006 (71 FR 20784); the rule is contained in 10
CFR Part 300. Unlike EPA's proposal, which requires reporting of greenhouse emissions from
facilities over a specific threshold, the DOE 1605(b) registry allows anyone (e.g., a public entity,
private company, or an individual) to report their emissions and their emissions reduction
projects to the registry. Large emitters (e.g., anyone that emits over 10,000 tons of CO26 per
year) who wish to register emissions reductions must submit annual company-wide GHG
emissions inventories following technical guidelines published by DOE and must calculate and
report net GHG emissions reductions. The program offers a range of reporting methodologies
from stringent direct measurement to simplified calculations using default factors and allows the
reporters to report using the methodological option they choose. In addition, as mentioned above,
unlike EPA's proposal, sequestration and offset projects can also be reported under the 1605(b)
program. There is additional flexibility offered to small sources that can choose to limit annual
inventories and emissions reduction reports to a single type of activity rather than reporting
company-wide GHG emissions, but must still follow the technical guidelines. Reported data are
made available on the Internet in a public use database.
6 The Performance Track program is permanently closed; see the Federal Register notice of May 14, 2009 for more
details (http://www.epa.gov/performancetrack/index.htm).
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2.4.2.6 Summary
These voluntary programs are different in nature from the mandatory GHG emissions
reporting rule. Industry participation in the programs and reporting to the programs is entirely
voluntary. A small number of sources report, compared to the number of facilities that will likely
be affected by 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 partner's successes in implementing such projects. For the programs that do
include annual emissions reporting (e.g., Climate Leaders, DOE 1605[b]) the scope and level of
detail are different. For example, Climate Leaders' annual reports are generally corporate-wide
and do not contain the facility and process-level details that would be needed by a mandatory
program to verify the accuracy of the emissions reports.
At the same time, aspects of the voluntary programs serve as useful starting points for the
mandatory GHG reporting rules. Greenhouse gas emission calculation principles and protocols
have been developed for various types of emission sources by Climate Leaders, the DOE
1605(b) program, and some partnerships such as the SFe 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.
2.4.3 Federal Mandatory Reporting Programs
2.4.3.1 A cid Rain Program
The Acid Rain Program (ARP) and NOX Budget Trading Program (NBP) are cap-and-
trade programs designed to reduce emissions of SO2 and NOX7. As a part of those programs,
facilities that serve a generator larger than 25 megawatts (MW) to report emissions. The 40 CFR
Part 75 continuous emissions monitoring rule establishes monitoring and reporting requirements
under these programs. The regulations in 40 CFR part 70 require continuous monitoring and
quarterly and annual emissions reporting of CO2 mass emissions, SO2 mass emissions, NOX
emission rate, and heat input. Part 75 contains specifications for the types of monitoring systems
that may be used to determine CO2 emissions and sets forth operations, maintenance, and quality
assurance/quality control (QA/QC) requirements for each system. In some cases, EGUs are
allowed to use simplified procedures other than CEMS(e.g., monitoring fuel feed rates and
7For more information about these cap and trade programs see http://www.epa.gov/airmarkets/
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conducting periodic sampling and analyses of fuel carbon content) to determine CC>2 emissions.
Under the regulations, affected EGUs must submit detailed quarterly and annual CC>2 emissions
reports using standardized electronic reporting formats. If CEMS are used, the quarterly reports
include hourly CEMS data and other information used to calculate emissions (e.g., monitor
downtime). If alternative monitoring programs are used, detailed data used to calculate CC>2
emissions must be reported.
The joint explanatory statement accompanying the FY2008 Consolidated Appropriations
Amendment specified that EPA could use the existing reporting requirements for electric
generating units under section 821 of the 1990 CAA Amendments. As described in Sections
V.C. and V.D. of this preamble, because the part 75 regulations already require reporting of high
quality CC>2 data from EGUs, the GHG reporting rule uses the same CC>2 data rather than require
additional reporting of CC>2 from EGUs. They will, however, have to include reporting of the
other GHG emissions, such as CH4 and N2O, at their facilities.
2.4.3.2 Toxics Release Inventory
TRI requires facility-level reporting of annual mass emissions of approximately 650 toxic
chemicals. If they are above established thresholds, facilities in a wide range of industries report
including manufacturing industries, metal and coal mining, electric utilities, and other industrial
sectors. Facilities must submit annual reports of total stack and fugitive emissions of the listed
toxic chemicals using a standardized form which can be submitted electronically. No information
is reported on the processes and emissions points included in the total emissions. The data
reported to TRI are not directly useful for the GHG rule because TRI does not include GHG
emissions and does not identify processes or emissions sources. However, the TRI program is
similar to the GHG reporting rule in that it requires direct emissions reporting from a large
number of facilities (roughly 23,000) across all major industrial sectors. Therefore, EPA
reviewed the TRI program for ideas regarding program structure and implementation.
2.4.3.3 Vehicle Reporting
EPA's existing criteria pollutant emissions certification regulations, as well as the fuel
economy testing regulations which EPA administers as part of the CAFE program, require
vehicle manufacturers to measure and report CC>2 for essentially all of their light duty vehicles.
In addition, many engine manufacturers currently measure CC>2 as an integral part of calculating
emissions of criteria pollutants, and some report CC>2 emissions to EPA in some form.
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2.4.4 Other EPA Emissions Inventories
2.4.4.1 National Emissions Inventory
EPA compiles the National Emissions Inventory (NEI), a database of air emissions
information provided primarily by state and local air agencies and tribes. The database contains
information on stationary and mobile sources that emit criteria air pollutants and their precursors,
as well as hazardous air pollutants. Stationary point source emissions that must be inventoried
and reported are those that emit over a threshold amount of at least one criteria pollutant. Many
states also inventory and report stationary sources that emit amounts below the thresholds for
each pollutant. The point source NEI includes over 60,000 facilities. Required point source
information consists of facility identification information; process information detailing the types
of air pollution emission sources, air pollution emission estimates (including annual emissions),
control devices in place, stack parameters, and location information. The NEI differs from the
GHG reporting rule in that the NEI contains no GHG data, and the data are reported primarily by
State agencies rather than directly reported by industries. However, in developing the rule, EPA
used the NEI to help determine sources that might need to report under the GHG reporting rule.
We considered the types of facility, process and activity data reported in NEI to support the
emissions data as a possible model for the types of data to be reported under the GHG reporting
rule.
2.4.5 State and Regional Voluntary Programs for Greenhouse Gas Emissions Reporting
A number of States have demonstrated leadership and developed corporate voluntary
GHG reporting programs individually or joined with other States to develop GHG reporting
programs as part of their approaches to addressing GHG emissions. The following discussion
summarizes two prominent voluntary efforts. In developing the greenhouse rules, EPA reviewed
the relevant protocols used by these programs as a starting point. We recognize that these
programs may have additional monitoring and reporting requirements than those outlined in the
rule in order to provide distinct program benefits.
2.4.5.1 California Climate A ction Registry
The California Climate Action Registry (CCAR) is a voluntary GHG registry already in
use in California. CCAR has released several methodology documents, including a general
reporting protocol, general certification (verification) protocol, and several sector-specific
protocols. Companies submit emissions reports using a standardized electronic system. Emission
reports may be aggregated at the company level or reported at the facility level.
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2.4.5.2 The Climate Registry
The Climate Registry (TCR) is a partnership formed by U.S. and Mexican states,
Canadian provinces, and tribes to develop standard GHG emissions measurement and
verification protocols and reporting system capable of supporting mandatory or voluntary GHG
emission reporting rules and policies for its member states. TCR has released a final General
Reporting Protocol that contains procedures to measure and calculate GHG emissions from a
wide range of source categories. They have also released a general verification protocol, and an
electronic reporting system. Founding reporters (companies and other organizations that have
agreed to voluntarily report their GHG emissions) implemented a pilot reporting program in
2008. Annual reports will be submitted covering six GHGs. Corporations must report facility-
specific emissions broken out by type of emission source (e.g., stationary combustion, electricity
use, direct process emissions) within the facility.
2.4.6 State and Regional Mandatory Programs for Greenhouse Gas Emissions Reporting
and Control
Several individual States and regional groups of States have demonstrated leadership and
are developing or have developed mandatory GHG reporting programs and GHG emissions
control programs. This section of the preamble summarizes two regional cap-and-trade programs
and several State mandatory reporting rules. We recognize that, like the current voluntary
regional and State programs, State and regional mandatory reporting programs may evolve or
develop to include additional monitoring and reporting requirements than those included in the
rule. In fact, these programs may be broader in scope or more aggressive in implementation
because the programs are either components of established reduction programs (e.g., cap and
trade) or being used to design and inform specific measures that indirectly reduce GHG
emissions (e.g., energy efficiency).
2.4.6.1 Regional Greenhouse Gas Initiative
The Regional Greenhouse Gas Initiative (RGGI) is a regional cap-and-trade program that
covers CC>2 emissions from EGUs larger than 25 MW in member states in the Mid-Atlantic and
Northeast. The program goal is to reduce CC>2 emissions to 10% below 1990 levels by the year
2020. RGGI will utilize the CO2 reported to and QA/QCed by EPA under 40 CFR Part 75 to
determine compliance of the EGUs in the cap-and-trade program. In addition, the EGUs in RGGI
that are not currently reporting to EPA under the Acid Rain and NOX Budget programs (e.g., co-
generation facilities) will start reporting their CC>2 data to EPA for QA/QC, similar to the sources
already reporting. 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
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model rule) to implement RGGI in each state. The RGGI cap-and-trade program took effect on
January 1, 2009.
2.4.6.2 Western Climate Initiative
WCI is another regional cap-and-trade program being developed by a group of Western
States and Canadian provinces. The goal is to reduce GHG emissions to 15 percent below 2005
levels by the year 2020. Draft options papers and program scope papers were released in early
2008, public comments were reviewed, and final program design recommendations were made in
September 2008. Other elements of the program, such as reporting requirements, market
operations, and offset program development continues. Several source categories are being
considered for inclusion in the cap and trade framework. 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-
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.
2.4.7 State Mandatory Greenhouse Gas Reporting Rules
Seventeen states have developed, or are developing, mandatory GHG reporting rules.8
The docket for this rule 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 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 and ARP.
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 sectors (e.g., large EGUs, cement plants,
refineries). Some state rules apply to any facility with stationary combustion sources that emit a
threshold level of CO2. Some apply to any facility, or to facilities within listed industries, if their
emissions exceed a specified threshold level of CO26. Many of the state rules apply to six GHGs
covered by this rule (CO2, methane, nitrous oxide, HFCs, PFCs, SFe); others apply only to CO2
or a subset of the six gases. Most require reporting at the facility level, or by unit or process
within a facility.
8These are California, Colorado, Connecticut, Delaware, Hawaii, Iowa, Maine, Maryland, Massachusetts, New
Jersey, New Mexico, North Carolina, Oregon, Virginia, Washington, West Virginia, and Wisconsin.
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The level of specificity regarding GHG monitoring and calculation methods varies. Some
of the states refer to use of protocols established by TCR or CCAR, to industry-specific protocols
(such as methods developed by the American Petroleum Institute [API]), to accepted
international methodologies such as IPCC, and/or to emission factors in EPA's Compilation of
Air Pollutant Emission Factors (known as AP-42) or other EPA guidance.
2.4.7.1 California Mandatory Greenhouse Gas Reporting Rule
The mandatory reporting rule of the California Air Resources Board (CARB) is an
example of a state rule that covers multiple source categories and contains relatively detailed
requirements, similar to this proposal developed by EPA. The regulation became effective on
January 2, 2009. According to CARB, selected facilities (e.g. general stationary combustion
facilities outside the oil-and-gas sector, and electricity generation and cogeneration plants not
within the operational control of larger facilities and entities) are required to file their first
emissions data reports by April 1, 2009. The rest of the facilities and entities report by June 1,
2009 (see http://www.arb.ca.gov/cc/reporting/ghg-rep/ghgschedadvisory.pdf). The rule requires
facility-level reporting of all GHGs (except PFCs) from cement manufacturing plants, electric
power generation and retail markets, cogeneration plants, petroleum refineries, hydrogen plants,
and facilities with stationary combustion sources emitting greater than 25,000 tons CC>2 per year.
Part 75 (ARP) data will be used for EGUs. The regulation contains specific GHG estimation
methods that are largely consistent with CCAR protocols, and also relies on API protocols and
IPCC/European Union protocols for certain types of sources. California continues to participate
in other national and regional efforts, such as TCR and WCI, to assist with developing consistent
reporting tools and procedures on a national and regional basis.
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SECTION 3
DEVELOPMENT OF THE MANDATORY REPORTING RULE
To develop the Mandatory GHG Reporting Rule, EPA considered various dimensions of
the reporting program and developed and evaluated several options for each dimension. After a
preliminary evaluation of the options for each dimension, a recommended reporting program
alternative was selected. Several possible program alternatives were selected, generally by
varying one dimension at a time, while retaining the recommended option for the other
dimensions. These alternatives were then evaluated based on estimated cost, cost-effectiveness
(cost per ton of emissions reported), and estimated impacts on small entities. This process is
discussed in greater detail below.
3.1 Rule Dimensions for Which Options Were Identified
Possible designs for the Mandatory GHG Reporting Rule were developed by varying
options across four dimensions:
1. Thresholds: In the language of the appropriations bill that calls for the development
of the reporting rule, the EPA Administrator is called upon to identify "appropriate
thresholds" above which facilities are required to report their GHG emissions.
Thresholds may be based on production or productive capacity, or they may be based
on emissions.
2. Measurement Methodology: To be able to report their GHG emissions, facilities
will be required to measure them using an appropriate methodology. Generally,
measurement methodologies may be based on instrumentation and direct
measurement, or on calculation of measurements based on other data available to the
facility (e.g., activity data and emissions factors).
3. Reporting Frequency: Reporting frequency may be annual, quarterly, or monthly.
4. Verification: For QA/QC purposes, a facility's reported emissions of GHG could be
verified, either by the Agency receiving the report (EPA, in this case), or by a third
party, or reported emissions could be self-certified by the reporter without
independent verification.
The options EPA considered for each dimension are discussed below and summarized in
Table 3-1.
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Table 3-1. Options Considered in Developing Scenarios (Recommended Option
Indicated by Shading)
Threshold
Methodology
Frequency
Verification
Capacity-based
Emissions based l,000t CO2e
Emissions-based 10,000
tCO2e
Emissions-based 25,000
tCO2e
Emissions-based 100,000
tC02e
Hybrid: 25,000 tCO2e unless
already reporting based on
capacity under another
program
Only upstream sources report
emissions
Direct measurement (CEMS) Quarterly for all
Hybrid: Direct measurement
for facilities already
reporting and facility-specific
calculations for others
Default emissions factors
from EPA
Existing federal data used for
measurement of fuel
suppliers
Annual for all except
quarterly for facilities
already reporting
quarterly
EPA verifies
Third-party verifier
3.1.1 Thresholds
Three options were considered in setting the threshold above which reporting of GHG
emissions will be required: capacity-based thresholds, emissions-based thresholds, or a hybrid of
the two. Within each option, various definitions and levels of the threshold were examined.
3.1.1.1 Option 1: Capacity-based threshold
A capacity-based threshold would be defined based on the emitting facility's throughput,
production, or productive capacity. In defining the capacity-based threshold, EPA considered
that using a source-level capacity measure for the threshold might be a more straightforward way
for facilities to know that they must report their GHG emissions, but the data on source-level
capacity is not currently universally available to EPA.
3.1.1.2 Option 2: Emissions-based threshold
Option 2 involves the use of actual facility-level emissions of GHGs, measured in metric
tons of CO2-equivalent emissions (tCO2e). Various levels were considered, ranging from 1,000
tCO2e to 100,000 tCO2e. Obviously, lower thresholds would require more sources to participate
in the reporting program. The emissions threshold was analyzed for upstream producers as well.
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In those cases the analyses were done on the quantity of emissions that would occur when the
fuel supplied was combusted or the chemicals supplied were used or released to the atmosphere
at the end of life of the product. An emissions based threshold was not considered for
manufacturers of motor vehicles and engines due to current reporting requirements that require
manufacturers to report in terms of an emissions rate. Given current data availability, an
emissions-based threshold will generally focus on larger, emissions-intensive industries for
which emissions data are readily calculated or measured.
3.1.1.3 Option 3: Hybrid (recommended)
The hybrid threshold option is a combination of three general groups: capacity,
emissions, or entire source category ("All in"). The thresholds developed are generally
equivalent to a facility-wide threshold of 25,000 metric tons of CC^e per year of actual
emissions. The preference is to establish thresholds for as many source categories as possible
based on a capacity metric, for example, tons of product produced per year. A capacity-based
threshold is least burdensome, because a facility would not have to estimate emissions to
determine if the rule applies. However, EPA faces two key challenges in trying to develop
capacity thresholds. First, in most cases, data are insufficient to determine an appropriate
capacity threshold. Secondly, for some source categories, defining the appropriate capacity
metric is infeasible. For example, for some source categories, GHG emissions are not related to
production capacity, but are more affected by design and operating factors.
3.1.2 Measurement Methodology
EPA identified three measurement methodology options, ranging from installing
emissions monitoring equipment on all sources to using default emissions factors to estimate
emissions. The measurement methodology options are discussed below.
3.1.2.1 Option 1: Direct measurement for all reporters
This option would apply direct measurement requirements to all reporters. This would
require facilities to use continuous emissions monitoring systems in the stacks from stationary
combustion units and industrial for solid fuel and processes emissions, continuous measurement
of solid fuel use (or solid fuel production for upstream producers), and fuel flow meters for
liquid and gaseous fuels and for upstream producers.
3.1.2.2 Option 2: Hybrid of direct measurement where already used and facility-specific
calculation for other sources (recommended)
EPA's recommended measurement methodology option would require direct
measurement of emissions from units at facilities that already are required to collect and report
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data using CEMS under other Federally enforceable programs (e.g., ARP, NSPS, NESHAP,
SIPs). facilities to use direct measurement of emissions where facilities are already using CEMS
(e.g., ARP) and Facilities with units that do not have CEMS installed could calculate emissions
using facility-specific information and methods specified in the rule.
3.1.2.3 Option 3: Default emissions factor calculation for both combustion and process
emissions
Under Option 3, EPA would require facilities to base their reported emissions on
simplified calculations performed at the facility level, based on EPA-provided default factors
combined with the type of fuel combusted, the type of process, production rate, and/or the
quantity of fuel/chemical inputs used.
3.1.3 Reporting Frequency
EPA identified two options for reporting frequency: quarterly reports or annual reports.
To minimize costs, EPA recommends annual reports, except for those facilities already reporting
quarterly under another program.
3.1.3.1 Option 1: Quarterly
Under Option 1, all reporters would be required to submit their emissions data quarterly.
3.1.3.2 Option 2: Annually (recommended)
Under Option 2, EPA would require all reporters to submit their emissions data annually,
except for those facilities already reporting data quarterly to the Energy Information
Administration or for existing mandatory reporting programs, such as ARP.
3.1.4 Verification
For QA/QC purposes, facility emissions reports could be verified by an outside entity,
whether the government or a private third party. A third option is self-certification by the
reporter without any independent verification.
3.1.4.1 Option 1: EPA as verifier (recommended)
Under this option, the reporter submits and self-certifies emissions data and other
specified activity data directly to EPA., and EPA would review the emissions estimates and the
supporting data contained in the reports, and perform other activities (e.g., comparison of data
across similar facilities, site visits) to verify that the reported emissions data are accurate and
complete, and perform the QA/QC checks using the submitted information. This is the approach
used for verification under ARP and a number of other EPA and federal programs.
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3.1.4.2 Option 2: Third-party verifier
Under this option, the reporter would self-certify their emissions data and also hire a
private firm to verify their data and estimation methods prior to submitting the emissions data to
EPA. The private firm would likely be required to be selected from a list of such firms that have
been pre-certified by EPA. This third-party verification is similar to the approach used for the
California mandatory reporting rule and the Climate Registry.
3.2 Selected Option
As described above, EPA evaluated a variety of options for each dimension of the GHG
reporting program, and selected a preferred or recommended option for each dimension.
Table 3-1 illustrates the options examined under each dimension, and shows the recommended
option by shading. We summarize the recommended option for each dimension below.
• Threshold: Hybrid approach
— The thresholds fall generally into three groups: capacity, emissions, or entire
source category ("All in"). Typically, a facility that emits 25,000 metric tons
CO2e/year or more reports all sources for which there are methods.
The capacity and "all-in" thresholds are roughly equivalent to 25,000 metric tons
CO2e/year.
— A facility may be subject to a capacity threshold when already reporting (e.g.,
ARP) or to another type of threshold due to unique issues or where an emissions-
based threshold is not practical (e.g., GHG generation threshold for landfills).
• Methodology: Combination of direct measurement and source-specific calculation
methodologies
- Direct measurement of emissions from units at facilities that are already required
to collect and report data using continuous emission monitoring systems under
other Federally enforceable programs, including for other regulatory programs
(e.g., CC>2 emissions from Electricity Generating Units [EGUs] in ARP;
requirements of NSPS, NESHAP, SIP)
— Source-specific calculation methods using facility-specific information for other
sources at the facility
• Reporting Frequency: Annual
— All reporters would report their emissions annually.
— An exception exists for those already reporting quarterly for existing mandatory
programs (e.g., ARP, EIA).
• Verification: Self-certification with EPA verification
— A facility would report emissions data and supporting information directly to
EPA; EPA will use the information to verify the data.
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3.3 Alternative Scenarios Evaluated
EPA developed alternative reporting scenarios and assessed the costs and emissions
associated with each. Alternative scenarios were developed by creating the recommended
scenario (the recommended option for each dimension, as shown in Table 3-1), then varying the
levels in one dimension while keeping the other three dimensions at the recommended options.
The alternative reporting scenarios evaluated are listed below:
1. A 1,000 tCO2e threshold; recommended options for methodology, frequency, and
verifier.
2. A 10,000 tCO2e threshold; recommended options for methodology, frequency, and
verifier.
3. A 100,000 tCO2e threshold; recommended options for methodology, frequency, and
verifier.
4. Direct techniques (CEMS, flow meters) are used to measure emissions; recommended
option for threshold, frequency, and verifier.
5. Default emissions factors (simplified methods) are used to measure emissions;
recommended option for threshold, frequency, and verifier.
6. Existing federal data used for measurement of fuel suppliers; recommended option
for threshold, frequency, verifier, and methodology for other sources.
7. EPA uses default carbon content for fuel suppliers; recommended option for
threshold, frequency, verifier, and methodology for other sources.
8. Reporting is quarterly; recommended option for threshold, methodology, and verifier.
9. Verification is done by a third party; recommended option for threshold,
methodology, and frequency.
10. Only upstream sources report emissions; recommended option for methodology,
frequency, and verifier.
The evaluation of the alternative reporting scenarios will allow policy makers, regulated entities,
and the general public to see the impact of each variation and assess their cost compared to the
recommended option. Total costs, emissions, and cost-effectiveness of the alternative reporting
scenarios by sector are discussed in Section 4. Additionally, Section 5 provides a qualitative
exploration of the effect on emissions coverage and total cost by moving to substantially lower
thresholds such as 100 or 250 tCO2e.
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3.4 Data Quality for This Analysis
For this analysis, EPA gathered existing data from EPA, industry trade associations,
states, and publicly available data sources (e.g., labor rates from the Bureau of Labor Statistics
[BLS]) to characterize the processes, sources, sectors, facilities, and companies/entities 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 (e.g., whether CC>2 or non-CC>2 CEMS
were already in use for combustion sources in specific sectors, typical labor hours required for
developing QA plans and performing fuel sampling), and an estimate of incremental activities
required to comply with the rule. Existing models, such as EPA's CEMS cost model, were used
across sectors to ensure consistency of cost inputs and assumptions.
The most important elements affecting the data quality for this analysis include the
number of affected facilities in each source category, the number and types of combustion units
at each facility, the number and types of production processes that emit GHGs, process inputs
and outputs (especially for monitoring procedures that involve a carbon mass balance), and the
measurements that are already being made for reasons not associated with the rule (to allow only
the incremental costs to be estimated). Many of the affected sources categories, especially those
that are the largest emitters of GHGs (e.g., electric utilities, industrial boilers, petroleum
refineries, cement plants, iron and steel production, pulp and paper) are subject to national
emission standards. In the development of those national standards, detailed background
information was gathered to characterize the industry (e.g., number of facilities, types of
processes, capacity), and this information was a valuable source of high quality data. The
background information for standards development, often collected from industry surveys, was
supplemented from numerous sources, including industry surveys from the U.S. Census Bureau,
trade associations, and operating permits, for example. Information on measurements that are
already made (and thus would not be associated with the rule) was obtained from discussions
with industry representatives, knowledge gained from previous site visits, and other sources. The
data collected to characterize the facilities in the various source categories are judged to be of
good quality and the best that is publicly available.
Other elements affecting the quality of the data include estimates of labor hours to
perform specific activities, cost of labor, and cost of monitoring equipment. Estimates of labor
hours were based on previous analyses of the costs of monitoring, reporting, and recordkeeping
for other rules; information from the industry characterization on the number of units or process
inputs and outputs to be monitored, and engineering judgment. Labor costs were taken from the
3-7
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BLS and adjusted to account for overhead. Monitoring costs were generally based on cost
algorithms or approaches that had been previously developed, reviewed, accepted as adequate,
and used specifically to estimate the costs associated with various types of measurements and
monitoring. The data quality associated with these elements of the cost analysis is analogous to
the quality of data used in the development of numerous other Information Collection Requests
for the different industrial source categories.
3-8
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SECTION 4
ENGINEERING COST ANALYSIS
4.1 Introduction
EPA estimated costs of complying with the rule for process emissions of GHGs in each
affected industrial facility, as well as emissions from stationary combustion sources at industrial
facilities and other facilities, and emissions of GHGs from mobile sources. EPA used available
industry and EPA data to characterize conditions at affected sources. Incremental monitoring,
recordkeeping, and reporting activities were then identified for each type of facility, and the
associated costs were estimated.
4.2 Overview of Cost Analysis
The costs of complying with the rule will vary from one facility to another, depending on
the types of emissions, the number of affected sources at the facility, existing monitoring,
recordkeeping, and reporting activities at the facility, etc. The costs include labor costs for
performing the monitoring, recordkeeping, and reporting activities necessary to comply with the
rule. For some affected facilities, costs include monitoring, recording, and reporting of GHG
emissions from production processes and from stationary combustion units. For other facilities,
the only emissions of GHGs are from stationary combustion. All costs referred to in this section
are reported in 2006 dollars.
For each source category, we first provide a general overview of baseline reporting (if
data are available); two costs components associated with this information collection; labor costs
(i.e., the cost of labor by facility staff to meet the information collection requirements of the
rule); and capital and operating and maintenance costs (e.g., the cost of purchasing and installing
monitoring equipment or contractor costs associated with providing the required information).
Additional details of the data, methods, and assumptions underlying the costs are documented in
a separate cost appendix and in accompanying Technical Support Documents (TSDs). The TSDs
also include information on the assumptions and methods used to identify representative entities
or groups of entities used to develop the cost analysis for each subpart.
4.2.1 Baseline Reporting
When data are available to determine how many companies are currently implementing
approaches consistent with the methods at the facility level to meet internal GHG management
programs or state or voluntary reporting programs at the domestic or international level, we
include a discussion of the baseline reporting practices. When data are not available, we are
assuming that none of the facilities in these source categories are currently reporting emissions
4-1
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and that many of the requirements will result in "new" or "full" costs to meet reporting
requirements. Specifically, we are assuming that there will be additional costs for any sampling
and testing in the requirements in methods (i.e., carbon contents of process inputs, such coke,
coal, carbonate composition, or actual emissions). We are also assuming that additional costs
will be incurred for preparing monitoring and QA/QC plans, performing the calculations,
reporting the results, and maintaining records. The only significant element for these sources that
we know is performed routinely by all companies is that they have measurements and records of
consumption of raw materials such as feedstocks, carbonates, and reducing agents as part of their
routine operation for accounting purposes.
4.2.2 Reporting Costs
To ensure consistency in the development of cost estimates across all sources, EPA
developed a cost spreadsheet template that each subpart used to compile, document, and
calculate per unit reporting costs. Please refer back to Section 3 for information on the subpart
process for source categories. Detailed instructions were provided along with the cost
spreadsheet template that clearly explained the data to be compiled and calculated. The template
included three tables; analysis of reporting thresholds, analysis of monitoring and reporting
options, and unit costs for monitoring and reporting. Key variables and data fields were clearly
defined to ensure that each sub group developed costs around a standard set of methods and
assumptions (e.g., method for annualization of capital costs, interest rate to be applied to capital).
Labor Costs. The costs of complying with and administering this rule include the time of
managers, technical, and administrative staff in both the private sector and the public sector.
Staff hours are estimated for activities including
• monitoring (private): staff hours to operate and maintain emissions monitoring
systems;
• reporting (private): staff hours to gather and process available data and reporting it to
EPA through electronic systems; and
• assuring and releasing data (public): staff hours to quality assure, analyze, and release
reports.
Staff activities and associated labor costs may vary over time. Thus, cost estimates are
developed for start-up, first-time reporting, and subsequent reporting.
Loaded hourly labor rates (also referred to as "wage rates") were developed for several
labor categories to represent the employer costs to use an hour of employees' time in each of the
manufacturing sector labor categories used in this analysis. The labor categories correspond to
4-2
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the job responsibilities of the personnel that are likely to be involved in GHG emissions
monitoring activities at the manufacturing facility level to comply with the rulemaking.
For purposes of this study, EPA adopted the methodology used by Cody Rice (2002) to
calculate the wage rates for the EPA's Toxics Release Inventory (TRI) Program. Thus, the wage
rates calculated for different labor categories included the employer costs for employee
compensation (comprising the basic wages and the corresponding benefits) and the overhead
costs to the employer9
For each labor category, the following formula was used to calculate the wage rates:
Loaded Hourly Labor Rate ($/hr.) = Basic Wages ($/hr.) *
(1 + Benefits Loading Factor + Overhead Loading Factor).
The benefits loading factor corresponds to the relative share of benefits compensation in
the total employee compensation (comprising basic wages and benefits). Although the benefits
factor tends to vary by labor category and by industry (0.37 to 0.50), for purposes of this
analysis, we have assumed the benefits loading factor (1.7) to remain the same for each labor
category across all industries within the manufacturing sector due to a lack of availability of
necessary industry-specific data on benefits paid to employees.
The overhead loading factor corresponds to the share of overhead costs to the employer
relative to the total employee compensation. For purposes of this analysis, we have also adopted
the same overhead loading factor that Cody Rice (2002) used in her wage rate calculations. Thus
the overhead loading factor that we used in the wage rate calculations remains the same for all
labor categories and across all industry types within the manufacturing sector. The overhead
loading factor was assumed to be 0.17.
The loaded labor rates for eight labor categories are used in the analysis and are also
reported in the appropriate sectors labor cost tables in the following sections. They include
• electricity manager: $88.79;
• refinery manager: $101.31;
• industrial manager: $71.03;
• lawyer: $101.00;
9For each employee, the employer also incurs overhead costs (comprising the rental costs of the office space,
computer hardware and software, telecommunication and other equipments, organizational support, etc.)
required for and used by the employee to effectively fulfill his/her job responsibilities. These costs are over and
above the employee compensation costs.
4-3
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• electricity engineer/technician: $60.84;
• refinery engineer/technician: $63.89;
• industrial engineer/technician: $55.20; and
• administrative support: $29.65.
Capital and O&M Costs. This includes the cost of purchasing and installing monitoring
equipment or contractor costs associated with providing the required information. Selected
subparts do not require capital expenditures because the selected monitoring option does not
require capital equipment or the reporter already owns the necessary monitoring equipment.
Equipment costs include both the initial purchase price of monitoring equipment and any
facility/process modification that may be required. For example, the cost estimation method for
mobile sources involves upstream measurement by the vehicle manufacturers. This may require
an upgrade to their test equipment and facility. Based on expert judgment, the engineering costs
analyses annualized capital equipment costs with the appropriate lifetime and interest rate
assumptions. Cost recovery periods vary by industry (5 to 15 years) with one-time capital costs
are amortized at a rate of 7%.
Other Recordkeeping and Reporting. Additional recordkeeping ($1,700 per entity) and
reporting ($500) costs were also added to the majority of sectors.
Reporting Determination. A potentially large number of facilities would need to calculate
their emissions in order to determine whether or not they had to report under the rule. Therefore,
to further minimize the burden on those facilities, any facility that has an aggregate maximum
rated heat input capacity of the stationary fuel combustion units less than 30 mmBtu/hr may
presume it has emissions below the threshold. According to our analysis, a facility with
stationary combustion units that have a maximum rated heat input capacity of less than 30
mmBtu/hr, operating full time (e.g., 8,760 hours per year) with all types of fossil fuel would not
exceed 25,000 metric tons CO2e/yr (EPA-HQ-OAR-2008-0508-049). Under this approach, we
estimate that 30,000 facilities will have to assess whether or not they have to report based on
stationary combustion activities. Of the 30,000, approximately 10,100 facilities would likely
meet the threshold and have to report. Therefore, an additional 19,900 facilities may have to
assess their applicability but potentially not meet the threshold for reporting. The rule requires
facilities to follow methodologies in the rule to make a determination. It is assumed that a facility
would utilize a fuel sampling methodology. The costs for this activity are outlined below:
• Planning costs assumed to include:
— 2 hours (industrial engineer/technician) for regulatory review
- 4 hours (industrial engineer/technician) to resolve questions
4-4
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- 4 hours (industrial engineer/technician) to develop sampling approach
• Recordkeeping and reporting costs assumed to include:
— 2 hours (industrial engineer/technician) for data reduction and review
• Fuel sampling costs assume 1 hour (industrial engineer/technician) and $150 lab cost
per sample.
Using the labor costs presented in Section 4.2.2 (industrial engineer/technician—
$55.20/hr) the total cost of the determination activity would be $867.60 per facility. These costs
would be for a one-time fuel sampling and are based on the costs for monthly fuel sampling
outlined in Section 4.3. We are soliciting comment and gathering information on an alternative
means of reporting determination that would provide simplified emissions calculation tools for
certain source categories. The use of such tools could reduce the cost of the determination
activity.
EPA estimates the public sector burden to be $17 million per year. $3.5 million per year
is for verification activities, and $13.5 million per year is for program implementation and
developing and maintaining the data collection system. Program implementation activities
include, but are not limited to, developing guidance and training materials to assist the regulated
community, responding to inquires from affected facilities on monitoring and applicability
requirements, and developing tools to assist in determining applicability.
4.2.3 Cost Analysis Summary by Subpart
At the end of this Section 4, we summarize the total facilities covered, emissions covered,
and the cost information for each subpart. The data are the basis for the economic impact
analysis described in detail in Section 5 of this document. This chapter provides these data, as
well as background information needed to understand the engineering costs analysis conducted
for each source and the reporting option selection.
4.3 Subpart C—General Stationary Fuel Combustion Sources and Subpart D—
Electricity Generation and Other Stationary Combustion Sources
Stationary combustion sources include stationary fossil fuel combustion units producing
GHG emissions. Stationary combustion units include electricity generating units, boilers,
furnaces, turbines, and kilns, among others. Costs for monitoring GHG emissions from stationary
combustion sources were developed for several monitoring categories, listed in Table 4-1. Due to
the methodological approaches taken, separate costing analyses were performed for monitoring
methods for combustion-related CC>2 emissions and monitoring methods for non-CC>2 emissions
(e.g., CH4 and N2O). For combustion-related non-CC>2 emissions, EPA will use IPCC default
emissions factors. These factors will be applied based on the fuel type used, thus there is minimal
cost to reporters for combustion-related non-CO2 emissions.
4-5
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Table 4-1. Per Unit Cost Breakdown by Monitoring Category: Stationary Combustion (2006$)
Scenario
CEMS-Add CO2 analyzer
and flow meter
CEMS-Add CO2 analyzer
only
CEMS-Add flow monitor
only
CEMS part 75 Appendix G
(non-ARP): add CO2 data
stream
CEMS part 75 ARP units-
report annual CO2,
methane and nitrous oxide
Daily fuel sampling
Description
Applies to non-Part 75, non-EGU (industrial)
units where O2 analyzers will not suffice, e.g.,
sources with process emissions (cement, lime,
glass).
Applies to non-Part 75, non-EGU (industrial)
combustion units and cogens that have a flow
monitor and NOX or SO2 analyzer
Applies to non-Part 75, non-EGU (industrial)
combustion units and cogens that have a CO2 or
O2 analyzer, consistent fuel and no process
emissions. We are assuming that 90% of solid
fossil fueled >250 mmBtu units have Part 60
analyzers.
Part 75 Appendix G oil and gas fired units that
will use default factors to calculate emissions.
Coal-fired units are assumed to have O2 or CO2
diluent in which case they will add the CO2 data
stream to their DAS.
ARP units already report CO2 so the only
change here is for the annual report.
Continuously measuring fuel use and daily
sampling of fuel characteristics for combustion
emissions, e.g., refinery, petrochem where
process control is in place.
Tier
4
4
4
4
4
3
Total
$56,040
$20,593
$24,511
$2,500
$1,000
$20,466
Annualized First-time Costs
Equipment
Purchase
Labor Costs and
Costs Other ODCs Total
$24,770 $6,024 $30,793
$7,421 $1,033 $8,454
$6,421 $4,199 $10,620
$0 $0 $0
$0 $0 $0
$2,770 $364 $3,134
Annual O&M Costs
Other
Labor Direct
Costs Costs Total
$20,629 $4,618 $25,247
$9,556 $2,583 $12,139
$11,342 $2,549 $13,891
$2,500 $0 $2,500
$1,000 $0 $1,000
$15,284 $2,049 $17,333
4-
O\
(continued)
-------
Table 4-1. Per Unit Cost Breakdown by Monitoring Category: Stationary Combustion (2006$) (continued)
Scenario
Monthly fuel sampling
Periodic in-stack gas
sampling
Periodic off-site flue gas
analysis
Description
Continuously measuring fuel use and monthly
sampling of fuel characteristics for combustion
emissions is sufficient.
Cost for site-specific EFs by periodically
sampling in-stack flue gas for process or
combustion emissions (or both).
Cost for site-specific EFs by periodically
sampling flue gas for process or combustion
emissions (or both). Analysis is off-site.
Tier
3
3
3
Total
$4,613
$12,322
$5,301
Annualized First-time Costs
Equipment
Purchase
Labor Costs and
Costs Other ODCs Total
$1,886 $0 $1,886
$4,234 $0 $4,234
$2,174 $0 $2,174
Annual O&M Costs
Other
Labor Direct
Costs Costs Total
$1,767 $960 $2,727
$7,729 $360 $8,089
$978 $2,148 $3,126
-------
For costing purposes, the monitoring categories for CC>2 were divided into those that
required the installation of new stack monitoring equipment (namely CEMS) and those that
relied on analysis of fuels that are combusted. For the stack monitoring categories, different costs
were assumed based on existing configurations of CEMS equipment.
A range of data sources were used to develop these per unit cost estimates. These datasets
include information currently collected by EPA under existing programs and other proprietary
databases.
For estimating costs for units within the electricity generation sector, data currently
collected under the Acid Rain Program was used. The data includes both fuel usage and CEMS
equipment installed. Additionally, EPA's EGrid database of electricity generation in the United
States contained information on facilities that are not reporting to the Acid Rain Program. The
majority of those data are provided to EGrid from DOE's Energy Information Administration
(EIA) survey forms. The database Velocity Suite® (Ventyx, 2008) was also used to cross-
reference these information sources.
For units in industrial sectors, the primary sources of data on individual units were EPA
analyses on certain industrial sectors, and a characterization of the U.S. boiler population.
Information on existing CEMS was collected from data already reported to EPA's NOX Budget
Trading Program. An overall examination of the fuels used in the industrial sector was
performed using data from EIA's 2002 Manufacturing Energy Consumption Survey (MECS).
For large emitters in the commercial sector, EIA's 2003 Commercial Building Energy
Consumption Survey (CBECS) was referenced, as well as EEA's Characterization of the U.S.
Industrial Commercial Boiler Population.
From these datasets, the appropriate information on the fuel being used at facilities was
gathered. Foremost, data was collected that allowed the determination to be made on whether a
solid fuel was being combusted at a large stationary combustion unit. In the event that a solid
fuel was combusted by such a large unit, additional details were available to understand existing
CEMS equipment and the appropriate upgrade costs to meet the requirements in this rule. For
those facilities that combusted natural gas or petroleum fuels, only a fuel analysis is required,
and the appropriate costing scenario was then applied.
4-8
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4.3.1 Labor Costs
Both first year and annual labor costs were constructed by estimating the number of staff
hours required to perform the activities and multiplying them by the relevant wage rate. Wage
rates to monetize staff time were obtained from the Bureau of Labor Statistics. Wage rates for
other various labor categories (e.g., manager, environmental engineer, engineering technician,
administrative support) were used as appropriate. A detailed breakdown of labor costs and other
costs for each monitoring category is provided in Table 4-1. Additional cost details for each
monitoring category are included in Tables 4-2a to 4-21. These tables describe the
requirements/activities for each category and show the labor hours and costs, consultant costs,
and other direct costs (ODCs).
4.3.2 Capital and O&M Costs
In addition to labor costs, some firms must also purchase equipment in order to comply
with the rule. Equipment purchase costs are upfront costs, frequently paid for over a period of
time. Therefore, these costs are annualized costs over a 15-year timeframe (which corresponds to
the expected lifetime of the equipment) and discounted at a rate of 7%. Firms complying with the
rule will incur O&M costs each year. These costs can be separated into a labor component,
accounted for in the above discussion of labor costs, and other direct costs, including the cost of
consumables and all other materials that may be required.
4-9
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Table 4-2a. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS-Add CO2 Analyzer and Flow Meter (2006$)
First costs
Planning
Select equipment
Support facilities
Purchase CEMS hardware
Install and check CEMS
Performance specification tests
QA/QC plan
Subtotal first costs
Annualized first costs
Annual costs
Day-to-day activities
Annual RAT A
Cylinder gas audits
Recordkeeping and reporting
Annual QA and O&M review and update
Subtotal annual costs
Total annualized first costs + annual costs
Labor
$3,477
$9,281
$0
$0
$2,987
$331
$1,500
$17,577
$17,577
$3,533
$800
$1,325
$1,214
$2,539
$9,411
$26,988
Consultants
(D
J>
$—
$—
$—
$—
$693
$6,500
$7,193
$7,193
$—
$11,218
$—
$—
(D
J>
$11,218
$18,411
ODCs
$364
$650
$5,400
$44,403
$3,970
$75
$—
$54,862
$6,024
$1,000
$—
$1,069
$50
$2,499
$4,618
$10,642
Table 4-2b. Detailed Summary of Stationary Combustion Monitoring Category
Total
$3,841
$9,931
$5,400
$44,403
$6,957
$1,099
$8,000
$79,632
$30,793
$4,533
$12,019
$2,393
$1,264
$5,038
$25,247
$56,040
Costs:
CEMS-Add CO2 Analyzer Only (2006$)
First costs
Planning
Select equipment
Purchase CEMS hardware
Install and check CEMS
Subtotal first costs
Annualized first costs
Annual costs
Day-to-day activities
Annual RATA
Cylinder gas audits
Recordkeeping and reporting
Annual QA and O&M review and update
Subtotal annual costs
Total annualized first costs + annual costs
Labor
$1,104
$2,602
$0
$2,214
$5,921
$6,921
$883
$304
$773
$883
$1,104
$3,947
$10,867
Consultants
$—
$—
$—
$—
$—
$500
(D
J>
$5,609
$—
$—
$—
$5,609
$6,109
ODCs
$—
$355
$8,363
$690
$9,408
$1,033
$—
$—
$534
$50
$1,999
$2,583
$3,616
Total
$1,104
$2,957
$8,363
$2,904
$15,329
$8,454
$883
$—
$—
$933
$3,103
$12,139
$20,593
4-10
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Table 4-2c. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS-Add Flow Monitor Only (2006$)
First costs
Planning
Select equipment
Purchase CEMS hardware
Install and check CEMS
Subtotal first costs
Annualized first costs
Annual costs
Day-to-day activities
Annual RATA
Recordkeeping and reporting
Annual QA and O&M review and update
Subtotal annual costs
Total annualized first costs + annual costs
Labor
$1,104
$2,602
$0
$1,214
$4,921
$5,921
$3,442
$304
$883
$1,104
$5,733
$11,653
Consultants
$—
$—
$—
$—
$—
$500
$—
$5,609
$—
$—
$5,609
$6,109
ODCs
$—
$355
$31,800
$690
$32,845
$4,199
$—
$—
$50
$2,499
$2,549
$6,748
Total
$1,104
$2,957
$31,800
$1,904
$37,766
$10,620
$3,442
$5,913
$933
$3,603
$13,891
$24,511
Table 4-2d. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS part 75 Appendix G (non-ARP): Add CO2 Data Stream (2006$)
Labor Consultants ODCs Total
Annual reporting $2,500 $2,500
Total annualized first costs + annual costs $2,500 $2,500
Table 4-2e. Detailed Summary of Stationary Combustion Monitoring Category Costs:
CEMS part 75 ARP Units—Report Annual CO2, Methane and Nitrous Oxide
(2006$)
Labor Consultants ODCs Total
Annual reporting $1,000 $1,000
Total annualized first costs + annual costs $1,000 $1,000
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Table 4-2f. Detailed Summary of Stationary Combustion Monitoring Category Costs:
Daily Fuel Sampling (2006$)
First costs
Planning
QA/QC plan
Subtotal first costs
Annualized first costs
Annual costs
Fuel sampling
Recordkeeping and reporting
Annual QA and O&M review and update
Subtotal annual costs
Total annualized first costs + annual costs
Labor
$1,270
$1,000
$2,270
$2,270
$13,297
$883
$1,104
$15,284
$17,553
Consultants
$—
$500
$500
$500
$—
$—
$—
$—
$500
Table 4-2g. Detailed Summary of Stationary Combustion Monitoring
Monthly Fuel Sampling (2006$)
First costs
Planning
QA/QC plan
Subtotal first costs
Annualized first costs
Annual costs
Fuel sampling
Recordkeeping and reporting
Annual QA and O&M review and update
Subtotal annual costs
Total annualized first costs + annual costs
Labor
$386
$1,000
$1,386
$1,386
$221
$442
$1,104
$1,767
$3,153
ODCs
$364
$—
$364
$364
$—
$50
$1,999
$2,049
$2,413
Category
Consultants ODCs
$—
$500
$500
$500
$—
$—
$—
$—
$500
$—
$—
$—
$—
$600
$50
$310
$960
$960
Total
$1,634
$1,500
$3,134
$3,134
$13,297
$933
$3,103
$17,333
$20,466
Costs:
Total
$386
$1,500
$1,886
$1,886
$821
$492
$1,414
$4,809
$4,613
4-12
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Table 4-2h. Detailed Summary of Stationary Combustion Monitoring Category Costs:
Periodic In-Stack Gas Sampling (2006$)
First costs
Planning
Select equipment
QA/QC plan
Subtotal first costs
Annualized first costs
Annual costs
Annual in-stock sample
Recordkeeping and reporting
Annual QA and O&M review and update
Subtotal annual costs
Total annualized first costs + annual costs
Labor
$1,270
$1,000
$1,000
$3,270
$3,270
$552
$883
$994
$2,429
$5,698
Consultants
$—
$—
$—
$—
$—
$5,300
$—
$—
$5,300
$5,300
ODCs
$364
$100
$500
$964
$964
$—
$50
$310
$360
$1,324
Total
$1,634
$1,100
$1,500
$4,234
$4,234
$5,852
$933
$1,304
$8,089
$12,322
Table 4-2i. Detailed Summary of Stationary Combustion Monitoring Category Costs:
Periodic Off-Site Flue Gas Analysis (2006$)
First costs
Planning
QA/QC plan
Subtotal first costs
Annualized first costs
Annual costs
Fuel sampling
Recordkeeping and reporting
Annual QA and O&M review and update
Subtotal annual costs
Total annualized first costs + annual costs
Labor
$386
$1,000
$1,386
$1,386
$221
$883
$662
$1,766
$3,153
Consultants
$—
$—
$—
$—
$—
$—
$—
$—
$—
$—
ODCs
$288
$500
$788
$788
$1,000
$50
$310
$1,360
$2,148
Total
$674
$1,500
$2,174
$2,174
$1,221
$933
$972
$3,126
$5,301
4-13
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4.3.3 Units Covered
The number of units estimated to report at the 1,000, 10,000, 25,000 hybrid, and 100,000
ton thresholds are reported in Table 4-3. The unit counts reported in this table cover all subparts
of the reporting program with the exception of Subpart H—cement production, Subpart Y—
petroleum refineries, and Subpart Q—iron and steel production. In these cases, the engineering
workgroups directly estimated labor, capital, and O&M costs associated with monitoring
stationary fossil fuel combustion units producing GHG emissions. All estimates were generated
using many of the above mentioned industry-specific databases, as well as expert judgment by
industry experts and EPA.
4.4 Subpart E—Adipic Acid Production
Overview. Costs were developed for the following monitoring method for estimating N2O
emissions from adipic acid production.
Labor Costs. A majority of the labor costs are associated with planning ($1,800) and
sampling and analysis activities ($2,300). These costs cover process emissions.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Reporting requires approximately $2,500 of O&M costs related to equipment,
performance testing, and travel. These costs cover process emissions.
4-14
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Table 4-3. Reporting Units by Threshold and Monitoring Category
Subpart
1,000 Threshold
D
C
C
C
C
H
S
V
G
E
CC
EE
K
Z
GG
R
BB
N
C
P
AA
Description
ARP electricity generation
Non-ARP electricity generation
CAIR electricity generation
MSW combustion
General unspecified industrial
combustion
Cement manufacture
Lime manufacture
Nitric acid production
Ammonia manufacture and urea
consumption
Adipic acid production
Soda ash manufacture and
consumption
Titanium dioxide production
Ferroalloy production
Phosphoric acid production
Zinc production
Lead production
Silicon carbide production and
consumption
Glass
Cogen
Hydrogen
Pulp and paper
Total
Unit Counts by Tier
Total
3,279
1,159
193
2
94,438
107
89
4
24
4
5
8
6
14
9
17
1
217
587
77
1,419
101,659
Tiers
1 or 2
0
1,127
0
93,659
0
0
0
0
0
5
8
0
0
0
0
1
0
0
0
94,800
TierS
0
58
0
598
5
0
0
24
4
0
6
0
9
17
0
217
191
77
937
2,143
Tier 4
3,279
0
193
2
181
102
89
4
0
0
0
0
14
0
0
0
0
396
0
482
4,742
Unit Counts by Monitoring Category
CEMS
Part 75
ARP
CEMS Units-
Part 75 Report
Non- Annual
CEMS- CEMS ARP: CO2, Industry
AddCO2 CEMS- Add Add Methane Monthly Periodic Periodic Specific
Analyzer Add CO2 Flow CO2 and Daily Fuel Fuel In-stack Off-site for
and Flow Analyzer Monitor Data Nitrous Sampling Sampling Gas Flue Gas Process
Monitor Only Only Stream Oxide (comb) (comb) Sampling Analysis Emission
3,279
0 58
193
2
48 133 598
99 3 5
89 0
4
24
4
14
6 17
9
0 217
0 47 164 185 191
77
278 168 36 937
532 0 348 396 3,466 0 2,110 28 0 5
(continued)
-------
Table 4-3. Reporting Units by Threshold and Monitoring Category (continued)
Subpart
10,000 Threshold
D
C
C
C
C
Q
H
Y
S
V
o
G
F
E
I
CC
X
T
EE
K
Z
GG
R
BB
N
C
P
AA
Description
ARP electricity generation
Non-ARP electricity generation
CAIR electricity generation
MSW combustion
General unspecified industrial
combustion
Iron and steel production
Cement manufacture
Petroleum systems — refineries
Lime manufacture
Nitric acid production
HCFC-22 production
Ammonia manufacture and urea
consumption
Aluminum production
Adipic acid production
Semiconductor manufacture
Soda ash manufacture and consumption
Petrochemical production (325-
ethylene, etc.)
Magnesium production and processing
Titanium dioxide production
Ferroalloy production
Phosphoric acid production
Zinc production
Lead production
Silicon carbide production and
consumption
Glass
Cogen
Hydrogen
Pulp and paper
Total
Unit Counts by Tier
Total
3,279
443
116
2
22,120
107
89
4
24
4
5
8
6
14
9
16
1
158
550
73
1,419
28,447
Tiers
1 or 2
0
334
0
21,341
0
0
0
0
5
8
0
0
0
0
1
0
0
0
21,689
TierS
0
109
0
598
5
0
0
24
4
0
6
0
9
16
0
158
154
73
937
2,093
Tier 4
3,279
0
116
2
181
102
89
4
0
0
0
14
0
0
0
0
396
0
482
4,665
Unit Counts by Monitoring Category
CEMS
Part 75
Non-
CEMS- CEMS ARP:
AddCO2 CEMS- Add Add
Analyzer Add CO2 Flow CO2
and Flow Analyzer Monitor Data
Monitor Only Only Stream
0
116
48 133
99 3
89
4
14
0
0 47 164
278 168 36
532 0 348 319
CEMS
Part 75
ARP
Units-
Report
Annual
CO2,
Methane Monthly
and Daily Fuel Fuel
Nitrous Sampling Sampling
Oxide (comb) (comb)
3,279
109
2
598
6 16
9
158
185 154
73
937
3,466 0 2,060
Industry
Periodic Periodic Specific
In-stack Off-site for
Gas Flue Gas Process
Sampling Analysis Emission
24
4
28 0
(continued)
-------
Table 4-3. Reporting Units by Threshold and Monitoring Category (continued)
Subpart
25,000 Threshold
D
C
C
C
C
Q
H
Y
S
V
o
G
F
E
I
CC
X
T
EE
K
Z
GG
R
BB
N
C
P
AA
Description
ARP electricity generation
Non-ARP electricity generation
CAIR electricity generation
MSW combustion
General unspecified industrial
combustion
Iron and steel production
Cement manufacture
Petroleum systems — refineries
Lime manufacture
Nitric acid production
HCFC-22 production
Ammonia manufacture and urea
consumption
Aluminum production
Adipic acid production
Semiconductor manufacture
Soda ash manufacture and consumption
Petrochemical production (325-ethylene,
etc.)
Magnesium production and processing
Titanium dioxide production
Ferroalloy production
Phosphoric acid production
Zinc production
Lead production
Silicon carbide production and
consumption
Glass
Cogen
Hydrogen
Pulp and paper
Total
Total
3,279
341
65
2
8,058
107
89
4
24
4
5
8
6
14
8
13
1
55
485
51
1,419
14,038
Unit Counts by
Tiers
Tier
lor 2 TierS
0
181
0
7,279
0
0
0
0
5
8
0
0
0
0
1
0
0
0
7,474 1,
0
100
0
598
5
0
0
24
4
0
6
0
8
13
0
55
89
51
937
890
Tier 4
3,279
60
65
2
181
102
89
4
0
0
0
14
0
0
0
0
396
0
482
4,674
Unit Counts by Monitoring Category
CEMS
Part 75
ARP
CEMS Units-
Part 75 Report
Non- Annual
CEMS- CEMS ARP: CO2, Industry
Add CO2 CEMS- Add Add Methane Monthly Periodic Periodic Specific
Analyzer Add CO2 Flow CO2 and Daily Fuel Fuel In-stack Off-site for
and Flow Analyzer Monitor Data Nitrous Sampling Sampling Gas Flue Gas Process
Monitor Only Only Stream Oxide (comb) (comb) Sampling Analysis Emission
3,279
60 100
65
2
48 133 598
99 3
89
4
24
4
14
6 13
8
0 55
0 47 164 185 89
51
278 168 36 937
532 0 408 268 3,466 0 1,857 28 0
(continued)
-------
Table 4-3. Reporting Units by Threshold and Monitoring Category (continued)
Subpart
100,000 Threshold
D
C
C
C
C
Q
H
Y
S
V
o
G
F
E
I
CC
X
T
EE
K
Z
GG
R
BB
N
C
P
AA
Description
ARP electricity generation
Non-ARP electricity generation
CAIR electricity generation
MSW combustion
General unspecified industrial
combustion
Iron and steel production
Cement manufacture
Petroleum systems — refineries
Lime manufacture
Nitric acid production
HCFC-22 production
Ammonia manufacture and urea
consumption
Aluminum production
Adipic acid production
Semiconductor manufacture
Soda ash manufacture and consumption
Petrochemical production (325-
ethylene, etc.)
Magnesium production and processing
Titanium dioxide production
Ferroalloy production
Phosphoric acid production
Zinc production
Lead production
Silicon carbide production and
consumption
Glass
Cogen
Hydrogen
Pulp and paper
Total
Unit Counts by Tier
Total
3,279
151
24
0
2,228
107
89
4
24
4
5
8
6
14
5
0
1
1
485
30
1,419
7,884
Tiers
lor 2
0
66
0
1,763
0
0
0
0
5
8
0
0
0
0
1
0
0
0
0
1,843
TierS
0
58
0
337
5
0
0
24
4
0
6
0
5
0
0
1
89
30
937
1,496
Tier 4
3,279
27
24
0
128
102
89
4
0
0
0
14
0
0
0
0
396
0
482
4,545
Unit Counts by Monitoring Category
CEMS
Part 75
ARP
CEMS Units-
Part 75 Report
Non- Annual
CEMS- CEMS ARP: CO2,
AddCO2 CEMS- Add Add Methane Monthly
Analyzer Add CO2 Flow CO2 and Daily Fuel Fuel
and Flow Analyzer Monitor Data Nitrous Sampling Sampling
Monitor Only Only Stream Oxide (comb) (comb)
3,279
64 27
24
0 0
103 25 103
102 99 3
89 89
0 4
0
0
0
0
0
1 14
0
0
0 0
47 0 47 164 185
0
550 278 168 36
956 509 0 345 227 3,464 0
Industry
Periodic Periodic Specific
In-stack Off-site for
Gas Flue Gas Process
Sampling Analysis Emission
58
337
24
4
6
5
1
89
30
937
1,463 28 0
oo
-------
Table 4-4. Subpart E Adipic Acid: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling, analysis,
and calculations
Reporting
Total
Labor Hours
Electricity
Manager
$88.79
First Subseq.
Year Year
Refinery
Manager
$101.31
First Subseq.
Year Year
8
Industrial
Manager
$71.03
First Subseq.
Year Year
2
19 19
4
32 26
Electricity
Lawyer Eng/Tech
$101.00 $60.84
First Subseq. First Subseq.
Year Year Year Year
1 1
1 1
Refinery Industrial
Eng/Tech Eng/Tech
$63.89 $55.20
First Subseq. First Subseq.
Year Year Year Year
16 4
8
8
8 19 19
8
24 24
63
Admin
$29.65
First Subseq.
Year Year
8
1 1
1 1
9 9
18 10
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,790 $464
$494 $494
$494 $494
$2,335 $2,335
$1,898 $1,898
$7,011 $5,685
VO
75
-------
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
Table 4-5. Subpart E Adipic Acid: Capital and O&M Costs (2006$)
Activity
Equipment (selection,
purchase, installation)
Performance testing
Recordkeeping
Travel
Total
Equipment Annualized
Lifetime Capital Cost
Capital Cost (years) (per year)
SO SO
O&M Costs
(per year)
$1,200
$117
$1,234
$2,551
Total Reporting per
Unit/Facility Cost
First
Year
$1,200
$117
$0
$1,234
$2,551
Subseq.
Year
$1,200
$117
$0
$1,234
$2,551
4.5 Subpart F—Aluminum Production
Overview. Aluminum production capacities at U.S. primary production facilities are
generally comparable (low hundreds of thousands of metric tons). Costs were therefore
developed for a single model facility based on reported average labor burdens and annualized
average non-labor costs (Tables 4-6 and 4-7).
Labor Costs. Total labor costs are $13,700; a majority of the costs are associated with
sampling and analysis activities performed by an industrial engineer/technician ($11,600).
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Reporting requires approximately $200 of sampling O&M costs. These costs cover
process emissions.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping, and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) costs.
4-20
-------
Table 4-6. Subpart F Aluminum Production: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
(calculations)
Reporting
Total
Labor Rates
Legal Managerial
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
3 3
53 53
25 25
SO SO
(per hour)
Technical Clerical
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
1 1
142 142
1 1
144 144 1 1
Labor Cost per
Year per Reporting
Unit/Facility3
First Subseq.
Year Year
$286 $286
$0 $0
$0 $0
$11,597 $11,597
$1,794 $1,794
$13,677 $13,677
a Assumes annual sampling; for more information, please refer to the cost appendix.
Table 4-7. Subpart F Aluminum Production: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost O&M Costs
Capital Cost (years) (per year) (per year)
$179
$0 $0 $179
Total Reporting
Cost per
Unit/Facility
First Subseq.
Year Year
$179 $179
$179 $179
4-21
-------
4.6 Subpart G—Ammonia Manufacturing
Baseline Reporting. We do not know how many ammonia manufacturing companies are
estimating and reporting emissions at the facility level to meet internal GHG management
programs or state or voluntary reporting programs at the domestic or international level. We are
assuming that no ammonia manufacturing facilities are currently reporting emissions and that
many of the requirements will result in "new" or "full" costs to meet reporting requirements.
We are assuming that the requirements will result in "full" costs primarily to meet EPA's
reporting requirements. Specifically, we assume that additional costs will be incurred for
preparing monitoring and QA/QC plans, sampling and analysis of feedstock for carbon content,
performing the calculations, reporting the results, and maintaining records. The only significant
element of the approach that we know is performed routinely by all companies is that they have
measurements and records of fuel and feedstock consumed as part of their routine operation for
accounting purposes.
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size. The selected option requires continuous measurement of fuel;
internal development of the methodology and monitoring plan for calculating emissions from
production process; managers' reviews of samples per sampling period; contacting supplier to
get the carbon content of the reducing agent; and QA/QC of supplier information on carbon
content of the reducing agent.
Labor Costs. Total labor costs are $2,000 in the first year and $800 in subsequent years; a
majority of the labor costs are associated with sampling and analysis activities performed by an
industrial engineer/technician.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Reporting requires approximately $200 of sampling O&M costs.
4-22
-------
Table 4-8. Subpart G Ammonia: Labor Costs (2006$)
Activity
Planning3
QA/QCb
Recordkeeping
Sampling and analysis0
Reporting
Total
Labor Rates (per hour)
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq First Subseq.
Year . Year Year Year
11 82
2 2
1 1 10 4
Industrial
Engineer/
Technician
$55.20
First Subseq.
Year Year
16 4
4 2
1 1
21 7
Administrative
Support
$29.65
First Subseq.
Year Year
0.5 0.5
0.5 0.5
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$378 $267
$0 $0
$55 $55
$0 $0
$1,985 $786
a Internally develop the methodology and monitoring plan for calculating emissions from production process per facility—First
year is developing plan, subsequent years are reviewing and updating plan.
b Engineer collects composite samples of inputs and sends it to vendor for chemical analysis to QA/QC supplier information on
an annual basis to confirm supplier's information. The industrial manager is allotted hours for review of sample results.
0 Assumes contacting the supplier to obtain carbon content of feedstock.
Table 4-9. Subpart G Ammonia: Capital and O&M (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costsa
Total
Cost Categories
Equipment Annualized
Capital Lifetime Capital Cost O&M Costs
Cost (years) (per year) (per year)
$200
$0 $0 $200
Total Reporting Cost per
Unit/Facility
First Subseq.
Year Year
$200 $200
$200 $200
a Refers to annual sampling of carbon contents.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
4-23
-------
4.7 Subpart H—Cement Production
Baseline Reporting. Under voluntary domestic initiatives (such as EPA's Climate
Leaders and DOE's Climate Vision, DOE's 1605b), some facilities are reporting emissions
source categories. The analysis is based on the understanding that cement facilities perform daily
sampling and LCA of their raw materials to determine carbonate and organic carbon contents, as
part of their normal business operations.
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size. If continuous emission monitoring systems (CEMS) are available,
direct measurement of combustion-related and process-related CC>2 emissions from cement kilns
using CEMS is used. If CEMS are not available, facility-specific non-CEMS-based emissions
estimates are to be developed using the mass-balance approach based on facility-specific analysis
of carbonate and non-carbonate contents of clinker produced and raw material consumption and
CKD usage and disposal.
Labor Costs. Total labor costs are $6,700 in the first year and $5,100 in subsequent years;
a majority of the labor costs are associated with sampling and analysis activities performed by an
industrial engineer/technician (approximately $5,200 in the first year and $4,700 in subsequent
years).
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. There is $300 in O&M sampling costs and reporting requires approximately $2,200 for
contractor costs for software development and maintenance costs.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping, and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
4-24
-------
Table 4-10. Subpart H Cement Manufacturing: Labor Costs (2006$)a
Activity
Planning15
QA/QC
Recordkeeping
Sampling and analysis
Material sampling0
Emissions calculation"1
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
11 82
14 16
2 2
12 14
1 1 22 18
(per hour)
Industrial
Engineer/ Administrative
Technician Support
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
16 4
76 64
36 24
40 40
92 68
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$5,189 $4,669
$2,129 $1,467
$3,060 $3,202
$0 $0
$6,742 $5,133
These costs correspond to incremental costs of monitoring emissions using non-CEMS method, via sampling. These costs are
applicable only for the cement plants that do not have NOX or CO2 CEMS. Eighty-two plants were identified to have no CEMS
installed on their kilns.
Corresponds to internally developing the methodology and monitoring plan for calculating emissions from the production
process.
Includes incremental sampling costs, including manger's review. The costs correspond to a laboratory chemical analysis of
nonfuel raw material inputs—carbonate and total organic carbon contents of 6 inputs, on average (the number of nonfuel raw
material inputs used in cement facilities is in the range of 2 to 10).
Includes costs of developing emissions calculations, based on raw material-specific carbon and carbonate measurements, raw
material consumption data, and facility-specific CKD contents of fuels developed through chemical analysis or other methods
approved by EPA. Also includes the costs of calculating CH4 andN2O emissions using emissions factors, if directed by EPA,
and performing QA/QC of GHG emission calculations. Includes the incremental costs for regular monitoring of total quantity
of all nonfuel raw material inputs (will vary by the type and number of raw materials to be measured and the monitoring
method) and cement kiln dust, including QA/QC ing and assembling data, as well. Plants do this activity as part of normal
business operations and incremental costs reflect additional procedures that they need to put in place to standardize the process
for regulatory data verification and onsite auditing.
4-25
-------
Table 4-11. Subpart H Cement Manufacturing: Capital and O&M Costs (2006$)a
Activity
Equipment (selection, purchase,
installation)15
Performance testing
Recordkeeping
Travel
Sampling costs0
Calculations'1
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost
Capital Cost (years) (per year)
SO SO
O&M Costs
(per year)
$300
$2,200
S300
Total Reporting Cost per
Unit/Facility
First Subseq.
Year Year
$300 $300
$2,200 $2,200
$2,500 $2,500
a These costs correspond to incremental costs of monitoring emissions using non-CEMS method, via sampling. These costs are
applicable only for the cement plants that do not have NOX or CO2 CEMS. Eighty-two plants were identified to have no CEMS
installed on their kilns.
b It was assumed that cement plants could use their existing equipment and that no additional equipment purchase was necessary
for the non-CEMS method of monitoring emissions.
0 The O&M costs correspond to the incremental costs of maintaining the existing onsite testing facilities and software needed
for documenting the biweekly sampling results, needed for emission calculations.
d O&M costs represent contractor costs for software development and maintenance costs.
4.8 Subpart K—Ferroalloy Production
Baseline Reporting. Under voluntary domestic initiatives (such as EPA's Climate
Leaders and DOE's Climate Vision, DOE's 1605b), some facilities are reporting emissions
source categories. The analysis assumes that facilities have measurements and records of
consumption of raw materials such as reducing agents as part of their routine operations and for
accounting purposes.
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size. Reporting requires annual carbon balance using monthly off-site
sampling by facilities to determine carbon content of each carbonaceous input.
Labor Costs. Total labor costs are $2,700 in the first year and $1,100 in subsequent years;
a majority of the labor costs are associated with sampling and analysis activities performed by an
industrial engineer/technician.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Reporting requires approximately $1,000 of sampling O&M costs.
4-26
-------
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
Table 4-12. Subpart K Ferroalloy Production: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis3
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
1182
(per hour)
Industrial
Engineer/
Technician
$55.20
First Subseq.
Year Year
16 4
20 10
36 14
Administrative
Support
$29.65
First Subseq.
Year Year
2.5 2.5
2.5 2.5
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$1,178 $626
$2,730 $1,090
a Refers to annual sampling of carbon contents for five inputs including coal, coke, electrode paste, prebaked electrodes, and
petroleum coke. For more information, please refer to the cost appendix.
Table 4-13. Subpart K Ferroalloy Production: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs3
Total
Cost Categories
Equipment Annualized
Capital Lifetime Capital Cost O&M Costs
Cost (years) (per year) (per year)
$1,000
$0 $0 $1,000
Total Reporting Cost per
Unit/Facility
First
Year Subseq. Year
$1,000 $1,000
$1,000 $1,000
Refers to annual sampling of carbon contents for five inputs including coal, coke, electrode paste, prebaked electrodes, and
petroleum coke; for more information, please refer to the cost appendix.
4-27
-------
4.9 Subpart N—Glass Production
Baseline Reporting. For glass production, we are not sure how many companies are
currently estimating and reporting emissions at the facility level to meet internal GHG
management programs or state or voluntary reporting programs at the domestic or international
level. Therefore, we are assuming that no glass production facilities are currently reporting
emissions and that many of the requirements will result in "new" or "additional" costs to meet
reporting requirements.
However, many glass production facilities are currently tracking much of the data
required to estimate process-related CC>2 emissions on a routine basis (carbonate inputs, supplier
information on carbonate composition of inputs). We are assuming that the requirements will
result in "additional" costs primarily to meet EPA's reporting requirements. For example, we
assume that additional costs incurred will be for preparing monitoring and QA/QC plans,
performing the calculations, reporting the results, and maintaining records (essentially
developing a monitoring plan, reporting, recordkeeping, and QA/QC).
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size. Reporting requires monthly onsite measurements of the weight
fraction of carbonate inputs (i.e., calcite, dolomite, and sodium carbonate) and calcination
fractions. This method uses IPCC default emission factors.
Labor Costs. Reporting requires 25 hours of labor at a cost of $1,500 in the first year. In
subsequent years, 7 hours are required at a cost of $464.
Capital and O&M Costs. There are no new capital equipment or O&M requirements for
this subpart.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping, and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
4-28
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Table 4-14. Subpart N Glass: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
1182
(per hour)
Industrial
Engineer/ Administrative
Technician Support
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
16 4
16 4
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$1,552 $464
Table 4-15. Subpart N Glass: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost O&M Costs
Capital Cost (years) (per year) (per year)
$0 $0 $0
Total Reporting Cost per
Unit/Facility
First Subseq.
Year Year
$0 $0
4.10 Subpart O—HCFC-22 Production
Overview. Three HCFC-22 production facilities operated in the United States in 2006.
For the purpose of estimating costs, a model facility was developed by taking the average of
facility-specific cost estimates; the facility-specific cost estimates vary primarily depending on
the process architecture of each facility. Hence, the model facility is an average facility that
incurs the average of costs across all facilities.
Labor Costs. Total labor costs are $5,600 in the first year and subsequent years; a
majority of the labor costs are associated with sampling and analysis activities.
4-29
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Capital and O&M Costs. There are no new capital equipment or O&M requirements for
this subpart.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping, and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
Table 4-16. Subpart O HCFC-22 Production: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
(calculations)
Reporting
Total
Labor Rates
Legal Managerial
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
2 2
2 2
(per hour)
Technical Clerical
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
85 85 25 25
85 85 25 25
Labor Cost per
Year per
Reporting
Unit/Facility3
First Subseq.
Year Year
$5,599 $5,599
$5,599 $5,599
a Sampling frequency varies by plant; for more information, please refer to the cost appendix.
Table 4-17. Subpart O HCFC-22 Production: Capital and O&M Costs (2006$)
Activity
Cost Categories
Equipment Annualized
Lifetime Capital Cost O&M Costs
Capital Cost (years) (per year) (per year)
Total Reporting Cost per
Unit/Facility
First
Year
Subseq.
Year
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs
Total
$0
$0
$0
$0
$0
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4.11 SubpartP—Hydrogen Production
Overview. The estimated 77 merchant hydrogen production facilities in the United States
range in capacity from around 6 to almost 200,000 metric tons of hydrogen per year. Even so, the
same amount of data are collected for each facility, and therefore the monitoring cost for each
site is the same. The feedstock mass balance cost data are calculated for merchant hydrogen
production facilities using natural gas, other hydrocarbon gases and liquids, and solid fuels (coal,
pet coke) as feedstock. For this analysis, there is no distinction in the feedstock mass balance
cost data for the various feedstock materials.
The monitoring approach is a hybrid method which combines direct measurement by
CEMS, where CEMS components are currently employed for other purposes, and the fuel and
feedstock mass balance approach at facilities where CEMS are not currently employed or at
facilities where combustion or process CC>2 emissions are emitted via secondary stacks or vents.
CEMS-method facilities will have CC>2 monitoring in place and will retrofit CEMS by installing
a stack flow meter. CEMS costs have been addressed under Stationary Combustion in the RIA,
consequently, this cost analysis is focused on only those facilities that will use the fuel and
feedstock mass balance approach.
Labor Costs. Total labor costs are about $2,900 in the first year and $1,500 in subsequent
years; a majority of the labor costs are associated with planning and sampling and analysis
activities with additional labor costs for QA/QC.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Reporting requires approximately $1,400 of sampling O&M costs in support of QA/QC
and sampling and analysis.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping, and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
4-31
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Table 4-18. Subpart P Hydrogen Production: Labor Costs (2006$)
Activity
Planning*
QA/QCb
Recordkeeping
Sampling and analysis
(calculations)0
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
11 82
2 2
1 1 10 4
(per hour)
Industrial
Engineer/
Technician
$55.20
First Subseq.
Year Year
16 4
4 2
16 13
36 19
Administrative
Support
$29.65
First Subseq.
Year Year
0.5 0.5
3 3
3.5 3.5
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$378 $267
$0 $0
$972 $807
$0 $0
$2,902 $1,538
a Internally develop the methodology and monitoring plan for calculating emissions from production process per facility—first
year is developing plan; subsequent years are reviewing and updating plan.
b QA/QC of supplier data; Assumes one QA/QC sampling event per year.
0 Assumes one contact per year to obtain supplier material data and 6 samples per year of a secondary fuel/feedstock.
Table 4-19. Subpart P Hydrogen Production: Capital and O&M Costs (2006$)
Activity
Equipment (selection,
purchase, installation)
Performance testing
Recordkeeping
Travel
Sampling costsa
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost O&M Costs
Capital Cost (years) (per year) (per year)
$1,400
$0 $0 $1,400
Total Reporting Cost per
Unit/Facility
First
Year Subseq. Year
$1,400 $1,400
$1,400 $1,400
Includes testing of annual QA/QC sampling of carbon content to check supplier data, plus 6 samples per year of a secondary
fuel/feedstock.
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4.12 Subpart Q—Iron and Steel Production
Baseline Reporting. Through voluntary domestic initiatives (such as DOE's Climate
Vision), the U.S. iron and steel industry as a sector has undertaken voluntary efforts to develop a
simple protocol (based on default emission factors), educate association members, and track
emission intensity of production (more information is available at:
http://www.climatevision.gov/sectors/steel/index.html).
Several iron and steel companies in the United States and abroad have recommended and
are using a carbon balance approach similar to the method. Based on private communications
with steel industry representatives and general knowledge of plant operations, it is recognized
that many of the measurements required for that approach, such as the amount of specific
feedstocks consumed, production rates from each process, process gas (coke oven gas, blast
furnace gas) production and consumption, and purchased fuel consumption, are already routinely
measured and used for accounting purposes (e.g., determining the cost of production), process
control, and yield calculations. For example, U.S. steel plants report many of these
measurements to the American Iron and Steel Institute (AISI), and AISI compiles annual
nationwide statistics from the reported information (e.g., see http://www.steel.org/AM/
Template.cfm?Section=Statistics). Consequently, the approach offers an advantage in that it
would use a significant amount of information that is already readily available to companies and
their facilities.
However, it is not clear how many companies are currently implementing this approach
at the facility level to meet internal GHG management programs or state or voluntary reporting
programs at the domestic or international level. Therefore, we are assuming that iron and steel
production facilities are not currently reporting emissions and that many of the requirements will
result in "new" or "additional" costs to meet reporting requirements. For example, we assume
that additional costs will be incurred for preparing monitoring and QA/QC plans, sampling and
analysis of process inputs and outputs for carbon content, performing the calculations, reporting
the results, and maintaining records. The only significant element of the approach that we know
is performed routinely by all companies is that they have measurements and records of process
inputs and outputs as part of their routine operation.
Overview. For the Iron & Steel subpart, model facilities were not developed due to
insufficient data for differentiating costs for compiling data and conducting sampling across
different facilities. Instead, site-specific data was used to calculate the cost for each process.
Three Options were considered, and are discussed below.
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Option 1 requires that an annual carbon balance of all inputs and outputs be performed
using measurements of the carbon content of specific process inputs and process outputs and
measure the mass rate of process inputs and process outputs. The next step is calculation of CC>2
emissions from the difference of carbon-in minus carbon-out assuming all is converted to CC>2.
Labor Costs. The labor costs are associated with all activities are $28,000 in the first year
and $14,100 in subsequent years.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Sampling costs are estimated to be $2,300.
Stationary Combustion Costs. This subpart is not assigned stationary combustion costs
as described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is not assigned additional
recordkeeping and reporting costs.
Table 4-20. Subpart Q Iron & Steel: Labor Costs (2006$)
Subpart Q — Iron and
Steel Industry-
Combustion & Process
Activity
Planning
QA/QC
Recordkeeping
Sampling, analysis, and
calculations
Reporting
Total
Labor Rates (per hour)
Industrial
Manager
$71.03
First Subseq.
Year Year
6.4 0.0
4.7 0.0
4.6 4.6
0.0 0.0
4.6 4.6
20.3 9.3
Industrial
Eng/Tech
$55.20
Subseq.
First Year Year
124.9 0.0
92.9 7.1
92.9 92.9
11.2 11.2
92.9 92.9
414.8 204.1
Admin
$29.65
Subseq.
First Year Year
12.5 0.0
37.1 0.0
37.1 37.1
0.0 0.0
37.1 37.1
123.7 74.1
Labor Cost per Year
per Reporting
Unit/Facility
Subseq.
First Year Year
$7,715 $0
$6,559 $391
$6,557 $6,557
$621 $621
$6,554 $6,554
$28,006 $14,123
4-34
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Table 4-21. Subpart Q Iron & Steel: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost
Capital Cost (years) (per year)
$0
$0 $0
O&M
Costs
(per year)
$2,255
$2,255
Total Reporting Cost per
Unit/Facility
First
Year Subseq. Year
$2,255 $2,253
$2,255 $2,253
4.13 Subpart R—Lead Production
Baseline Reporting. Under voluntary domestic initiatives (such as EPA's Climate
Leaders and DOE's Climate Vision, DOE's 1605b), some facilities are reporting emissions
source categories. The analysis assumes that facilities have measurements and records of
consumption of raw materials such as reducing agents as part of their routine operations and for
accounting purposes.
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size. Reporting requires Annual carbon balance using monthly
measurement of the carbon content of up to three reductants (e.g., metallurgical coke) sent off-
site for lab sampling.
Labor Costs. Total labor costs are $2,300 in the first year and $800 in subsequent years; a
majority of the labor costs are associated with planning ($1,600) and sampling and analysis
activities ($700). Planning costs fall to $500 and sampling and analysis activities fall to $400 in
sub sequent years.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Reporting requires approximately $600 of sampling O&M costs.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
4-35
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Recordkeeping, and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
Table 4-22. Subpart R Lead: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis3
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
1182
(per hour)
Industrial
Engineer/
Technician
$55.20
First Subseq.
Year Year
16 4
12 6
28 6
Administrative
Support
$29.65
First Subseq.
Year Year
1.5 1.5
1.5 1.5
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$0 $0
$0 $0
$707 $376
$0 $0
$2,259 $840
a Assumes annual sampling event per year; for more information, please refer to the cost appendix.
Table 4-23. Subpart R Lead: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costsa
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost O&M Costs
Capital Cost (years) (per year) (per year)
$600
$0 $0 $600
Total Reporting Cost per
Unit/Facility
First Subseq.
Year Year
$600 $600
$600 $600
a Refers to annual sampling of Carbon contents.
4.14 Subpart S—Lime Manufacturing
Baseline Reporting. Under voluntary domestic initiatives (such DOE's Climate Vision,
DOE's 1605b), the National Lime Association (NLA), which represents 95% of the domestic
commercial lime production sector, has undertaken voluntary efforts to develop a GHG
emissions protocol (based on facility specific information), educate association members, and
track emissions intensity of production (more information is available at:
http://www.climatevision.gov/sectors/lime/index.html).
4-36
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NLA members have recommended and are using the NLA method. For example, U.S.
lime manufacturing facilities report many of these measurements to NLA, and NLA compiles
annual nationwide statistics from the reported information. Consequently, the approach offers an
advantage in that it would use a significant amount of information that is already readily
available to companies and their facilities.
Given that NLA represents a significant number of lime producers and a significant
amount of domestic lime production, we are assuming that lime production facilities are
currently collecting the data to report process related CC>2 emissions at the facility level (monthly
lime production, CaO and MgO content of lime products, calcinations of byproducts). We are
assuming that the requirements will result in "additional" costs primarily to meet EPA's
reporting requirements. For example, we assume that additional costs incurred will be for
preparing monitoring and QA/QC plans, performing the calculations, reporting the results, and
maintaining records (essentially developing a monitoring plan, reporting, recordkeeping, and
QA/QC).
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size.
Labor Costs. The labor costs are associated with planning are $1,600 in the first year and
subsequent years.
Capital and O&M Costs. There are no new capital equipment and O&M requirements for
this subpart.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
4-37
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Table 4-24. Subpart S Lime Manufacturing: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
1182
(per hour)
Industrial
Engineer/ Administrative
Technician Support
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
16 4
16 4
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$1,552 $464
Table 4-25. Subpart S Lime Manufacturing: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost O&M Costs
Capital Cost (years) (per year) (per year)
$0 $0 $0
Total Reporting Cost per
Unit/Facility
First Subseq.
Year Year
$0 $0
4.15 Subpart V—Nitric Acid Production
Overview. Costs were developed for the following monitoring option for estimating N2O
emissions from nitric acid production. The option is to follow the Tier 3 approach established by
IPCC using non-continuous monitoring: directly monitor N2O emissions and determine the
relationship between nitric acid production and the amount of N2O emissions (i.e., develop a
site-specific emissions factor). The site-specific emissions factor and production rate (activity
level) is used to calculate the emissions. Annual testing of N2O emissions would also be required
to verify the emission factor over time. Testing would also be required whenever significant
process changes are made.
4-38
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This option uses non-continuous direct monitoring of N2O emissions to determine the
relationship between nitric acid production and the amount of N2O emissions. As the production
rate changes, a new N2O emission rate could be calculated. Annual testing of N2O emissions
would also be required to verify the emission factor over time. Testing would also be required
whenever significant process changes are made.
The monitoring method for calculating process emissions from nitric acid production
would involve this facility-level calculation on a monthly basis and stack testing on an annual
basis. Each facility needs to internally develop the methodology and monitoring plan for
calculating the process emissions from the nitric acid production process.
Labor Costs. Total labor costs are $8,800 in the first year and $7,700 in subsequent years;
a majority are associated with planning, sampling and analysis, and reporting activities.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Reporting requires performance testing, recordkeeping and travel (approximately
$3,800).
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
4-39
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Table 4-26. Subpart V Nitric Acid: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling,
analysis, and
calculations
Reporting
Total
Labor Hours
Electricity Refinery Industrial
Manager Manager Manager
$88.79 $101.31 $71.03
First Subseq First Subseq First Subseq
Year . Year Year . Year Year . Year
8 2
38 38
12 12
58 52
Electricity
Lawyer Eng/Tech
$101.00 $60.84
First Subseq First Subseq
Year . Year Year . Year
1 1
1 1
Refinery Industrial
Eng/Tech Eng/Tech Admin
$63.89 $55.20 $29.65
First Subseq First Subseq First Subseq
Year . Year Year . Year Year . Year
16 4
50 50
12 12 12 12
77 65 12 12
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$0 $0
$0 $0
$5,469 $5,460
$1,801 $1,801
$8,822 $7,725
J^.
o
-------
Table 4-27. Subpart V Nitric Acid: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Total
Cost Categories
Equipment
Lifetime
Capital Cost (years)
SO
Annualized
Capital Cost
(per year)
SO
O&M Costs
(per year)
$3,466
$72
$231
$3,769
Total Reporting Cost per
Unit/Facility
First
Year
$3,466
$72
$231
$3,769
Subseq. Year
$3,466
$72
$231
$3,769
4.16 Subpart X—Petrochemical Production
Overview. Each petrochemical production facility would measure the flow rate and
carbon content (or composition) of each feedstock and each product. Flow rates would be
measured continuously, and carbon content would be measured at least once per week. The
difference in the carbon content between the feedstocks and the products would provide an
estimate of the process-based CO2 emissions. Facilities would also measure the flow and carbon
content of supplemental fuel used in combustion units that supply energy to the petrochemical
process at the recommended frequency for stationary fuel combustion sources. For this analysis,
natural gas was assumed to be the supplemental fuel, which means the flow would be measured
continuously, and the carbon content would be measured once per month. This information
would be used in the applicable equations for stationary fuel combustion sources to estimate the
CO2, CH4, and N2O emissions from combustion sources associated with petrochemical
processes.
Labor Costs. Total labor costs are $16,400 in the first year and $12,000 in subsequent
years; a majority of the labor costs are associated with quality assurance and control checks,
recordkeeping, and planning activities.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. O&M costs are approximately $11,000 in the first year and $9,200 in subsequent years.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. No additional costs are assigned to this subpart.
4-41
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Table 4-28. Subpart X Petrochemical Production: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling,
analysis,
and
calculations
Reporting
Total
Labor Hours
Industrial Electricity Refinery
Electricity Manager Refinery Manager Manager Lawyer Eng/Tech Eng/Tech
$88.79 $101.31 $71.03 $101.00 $60.84 $63.89
First Subseq. First
Year Year Year
2.10
2.79
1.50
4.92
0.60
11.90
Subseq. First Subseq. First Subseq. First Subseq. First Subseq.
Year Year Year Year Year Year Year Year Year
0.90
0.90
1.50
4.92
0.60
8.81
Industrial
Eng/Tech
$55.20
First Subseq.
Year Year
41.91 17.97
55.85 17.97
29.94 29.94
98.33 98.33
11.98 11.98
238.01 176.18
Admin
$29.65
First Subseq.
Year Year
4.19 1.80
5.59 1.80
2.99 2.99
9.83 9.83
1.20 1.20
23.80 17.62
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$2,882 $1,235
$3,840 $1,235
$2,059 $2,059
$6,762 $6,762
$824 $824
$16,366 $12,115
Note: Assumes each petrochemical manufacturing company site is the reporting unit (80 company sites).
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Table 4-29. Subpart X Petrochemical Production: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Total
Cost Categories
Annualized
Equipment Capital
Capital Lifetime Cost
Cost (years) (per year)
$0 $0
O&M
Costs
(first
year)
$1,818
$8,156
$938
$0
$10,912
O&M
Costs
(Subseq
years)
$151
$8,156
$938
$0
$9,245
Total Reporting Cost per
Unit/Facility
First
Year
$1,818
$8,156
$938
$0
$10,912
Subseq.
Year
$151
$8,156
$938
$0
$9,245
Note: Assumes each petrochemical manufacturing company site is the reporting unit (80 company sites).
4.17 Subpart Y—Petroleum Refineries
Overview. For costing purposes, the monitoring options were divided into those that
required the installation of new monitors and those that did not. As described below, the costs
associated with installing and operating a new monitor also include costs of QA/QC checks and
reporting. Costs for monitoring options that are not expected to require new monitoring systems
were estimated by the anticipated amount of labor needed to carry out the monitoring option.
Labor Costs. Total labor costs are $39,700 in the first year and $26,100 in subsequent
years; a majority of the labor costs are associated with planning, QA/QC checks, and
recordkeeping and reporting and planning activities. These costs cover process emissions and
stationary combustion sources.
Capital and O&M Costs. Average annualized capital equipment requirements are
approximately $1,200 per year. Equipment O&M costs approximately $1,800 per year. These
costs cover process emissions and stationary combustion sources.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping, and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) costs.
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Table 4-30. Subpart Y Petroleum Refineries: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling,
analysis, and
calculations
Reporting
Total
Labor Hours
Electricity Refinery
Manager Manager
$88.79 $101.31
First Subseq First Subseq
Year . Year Year . Year
6 0
8 5
5 5
3 3
22 13
Industrial Electricity
Manager Lawyer Eng/Tech
$71.03 $101.00 $60.84
First Subseq First Subseq First Subseq
Year . Year Year . Year Year . Year
Refinery
Eng/Tech
$63.89
First Subseq
Year . Year
116 0
164 91
96 96
119 119
70 70
565 376
Industrial
Eng/Tech Admin
$55.20 $29.65
First Subseq First Subseq
Year . Year Year . Year
12 0
16 9
10 10
7 7
45 26
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$8,307 $0
$11,830 $6,534
$6,916 $6,916
$7,626 $7,626
$5,033 $5,033
$39,711 $26,108
-------
Table 4-31. Subpart Y Petroleum Refineries: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Total
Cost Categories
Capital
Cost
$10,286
$0
$500
$0
$10,786
Equipment
Lifetime
(years)
15
15
Annualized
Capital Cost
(per year)
$1,129
$55
$1,184
O&M Costs
(per year)
$1,741
$0
$40
$0
$1,781
Total Reporting Cost per
Unit/Facility
First
Year
$2,870
$0
$95
$0
$2,965
Subseq. Year
$2,870
$0
$95
$0
$2,965
4.18 Subpart Z—Phosphoric Acid Production
Baseline Reporting. We are not aware of any phosphoric acid production facilities that
are estimating and reporting emissions for internal GHG management programs or for state or
voluntary reporting programs at the domestic or international level. Thus, we are assuming that
no phosphoric acid production facilities are currently reporting emissions and that many of the
requirements will result in "additional" costs to meet reporting requirements.
Facilities are tracking and collecting the data required for estimating emissions such as
such as phosphate rock feed rates and sampling and testing phosphate rock for its inorganic
carbon contents. According to Jasinski (2008), the companies conduct analysis on the rock
frequently to determine the P2O5 content and the level of impurities. According to CF industries
(Falls, 2008), they analyze a composite of incoming phosphate rock for carbon contents on a
daily basis. The phosphate rock consumed or entering the digestion process is also measured on a
daily basis.
Therefore, we are assuming that the requirements will result in "additional" costs
primarily to meet EPA's reporting requirements. Specifically, we assume that additional costs
will be incurred for preparing monitoring and QA/QC plans, performing the calculations,
reporting the results, and maintaining records.
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size.
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Labor Costs. The labor costs are associated with planning are $1,600 in the first year and
$500 in subsequent years related to industrial process emissions.
Capital and O&M Costs. There are no new capital equipment and O&M requirements for
this subpart related to industrial process emissions.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
Table 4-32. Subpart Z Phosphoric Acid Production: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
1182
(per hour)
Industrial
Engineer/ Administrative
Technician Support
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
16 4
16 4
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$1,552 $464
Table 4-33. Subpart Z Phosphoric Acid Production: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs
Total
Cost Categories
Equipment Annualized
Capital Lifetime Capital Cost O&M Costs
Cost (years) (per year) (per year)
$0 $0 $0
Total Reporting Cost per
Unit/Facility
First
Year Subseq. Year
$0 $0
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4.19 Subpart AA—Pulp and Paper Manufacturing
Overview. The cost estimates of the monitoring procedures for the pulp and paper sector
for combination biomass/fossil fuel-fired boilers, kraft and soda chemical recovery furnaces,
sulfite and semichemical combustion units, lime kilns, and use of makeup chemicals. Monitoring
cost estimates for some of the other GHG sources in the pulp and paper sector (fossil fuel-fired
boilers, gas turbines, thermal oxidizers, and RTOs) are also addressed.
Labor Costs. Total labor costs are $3,000 in the first year and subsequent years; a
majority of the labor costs are associated with planning ($1,000) and recordkeeping ($1,300).
Capital and O&M Costs. Average annualized capital equipment requirements are
$14,700 per year. Equipment O&M costs are approximately $400 per year.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping, and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
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Table 4-34. Subpart AA Pulp and Paper: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling,
analysis, and
calculations
Reporting
Total
Labor Hours
Electricity Refinery Industrial Electricity
Manager Manager Manager Lawyer Eng/Tech
$88.79 $101.31 $71.03 $101.00 $60.84
First Subseq First Subseq First Subseq First Subseq First Subseq
Year . Year Year . Year Year . Year Year . Year Year . Year
Refinery Industrial
Eng/Tech Eng/Tech Admin
$63.89 $55.20 $29.65
First Subseq First Subseq First Subseq
Year . Year Year . Year Year . Year
19 19
24 24
12 12
55 55
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,041 $1,041
$0 $0
$1,325 $1,325
$662 $662
$0 $0
$3,028 $3,028
J^.
oo
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Table 4-35. Subpart AA Pulp and Paper: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Total
Cost Categories
Equipment
Lifetime
Capital Cost (years)
$34,927 5
$34,927
Annualized
Capital Cost O&M Costs
(per year) (per year)
$14,731 $371
$14,731 $371
Total Reporting Cost per
Unit/Facility
First Subseq.
Year Year
$15,102 $15,102
$15,102 $15,102
4.20 Subpart BB—Silicon Carbide Production
Baseline Reporting. Under voluntary domestic initiatives (such as EPA's Climate
Leaders and DOE's Climate Vision, DOE's 1605b), some facilities are reporting emissions
source categories. The analysis assumes that facilities have measurements and records of
consumption of the amount of petroleum coke as part of their routine operations and for
accounting purposes.
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size. Reporting requires estimating CO2 emissions based on quarterly
measurement of the amount of petroleum coke consumed. This method uses plant-specific
carbon content and carbon oxidation factors.
Labor Costs. Total labor costs are $2,000 in the first year and $800 in subsequent years; a
majority of the labor costs are associated with planning ($1,600). Planning costs fall to $500 in
subsequent years.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Reporting requires approximately $200 of sampling O&M costs.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
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Table 4-36. Subpart BB Silicon Carbide: Labor Costs (2006$)
Activity
Planning
QA/QCa
Recordkeeping
Sampling and analysis'5
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
2 2
1 1 10 4
(per hour)
Industrial
Engineer/
Technician
$55.20
First Subseq.
Year Year
16 4
4 2
1 1
21 7
Administrative
Support
$29.65
First Subseq.
Year Year
0.5 0.5
0.5 0.5
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$378 $267
$0 $0
$55 $55
$0 $0
$1,985 $786
a Annual QA/QC of supplier data on carbon content of petroleum coke. For more information, please refer to the cost appendix.
b Includes facility contacts supplier for obtaining monthly data on carbon content of petroleum coke. For more information,
please refer to the cost appendix.
Table 4-37. Subpart BB Silicon Carbide: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs3
Total
Cost Categories
Equipment Annualized
Capital Lifetime Capital Cost O&M Costs
Cost (years) (per year) (per year)
$200
$0 $0 $200
Total Reporting Cost per
Unit/Facility
First Subseq.
Year Year
$200 $200
$200 $200
a Annual QA/QC of supplier data on carbon content of petroleum coke. For more information, please refer to the cost appendix.
4.21 Subpart CC—Soda Ash Manufacturing
Baseline Reporting. Under voluntary domestic initiatives (such as DOE's Climate
Vision, DOE's 1605b), the Industrial Minerals Association North America (IMA-NA), which
represents soda ash producers as a sector, has undertaken voluntary efforts to develop a GHG
emissions protocol (based default emissions factors), educate association members about
measuring and reporting GHG emissions, and track emissions intensity of production for the
sector (more information is available at: http://www.climatevision.gov/sectors/minerals/
index.html).
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We do not know how many soda ash companies are currently implementing this
approach at the facility level to meet internal GHG management programs or state or voluntary
reporting programs at the domestic or international level. We are assuming that no soda ash
production facilities are currently reporting emissions and that many of the requirements will
result in "new" or "additional" costs to meet reporting requirements.
However, soda ash production facilities are currently collecting and tracking the data
required for estimating process-related CC>2 emissions on a routine basis. We understand that
soda ash producers sample and measure purity of soda ash and/or trona in-house on a routine
basis (i.e., inorganic carbon contents of trona). We are assuming that the requirements will result
in "additional" costs primarily to meet EPA's reporting requirements. Specifically, we are
assuming that additional costs incurred will be for preparing monitoring and QA/QC plans,
performing the calculations, reporting the results, and maintaining records (essentially
developing a monitoring plan, reporting, recordkeeping, and QA/QC).
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size.
Labor Costs. Total labor costs are associated with planning, sampling and analysis, and
reporting ($6,600). These costs fall to $5,500 in subsequent years.
Capital and O&M Costs. There are no new capital equipment and $1,800 in O&M
requirements for this subpart.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
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Table 4-38. Subpart CC Soda Ash: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis*
Reporting3
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
26.5 26.5
8 8
1 1 42.5 36.5
(per hour)
Industrial
Engineer/ Administrative
Technician Support
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
16 4
34.5 34.5
8888
58.5 46.5 8 8
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$0 $0
$0 $0
$3,787 $3,787
$1,247 $1,247
$6,586 $5,498
a Costs only associated with a facility that uses the site-specific emission factor mentioned. For total cost calculations only one
facility was assumed to use site-specific method.
Table 4-39. Subpart CC Soda Ash: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing3
Recordkeeping3
Travel3
Sampling costs
Total
Cost Categories
Equipment Annualized
Capital Lifetime Capital Cost
Cost (years) (per year)
$0 $0
O&M Costs
(per year)
$1,600
$50
$160
$1,810
Total Reporting Cost
per Unit/Facility
First Subseq.
Year Year
$1,600 $1,600
$50 $50
$160 $160
$1,810 $1,810
4.22 Subpart EE—Titanium Dioxide Production
Baseline Reporting. In this sector, data are not available on how many companies are
currently estimating and reporting GHG emissions at the facility level to meet internal GHG
management programs or state or voluntary reporting programs at the domestic or international
level. We are assuming that no titanium dioxide production facilities are currently reporting
emissions and that many of the requirements will result in "new" or "additional" costs to meet
reporting requirements.
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However, many titanium dioxide production facilities are currently tracking much of the
data required to estimate process-related CC>2 emissions on a routine basis (calcined petroleum
coke consumption). We are assuming that the requirements will result in "additional" costs
primarily to meet EPA's reporting requirements. For example, we assume that additional costs
incurred will be for preparing monitoring and QA/QC plans, performing the calculations,
reporting the results, and maintaining records (essentially developing a monitoring plan,
reporting, recordkeeping, and QA/QC).
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size.
Labor Costs. The labor costs are associated with planning, QA/QC, and reporting are
$2,200 in the first year and $900 in subsequent years related to industrial process emissions.
Capital and O&M Costs. There are no new capital equipment and $400 O&M
requirements (sampling) for this subpart related to industrial process emissions.
Stationary Combustion Costs. This subpart is assigned stationary combustion costs as
described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
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Table 4-40. Subpart EE Titanium Dioxide: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
2 2
1 1 10 4
(per hour)
Industrial
Engineer/
Technician
$55.20
First Subseq.
Year Year
16 4
4 2
5 3
25 9
Administrative
Support
$29.65
First Subseq.
Year Year
0.5 0.5
0.5 0.5
1 1
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$378 $267
$291 $180
$2,221 $912
Table 4-41. Subpart EE Titanium Dioxide: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs
Total
Cost Categories
Equipment Annualized
Capital Lifetime Capital Cost O&M Costs
Cost (years) (per year) (per year)
$400
$0 $0 $400
Total Reporting Cost
per Unit/Facility
Subseq.
First Year Year
$400 $400
$400 $400
4.23 Subpart GG—Zinc Production
Baseline Reporting. Under voluntary domestic initiatives (such as EPA's Climate
Leaders and DOE's Climate Vision, DOE's 1605b), some facilities are reporting emissions
source categories. The analysis assumes that facilities have measurements and records of
consumption of raw materials such as reducing agents as part of their routine operations and for
accounting purposes.
Overview. Insufficient data was available to differentiate costs for compiling data and
conducting sampling across different facilities; hence, model facilities were not developed.
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Professional judgment was used to develop cost estimates and sampling frequency was assumed
not to differ by facility size. Reporting requires annual carbon balance using monthly off-site
sampling of the amount of carbon contained in the reducing agent, usually metallurgical coke.
Labor Costs. A majority of the labor costs are associated with planning ($1,500 in the
first year) and sampling and analysis activities ($900). Planning activity costs fall to $500 in
subsequent years.
Capital and O&M Costs. There are no new capital equipment requirements for this
subpart. Sampling activities require approximately $800 of O&M costs. The costs are associated
with process emissions.
Stationary Combustion Costs. This subpart is assigned additional stationary combustion
costs as described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
Table 4-42. Subpart GG Zinc: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis3
Reporting
Total
Labor Rates
Industrial
Lawyer Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1182
1182
(per hour)
Industrial
Engineer/ Administrative
Technician Support
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
16 4
16 8 2 2
32 12 2 2
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$1,552 $464
$0 $0
$0 $0
$942 $501
$2,495 $965
Refers to monthly sampling of carbon contents for one input, which is generally petroleum coke, metallurgical coke, or
anthracite coal. For more information, please refer to the cost appendix.
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Table 4-43. Subpart GG Zinc: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs3
Total
Cost Categories
Equipment Annualized
Capital Lifetime Capital Cost O&M Costs
Cost (years) (per year) (per year)
$800
SO SO S800
Total Reporting Cost
per Unit/Facility
First Subseq.
Year Year
$800 $2800
S800 S800
a Refers to monthly sampling of carbon contents for one input, which is generally petroleum coke, metallurgical coke, or
anthracite coal. For more information, please refer to the cost appendix.
4.24 Subpart HH—Landfills
Overview. Costs were developed to model emissions using the IPCC waste model (or
similar model) using the waste composition option (all landfills). Tables 4-44 and 4-45 report the
average values for MSW landfills.
Labor Costs. Labor costs are estimated to be approximately $4,715 per entity in the first
year and $2,000 in subsequent years.
Capital and O&M Costs. The capital investment is $500. Using a lifetime of 15 years
and an interest rate of 7%, the annualized capital expenditures are approximately $55 per
affected entity. There is an additional $106 in equipment O&M costs per year.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is not assigned additional
recordkeeping and reporting costs.
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Table 4-44. Subpart HH Landfills: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling, analysis,
and calculations
Reporting
Total
Labor Hours
Electricity Refinery
Manager Manager
$88.79 $101.31
First Subseq. First Subseq.
Year Year Year Year
0 0 - -
Industrial
Manager
$71.03
First Subseq.
Year Year
1
1
1
1
0
4
-
0
1
0
0
2
Electricity Refinery
Lawyer Eng/Tech Eng/Tech
$101.00 $60.84 $63.89
Industrial
Eng/Tech
$55.20
First Subseq. First Subseq. First Subseq. First Subseq.
Year Year Year Year Year Year Year Year
21
13
22
16
5
76
-
6
14
8
5
32
Admin
$29.65
First Subseq.
Year Year
2
1
2
2
1
8
-
1
1
1
1
3
Labor Cost per Year
per Reporting
Unit/Facility
First Subseq.
Year Year
$1,273 $0
$815 $359
$1,349 $856
$961 $467
$317 $317
$4,715 $1,999
-------
Table 4-45. Subpart HH Landfills: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Total
Capital
Cost
$0
$0
$500
$0
$500
Equipment
Lifetime
(years)
15
15
Annualized
Capital Cost
(per year)
$0
$55
$55
O&M Costs
(per year)
$66
$0
$40
$0
$106
Total Reporting per
Unit/Facility Cost
Subseq.
First Year Year
$66 $66
$0 $0
$95 $95
$0 $0
$161 $161
4.25 Subpart JJ—Manure Management
Baseline Reporting. Farms maintain records on the number and types of animals present;
however, they generally do not run calculations for CH4 and N2O generation. It is therefore
assumed that the costs for monitoring and reporting emissions are new costs.
Overview. For this source category, EPA developed a number of model farms to
represent the manure management systems that are most common on large farms and have the
greatest potential to exceed the GHG thresholds. Operations were divided into model farms
representing 12 distinct manure management systems:
• a beef farm with a pasture system;
• a beef feedlot;
• a dairy farm with an anaerobic lagoon system without solid separation;
• a dairy farm with an anaerobic lagoon system with solid separation;
• a dairy farm with a liquid/slurry system without solid separation;
• a dairy farm with a liquid/slurry system with solid separation;
• a farrow-to-finish swine farm with a deep pit system;
• a farrow-to-finish swine farm with an anaerobic lagoon system;
• a caged layer farm with an anaerobic lagoon system;
• a caged layer farm with manure drying;
• a turkey farm with bedding (litter); and
• a broiler farm with bedding (litter).
EPA determined the number of head that would need to be present at each model farm to
reach the reporting threshold under consideration (assuming no anaerobic digester is present on
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the farm). Based on information from EPA's Development Document for the Final Revisions to
the National Pollutant Discharge Elimination System (NPDES) Regulation and the Effluent
Guidelines for Concentrated Animal Feeding Operations (CAFOs), model dairy farms were
assumed to have population distributions that are comprised of 63% dairy cows, 19% dairy
heifers, and 19% calves. At each model dairy farm, the heifers and calves were assumed to be
managed on dry lots, and the dairy cows were managed on liquid systems (either anaerobic
lagoons or liquid/slurry systems). The population distributions for beef and swine were estimated
based on the U.S. total populations from the National Inventory; this estimate assumes that all
U.S. farms would have the same distribution of animal types.
Labor Costs. Assigning labor hours for all cost elements was based on expert judgment.
The farm owner is responsible for collecting the data required to perform the calculations
required by the rule. These data include the population of animals at the facility, the average
weight of the animals, and the annual average ambient temperature. The annual gathering of
these data, performing the calculations, and completing the paperwork are estimated to require 8
hours at an estimated cost of $396.
Operations will also incur one-time costs to develop a monitoring plan for compliance.
For operations without digesters, EPA estimates the monitoring/modeling plan includes defining
the animal populations present, manure management system(s), percent manure by system, and
appropriate reference values to use for modeling operations. The plan also includes development
of an initial emission estimate to confirm the need to report. EPA assumes this will require 12
hours at an estimated cost of $461. For operations with digesters, EPA estimates the operation
will need to conduct product research for digester monitoring instruments before actual purchase,
and develop a monitoring plan before actual monitoring commences. EPA assumes this will
require 20 hours at an estimated cost of $723.
The annual cost to operate the continuous measurement system includes the cost to
calibrate the analyzers monthly and to compile annual emission reports. These tasks are assumed
to require 14 hours a year at a rate of $49.53 per hour for the farm owner or designee. The annual
costs also include $200 for gas analyzer calibration kits. The total annual costs including labor
and calibration kits are $893.
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.
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Capital and O&M Costs. For one farm, reporting requiring continuous gas composition
monitoring equipment for anaerobic digestion systems would require a continuous gas flow
meter, a continuous gas composition analyzer, a temperature sensor, a gas pressure sensor, and a
data logger; the total capital cost is $6,750. EPA used an equipment lifetime of 10 years and an
interest rate of 7% to annualize capital costs. Annualized capital costs are $961 per year.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
Table 4-46. Subpart JJ Manure Management: Labor Costs (2006$)
Activity
Planning — without digester
Planning — digester
Calculations
Monitoring — digester
Total — Farm w/digester
Total — Farm w/out digester
Labor Hours
Farm, Ranch, and Other
Agricultural Manager
($49.53/hr)
First Year Subseq. Year
8
12
8 8
14 14
34 22
16 8
Farm worker
($16.12/hr)
First Year Subseq. Year
4
8
8 0
4 0
Labor Cost per Year per
Reporting Unit/Facility
First Year Subseq. Year
$461
$723
$396 $396
$693 $693
$1,812 $1,089
$857 $396
Table 4-47. Subpart JJ Manure Management: Capital and O&M Costs (2006$)
Capital
Activity Cost
Equipment
Lifetime
(years)
Annualized
Capital Cost O&M Costs (per
(per year) year)
Total Reporting per
Unit/Facility Cost
First Year Subseq. Year
Equipment (selection, $6,750
purchase, installation)
Recordkeeping
Total $6,750
10
$961
$961
$200
$200
5,950
$6,950
$200
$200
Note: Applies only to manure management operations with digesters.
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4.26 Subpart MM—Suppliers of Petroleum Products
Overview. All refineries are required to report under this rule. The unit of reporting is the
individual refinery. No distinction has been made between the sizes of refineries for estimating
the monitoring costs because the rule would require additional processing of data that refineries
already collect and report. Under the rule, individual operating refineries are the reporters as
opposed to the parent company. For example, Exxon Corporation owns and operates six
refineries within the United States. Each operating refinery will be a reporter under this rule, not
Exxon Corporation. A section for facilities that produce liquid fuel from coal is also included in
this rule. Since no such facilities are in operation in the United States, however, a cost analysis
was not conducted. It is anticipated that such facilities may be in operation in the future.
Labor Costs. Labor costs for refineries are estimated to be approximately $11,800 per
entity in the first year and $3,300 in subsequent years. Most of the costs are related to
registration and monitoring. Labor costs for importers/exporters are estimated to be
approximately $10,000 per entity in the first year and $3,100 in subsequent years.
Capital and O&M Costs. There are no new capital equipment or O&M expenses.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is not assigned any additional costs.
Table 4-48a. Subpart MM Petroleum Suppliers (Refineries): Labor Costs (2006$)
Activity
Registration
Monitoring
Reporting
Archiving
Auditing
Total
Labor Hours
Senior Manager
$101.31
First Subseq.
Year Year
5.00 2.00
4.00 0.00
2.00 0.00
0.00 0.00
0.00 1.00
11.00 3.00
Environmental
Manager
$88.79
First Subseq.
Year Year
16.00 4.00
20.00 2.00
8.00 1.00
1.00 1.00
0.00 4.00
45.00 12.00
Environmental
Engineer
$71.03
First Subseq.
Year Year
44.00 7.00
26.00 6.00
12.00 1.00
4.00 4.00
0.00 4.00
86.00 22.00
Legal Counsel
$101.00
First Subseq.
Year Year
6.00 2.00
0.00 0.00
0.00 0.00
0.00 0.00
0.00 1.00
6.00 3.00
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$5,659 $1,257
$4,028 $604
$1,765 $160
$373 $373
$0 $842
$11,825 $3,235
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Table 4-48b. Subpart MM Petroleum Suppliers (Imports/Exporters): Labor Costs (2006$)
Activity
Registration
Monitoring
Reporting
Archiving
Auditing
Total
Labor Hours
Senior Manager
$101.31
First Subseq.
Year Year
5.00 2.00
4.00 0.00
2.00 0.00
0.00 0.00
0.00 1.00
11.00 3.00
Environmental
Manager
$88.79
First Subseq.
Year Year
16.00 4.00
16.00 2.00
8.00 1.00
1.00 1.00
0.00 4.00
41.00 12.00
Environmental
Engineer
$71.03
First Subseq.
Year Year
34.00 7.00
20.00 4.00
8.00 1.00
4.00 4.00
0.00 4.00
66.00 20.00
Legal Counsel
$101.00
First Subseq.
Year Year
6.00 2.00
0.00 0.00
0.00 0.00
0.00 0.00
0.00 1.00
6.00 3.00
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$4,948 $1,257
$3,246 $462
$1,481 $160
$373 $373
$0 $842
$10,049 $3,093
Table 4-49. Subpart MM Petroleum Suppliers: Capital and O&M Costs (2006$)
Activity
Annualized
Equipment Capital Cost O&M Costs
Capital Cost Lifetime (years) (per year) (per year)
Total Reporting per
Unit/Facility Cost
First Year Subseq. Year
Equipment (selection,
purchase, installation)
Performance testing
Recordkeeping
Travel
Total
$0
$0
$0
$0
$0
4.27 Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids
Overview. All local distribution companies (LDCs) are required to report under this rule.
The unit of reporting is the individual LDC. No distinction has been made between the sizes of
LDCs for estimating the monitoring costs because the rule would require additional processing
of data that LDCs already collect and report. Under the rule, individual operating LDCs are the
reporters as opposed to holding companies. For example, National Grid PLC is a holding
company that operates two LDCs in New York, namely Keyspan on Long Island and Niagara
Mohawk in upstate; and other LDCs in New Hampshire, Massachusetts, and Rhode Island. Each
operating company in each state will be a reporter under this rule, not National Grid.
4-62
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The Rule covers all fractionators of natural gas liquids (NGLs). The unit of reporting is
the fractionation plant or facility. As defined in the Rule, these are plants that fractionate bulk or
y-grade NGLs into their constituent liquids: ethane, propane, butane, isobutane and C5+. Not
covered by this subpart of the rule are field gathering and boosting stations or natural gas
processing plants that produce only bulk or y-grade NGLs and do not fractionate these into their
constituent liquids. Companies may own more than one fractionation plant: each plant is required
to report under this rule. No distinction has been made between the sizes of fractionation plants
for estimating the monitoring costs because the Rule only would require additional processing of
data that plants already collect as part of their on-going business and report on EIA Form 816.
Labor Costs. Labor costs for LDC's are estimated to be approximately $2,600 per entity
in the first year and $1,300 in subsequent years. Most of the costs are related to registration and
monitoring. Labor costs for natural gas liquids fractionators are estimated to be approximately
$3,500 per entity in the first year and $3,000 in subsequent years. Most of the costs are related to
registration and monitoring.
Capital and O&M Costs. There are no new capital equipment or O&M expenses.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping, and Reporting Costs. This subpart is assigned additional recordkeeping
costs ($1,700).
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Table 4-50a. Subpart NN Natural Gas Suppliers (LDCs): Labor Costs (2006$)
Average
Activity
Registration
Monitoring
Reporting
Archiving
Auditing
Total
Labor Hours
Electricity Refinery Industrial
Manager Manager Manager
$88.79 $101.31 $71.03
First Subseq. First Subseq. First Subseq.
Year Year Year Year Year Year
3 1
1 1
0 0
0 0
0 0
000052
Electricity
Lawyer
$101.00
First Subseq.
Year Year
2
1
0
0
0
3
1
0
0
0
0
2
Eng/Tech
$60.84
First
Year
0
0
0
0
0
0
Subseq.
Year
0
0
0
0
0
0
Refinery
Eng/Tech
$63.89
First Subseq.
Year Year
0 0
0 0
0 0
0 0
0 0
0 0
Industrial
Eng/Tech
$55.20
First
Year
5
5
1
0
0
11
Subseq.
Year
2
3
1
0
1
7
Admin
$29.65
First Subseq.
Year Year
1
1
1
0
0
3
0
1
1
0
0
3
Labor Cost
per Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$761 $288
$413 $278
$105 $105
$20 $20
$22 $101
$1,32 $793
1
Table 4-50b. Subpart NN Natural Gas Suppliers (Natural Gas Liquids Fractionators): Labor Costs (2006$)
Labor Hours
Manager
Activity
Registration
Monitoring
Reporting
Archiving
Auditing
Total
($101
First Year
4.40
3.00
1.00
0.00
0.40
8.80
.00/hr)
Subseq. Year
3.50
1.00
0.50
0.00
0.80
5.80
Industrial Engineer/ Technician Administrator
($63.89/hr)
First Year
6.50
14.00
4.00
0.50
0.80
25.80
Subseq. Year
8.00
11.00
3.00
0.50
1.60
24.10
($29.65/hr)
First Year
1.30
2.00
2.00
0.50
0.10
5.90
Subseq. Year
2.17
3.00
4.00
0.50
0.20
9.87
Legal
Counsel
($101.00/hr)
First Year
4.50
1.00
2.00
0.00
0.10
7.60
Subseq. Year
4.00
1.00
0.50
0.00
0.20
5.70
• Labor Cost per Year per
Reporting Unit/Facility
(2006$)
First Year Subseq. Year
$1,353
$1,358
$618
$47
$105
$3,480
$1,333
$256
$994
$411
$2,994
-------
Table 4-51. Subpart NN Natural Gas Suppliers: Capital and O&M Costs (2006$)
Activity
Equipment
Capital Cost Lifetime (years)
Annualized
Capital Cost
(per year)
O&M Costs
(per year)
Total Reporting per
Unit/Facility Cost
First
Year
Subseq.
Year
Equipment (selection,
purchase, installation)
Performance testing
Recordkeeping
Travel
Total
SO
SO
so
so
so
4.28 Subpart OO—Suppliers of Industrial Greenhouse Gases
Overview. The industrial gas supply category includes facilities that produce N2O or
fluorinated GHGs (e.g., HFCs, PFCs, SF6, NFS, and fluorinated anesthetics), importers of N2O
or fluorinated GHGs, and exporters of N2O or fluorinated GHGs. As described below, costs were
estimated for model facilities that encompass the likely combinations of these entities and
activities. In addition, because importers of fluorinated GHGs andN2O frequently also import
CC>2, and because importers would be required to sum their CCVequivalent imports across gases
to determine whether they exceeded the reporting threshold, this analysis considers imports of
CC>2. While a TSD was prepared for imports of gas in products, EPA is not proposing to require
that importers of products report. Thus, imports in products are not included in the totals below.
However, EPA estimates that the burden and cost per importer for importers of pre-charged
products would be comparable to (slightly smaller than) those estimated below for producers and
importers of bulk gases.
There are four model facilities that fall under Industrial Gas Supply. Each one represents
the specific reporting activities (production, import, export, transformation, or destruction) and
costs relevant to each category.
Labor Costs. Labor costs are estimated to be approximately $908 per entity in the first
year and $908 in subsequent years. Most of the costs are related to registration and monitoring.
Labor costs for N2O producers are estimated at $473 in the first and subsequent years
(Table 4-52a). Anesthetic producers (Table 4-52b) and fluorinated gas producers (Table 4-52d)
face an approximate labor cost of $820 per year. The labor cost for fluorinated gas importers is
estimated to be $946 annually for each facility (Table 4-52c).
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Capital and O&M Costs. There are no new capital equipment or O&M expenses.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
Table 4-52a. N2O Producers: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
(calculations)
Reporting
Total
Labor Rates
Legal Managerial
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
2 2
0022
(per hour)
Technical Clerical
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
6 6
6600
Labor Cost per
Year per
Reporting
Unit/Facility3
First Subseq.
Year Year
$473 $473
$473 $473
Table 4-52b. Anesthetic Producers: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
(calculations)
Reporting
Total
Labor Rates
Legal Managerial
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
3 3
0033
(per hour)
Technical Clerical
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
11 11
11 11 0 0
Labor Cost per
Year per
Reporting
Unit/Facility3
First Subseq.
Year Year
$820 $820
$820 $820
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Table 4-52c. Fluorinated Gas Importers (Bulk): Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
(calculations)
Reporting
Total
Legal
$101.00
First Subseq.
Year Year
0 0
0 0
0 0
0 0
0 0
0 0
Labor Rates
Managerial
$71.03
First Subseq.
Year Year
0 0
0 0
0 0
4 4
0 0
4 4
(per hour)
Technical
$55.20
First Subseq.
Year Year
0 0
0 0
0 0
12 12
0 0
12 12
Clerical
$29.65
First Subseq.
Year Year
0
0
0
0
0
0
0
0
0
0
0
0
Labor Cost per
Year per
Reporting
Unit/Facility3
First Subseq.
Year Year
$0 $0
$0 $0
$0 $0
$946 $946
$0 $0
$946 $946
Table 4-52d. Fluorinated Gas Producers (Bulk): Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis
(calculations)
Reporting
Total
Labor Rates
Legal Managerial
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
3 3
0033
(per hour)
Technical Clerical
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
11 11
11 11 0 0
Labor Cost per
Year per
Reporting
Unit/Facility3
First Subseq.
Year Year
$820 $820
$820 $820
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Table 4-53. Subpart OO Suppliers of Industrial Gases: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs3
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost O&M Costs
Capital Cost (years) (per year) (per year)
SO SO SO
Total Reporting Cost
per Unit/Facility
Subseq.
First Year Year
SO SO
4.29 Subpart PP—Suppliers of Carbon Dioxide (CO2)
Overview. All 13 existing CO2 capture sites and CO2 production well sites are included in
the cost estimate. The monitoring option for each site involves a CO2 flow meter, and therefore
the monitoring cost for each site is the same. Hence, model facilities were not needed for
characterizing the facility and estimating the relevant costs. A cost that is missing from the
Subpart PP total cost is the cost of taking quarterly samples of the CO2 stream and conducting
quarterly tests on the sample to determine the CO2 composition. To estimate these costs we
have applied the same assumptions that were used in Subpart OO for sampling and testing of
industrial gases. We have estimated the cost of sampling and testing the CO2 stream for CO2
composition to be $1,411 the first year and $1,301 in each subsequent year. These costs were
omitted from the total cost but are being discussed here for thoroughness. For further detail on
the costs of taking quarterly samples of the CO2 stream, see the cost appendix.
Labor Costs. Labor costs are estimated to be approximately $237 per entity in the first
year and subsequent years.
Capital and O&M Costs. There are no new capital equipment or O&M expenses.
Stationary Combustion Costs. This subpart is not assigned additional stationary
combustion costs as described in subpart C (Table 4-3).
Recordkeeping and Reporting Costs. This subpart is assigned recordkeeping ($1,700 per
entity) and reporting ($500) costs.
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Table 4-54. Subpart PP Suppliers of CO2: Labor Costs (2006$)
Activity
Planning
QA/QC
Recordkeeping
Sampling and analysis3
Reporting
Total
Labor Rates
Lawyer Industrial Manager
$101.00 $71.03
First Subseq. First Subseq.
Year Year Year Year
1 1
1 1
(per hour)
Industrial
Engineer/ Administrative
Technician Support
$55.20 $29.65
First Subseq. First Subseq.
Year Year Year Year
3 3
3 3
Labor Cost per
Year per
Reporting
Unit/Facility
First Subseq.
Year Year
$237 $237
$237 $237
a Assumes four data collection events per year for one input (CO2 flow meter data); no estimates for calculations are provided in
this row. For more information refer to the cost appendix.
Table 4-55. Subpart PP Suppliers of CO2: Capital and O&M Costs (2006$)
Activity
Equipment (selection, purchase,
installation)
Performance testing
Recordkeeping
Travel
Sampling costs
Total
Cost Categories
Equipment Annualized
Lifetime Capital Cost O&M Costs
Capital Cost (years) (per year) (per year)
$0 $0 $0
Total Reporting per
Unit/Facility Cost
Subseq.
First Year Years
$0 $0
Note: There are no capital or O&M costs for the monitoring option for the CO2 Capture Sites and CO2 Production Well Sites
Category CO2 flow meters are assumed to exist at all existing sites and that there is no incremental O&M cost for their
operation.
4.30 Mobile Sources
Mobile source costs for the rule are estimated for upstream heavy-duty vehicles and
nonroad engine manufacturers (the rule does not apply to light-duty vehicle manufacturers) and
are associated with the fixed certification costs of a new regulation. Typically, our cost analysis
focuses on variable costs associated with engine or vehicle technologies needed to meet new
emissions standards. However, since we are not promulgating new emission standards, the
requirements have no such variable costs. Certification costs, including those estimated here, are
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typically modest relative to the much larger costs of redesigning and modifying vehicles and
engines to comply with new emissions standards. Costs are categorized into reporting and
recordkeeping (labor) costs, new test equipment/facility (equipment) costs, and incremental
testing (operating and maintenance) costs.
4.30.1 Source Description and Baseline Reporting
The concept of a reporting "threshold" for mobile engine manufacturers differs from the
approach for other sectors in this rule. EPA would not have manufacturers determine their
eligibility based on total tons emitted per year. EPA's current mobile source criteria pollutant
control programs are based on emissions rates over prescribed test cycles rather than tons per
year estimates. Since EPA is building on our existing system, we believe that a threshold based
on manufacturer size is appropriate for the mobile source sector. Although the emission rates of
some heavy-duty vehicles and nonroad engines would not be reported, we do not believe this is a
concern because the technologies—and thus emission rates—from larger manufacturers
represent the same basic technologies and emission rates of essentially all heavy-duty vehicles
and nonroad engines. Estimates of the number of affected manufacturers are provided in
Table 4-56.
Table 4-56. Mobile Source Heavy-duty Vehicle and Nonroad Engine Categories
Category
Estimated Number of Affected Manufacturers
Highway heavy-duty vehicles (chassis-certified)
Highway heavy-duty engines
Highway motorcycles
Nonroad diesel engines
Marine diesel engines
Locomotives
Nonroad small spark ignition engines
Nonroad large spark ignition engines
Marine spark ignition engines/personal watercraft
Snowmobiles
Off-highway motorcycles and ATVs
Mobile sources
3
11
46
66
27
6
81
9
12
4
52
317
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Baseline Reporting. Manufacturers currently conduct vehicle and engine emissions
testing as part of EPA's existing emissions control programs. Manufacturers already measure
CC>2, although in some cases are not currently required to report CC>2 test results to EPA. N2O
and CH4 measurement and reporting would be new for several mobile source categories, as
discussed below. Manufacturers not already measuring N2O and CH4 would need to install new
measurement equipment, but new testing would not be needed since these pollutants would be
measured over existing tests. Regarding the aircraft engine category, we assume that there are no
costs associated with reporting requirements.
4.30.2 Labor Costs: Reporting andRecordkeeping
Reporting and recordkeeping cost estimates account for the staff and management hours
needed to review and submit new data to EPA as part of the certification process. For all covered
categories, manufacturers would be required to report CC>2, CH4, and N2O emissions levels.
Manufacturers have been submitting certification data to EPA for many years, and the process
for collecting and submitting data to EPA is highly automated for most manufacturers. Once the
test cells and computer systems are set up to collect and submit the data, the act of submitting the
incremental emissions data to EPA as part of certification would be routine. We therefore
estimate a minimal incremental burden for reporting, 10 to 20 minutes each for managerial staff,
engineering staff, and secretarial staff per vehicle/engine family, to ensure the appropriate data
are submitted to EPA.
Using labor rate statistics from the Bureau of Labor Statistics for vehicle and engine
manufacturers, with overhead 60% over the baseline applied (a multiplier of 1.6), we estimated
reporting costs for each mobile source category.1 For emissions reporting and recordkeeping, we
used these labor rates, the estimated hours needed for reporting/recordkeeping for each
vehicle/engine family as described above, and the number of vehicle and engine families
estimated from EPA's certification databases, to calculate reporting costs. The estimated number
of vehicle/engine families and the average of the low and high estimates are provided in
Table 4-57.
y 2007 BLS National Industry-Specific Occupational Employment and Wage Estimates, labor rates for
engineering managers, mechanical engineers, and secretaries (except legal, medical, and executives), NAICs
code 336100 for vehicles and 333618 for engines. Vehicles: $52.81, $35.81, and $19.53 for managerial,
engineering, and secretarial hours, respectively. Engines: $47.33, $33.81, and $15.86 for managerial,
engineering, and secretarial hours, respectively.
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Table 4-57. Mobile Source Vehicle and Engine Reporting/Recordkeeping Costs (2006$)
Estimated Number of
Category Vehicle/Engine Families
Highway heavy-duty vehicles
Highway heavy-duty engines
Highway motorcycles
Nonroad diesel engines
Marine diesel engines
Locomotives
Nonroad small spark ignition engines
Nonroad large spark ignition engines
Marine spark ignition engines/personal watercraft
Snowmobiles
Off-highway motorcycles and ATVs
Mobile sources
17
71
224
636
138
59
802
31
111
37
214
2,340
Estimated Average Annual
Reporting/Record-
Keeping Costs
$700
$2,800
$8,700
$25,000
$5,400
$2,300
$31,000
$1,200
$4,300
$1,400
$8,300
$91,000
4.30.3 Equipment Costs: Test Equipment/Facility Upgrades
We have included estimated "start-up" capital costs associated with new test equipment
for measuring N20 and CH4 for each affected test cell, except in cases where manufacturers
already have this equipment. We estimated the number of test cells that would be affected in
each category. For all categories, where we do not have detailed test cell information for all
manufacturers, we estimated one test cell for every six engine families certified for each
manufacturer, based on our general understanding of certification testing and manufacturer test
facilities.
We are including $50,000 per test cell for equipping the test cells with CH4 measurement
capabilities and $50,000 per test cell forN20 measurement capabilities. These costs include the
costs of the analyzers and related costs, including installation. There are no facilities or
equipment costs associated with CO2 because manufacturers already measure CO2. This is also
the case for CH4 for heavy-duty vehicles and locomotives. For each manufacturer, we have also
included an estimated cost to account for information technology (IT) system modifications that
may be needed to process the new emissions test data being collected. As mentioned above, the
test data collection and processing is often highly automated. We have based the cost on 40
hours of IT staff time at $100 per hour for each manufacturer. We have amortized the costs for
the test facility and equipment upgrades described above over a 10-year recovery period using an
amortization rate of 7% in our analysis. We believe that this approach reasonably accounts for
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the lifecycle of testing facilities and equipment. Also, these costs are projected to occur 1 year
prior to the start of the program (manufacturers would need to install equipment and upgrade
facilities ahead of and in preparation for the beginning of the reporting requirements) and the
costs are adjusted using the 7% rate of return to reflect the time value of money. This
methodology allows us to estimate an overall annualized cost, an average annual cost per
manufacturer, and an average per vehicle or engine cost. Table 4-58 provides the estimated
number of test cells and the total annualized facility costs for each mobile source category.
Table 4-58. Mobile Source Annualized Equipment/Facility Costs (2006$)
CH4
Highway heavy-duty vehicles
Highway heavy-duty engines x
Highway motorcycles x
Nonroad diesel engines x
Marine diesel engines x
Locomotives
Nonroad small spark ignition engines x
Nonroad large spark ignition engines x
Marine spark ignition x
engines/personal watercraft
Snowmobiles x
Off-highway motorcycles and ATVs x
Mobile sources
Estimated Average
Estimated Number of Annualized
N2O Test Cells Equipment/Facility Costs
x
x
X
X
X
X
X
X
X
X
X
3
15
55
129
35
11
164
9
22
7
65
740
$30,000
$255,000
$950,000
$2,127,000
$599,000
$98,000
$2,696,000
$159,000
$364,000
$116,000
$1,117,000
$8,514,000
4.30.4 O&M Costs
There would be no additional O&M costs associated with other emissions measurements
being adopted because these measurements would be done during tests already performed by
manufacturers as part of current emissions testing requirements.
4.30.5 Total Aggregate Annualized Costs, and Average Per Manufacturer and Per Unit Costs
We estimated total annualized costs for each category and for mobile sources as a whole
by summing the costs described above. We estimated per manufacturer average costs by dividing
the annualized aggregate costs by the estimated number of manufacturers in each category, and
per unit costs by dividing by the estimated annual sales for each category from the certification
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databases. Table 4-59 provides a summary of the costs described above and Table 4-60 provides
the aggregate costs, average per manufacturer, and average per unit cost estimates. The aggregate
costs by category vary depending primarily on the new requirements for each category, and the
number of manufacturers, engine families, and test cells for each category. The costs are minimal
relative to the typical costs for emissions certification. The total annualized cost for mobile
sources is estimated to be about $8.6 million.
Table 4-59. Summary of Estimated Annual Mobile Source Costs by Category (2006$)
Category
Highway heavy-duty
vehicles
Highway heavy-duty
engines
Highway motorcycles
Nonroad diesel
engines
Marine diesel engines
Locomotives
Nonroad small spark
ignition engines
Nonroad large spark
ignition engines
Marine spark ignition
engines/personal
watercraft
Snowmobiles
Off-highway
motorcycles and
ATVs
Mobile sources
Annual
Labor1
$700
$2,800
$8,700
$25,000
$5,400
$2,300
$31,300
$1,200
$4,300
$1,400
$8,300
$91,100
Annualized
IT Start-up
$7,300
$27,000
$112,000
$161,000
$66,000
$15,000
$197,000
$22,000
$29,000
$9,800
$127,000
$773,000
C02
O&M
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
C02
Annualized
Capital/
Facility
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
N20
O&M
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
N20
Annualized
Capital/
Equipment
$23,000
$114,000
$419,000
$983,000
$267,000
$84,000
$1,249,000
$69,000
$168,000
$53,000
$495,000
$3,924,000
CH,
O&M
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
CH,
Annualized
Capital/
Equipment
$0
$114,000
$419,000
$983,000
$267,000
$0
$1,249,000
$69,000
$168,000
$53,000
$495,000
$3,817,000
1 Includes annual labor costs associated with emissions test data reporting and recordkeeping for all pollutants.
2 A/C system scoring would not involve testing and therefore costs are for reporting and recordkeeping only.
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Table 4-60. Estimated Mobile Source Vehicle and Engine Annualized Aggregate Costs,
Average Per Manufacturer Costs, and Average Per Unit Costs ($2006)
Estimated Annualized
Category Aggregate Costs
Highway heavy-duty vehicles
Highway heavy-duty engines
Highway motorcycles
Nonroad diesel engines
Marine diesel engines
Locomotives
Nonroad small spark ignition engines
Nonroad large spark ignition engines
Marine spark ignition
engines/personal watercraft
Snowmobiles
Off-highway motorcycles and ATVs
Mobile sources
$30,000
$258,000
$959,000
$2,151,000
$604,000
$101,000
$2,727,000
$160,000
$369,000
$118,000
$1,125,000
$8,603,000
Estimated Average Per
Manufacturer Costs
$10,000
$24,000
$21,000
$25,000
$22,000
$11,000
$34,000
$18,000
$31,000
$30,000
$22,000
Estimated Average
Per Unit Costs
$0.10
$0.37
$1.06
$1.30
$24.87
$21.89
$0.07
$1.47
$0.74
$1.19
$0.44
$0.19
4.31 Summary
Tables 4-61 and 4-62 present summary estimates of the impacts of the rule under the four
thresholds. Table 4-61 shows, for each subpart at each threshold, the number and share of entities
and emissions covered by the rule. Table 4-62 summarizes the national costs and costs per
representative entity for each subpart and each threshold.
As shown in Table 4-61, at lower thresholds a higher number and share of facilities and
emissions are covered by the rule. As the threshold increases, smaller numbers and shares of
entities and emissions are affected. At the 1,000 MT threshold, 20 subparts report that 100% of
the entities and/or 100% of the emissions are covered. At this threshold, the median share of
entities and emissions is 100%; however, the Manure Management subpart has fewer than 5% of
entities covered—even at the lowest threshold—and less than 80% of emissions covered. At the
25,000 MT threshold, on the other hand, 18 subparts have 100% of entities covered and/or 100%
of the emissions are covered. The median share of entities covered is 100% and the median share
of emissions covered remains 100%. The manure management subpart again has the lowest share
of entities covered (less than 1%) and only 6% of emissions covered. At the highest threshold
(100,000 MT), only ten subparts have 100% of entities covered and/or 100% of the emissions are
4-75
-------
covered. At this threshold, four subparts have less than 1% of entities covered. The median share
of entities covered has fallen to 89%, but the median share of emissions covered remains high at
99%.
Table 4-61. Number and Share of Entities and Emissions Covered by Threshold
Total Covered
Emissions Emissions
Number Percent of (Million (Million Percent of
Number of of Entities Entities MTCO2e/ MTCO2e/ Emissions
Subpart Implied Sectors Entities Covered Covered Year) Year) Covered
1,000 Threshold
C
D
E
F
G
H
K
N
O
P
Q
R
S
V
X
Y
Z
AA
BB
CC
EE
GG
HH
JJ
MM
NN
OO
PP
QQ
Stationary Combustion
Electricity Generation3
Adipic Acid Production3
Aluminum Production3
Ammonia Manufacture and Urea
Consumption3
Cement Manufacture3
Ferroalloy Production
Glass
HCFC-22 Production & HFC
Destruction3
Hydrogen
Iron and Steel Production
Lead Production
Lime Manufacture3
Nitric Acid Production3
Petrochemical Production (325-
ethylene, etc)3
Petroleum Refineries3
Phosphoric Acid Production3
Pulp & Paper
Silicon Carbide Production and
Consumption3
Soda Ash Manufacture and
Consumption3
Titanium Dioxide Production3
Zinc Production
Landfills
Manure Management
Suppliers of Petroleum Products'5
Suppliers of Natural Gas and Natural
Gas Liquids3
Suppliers of Industrial GHGs
Suppliers of Carbon Dioxideb
Mobile Sources3
350,000
1,108
4
14
23
107
9
374
3
77
130
27
89
45
80
150
14
425
1
5
8
9
7,800
329,304
364
1,502
383
13
NA
32,000
1,108
4
14
23
107
9
217
3
73
130
17
89
45
80
150
14
425
1
5
8
9
6,830
10,577
315
1,502
284
13
317
9%
100%
100%
100%
100%
100%
100%
58%
100%
95%
100%
63%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
88%
3%
87%
100%
74%
100%
410
2,262
9
6
13
87
2
4
14
15
85
1
25
18
54
205
4
58
0
3
4
1
111
54
2,841
783
644
40
2,103
250
2,262
9
6
13
87
2
4
14
15
85
1
25
18
54
205
4
58
0
3
4
1
111
50
2,841
783
644
40
35
61%
100%
100%
100%
100%
100%
100%
98%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
92%
100%
100%
100%
100%
(continued)
4-76
-------
Table 4-61. Number and Share of Entities and Emissions Covered by Threshold
(continued)
Subpart Implied Sectors
Total Covered
Emissions Emissions
Number of Percent of (Million (Million Percent of
Number of Entities Entities MTCO2e/ MTCO2e/ Emissions
Entities Covered Covered Year) Year) Covered
10,000 Threshold
C
D
E
F
G
H
K
N
O
P
Q
R
S
V
X
Y
Z
AA
BB
CC
EE
GG
HH
JJ
MM
NN
OO
PP
QQ
Stationary Combustion
Electricity Generation
Adipic Acid Production
Aluminum Production
Ammonia Manufacture and Urea
Consumption
Cement Manufacture
Ferroalloy Production
Glass
HCFC-22 Production & HFC
Destruction
Hydrogen
Iron and Steel Production
Lead Production
Lime Manufacture
Nitric Acid Production
Petrochemical Production (325-
ethylene, etc)
Petroleum Refineries
Phosphoric Acid Production
Pulp & Paper
Silicon Carbide Production and
Consumption
Soda Ash Manufacture and
Consumption
Titanium Dioxide Production
Zinc Production
Landfills
Manure Management
Suppliers of Petroleum Products
Suppliers of Natural Gas and
Natural Gas Liquids
Suppliers of Industrial GHGs
Suppliers of Carbon Dioxide
Mobile Sources
350,000
1,108
4
14
23
107
9
374
3
77
130
27
89
45
80
150
14
425
1
5
8
9
7,800
329,304
364
1,502
383
13
NA
8,000
1,108
4
14
23
107
9
158
3
51
128
16
89
45
80
150
14
425
1
5
8
8
3,484
568
315
1,502
213
13
317
2%
100%
100%
100%
100%
100%
100%
42%
100%
66%
98%
59%
100%
100%
100%
100%
100%
100%
100%
100%
100%
89%
45%
<1%
87%
100%
56%
100%
410
2,262
9
6
13
87
2
4
14
15
85
1
25
18
54
205
4
58
0
3
4
1
111
54
2,841
783
644
40
2,103
230
2,262
9
6
13
87
2
4
14
15
85
1
25
18
54
205
4
58
0
3
4
1
104
12
2,841
783
644
40
35
56%
100%
100%
100%
100%
100%
100%
91%
100%
99%
100%
99%
100%
100%
100%
100%
100%
100%
100%
100%
100%
99%
94%
22%
100%
100%
100%
100%
(continued)
4-77
-------
Table 4-61. Number and Share of Entities and Emissions Covered by Threshold
(continued)
Subpart Implied Sectors
Total Covered
Emissions Emissions
Number of Percent of (Million (Million Percent of
Number of Entities Entities MTCO2e/ MTCO2e/ Emissions
Entities Covered Covered Year) Year) Covered
25,000 Threshold
C
D
E
F
G
H
K
N
0
P
Q
R
S
V
X
Y
Z
AA
BB
CC
EE
GG
HH
JJ
MM
NN
00
PP
QQ
Stationary Combustion
Electricity Generation
Adipic Acid Production
Aluminum Production
Ammonia Manufacture and Urea
Consumption
Cement Manufacture
Ferroalloy Production
Glass
HCFC-22 Production & HFC
Destruction
Hydrogen
Iron and Steel Production
Lead Production
Lime Manufacture
Nitric Acid Production
Petrochemical Production (325-
ethylene, etc)
Petroleum Refineries
Phosphoric Acid Production
Pulp & Paper
Silicon Carbide Production and
Consumption
Soda Ash Manufacture and
Consumption
Titanium Dioxide Production
Zinc Production
Landfills
Manure Management
Suppliers of Petroleum Products
Suppliers of Natural Gas and
Natural Gas Liquids
Suppliers of Industrial GHGs
Suppliers of Carbon Dioxide
Mobile Sources
350,000
1,108
4
14
23
107
9
374
3
77
130
27
89
45
80
150
14
425
1
5
8
9
7,800
329,304
364
1,502
383
13
NA
3,000
1,108
4
14
23
107
9
55
3
41
121
13
89
45
80
150
14
425
1
5
8
5
2,551
107
315
1,502
167
13
317
1%
100%
100%
100%
100%
100%
100%
15%
100%
53%
93%
48%
100%
100%
100%
100%
100%
100%
100%
100%
100%
56%
33%
<1%
87%
100%
44%
100%
410
2,262
9
6
13
87
2
4
14
15
85
1
25
18
54
205
4
58
0
3
4
1
111
54
2,841
783
644
40
2,103
220
2,262
9
6
13
87
2
2
14
15
85
1
25
18
54
205
4
58
0
3
4
1
91
5
2,841
783
643
40
35
54%
100%
100%
100%
100%
100%
100%
51%
100%
98%
100%
93%
100%
100%
100%
100%
100%
100%
100%
100%
100%
94%
82%
8%
100%
100%
100%
100%
(continued)
4-78
-------
Table 4-61. Number and Share of Entities and Emissions Covered by Threshold
(continued)
Subpart Implied Sectors
100,000
C
D
E
F
G
H
K
N
0
P
Q
R
S
V
X
Y
Z
AA
BB
CC
EE
GG
HH
JJ
MM
NN
00
PP
QQ
Threshold
Stationary Combustion
Electricity Generation
Adipic Acid Production
Aluminum Production
Ammonia Manufacture and Urea
Consumption
Cement Manufacture
Ferroalloy Production
Glass
HCFC-22 Production & HFC
Destruction
Hydrogen
Iron and Steel Production
Lead Production
Lime Manufacture
Nitric Acid Production
Petrochemical Production (325-
ethylene, etc)
Petroleum Refineries
Phosphoric Acid Production
Pulp & Paper
Silicon Carbide Production and
Consumption
Soda Ash Manufacture and
Consumption
Titanium Dioxide Production
Zinc Production
Landfills
Manure Management
Suppliers of Petroleum Products
Suppliers of Natural Gas and
Natural Gas Liquids
Suppliers of Industrial GHGs
Suppliers of Carbon Dioxide
Mobile Sources
Total Covered
Emissions Emissions
Number of Percent of (Million (Million Percent of
Number of Entities Entities MTCO2e/ MTCO2e/ Emissions
Entities Covered Covered Year) Year) Covered
350,000
1,108
4
14
23
107
9
374
3
77
130
27
89
45
80
150
14
425
1
5
8
9
7,800
329,304
364
1,502
383
13
NA
1,000
1,108
4
14
22
106
8
1
3
30
111
0
52
40
80
150
14
410
1
5
7
4
1,038
0
260
1,502
113
9
317
0%
100%
100%
100%
96%
99%
89%
0%
100%
39%
85%
0%
58%
89%
100%
100%
100%
96%
100%
100%
88%
44%
13%
0%
71%
100%
30%
69%
410
2,262
9
6
13
87
2
4
14
15
85
1
25
18
54
205
4
58
0
3
4
1
111
54
2,841
783
644
40
2,103
170
2,262
9
6
13
87
2
0
14
14
84
0
24
18
54
205
4
58
0
3
4
1
66
0
2,837
783
640
39
35
41%
100%
100%
100%
99%
100%
97%
5%
100%
94%
99%
0%
94%
99%
100%
100%
100%
100%
100%
100%
98%
84%
59%
0%
100%
100%
99%
100%
aWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule. For further information on who must report, please see Section III A of the preamble.
bWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule, with the exception of total bulk imports or total bulk exports that exceed 25,000 metric tons CO2e
per year. For further information on who must report, please see Section IIIA of the preamble.
4-79
-------
Table 4-62 presents the costs of compliance for each subpart at each threshold. The first
eight columns report subsets of costs, including costs associated with processes (labor,
annualized capital, and operating and maintenance costs), costs associated with wastewater
treatment, costs associated with landfills, costs associated with reporting electricity usage, costs
associated with reporting and recordkeeping, and costs associated with stationary combustion.
The final four columns report total national costs and total per-entity costs for the first year and
for subsequent years. (Because the first year entails added compliance activities, relative to
subsequent years, many subparts have higher costs in the first year relative to subsequent years).
As described in Table 4-61, at lower thresholds, a larger number of entities 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 MT to 10,000 MT, to 25,000 MT,
and finally to 100,000 MT. First year private national costs for reporters, for example, range
from $312 million at the 1,000 MT threshold, to $132 million at the 10,000 MT threshold, to $98
million at the 25,000 MT threshold, to $71 million at the 100,000 MT threshold. Cost per
representative entity for a particular subpart generally remains the same or declines slightly from
lower thresholds to higher ones; however, it varies considerably from subpart to subpart.
4-80
-------
Table 4-62. Summary of Costs and Costs per Representative Entity by Threshold (Million $2006)
oo
Subsequent
Subpart
Threshold
C
D
E
F
G
H
K
N
O
P
Q
R
S
V
X
Y
Z
AA
BB
CC
EE
GG
JJ
MM
Implied Sectors
: 1,000
Stationary Combustion
Electricity Generation3
Adipic Acid Production3
Aluminum Production3
Ammonia Manufacture and Urea
Consumption3
Cement Manufacture3
Ferroalloy Production
Glass
HCFC-22 Production & HFC
Destruction3
Hydrogen
Iron and Steel Production
Lead Production
Lime Manufacture3
Nitric Acid Production3
Petrochemical Production (325-
ethylene, etc)3
Petroleum Refineries3
Phosphoric Acid Production3
Pulp & Paper
Silicon Carbide Production and
Consumption3
Soda Ash Manufacture and
Consumption3
Titanium Dioxide Production3
Zinc Production
Manure Management
Suppliers of Petroleum Products'5
First Year
Process
Costs
$0.000
$0.000
$0.038
$0.194
$0.050
$0.989
$0.034
$0.348
$0.017
$0.088
$3.934
$0.049
$0.138
$0.567
$2.182
$5.861
$0.022
$7.705
$0.002
$0.042
$0.021
$0.030
$9.153
$3.655
Year
Process
Costs
$0.000
$0.000
$0.033
$0.194
$0.023
$0.817
$0.019
$0.112
$0.017
$0.060
$2.129
$0.024
$0.041
$0.517
$1.709
$3.820
$0.006
$7.705
$0.001
$0.037
$0.010
$0.016
$4.266
$1.068
First Year
Combus-
tion Costs
$184.090
$3.279
$0.049
$0.000
$0.296
$5.555
$0.028
$1.001
$0.000
$0.355
$0.000
$0.078
$4.988
$0.224
$0.000
$0.000
$0.785
$0.000
$0.006
$0.028
$0.044
$0.042
$0.000
$0.000
Second
Year
Combus-
tion Costs
$180.148
$3.279
$0.033
$0.000
$0.195
$3.103
$0.016
$0.592
$0.000
$0.210
$0.000
$0.046
$2.783
$0.125
$0.000
$0.000
$0.438
$0.000
$0.006
$0.028
$0.044
$0.025
$0.000
$0.000
Reporting
and
Record-
keeping
Costs
$0.000
$0.000
$0.009
$0.024
$0.051
$0.235
$0.020
$0.477
$0.007
$0.161
$0.000
$0.037
$0.196
$0.099
$0.000
$0.255
$0.031
$0.935
$0.002
$0.011
$0.018
$0.020
$23.270
$0.000
First Year
National
Costs
$184.090
$3.279
$0.096
$0.218
$0.397
$6.780
$0.081
$1.826
$0.023
$0.604
$3.934
$0.164
$5.322
$0.890
$2.182
$6.116
$0.837
$8.640
$0.010
$0.080
$0.083
$0.091
$32.423
$3.655
First Year
Repre-
sentative
Entity Cost
$0.006
$0.003
$0.024
$0.016
$0.017
$0.063
$0.009
$0.008
$0.008
$0.008
$0.030
$0.010
$0.060
$0.020
$0.027
$0.041
$0.060
$0.020
$0.010
$0.016
$0.010
$0.010
$0.003
$0.012
Subsequent
Year
National
Costs
$180.148
$3.279
$0.074
$0.218
$0.269
$4.155
$0.055
$1.181
$0.023
$0.431
$2.129
$0.108
$3.020
$0.741
$1.709
$4.075
$0.475
$8.640
$0.009
$0.075
$0.072
$0.060
$27.536
$1.068
Subsequent
Year
Repre-
sentative
Entity Cost
$0.006
$0.003
$0.019
$0.016
$0.012
$0.039
$0.006
$0.005
$0.008
$0.006
$0.016
$0.006
$0.034
$0.016
$0.021
$0.027
$0.034
$0.020
$0.009
$0.015
$0.009
$0.007
$0.003
$0.003
(continued)
-------
Table 4-62. Summary of Costs and Costs per Representative Entity by Threshold (Million $2006) (continued)
oo
to
Subpart
NN
00
PP
QQ
Total
Reporting
Subsequent Second and First Year Subsequent
First Year Year First Year Year Record- First Year Repre- Year
Process Process Combus- Combus- keeping National sentative National
Implied Sectors Costs Costs tion Costs tion Costs Costs Costs Entity Cost Costs
Suppliers of Natural Gas and Natural
Gas Liquids3
Suppliers of Industrial GHGs
Suppliers of Carbon Dioxideb
Mobile Sources3
$4.209
$0.264
$0.003
$72.898
$2.463
$0.264
$0.003
$40.104
$0.000
$0.000
$0.000
$200.847
$0.000
$0.000
$0.000
$191.070
$2.553
$0.625
$0.029
$29.063
$6.763
$0.889
$0.032
$8.605
$311.413
$0.005
$0.003
$0.002
$0.027
$5.017
$0.889
$0.032
$8.605
$268.842
Subsequent
Year
Repre-
sentative
Entity Cost
$0.003
$0.003
$0.002
$0.027
10,000 Threshold
C
D
E
F
G
H
K
N
0
P
Q
R
S
V
X
Y
Z
AA
BB
Stationary Combustion
Electricity Generation
Adipic Acid Production
Aluminum Production
Ammonia Manufacture and Urea
Consumption
Cement Manufacture
Ferroalloy Production
Glass
HCFC-22 Production & HFC
Destruction
Hydrogen
Iron and Steel Production
Lead Production
Lime Manufacture
Nitric Acid Production
Petrochemical Production (325-
ethylene, etc)
Petroleum Refineries
Phosphoric Acid Production
Pulp & Paper
Silicon Carbide Production and
Consumption
$0.000
$0.000
$0.038
$0.194
$0.050
$0.989
$0.034
$0.253
$0.017
$0.088
$3.873
$0.046
$0.138
$0.567
$2.182
$5.861
$0.022
$7.705
$0.002
$0.000
$0.000
$0.033
$0.194
$0.023
$0.817
$0.019
$0.081
$0.017
$0.060
$2.096
$0.023
$0.041
$0.517
$1.709
$3.820
$0.006
$7.705
$0.001
$52.067
$3.279
$0.049
$0.000
$0.296
$5.555
$0.028
$0.729
$0.000
$0.337
$0.000
$0.074
$4.988
$0.224
$0.000
$0.000
$0.785
$0.000
$0.006
$48.098
$3.279
$0.033
$0.000
$0.195
$3.103
$0.016
$0.431
$0.000
$0.199
$0.000
$0.044
$2.783
$0.125
$0.000
$0.000
$0.438
$0.000
$0.006
$0.000
$0.000
$0.009
$0.024
$0.051
$0.235
$0.020
$0.348
$0.007
$0.112
$0.000
$0.035
$0.196
$0.099
$0.000
$0.255
$0.031
$0.935
$0.002
$52.067
$3.279
$0.096
$0.218
$0.397
$6.780
$0.081
$1.330
$0.023
$0.537
$3.873
$0.155
$5.322
$0.890
$2.182
$6.116
$0.837
$8.640
$0.010
$0.007
$0.003
$0.024
$0.016
$0.017
$0.063
$0.009
$0.008
$0.008
$0.011
$0.030
$0.010
$0.060
$0.020
$0.027
$0.041
$0.060
$0.020
$0.010
$48.098
$3.279
$0.074
$0.218
$0.269
$4.155
$0.055
$0.860
$0.023
$0.371
$2.096
$0.102
$3.020
$0.741
$1.709
$4.075
$0.475
$8.640
$0.009
$0.006
$0.003
$0.019
$0.016
$0.012
$0.039
$0.006
$0.005
$0.008
$0.007
$0.016
$0.006
$0.034
$0.016
$0.021
$0.027
$0.034
$0.020
$0.009
(continued)
-------
Table 4-62. Summary of Costs and Costs per Representative Entity by Threshold (Million $2006) (continued)
J^.
oo
Subpart
CC
EE
GG
HH
JJ
MM
NN
00
PP
QQ
Total
Reporting
Subsequent Second and First Year Subsequent
First Year Year First Year Year Record- First Year Repre- Year
Process Process Combus- Combus- keeping National sentative National
Implied Sectors Costs Costs tion Costs tion Costs Costs Costs Entity Cost Costs
Soda Ash Manufacture and
Consumption
Titanium Dioxide Production
Zinc Production
Landfills
Manure Management
Suppliers of Petroleum Products
Suppliers of Natural Gas and Natural
Gas Liquids
Suppliers of Industrial GHGs
Suppliers of Carbon Dioxide
Mobile Sources
$0.042
$0.021
$0.026
$16.988
$0.491
$3.655
$4.209
$0.197
$0.003
$0.037
$0.010
$0.014
$7.523
$0.229
$1.068
$2.463
$0.197
$0.003
$28.708
$0.028
$0.044
$0.042
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
$68.528
$0.028
$0.044
$0.025
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
$58.845
$0.011
$0.018
$0.018
$0.000
$1.249
$0.000
$2.553
$0.469
$0.029
$6.704
$0.080
$0.083
$0.085
$16.988
$1.740
$3.655
$6.763
$0.666
$0.032
$8.605
$131.529
$0.016
$0.010
$0.011
$0.005
$0.003
$0.012
$0.005
$0.003
$0.002
$0.027
$0.075
$0.072
$0.056
$7.523
$1.478
$1.068
$5.017
$0.666
$0.032
$8.605
$102.862
Subsequent
Year
Repre-
sentative
Entity Cost
$0.015
$0.009
$0.007
$0.002
$0.003
$0.003
$0.003
$0.003
$0.002
$0.027
25,000 Threshold
C
D
E
F
G
H
K
N
0
P
Q
R
S
V
Stationary Combustion
Electricity Generation
Adipic Acid Production
Aluminum Production
Ammonia Manufacture and Urea
Consumption
Cement Manufacture
Ferroalloy Production
Glass
HCFC-22 Production & HFC
Destruction
Py^jgen
Iron and Steel Production
Lead Production
Lime Manufacture
Nitric Acid Production
$0.000
$0.000
$0.038
$0.194
$0.050
$0.989
$0.034
$0.088
$0.017
$0.088
$3.662
$0.037
$0.138
$0.567
$0.000
$0.000
$0.033
$0.194
$0.023
$0.817
$0.019
$0.028
$0.017
$0.060
$1.981
$0.019
$0.041
$0.517
$25.761
$3.279
$0.049
$0.000
$0.296
$5.555
$0.028
$0.254
$0.000
$0.235
$0.000
$0.060
$4.988
$0.224
$21.546
$3.279
$0.033
$0.000
$0.195
$3.103
$0.016
$0.150
$0.000
$0.139
$0.000
$0.035
$2.783
$0.125
$0.000
$0.000
$0.009
$0.024
$0.051
$0.235
$0.020
$0.121
$0.007
$0.045
$0.000
$0.029
$0.196
$0.099
$25.761
$3.279
$0.096
$0.218
$0.397
$6.780
$0.081
$0.463
$0.023
$0.369
$3.662
$0.126
$5.322
$0.890
$0.009
$0.003
$0.024
$0.016
$0.017
$0.063
$0.009
$0.008
$0.008
$0.009
$0.030
$0.010
$0.060
$0.020
$21.546
$3.279
$0.074
$0.218
$0.269
$4.155
$0.055
$0.299
$0.023
$0.244
$1.981
$0.083
$3.020
$0.741
$0.007
$0.003
$0.019
$0.016
$0.012
$0.039
$0.006
$0.005
$0.008
$0.006
$0.016
$0.006
$0.034
$0.016
(continued)
-------
Table 4-62. Summary of Costs and Costs per Representative Entity by Threshold (Million $2006) (continued)
J^.
oo
Reporting Subsequent
Subsequent Second and First Year Subsequent Year
First Year Year First Year Year Record- First Year Repre- Year Repre-
Process Process Combus- Combus- keeping National sentative National sentative
Subpart Implied Sectors Costs Costs tion Costs tion Costs Costs Costs Entity Cost Costs Entity Cost
X
Y
Z
AA
BB
CC
EE
GG
HH
JJ
MM
NN
00
PP
QQ
Total
100,000
C
D
E
F
G
H
K
N
Petrochemical Production (325-
ethylene, etc)
Petroleum Refineries
Phosphoric Acid Production
Pulp & Paper
Silicon Carbide Production and
Consumption
Soda Ash Manufacture and
Consumption
Titanium Dioxide Production
Zinc Production
Landfills
Manure Management
Suppliers of Petroleum Products
Suppliers of Natural Gas and Natural
Gas Liquids
Suppliers of Industrial GHGs
Suppliers of Carbon Dioxide
Mobile Sources
Threshold
Stationary Combustion
Electricity Generation
Adipic Acid Production
Aluminum Production
Ammonia Manufacture and Urea
Consumption
Cement Manufacture
Ferroalloy Production
Glass
$2.182
$5.861
$0.022
$7.705
$0.002
$0.042
$0.021
$0.016
$12.439
$0.094
$3.655
$4.209
$0.153
$0.003
$0.000
$0.000
$0.038
$0.194
$0.048
$0.980
$0.030
$0.002
$1.709
$3.820
$0.006
$7.705
$0.001
$0.037
$0.010
$0.009
$5.509
$0.044
$1.068
$2.463
$0.153
$0.003
$26.288
$0.000
$0.000
$0.033
$0.194
$0.022
$0.809
$0.017
$0.001
$0.000
$0.000
$0.785
$0.000
$0.006
$0.028
$0.044
$0.037
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
$41.627
$8.737
$3.279
$0.049
$0.000
$0.296
$5.555
$0.028
$0.005
$0.000
$0.000
$0.438
$0.000
$0.006
$0.028
$0.044
$0.022
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
$31.942
$6.068
$3.279
$0.033
$0.000
$0.195
$3.103
$0.016
$0.003
$0.000
$0.255
$0.031
$0.935
$0.002
$0.011
$0.018
$0.011
$0.000
$0.236
$0.000
$2.553
$0.367
$0.029
$5.283
$0.000
$0.000
$0.009
$0.024
$0.048
$0.233
$0.018
$0.002
$2.182
$6.116
$0.837
$8.640
$0.010
$0.080
$0.083
$0.064
$12.439
$0.330
$3.655
$6.763
$0.521
$0.032
$8.605
$97.823
$8.737
$3.279
$0.096
$0.218
$0.392
$6.768
$0.075
$0.008
$0.027
$0.041
$0.060
$0.020
$0.010
$0.016
$0.010
$0.013
$0.005
$0.003
$0.012
$0.005
$0.003
$0.002
$0.027
$0.009
$0.003
$0.024
$0.016
$0.018
$0.064
$0.009
$0.008
$1.709
$4.075
$0.475
$8.640
$0.009
$0.075
$0.072
$0.042
$5.509
$0.281
$1.068
$5.017
$0.521
$0.032
$8.605
$72.118
$6.068
$3.279
$0.074
$0.218
$0.265
$4.146
$0.051
$0.005
$0.021
$0.027
$0.034
$0.020
$0.009
$0.015
$0.009
$0.008
$0.002
$0.003
$0.003
$0.003
$0.003
$0.002
$0.027
$0.006
$0.003
$0.019
$0.016
$0.012
$0.039
$0.006
$0.005
(continued)
$42.307
-------
Table 4-62. Summary of Costs and Costs per Representative Entity by Threshold (Million $2006) (continued)
J^.
oo
Subpart
O
P
Q
R
S
V
X
Y
Z
AA
BB
CC
EE
GG
HH
JJ
MM
NN
00
PP
QQ
Total
Reporting Subsequent
Subsequent Second and First Year Subsequent Year
First Year Year First Year Year Record- First Year Repre- Year Repre-
Process Process Combus- Combus- keeping National sentative National sentative
Implied Sectors Costs Costs tion Costs tion Costs Costs Costs Entity Cost Costs Entity Cost
HCFC-22 Production & HFC
Destruction
Hydrogen
Iron and Steel Production
Lead Production
Lime Manufacture
Nitric Acid Production
Petrochemical Production (325-
ethylene, etc)
Petroleum Refineries
Phosphoric Acid Production
Pulp & Paper
Silicon Carbide Production and
Consumption
Soda Ash Manufacture and
Consumption
Titanium Dioxide Production
Zinc Production
Landfills
Manure Management
Suppliers of Petroleum Products
Suppliers of Natural Gas and Natural
Gas Liquids
Suppliers of Industrial GHGs
Suppliers of Carbon Dioxide
Mobile Sources
$0.017
$0.129
$3.359
$0.000
$0.081
$0.504
$2.182
$5.861
$0.022
$7.433
$0.002
$0.042
$0.018
$0.013
$5.061
$0.000
$3.103
$4.209
$0.102
$0.002
$33.432
$0.017
$0.060
$1.818
$0.000
$0.024
$0.460
$1.709
$3.820
$0.006
$7.433
$0.001
$0.037
$0.009
$0.007
$2.241
$0.000
$0.898
$2.463
$0.102
$0.002
$22.184
$0.000
$0.138
$0.000
$0.000
$4.988
$0.224
$0.000
$0.000
$0.785
$0.000
$0.006
$0.028
$0.044
$0.023
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
$24.184
$0.000
$0.082
$0.000
$0.000
$2.783
$0.125
$0.000
$0.000
$0.438
$0.000
$0.006
$0.028
$0.044
$0.014
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
$16.216
$0.007
$0.066
$0.000
$0.000
$0.114
$0.088
$0.000
$0.255
$0.031
$0.902
$0.002
$0.011
$0.015
$0.009
$0.000
$0.000
$0.000
$2.553
$0.249
$0.020
$4.656
$0.023
$0.333
$3.359
$0.000
$5.183
$0.816
$2.182
$6.116
$0.837
$8.335
$0.010
$0.080
$0.078
$0.045
$5.061
$0.000
$3.103
$6.763
$0.351
$0.022
$8.605
$70.877
$0.008
$0.011
$0.030
NA
$0.100
$0.020
$0.027
$0.041
$0.060
$0.020
$0.010
$0.016
$0.011
$0.011
$0.005
NA
$0.012
$0.005
$0.003
$0.002
$0.027
$0.023
$0.208
$1.818
$0.000
$2.922
$0.673
$1.709
$4.075
$0.475
$8.335
$0.009
$0.075
$0.069
$0.029
$2.241
$0.000
$0.898
$5.017
$0.351
$0.022
$8.605
$51.661
$0.008
$0.007
$0.016
NA
$0.056
$0.017
$0.021
$0.027
$0.034
$0.020
$0.009
$0.015
$0.010
$0.007
$0.002
NA
$0.003
$0.003
$0.003
$0.002
$0.027
aWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered in this subpart for this rule. For further
information on who must report, please see Section III. A of the preamble.
bWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered in this subpart for this rule, with the exception of
total bulk imports or total bulk exports that exceed 25,000 metric tons CO2e per year. For further information on who must report, please see Section ILIA of the preamble.
-------
Across thresholds, some subsets of costs are typically larger (process, combustion)
compared to other subsets (electricity usage, reporting and recordkeeping). Entities in some
subparts incur higher costs relative to other subparts, regardless of the threshold. The subparts
incurring higher costs of compliance in general are stationary combustion, pulp and paper
manufacturing, iron and steel manufacturing, and oil and natural gas systems.
4-1
-------
SECTION 5
ECONOMY-WIDE ANALYSIS OF REPORTING RULE OPTIONS
In 2006, the total estimated U.S. GHG emissions as reported in the Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2006 are 7.1 billion MtCC^e. As shown in
Table 5-1, the total national emissions covered under the selected option are 3.9 billion MtCC^e.
The majority of these covered emissions are from the electricity generation units covered by
ARP (2.3 billion MtCC^e). Adding upstream fuel suppliers emissions would increase this
estimate by approximately 30% but would also double-count an unknown fraction of
downstream emissions.11
Although the majority of cost and emissions information reported in this economic and
small entity analysis is organized by subpart, EPA mapped each subpart to an industry included
in the North American Industry Classification System (NAICS) so that they could be used in
conjunction with economic census data. Since several subparts contain NAICS codes that fall
into different sectors, they may appear in multiple sectors. For example, Subpart PP (suppliers of
carbon dioxide (CO2) include facilities with NAICS that fall into oil and natural gas
transportation (NAICS 486), chemical manufacturing (NAICS 325), and oil and gas extraction
(NAICS 211).
As shown in Table 5-2, the total national costs for the selected option are estimated to be
$132 million in the first year and $89 million in subsequent years ($2006). More than 80% of
these costs fall on the private sector. Sectors bearing the greatest share of the ongoing costs of
the rule are general station combustion (24%), Pulp and Paper Manufacturers (10%), and Motor
Vehicle and Engine Manufacturers (10%).
In addition to total national costs by sector under the selected option, we also report
average cost per ton to support additional analysis of the mandatory reporting programs. The
average ongoing private cost per metric ton of CC^e reported is $0.02. This measure varies by
sector; measures range from less than $0.01 per ton (e.g., electricity generation [ARP]) to $0.24
per ton (motor vehicle and engine manufacturers).
11 While the fraction of overlap is unknown, it is estimated in Section 5.1.7.
5-1
-------
Table 5-1. Estimates of Emissions (MtCO2e) Reported in 2006 Under the Selected
Option
Sector Quantity
Subpart A—General Provisions 0.0
Subpart B—Reserved 0.0
Subpart C—General Stationary Fuel Combustion Sources 220.0
Subpart D—Electricity Generation3 2262.0
Subpart E—Adipic Acid Production3 9.3
Subpart F—Aluminum Production3 6.4
Subpart G—Ammonia Manufacturing3 12.9
Subpart H—Cement Production3 86.8
Subpart K—Ferroalloy Production 2.3
Subpart N—Glass Production 2.2
Subpart O—HCFC-22 Production3 13.8
Subpart P—Hydrogen Production 15.0
Subpart Q—Iron and Steel Production 85.0
Subpart R—Lead Production 0.8
Subpart S—Lime Manufacturing3 25.4
Subpart U—Miscellaneous Uses of Carbonates 0.0
Subpart V—Nitric Acid Production3 17.7
Subpart X—Petrochemical Production3 54.4
Subpart Y—Petroleum Refineries3 204.7
Subpart Z—Phosphoric Acid Production3 3.8
Subpart AA—Pulp and Paper Manufacturing 57.7
Subpart BB—Silicon Carbide Production3 0.1
Subpart CC—Soda Ash Manufacturing3 3.1
Subpart EE—Titanium Dioxide Production3 3.7
Subpart GG—Zinc Production 0.8
Subpart HH—Landfills 91.1
Subpart JJ—Manure Management 4.5
Subpart OO—Suppliers of Industrial Greenhouse Gases 643.4
Subpart QQ—Motor Vehicle and Engine Manufacturers3 N/A
Total 3,827. lb
aWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule. For further information on who must report, please see Section III.A of the preamble.
bThis estimate only includes downstream emissions. Adding upstream fuel suppliers emissions would increase this estimate by
30% but would double-count an unknown fraction of downstream emissions. While the fraction of overlap is unknown, it is
estimated in Section 5.1.7.
5-2
-------
Table 5-2. National Cost Estimates by Sector: Selected Option
Subpart
Subpart A — General Provisions
Subpart B — Reserved
Subpart C — General Stationary Fuel
Combustion Sources
Subpart D — Electricity Generation3
Subpart E — Adipic Acid Production*
Subpart F — Aluminum Production3
Subpart G — Ammonia Manufacturing3
Subpart H — Cement Production3
Subpart K — Ferroalloy Production
Subpart N — Glass Production
Subpart O— HCFC-22 Production3
Subpart P — Hydrogen Production
Subpart Q — Iron and Steel Production
Subpart R — Lead Production
Subpart S — Lime Manufacturing3
Subpart U — Miscellaneous Uses of
Carbonates
Subpart V — Nitric Acid Production3
Subpart X — Petrochemical Production3
Subpart Y — Petroleum Refineries3
Subpart Z — Phosphoric Acid Production3
Subpart AA — Pulp and Paper
Manufacturing
Subpart BB — Silicon Carbide Production3
Subpart CC — Soda Ash Manufacturing3
Subpart EE — Titanium Dioxide Production3
Subpart GG — Zinc Production
Subpart HH— Landfills
Subpart JJ — Manure Management
Subpart LL — Suppliers of Coal-based
Liquid Fuels and Subpart MM —
Suppliers of Petroleum Products
Subpart NN — Suppliers of Natural Gas and
Natural Gas Liquids3
Subpart OO — Suppliers of Industrial
Greenhouse Gases
NAICS
325
331
325
327
331
327
325
325
331
331
327
325
325
324
325
322
327
325
325
331
562
112
324
221,486
325
First Year
Million
$2006
$25.8
$3.3
$0.1
$0.2
$0.4
$6.8
$0.1
$0.5
$0.0
$0.4
$3.7
$0.1
$5.3
$0.0
$0.9
$2.2
$6.1
$0.8
$8.6
$0.0
$0.1
$0.1
$0.1
$12.4
$0.3
$3.7
$6.8
$0.5
S/ton
$0.12
$0.00
$0.01
$0.03
$0.03
$0.08
$0.03
$0.21
$0.00
$0.02
$0.04
$0.16
$0.21
$0.00
$0.05
$0.04
$0.03
$0.22
$0.15
$0.09
$0.03
$0.02
$0.08
$0.14
$0.07
$0.00
$0.01
$0.00
Share
20%
2%
0%
0%
0%
5%
0%
0%
0%
0%
3%
0%
4%
0%
1%
2%
5%
1%
7%
0%
0%
0%
0%
9%
0%
3%
5%
0%
Subsequent Years
Million
$2006
$21.5
$3.3
$0.1
$0.2
$0.3
$4.2
$0.1
$0.3
$0.0
$0.2
$2.0
$0.1
$3.0
$0.0
$0.7
$1.7
$4.1
$0.5
$8.6
$0.0
$0.1
$0.1
$0.0
$5.5
$0.3
$1.1
$5.0
$0.5
$/ton
$0.10
$0.00
$0.01
$0.03
$0.02
$0.05
$0.02
$0.13
$0.00
$0.02
$0.02
$0.10
$0.12
$0.00
$0.04
$0.03
$0.02
$0.12
$0.15
$0.08
$0.02
$0.02
$0.05
$0.06
$0.06
$0.00
$0.01
$0.00
Share
24%
4%
0%
0%
0%
5%
0%
0%
0%
0%
2%
0%
3%
0%
1%
2%
5%
1%
10%
0%
0%
0%
0%
6%
0%
1%
6%
1%
(continued)
5-3
-------
Table 5-2. National Cost Estimates by Sector: Selected Option (continued)
Subpart
Subpart PP — Suppliers of Carbon Dioxide
(C02)b
Subpart QQ — Motor Vehicle and Engine
Manufacturers3
Coverage Determination Costs for Non-
Reporters
Private Sector, Total
Public Sector, Total
Total
NAICS
211,325,
486
First Year
Million
$2006 S/ton
$0.0 $0.00
$8.6 °
$17.2
$115.0
$17.0
$132.0
Share
0%
7%
0%
87%
13%
100%
Subsequent Years
Million
$2006
$0.0
$8.6
$0.0
$72.1
$17.0
$89.1
$/ton Share
$0.00 0%
c 10%
0%
81%
19%
100%
Note: An additional $3.5 million is incurred annually by the public sector during the rulemaking process, which will last between
1 and 2 years.
aWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule. For further information on who must report, please see Section III.A of the preamble.
bWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule, with the exception of total bulk imports or total bulk exports that exceed 25,000 metric tons CO2e
per year. For further information on who must report, please see Section III.A of the preamble.
The cost per ton cost-effectiveness metric could not be calculated for this subpart because the reported value is CO2 in
grams/mile.
5.1 Evaluating Alternative Options for Implementation of the Rule
The selected option was evaluated based on a cost-effectiveness analysis. This approach
compares the benefits and costs of alternative options for the rule. For example, in selecting the
emissions threshold, we compared the incremental emissions reported with the incremental costs
(associated with the change in the facilities that would be required to report their emissions).
Similarly, in selecting the reporting methodology option, we compared the change in uncertainty
with the change in costs associated with different emission measurement/estimation techniques.
The metrics used and the results of the cost-effectiveness analysis are discussed below. A
discussion of the number of reporters, methods, and cost assumptions associated with the
alternative options is presented in the cost appendix (Appendix A) and in the Technical Support
Documents (TSDs).
Ten alternative options were evaluated for this analysis. While we believe these 10
alternatives represent the most likely variations in the selected option, we recognize that in some
cases particular interests may wish to evaluate more nuanced alternative options. To maintain
transparency in the analysis, all of the data necessary to conduct further alternative option
analyses can be found in Tables 4-61 and 4-62, specific industrial subsections in Section 4 of this
document and in the cost appendix to the RIA. For example, if you wanted to change the
5-4
-------
coverage of fuel suppliers or the downstream12 coverage of specific fuels, such as natural gas or
coal, you would evaluate the appropriate subparts for these fuels and using the data in cost
appendix to the RIA or in Tables 4-61-4-62.
5.1.1 Analysis of Alternative Threshold Options
The threshold, in large part, determines the number of entities required to report GHG
emissions under the rule. The higher the threshold, the more entities that are excluded. It is
assumed that the per unit/entity cost does not change at different thresholds so that changes in the
national cost estimates are driven by the number of reporting entities. The per unit/entity costs
outlined in Section 4, along with the estimates of numbers of covered entities at various
thresholds, form the basis for this analysis. Two metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost per ton of emissions
reported. The second metric for evaluating the threshold option is the marginal cost of additional
reported emissions ($/ton CC^E) relative to the option adopted in the final rule. To compute this
metric, we compute the change in emissions reported by lowering or raising the threshold and
divide this by the change in total reporting costs. Table 5-3 provides the cost-effectiveness
analysis for the various thresholds. As shown in Table 5-3, the total average cost per ton for the
selected hybrid option of 25,000 tons CC^e is approximately $0.03 (first year). As the threshold
increases, the number of covered entities, total cost, and emissions decrease, although not at the
same rate. As a result, the total average cost per ton for the first year decreases from $0.03 to
$0.02.
Table 5-3. Summary of Threshold Cost-Effectiveness Analysis (First Year): Selected
Hybrid Option is 25,000 tons CO2e
Threshold
(tons CO2e)
1,000
10,000
25,000
100,000
Facilities
Required to
Report
54,229
16,718
10,152
6,269
Total Costs
(million $2006)
$397.6
$160.1
$132.0
$88.2
Downstream
Emissions
Reported
(MtC02e/
year)
3,926
3,861
3,827
3,738
Percentage of
Total
Downstream
Emissions
Reported
56%
55%
54%
53%
Average Reporting
Cost (S2006/ton)
$0.10
$0.04
$0.03
$0.02
Marginal
Cost
(S2006/ton)
$2.70
$0.83
-$0.49
Note: Does not include emissions for Motor Vehicle and Engine Manufacturers (Subpart QQ).
12 This refers to direct emissions versus emissions associated with the use of product.
5-5
-------
The analysis also shows that the marginal cost (reduction) of moving from the selected
threshold of 25,000 tons CO2e to a higher threshold (100,000 tons) is $0.49 per ton and decreases
the total emissions captured by approximately 2%. Similarly, the marginal cost of moving the
threshold from 25,000 to 10,000 is $0.83 per ton and increases the emissions captured by 1%.
Finally, the marginal cost of lowering the threshold from 10,000 to 1,000 yields the highest cost
increase in marginal cost reported ($2.70 per ton), and increases the percentage of covered
emissions by approximately 2%. Similar data is presented for subsequent year in Table 5-4.
Information on how costs are distributed across sectors at each threshold is provided in the
following tables: Table 5-5 (1,000 tCO2e threshold), Table 5-6 (10,000 tCO2e threshold),
Table 5-2 (25,000 tCO2e threshold), and Table 5-7 (100,000 tCO2e threshold).
Table 5-4. Summary of Threshold Cost-Effectiveness Analysis (Subsequent Years)
Threshold (tons
C02e)
1,000
10,000
25,000
100,000
Facilities
Required to
Report
54,229
16,718
10,152
6,269
Total Private
Costs
(million $2006)
$285.8
$119.9
$89.1
$68.7
Downstream
Emissions
Reported
(MtC02e/
year)
3,926
3,861
3,827
3,738
Percentage of Total
Downstream
Emissions
Reported
56%
55%
54%
53%
Average
Reporting Cost
(S2006/ton)
$0.07
$0.03
$0.02
$0.02
Marginal
Cost
(S2006/ton)
$2.00
$0.91
-$0.23
Note: Does not include emissions for Motor Vehicle and Engine Manufacturers (Subpart QQ).
Table 5-5. National Cost Estimates by Sector: 1,000 tCO2e Threshold
Sector
Subpart A — General Provisions
Subpart B — Reserved
Subpart C — General Stationary Fuel Combustion
Sources
Subpart D — Electricity Generation3
Subpart E — Adipic Acid Production3
Subpart F — Aluminum Production3
Subpart G — Ammonia Manufacturing3
Subpart H — Cement Production3
Subpart K — Ferroalloy Production
Subpart N — Glass Production
Subpart O— HCFC-22 Production3
Subpart P — Hydrogen Production
Subpart Q — Iron and Steel Production
First Year
Million
$184.1
$3.3
$0.1
$0.2
$0.4
$6.8
$0.1
$1.8
$0.0
$0.6
$3.9
S/ton
$0.74
$0.00
$0.01
$0.03
$0.03
$0.08
$0.03
$0.42
$0.00
$0.04
$0.05
Share
46%
1%
0%
0%
0%
2%
0%
0%
0%
0%
1%
Subsequent Years
Million
$180.1
$3.3
$0.1
$0.2
$0.3
$4.2
$0.1
$1.2
$0.0
$0.4
$2.1
S/ton
$0.72
$0.00
$0.01
$0.03
$0.02
$0.05
$0.02
$0.27
$0.00
$0.03
$0.03
Share
63%
1%
0%
0%
0%
1%
0%
0%
0%
0%
1%
(continued)
5-6
-------
Table 5-5. National Cost Estimates by Sector: 1,000 tCO2e Threshold (continued)
Sector
Subpart R — Lead Production
Subpart S — Lime Manufacturing*
Subpart U — Miscellaneous Uses of Carbonates
Subpart V — Nitric Acid Production3
Subpart X — Petrochemical Production*
Subpart Y — Petroleum Refineries3
Subpart Z — Phosphoric Acid Production3
Subpart AA — Pulp and Paper Manufacturing
Subpart BB — Silicon Carbide Production3
Subpart CC — Soda Ash Manufacturing3
Subpart EE — Titanium Dioxide Production3
Subpart GG — Zinc Production
Subpart HH— Landfills
Subpart JJ — Manure Management
Subpart LL — Suppliers of Coal-based Liquid Fuels and
Subpart MM — Suppliers of Petroleum Products'5
Subpart NN — Suppliers of Natural Gas and Natural Gas
Liquids3
Subpart OO — Suppliers of Industrial Greenhouse Gases
Subpart PP— Suppliers of Carbon Dioxide (CO2)b
Subpart QQ — Motor Vehicle and Engine Manufacturers3
Coverage Determination Costs for Non-Reporters
Private Sector, Total
Public Sector, Total
Total
First Year
Million
2006$
$0.2
$5.3
$0.0
$0.9
$2.2
$6.1
$0.8
$8.6
$0.0
$0.1
$0.1
$0.1
$33.3
$32.4
$3.7
$6.8
$0.9
$0.0
$8.6
$69.2
$380.6
$17.0
$397.6
S/ton
$0.19
$0.21
$0.00
$0.05
$0.04
$0.03
$0.22
$0.15
$0.09
$0.03
$0.02
$0.11
$0.30
$0.65
$0.00
$0.01
$0.00
$0.00
c
Share
0%
1%
0%
0%
1%
2%
0%
2%
0%
0%
0%
0%
8%
8%
1%
2%
0%
0%
2%
0%
96%
4%
100%
Subsequent Years
Million
2006$
$0.1
$3.0
$0.0
$0.7
$1.7
$4.1
$0.5
$8.6
$0.0
$0.1
$0.1
$0.1
$14.7
$27.5
$1.1
$5.0
$0.9
$0.0
$8.6
$0.0
$268.8
$17.0
$285.8
$/ton
$0.13
$0.12
$0.00
$0.04
$0.03
$0.02
$0.12
$0.15
$0.08
$0.02
$0.02
$0.07
$0.13
$0.55
$0.00
$0.01
$0.00
$0.00
c
Share
0%
1%
0%
0%
1%
1%
0%
3%
0%
0%
0%
0%
5%
10%
0%
2%
0%
0%
3%
0%
94%
6%
100%
3While the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule. For further information on who must report, please see Section IIIA of the preamble.
bWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule, with the exception of total bulk imports or total bulk exports that exceed 25,000 metric tons CO2e
per year. For further information on who must report, please see Section IIIA of the preamble.
The cost per ton cost-effectiveness metric could not be calculated for this subpart because the reported value is CO2 in
grams/mile.
5-7
-------
Table 5-6. National Cost Estimates by Sector: 10,000 tCO2e Threshold
Sector
Subpart A — General Provisions
Subpart B — Reserved
Subpart C — General Stationary Fuel Combustion Sources
Subpart D — Electricity Generation3
Subpart E — Adipic Acid Production3
Subpart F — Aluminum Production3
Subpart G — Ammonia Manufacturing3
Subpart H — Cement Production3
Subpart K — Ferroalloy Production
Subpart N — Glass Production
Subpart O— HCFC-22 Production3
Subpart P — Hydrogen Production
Subpart Q — Iron and Steel Production
Subpart R — Lead Production
Subpart S — Lime Manufacturing3
Subpart U — Miscellaneous Uses of Carbonates
Subpart V — Nitric Acid Production3
Subpart X — Petrochemical Production3
Subpart Y — Petroleum Refineries3
Subpart Z — Phosphoric Acid Production
Subpart AA — Pulp and Paper Manufacturing
Subpart BB — Silicon Carbide Production3
Subpart CC — Soda Ash Manufacturing3
Subpart EE — Titanium Dioxide Production3
Subpart GG — Zinc Production
Subpart HH— Landfills
Subpart JJ — Manure Management
Subpart LL — Suppliers of Coal-based Liquid Fuels and
Subpart MM — Suppliers of Petroleum Products'5
Subpart NN — Suppliers of Natural Gas and Natural Gas
Liquids3
Subpart OO — Suppliers of Industrial Greenhouse Gases
Subpart PP— Suppliers of Carbon Dioxide (CO2)b
Subpart QQ — Motor Vehicle and Engine Manufacturers3
Coverage Determination Costs for Non-Reporters
Private Sector, Total
Public Sector, Total
Total
First Year
Million
2006$
$52.1
$3.3
$0.1
$0.2
$0.4
$6.8
$0.1
$1.3
$0.0
$0.5
$3.9
$0.2
$5.3
$0.0
$0.9
$2.2
$6.1
$0.8
$8.6
$0.0
$0.1
$0.1
$0.1
$17.0
$1.7
$3.7
$6.8
$0.7
$0.0
$8.6
$11.5
$143.1
$17.0
$160.1
S/ton
$0.23
$0.00
$0.01
$0.03
$0.03
$0.08
$0.03
$0.33
$0.00
$0.04
$0.05
$0.18
$0.21
$0.00
$0.05
$0.04
$0.03
$0.22
$0.15
$0.09
$0.03
$0.02
$0.10
$0.16
$0.15
$0.00
$0.01
$0.00
$0.00
c
Share
33%
2%
0%
0%
0%
4%
0%
1%
0%
0%
2%
0%
3%
0%
1%
1%
4%
1%
5%
0%
0%
0%
0%
11%
1%
2%
4%
0%
0%
5%
0%
89%
11%
100%
Subsequent Years
Million
2006$
$48.1
$3.3
$0.1
$0.2
$0.3
$4.2
$0.1
$0.9
$0.0
$0.4
$2.1
$0.1
$3.0
$0.0
$0.7
$1.7
$4.1
$0.5
$8.6
$0.0
$0.1
$0.1
$0.1
$7.5
$1.5
$1.1
$5.0
$0.7
$0.0
$8.6
$0.0
$102.9
$17.0
$119.9
$/ton
$0.21
$0.00
$0.01
$0.03
$0.02
$0.05
$0.02
$0.21
$0.00
$0.02
$0.02
$0.12
$0.12
$0.00
$0.04
$0.03
$0.02
$0.12
$0.15
$0.08
$0.02
$0.02
$0.07
$0.07
$0.12
$0.00
$0.01
$0.00
$0.00
c
Share
40%
3%
0%
0%
0%
3%
0%
1%
0%
0%
2%
0%
3%
0%
1%
1%
3%
0%
7%
0%
0%
0%
0%
6%
1%
1%
4%
1%
0%
7%
0%
86%
14%
100%
3While the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule. For further information on who must report, please see Section IIIA of the preamble.
bWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule, with the exception of total bulk imports or total bulk exports that exceed 25,000 metric tons CO2e
per year. For further information on who must report, please see Section IIIA of the preamble.
The cost per ton cost-effectiveness metric could not be calculated for this subpart because the reported value is CO2 in
grams/mile.
5-8
-------
Table 5-7. National Cost Estimates by Sector: 100,000 tCO2e Threshold
Sector
Subpart A — General Provisions
Subpart B — Reserved
Subpart C — General Stationary Fuel Combustion Sources
Subpart D — Electricity Generation3
Subpart E — Adipic Acid Production3
Subpart F — Aluminum Production3
Subpart G — Ammonia Manufacturing3
Subpart H — Cement Production3
Subpart K — Ferroalloy Production
Subpart N — Glass Production
Subpart O— HCFC-22 Production3
Subpart P — Hydrogen Production
Subpart Q — Iron and Steel Production
Subpart R — Lead Production
Subpart S — Lime Manufacturing3
Subpart U — Miscellaneous Uses of Carbonates
Subpart V — Nitric Acid Production3
Subpart X — Petrochemical Production3
Subpart Y — Petroleum Refineries3
Subpart Z — Phosphoric Acid Production3
Subpart AA — Pulp and Paper Manufacturing
Subpart BB — Silicon Carbide Production3
Subpart CC — Soda Ash Manufacturing3
Subpart EE — Titanium Dioxide Production3
Subpart GG — Zinc Production
Subpart HH— Landfills
Subpart JJ — Manure Management
Subpart LL — Suppliers of Coal-based Liquid Fuels and
Subpart MM — Suppliers of Petroleum Products'5
Subpart NN — Suppliers of Natural Gas and Natural Gas
Liquids3
Subpart OO — Suppliers of Industrial Greenhouse Gases
Subpart PP— Suppliers of Carbon Dioxide (CO2)b
Subpart QQ — Motor Vehicle and Engine Manufacturers3
Coverage Determination Costs for Non-Reporters
Private Sector, Total
Public Sector, Total
Total
Million
2006$
$8.7
$3.3
$0.1
$0.2
$0.4
$6.8
$0.1
$0.0
$0.0
$0.3
$3.4
$0.0
$5.2
$0.0
$0.8
$2.2
$6.1
$0.8
$8.3
$0.0
$0.1
$0.1
$0.0
$5.1
$0.0
$3.1
$6.8
$0.4
$0.0
$8.6
$0.4
$71.2
$17.0
$88.2
First Year
S/ton
$0.05
$0.00
$0.01
$0.03
$0.03
$0.08
$0.03
$0.04
$0.00
$0.02
$0.04
NA
$0.22
$0.00
$0.05
$0.04
$0.03
$0.22
$0.14
$0.09
$0.03
$0.02
$0.06
$0.08
NA
$0.00
$0.01
$0.00
$0.00
c
Share
10%
4%
0%
0%
0%
8%
0%
0%
0%
0%
4%
0%
6%
0%
1%
2%
7%
1%
9%
0%
0%
0%
0%
6%
0%
4%
8%
0%
0%
10%
0%
81%
19%
100%
Subsequent Years
Million
2006$
$6.1
$3.3
$0.1
$0.2
$0.3
$4.1
$0.1
$0.0
$0.0
$0.2
$1.8
$0.0
$2.9
$0.0
$0.7
$1.7
$4.1
$0.5
$8.3
$0.0
$0.1
$0.1
$0.0
$2.2
$0.0
$0.9
$5.0
$0.4
$0.0
$8.6
$0.0
$51.7
$17.0
$68.7
$/ton
$0.04
$0.00
$0.01
$0.03
$0.02
$0.05
$0.02
$0.03
$0.00
$0.01
$0.02
NA
$0.12
$0.00
$0.04
$0.03
$0.02
$0.12
$0.14
$0.08
$0.02
$0.02
$0.04
$0.03
NA
$0.00
$0.01
$0.00
$0.00
c
Share
9%
5%
0%
0%
0%
6%
0%
0%
0%
0%
3%
0%
4%
0%
1%
2%
6%
1%
12%
0%
0%
0%
0%
3%
0%
1%
7%
1%
0%
13%
0%
75%
25%
100%
NA: No facilities are required to report at this threshold.
3While the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule. For further information on who must report, please see Section IIIA of the preamble.
bWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule, with the exception of total bulk imports or total bulk exports that exceed 25,000 metric tons CO2e
per year. For further information on who must report, please see Section IIIA of the preamble.
The cost per ton cost-effectiveness metric could not be calculated for this subpart because the reported value is CO2 in
grams/mile.
5-9
-------
The selection decision weighed the marginal cost of capturing additional emissions with
the percentage of emissions needed to accurately estimate the U.S. GHG emissions nationally
and by sector. This is shown in Figure 5-1, which illustrates the total average cost per ton and the
marginal cost per ton as a function of the percentage of total emissions reported.
a. Average Cost
0.12
0.10
0.08
c
,2 0.06
0.04
0.02
0.00
100K
25K
10K
53.0
54.3 54.7
% of Total Emissions Reported
55.6
o
3.00
2.50
2.00
1.50
1.00
0.50
0.00
-0.50
-1.00
b. Marginal Cost Relative to Final Rule
1K
100K
25K
54.3
10K
54.7
55.6
% of Total Emissions Reported
Figure 5-1. Average and Marginal Cost per Ton of Emissions Reported by Threshold
5-10
-------
In addition to the typical emissions thresholds associated with GHG reporting and
reduction programs (e.g., 25,000 metric tons CC^e), under the CAA, there are (1) the Title V
program that requires all major stationary sources with emissions over 100 tons per year (tpy) to
hold an operating permit and (2) the Prevention of Significant Deterioration (PSD)/New Source
Review (NSR) program that requires new major sources and major sources that are undergoing
major modifications to obtain a permit. A major source for NSR/PSD is defined as any source
that emits or has the potential to emit either 100 tpy or 250 tpy of a regulated pollutant,
dependent on the source category and attainment status of the area. The 100 tpy level is the level
at which existing sources in 28 industry categories listed in the CAA are classified as major for
the PSD program. The 250 tpy level is the level at which existing sources in all other categories
are classified as major for PSD purposes.
EPA performed some preliminary analyses to generally estimate the existing stock of
major sources in order to then estimate the approximate number of new facilities that could be
required to obtain NSR/PSD permits. EPA roughly estimated that currently approximately
350,000 facilities have emissions greater than 100 tons per year, while approximately 235,000
have more than 250 tons per year. If the 100 and 250 tpy thresholds were applied in the context
of GHGs, the Agency estimates the number of PSD permits required to be issued each year
would increase by a factor greater than 10 (i.e., more than 2,000 to 3,000 permits per year) (EPA,
2008). The additional permits would generally be issued to smaller industrial sources, as well as
large office and residential buildings, hotels, large retail establishments, and similar facilities.
EPA rejected setting similar reporting thresholds in this rule due to the uncertainty in the
estimates in the number of affected facilities and the additional burden likely placed on a large
number of small sources.
It should be noted that the estimates in the U.S. Environmental Protection Agency
Advance Notice of Proposed Rulemaking: Regulating Greenhouse Gas Emissions Under the
Clean Air (ANPR) of sources that would be required to report are rough estimates and are not as
robust as the threshold analysis performed for this rule. In addition, even if we assumed the per
facility costs were the same, a threshold significantly lower than the 25,000 ton hybrid threshold
would dramatically increase the cost of the rule overall and more than likely impose significant
small business impacts.
5-11
-------
5.1.2 Analysis of Alternative Monitory Method Options
Each monitoring technique for which reporting costs were estimated in Section 4 is
expected to provide the same estimate of total emissions by reporting facility. However, the
different methods of monitoring emissions differ in their accuracy in estimating actual emissions.
Therefore, the gain from increasing the cost of monitoring is to have more precise estimates of
facility emissions. The methods considered for determining emissions ranged from applying
average industry parameters (referred to as "default parameters") to material inputs or
throughputs, to the use of CEMS to directly measure emissions. As discussed previously, the
selected option (referred to as the "hybrid method") requires the use of CEMS if they are already
required for other regulations; otherwise, facility-specific measurements are made to support
calculations of GHG emissions. In this section, we evaluate the change in cost and change in
accuracy for two alternative monitoring options. Generally speaking, under one of the
alternatives, default parameters would be used in lieu of CEMS and facility-level estimates, and
in the other options, CEMS are required for all sources. We use the term "CEMS" and "default
parameters" as shorthand to describe alternative options. Estimated costs for each monitoring
method are shown in Table 5-8.
To compute the cost for the CEMS option, we multiply the selected option costs by a
ratio of Tier 4 costs ($56,040 in the first year and $31, 271 in subsequent years) to Tier 2 costs
($5,500 in both first and subsequent years). This ratio is estimated to be approximately 10.2 in
the first year and 5.7 in subsequent years. The Tier 4 option applies to non-Part 75, non-EGU
(industrial) units where C>2 analyzers will not suffice (e.g., sources with process emissions
[cement, lime, glass]) and requires adding a CC>2 analyzer and flow meter (see discussion in
Section 4). For the Tier 2 methodology, CC>2 mass emissions are estimated using measured high
heat values, a default CC>2 emission factor, a default oxidation factor, and the quantity of fuel
combusted. Default CFLi and N2O emission factors and measure heat content (see stationary
combustion TSD). Additional details for these CEMS costs are reported in section 4 of the RIA
under subpart C costs.
5-12
-------
Table 5-8. Analysis of Alternative Monitoring Methods by Sector
Sector
Subpart A — General Provisions
Subpart B — Electricity Use
Subpart C — General Stationary Fuel Combustion
Sources
Subpart D — Electricity Generation8
Subpart E — Adipic Acid Production*
Subpart F — Aluminum Production*
Subpart G — Ammonia Manufacturing*
Subpart H — Cement Production*
Subpart K — Ferroalloy Production
Subpart N — Glass Production
Subpart O— HCFC-22 Production*
Subpart P — Hydrogen Production
Subpart Q — Iron and Steel Production
Subpart R — Lead Production
Subpart S — Lime Manufacturing*
Subpart U — Miscellaneous Uses of Carbonates
Subpart V — Nitric Acid Production*
Subpart X — Petrochemical Production*
Subpart Y — Petroleum Refineries*
Subpart Z — Phosphoric Acid Production*
Subpart AA — Pulp and Paper Manufacturing
Subpart BB — Silicon Carbide Production*
CEMS
Subsequent
First Year Years
(million (million
$2006) $2006)
$262.5 $122.5
$33.4 $18.6
$1.0 $0.4
$2.2 $1.2
$4.0 $1.5
$69.1 $23.6
$0.8 $0.3
$4.7 $1.7
$0.2 $0.1
$3.8 $1.4
$37.3 $11.3
$1.3 $0.5
$54.2 $17.2
$0.0 $0.0
$9.1 $4.2
$22.2 $9.7
$62.3 $23.2
$8.5 $2.7
$88.0 $49.1
$0.1 $0.0
Selected Option (Hybrid Approach)
#of
Units/Entitie
s using
CEMS
1,491.0
3,279.0
4.0
24.0
107.0
6.0
55.0
51.0
a
13.0
89.0
4.0
a
a
14.0
b
%of
Units/Entitie
s Using
CEMS
17%
100%
100%
100%
100%
100%
100%
100%
a
100%
100%
100%
a
a
100%
b
Subsequent
First Year Years
(million (million
$2006) $2006)
$25.8 $21.5
$3.3 $3.3
$0.1 $0.1
$0.2 $0.2
$0.4 $0.3
$6.8 $4.2
$0.1 $0.1
$0.5 $0.3
$0.0 $0.0
$0.4 $0.2
$3.7 $2.0
$0.1 $0.1
$5.3 $3.0
$0.0 $0.0
$0.9 $0.7
$2.2 $1.7
$6.1 $4.1
$0.8 $0.5
$8.6 $8.6
$0.0 $0.0
Default Parameters
Subsequent
First Year Years
(million (million
$2006) $2006)
$10.3 $8.6
$1.3 $1.3
$0.0 $0.0
$0.1 $0.1
$0.2 $0.1
$2.7 $1.7
$0.0 $0.0
$0.2 $0.1
$0.0 $0.0
$0.1 $0.1
$1.5 $0.8
$0.1 $0.0
$2.1 $1.2
$0.0 $0.0
$0.4 $0.3
$0.9 $0.7
$2.4 $1.6
$0.3 $0.2
$3.5 $3.5
$0.0 $0.0
(continued)
-------
Table 5-8. Analysis of Alternative Monitoring Methods by Sector (continued)
Sector
Subpart CC — Soda Ash Manufacturing*
Subpart EE — Titanium Dioxide Production*
Subpart GG — Zinc Production
Subpart HH— Landfills
Subpart JJ — Manure Management
Subpart LL — Suppliers of Coal-based Liquid
Fuels and Subpart MM — Suppliers of
Petroleum Products0
Subpart NN — Suppliers of Natural Gas and
Natural Gas Liquids*
Subpart OO — Suppliers of Industrial Greenhouse
Gases
Subpart PP — Suppliers of Carbon Dioxide
(C02)c
Subpart QQ — Motor Vehicle and Engine
Manufacturers*
Coverage Determination Costs for Non-
Reporters
Private Sector, Total
Public Sector, Total
Total
CEMS
Subsequent
First Year Years
(million (million
$2006) $2006)
$0.8 $0.4
$0.8 $0.4
$0.7 $0.2
$126.7 $31.3
$3.4 $1.6
$37.2 $6.1
$68.9 $28.5
$5.3 $3.0
$0.3 $0.2
$87.7 $48.9
$17.2 $0.00
$1,014 $410
$17.0 $17.0
$1,030.9 $427.0
Selected Option (Hybrid Approach)
#of
Units/Entitie
s using
CEMS
8.0
%of
Units/Entitie
s Using
CEMS
100%
Subsequent
First Year Years
(million (million
$2006) $2006)
$0.1 $0.1
$0.1 $0.1
$0.1 $0.0
$12.4 $5.5
$0.3 $0.3
$3.7 $1.1
$6.8 $5.0
$0.5 $0.5
$0.0 $0.0
$8.6 $8.6
$17.2 $0.0
$115.0 $72.1
$17.0 $17.0
$132.0 $89.1
Default Parameters
Subsequent
First Year Years
(million (million
$2006) $2006)
$0.0 $0.0
$0.0 $0.0
$0.0 $0.0
$5.0 $2.2
$0.1 $0.1
$1.5 $0.4
$2.7 $2.0
$0.2 $0.2
$0.0 $0.0
$3.4 $3.4
$17.2 $0.0
$56.3 $28.8
$17.0 $17.0
$73.3 $45.8
*While the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered in this subpart for this rule. For further
information on who must report, please see Section III. A of the preamble.
bSubparts Q X, Y, and AA also use of CEMS to directly measure emissions as part of the hybrid approach. However, due to a lack of information counts for the units of CEMS
used in each subpart is not available.
"While the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered in this subpart for this rule, with the exception of
total bulk imports or total bulk exports that exceed 25,000 metric tons CO2e per year. For further information on who must report, please see Section ILIA of the preamble.
-------
For the default parameter options, we multiply the selected option costs by a ratio of Tier
1 CEMS costs ($2,200 in both first and subsequent years) to Tier 2 CEMS costs ($5,500 in both
first and subsequent years), or 0.40 in both first and subsequent years. The Tier 1 method
includes calculation with fuel-specific default emission factors, a default high heating value, a
default oxidation factor, and the annual fuel consumption. Measurement of annual fuel
consumption is assumed to be a standard business practice and not included in incremental cost
of the GHG monitoring (see stationary combustion TSD). First year costs include a monitoring
plan and a QA/QC plan. Additional details for these CEMS costs are reported in section 4 of the
RIA under subpart C costs.
EPA contract engineers also developed uncertainty estimates for all three methods for
each affected sector. The uncertainties in individual measurements were based on quoted
accuracies of the instruments or engineering judgment. These individual measurement
uncertainties were assumed to represent 95% confidence intervals. Uncertainties in the overall
method were determined via error propagation or Monte Carlo assessment and reported as the
95% confidence interval about the mean or expected value (as a percentage of that value).
5.1.2.1 Monitoring Method Uncertainty
For 10 of the top GHG emitting sectors, engineering experts were asked to provide
uncertainty values for the three methodologies being considered. This information is shown in
Table 5-9. Whereas the CEMS approach is constant at 7% (i.e., the CEMS measurement would
be within 7 percent of the actual emissions), the uncertainty for the engineering and hybrid
methods varies considerably across sectors. The highest uncertainty was associated with using
the engineering estimate method to estimate emissions in industrial gas manufacturing. For the
industrial gas sector, applying the default parameter approach requires measuring production
flows accurately and calculating the flow difference to estimate emissions.
In general, the uncertainty cost-effectiveness analysis was useful in selecting the selected
hybrid methodology and was evaluated in conjunction with other considerations such as
consistency with other regulations and the burden on small entities.
5-15
-------
Table 5-9. Uncertainty Estimates by Methodology Option
Share of Total
Emission
Electricity generation (ARP, non-ARP, and MSW)
Industrial gas manufacturing
Fluorocarbon producers
Imports/exports of industrial gases-SF7
Electricity generation (ARP, non-ARP, and MSW)
Industrial
Petroleum refineries
Pulp, paper, and paperboard mills
Iron and steel mills
Cement manufacturing
Oil gas and mining
Gas processing
Compressor stations
Weighted Average
57%
13%
3%
57%
7%
3%
2%
1%
1%
2%
Uncertainty Estimates
Engr. Est
10%
50%
50%
10%
18%
22%
15%
17%
50%
50%
19.7%
Hybrid
8%
10%
10%
8%
7%
10%
25%
9%
30%
30%
9.4%
CEMS
7%
7%
7%
7%
7%
7%
7%
7%
7%
7%
7.0%
Note: Uncertainty estimates for the three options are presented as point estimates. Uncertainty ranges were not available for all
sectors.
To evaluate the trade-off between cost and uncertainty across the alternative methods,
three measures (i.e., metrics) of cost-effectiveness were developed.
1. Incremental cost. This is the total national private cost difference between the options.
For example, as illustrated in Tables 5-10 and 5-11, by moving from the selected
hybrid method to CEMS, the total national cost increases by $899 million for the first
year and $338 million for subsequent years.
2. Average cost per percentage point uncertainty. This compares the average cost per
percentage point uncertainty across the three alternative methods. The percentage
point uncertainty is an emissions weighted average across the sectors for which we
have uncertainty estimates for different reporting methodologies. For example, the
cost for the selected hybrid method is ($115M/9.4%) = $12.2M per percentage point
uncertainty. The average cost for the CEMS and default parameter approaches are
($1,014M/7.0%) = $145M and ($56M/19.7%) = $2.9M, respectively.
3. Marginal cost per percentage point reduction in uncertainty. This compares the cost
of reducing the coefficient of variation by 1%. For example, the incremental cost per
percent point reduced in going from a default parameter approach to a hybrid
approach is $59M/(9.4%-19.7%)= -$5.7M in the first year, and the incremental cost
of moving from a hybrid approach to an approach where CEMS are used is
$899M/(7.0% - 9.4) = $375M in the first year.
5-16
-------
Table 5-10. Uncertainty Cost-Effectiveness Analysis (First Year): Selected Option is the
Hybrid Approach
Threshold(tons CO2e)
= 25,000
CEMS
Selected — hybrid
Default parameters
First Year
Total Private
Reporting
Costs (million
$2006)
$1,014
$115
$56
Downstream
Emissions
Reported
(MtC02e/
year)
3,827
3,827
3,827
Average
Uncertainty
7.00%
9.40%
19.70%
Incremental
Reporting
Cost (million
$2006)
$899
-$59
Average
Reporting
Cost per
Percentage
Point of
Uncertainty
(million
$20067%)
$145
$12.2
$2.9
Marginal Cost
per
Percentage
Point
Uncertainty
(million
$20067%)
$374.5
-$5.7
Table 5-11. Uncertainty Cost-Effectiveness Analysis (Subsequent Year): Selected Option
is the Hybrid Approach
Threshold(tons
CO2e) = 25,000
CEMS
Selected — hybrid
Default parameters
Subsequent
Year Total
Private
Reporting
Costs (million
$2006)
$410
$72
$29
Downstream
Emissions
Reported
(MtCO2e7
year)
3,827
3,827
3,827
Average
Uncertainty
7.00%
9.40%
19.70%
Incremental
Reporting Cost
(million $2006)
$338
-$43
Average
Reporting Cost
per Percentage
Point of
Uncertainty
(million
$20067%)
$58.6
$7.7
$1.5
Marginal Cost
per Percentage
Point
Uncertainty
(million
$20067%)
$140.8
-$4.2
Figure 5-2 shows the average cost per percentage point of uncertainty. The figure shows
that the average cost increases rapidly as uncertainty decreases.
$70
$60
$50
g $40
£ $30
$20
$10
$0
CEMS,
DefayiL
19.7%
9.4%
Average Uncertainty
7.0%
Figure 5-2. Average Cost per Percentage Point of Uncertainty
5-17
-------
5.1.3 EPA Uses Existing Federal Data for Fuel Quantity
Under this scenario, upstream fuel suppliers (Subparts LL, MM, NN), would not be
required to report their fuel quantity data to EPA. Rather than collecting this information from
upstream fuel suppliers, the EPA would access the quantity data each fuel supplier is currently
reporting to other federal agencies such as EIA. The reduction in cost from this option is a result
of fuel suppliers not having to duplicate the reporting of their fuel quantity data. However, most
other costs will stay the same because suppliers currently do not test for carbon content and
because they will still have to report fuel quality (i.e., carbon content) directly to EPA. It is
assumed that the accuracy and coverage of reported emissions for fuel suppliers would be
unchanged under this scenario.
EPA estimates that this would result in a labor savings of 2 hours for each reporting
entity, yielding a decreased private sector cost of $0.2 million.
(1,817 entities) x (2 hrs/entity) x (57 $/hr) = $207,138
However, there likely would be an increased cost to the public sector resulting from the
EPA need to obtain data from EIA and integrate the data with the fuel quality information
obtained from the GHG mandatory reporting rule. In addition, this task will be complicated by
issues related to maintaining data confidentiality, as discussed in the preamble. As a result, it is
unclear whether this option will result in a net decrease in total national costs of the program.
Table 5-12. Alternative Option 6
Facilities
Required to
Report
Upstream
Emissions
Reported
(MtCO2e/
year)
Downstream
Emissions
Reported
(MtCO2e/
year)
First Year
Private Costs
(million
$2006)
Subsequent
Year Private
Costs
(million
$2006)
Selected option
Alternative options
6. Existing federal data used for
measurement of fuel suppliers;
selected option for threshold,
frequency, verifier, and
10,152
3,663
3,827
$115.0
$72.1
methodology for other sources.
Absolute difference
Percentage difference
10,152
0
0%
3,663
0
0%
3,827
0
0%
$114.8
-0.2
-0.2%
$71.9
-0.2
-0.3%
5-18
-------
5.1.4 EPA Uses Default Carbon Content for Fuel Suppliers
Under this scenario, the only change to the selected approach is that fuel suppliers
(Subparts LL, MM, NN), are required to report their production to EPA in addition to their
downstream emissions, but EPA would use default carbon content parameters to calculate the
upstream emissions of these facilities. Under this scenario, the fuel suppliers' first year costs
would decrease from $10.4 million to zero. However, this change would increase the uncertainty
of the upstream emissions estimate from 4% to 6% (see Section 5.1.2 for a discussion of
uncertainty estimates).
The 2% increase in uncertainty represents 73.3 MtCO2e (3,663 MtCO2e x 0.02) of
emissions uncertainty for fuel suppliers. This yields a marginal cost of reducing uncertainty by
moving from Alternative Option 7 to the adopted option of
-$10.4 million/ 73.3 MtCO2e = 0.14$/tCO2e
Table 5-13. Alternative Option 7
Selected option
Alternative options
Facilities
Required to
Report
10,152
Upstream
Emissions
Reported
(MtCO2e/
year)
3,663
Downstream
Emissions
Reported
(MtCO2e/
year)
3,827
First Year
Private Costs
(million $2006)
$115.0
Subsequent
Year Private
Costs
(million $2006)
$72.1
7. EPA uses default carbon content for
fuel suppliers; selected option for
threshold, frequency, verifier, and
methodology for other sources.
Absolute difference
Percentage difference
10,152
0
0%
3,663
0
0%
3,827
0
0%
$104.6
-10.4
-9.1%
$66.0
-6.1
-8.4%
5.1.5 Frequency of Reporting: Quarterly
The selected reporting frequency is annually, unless entities are already required to report
quarterly. Under this scenario, all entities are required to report quarterly. To compute the cost of
the rule under a quarterly reporting scenario, we assume these costs increase proportionally for
each sector and used a ratio of quarterly to annual costs derived from the oil, gas, and mining
engineering cost analysis to scale each sector's selected option costs.13 This ratio was estimated
to be approximately 2.0 and primarily reflects the increased labor costs associated with
13Currently, this is the only industry sector available in the analysis that produced both quarterly and annual
reporting cost estimates. Under the recommended option, oil, gas, and mining sectors report annually.
5-19
-------
monitoring and reporting activities. As a result, quarterly reporting would lead to an increase in
the total annual private sector cost from $115 million to $230 million in the first year and from
$72 million to $144 million in subsequent years.
It is unclear what impact this would have on the accuracy of reported emissions. In
industries where processes or fuel inputs are highly variable, increased reporting would help
document the variability. However, for industries with stable processes, the impact on accuracy
would likely be minimal.
Table 5-14. Alternative Option 8
Selected option
Alternative options
8. Reporting is quarterly; selected
option for threshold,
methodology, and verifier.
Absolute difference
Percentage difference
Facilities
Required to
Report
10,152
10,152
0
0%
Upstream
Emissions
Reported
(MtC02e/
year)
3,663
3,663
0
0%
Downstream
Emissions
Reported
(MtC02e/
year)
3,827
3,827
0
0%
First Year
Private Costs
(million $2006)
$115.0
$230.1
115.0
100.0%
Subsequent
Year Private
Costs
(million $2006)
$72.1
$144.2
72.1
100.0%
5.1.6 Third-Party Verification
An alternative to having EPA QA/QC self-certified emissions based on information
provided by reporting entities is to have independent third-party verification. This would lead to
increased private-sector costs and potentially some reduction in Agency costs. Overall costs to
society will likely be higher for a third-party verification system than for a government
verification system because of increased transaction costs and lower economies of scale
compared to a centralized system. As shown in Table 5-15, private-sector third-party verification
costs are estimated to be approximately $42 million, compared with public-sector cost (if EPA
provides verification) of $7 million. Table 5-16 compares this alternative with the selected
option.
5-20
-------
Table 5-15. Private-Sector Third-Party Verification Costs
NAICS or Other Description
Subpart A — General Provisions
Subpart B — Electricity Use
Subpart C — General Stationary Fuel Combustion
Sources
Subpart D — Electricity Generation*
Subpart E — Adipic Acid Production3
Subpart F — Aluminum Production3
Subpart G — Ammonia Manufacturing3
Subpart H — Cement Production3
Subpart K — Ferroalloy Production
Subpart N — Glass Production
Subpart O— HCFC-22 Production3
Subpart P — Hydrogen Production
Subpart Q — Iron and Steel Production
Subpart R — Lead Production
Subpart S — Lime Manufacturing3
Subpart U — Miscellaneous Uses of Carbonates
Subpart V — Nitric Acid Production3
Subpart X — Petrochemical Production3
Subpart Y — Petroleum Refineries3
Subpart Z — Phosphoric Acid Production3
Subpart AA — Pulp and Paper Manufacturing
Subpart BB — Silicon Carbide Production3
Subpart CC — Soda Ash Manufacturing3
Subpart EE — Titanium Dioxide Production3
Subpart GG — Zinc Production
Subpart HH— Landfills
Subpart JJ — Manure Management
Subpart MM — Suppliers of Petroleum Products'5
Subpart NN — Suppliers of Natural Gas and Natural
Gas Liquids3
Subpart OO — Suppliers of Industrial Greenhouse
Gases
Subpart PP— Suppliers of Carbon Dioxide (CO2)b
Subpart QQ — Motor Vehicle and Engine
Manufacturers3
Total
Facilities
Required to
Report
3,000
1,108
4
14
23
107
9
55
3
41
121
13
89
0
45
80
150
14
425
1
5
8
5
2,551
107
315
1,502
167
13
317
10,152
Private
Costs per
Entity
($2006)
$2,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
$5,000
First Year
Total Costs
($2006)
$0
$0
$6,000,000
$5,540,000
$20,000
$70,000
$115,000
$535,000
$45,000
$275,000
$15,000
$205,000
$605,000
$65,000
$445,000
$0
$225,000
$400,000
$750,000
$70,000
$2,125,000
$5,000
$25,000
$40,000
$25,000
$12,755,000
$537,083
$1,575,000
$7,510,000
$835,000
$65,000
$1,585,000
$42,461,943
Public
$7,000,000
3While the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule. For further information on who must report, please see Section III A of the preamble.
bWhile the threshold analysis indicates that source coverage for this subpart varies at different thresholds, all sources are covered
in this subpart for this rule, with the exception of total bulk imports or total bulk exports that exceed 25,000 metric tons CO2e
per year. For further information on who must report, please see Section IIIA of the preamble.
5-21
-------
Table 5-16. Alternative Option 9
Selected option
Alternative options
9. Verification is done by a third
party; selected option for
threshold, methodology, and
frequency.
Absolute difference
Percentage difference
Facilities
Required to
Report
10,152
10,152
0
0%
Upstream
Emissions
Reported
(MtCO2e/
year)
3,663
3,663
0
0%
Downstream
Emissions
Reported
(MtCO2e/
year)
3,827
3,827
0
0%
First Year
Private Costs
(million
$2006)
$115.0
$157.5
42.5
36.9%
Subsequent
Year Private
Costs
(million
$2006)
$72.1
$114.6
42.5
58.9%
EPA's review of a study conducted by CARB found that third-party verification costs
range from $40,000 per entity for refineries to $2,000 per entity for miscellaneous facilities
(EPA-HQ-OAR-2008-0508, Review of Program Costs for Emissions Verification). The cost
information was based on self-reported information by approximately 20 facilities. The costs
reported by CARB were reviewed by EPA contract engineers and were assessed to be reasonable
based on field experience. Process-related third-party verification costs varied, but averaged
around $5,000 per facility. Facilities with stationary combustion sources had the lowest third-
party verification costs of $2,000 per facility. In analyzing the cost of this option, we assumed
that EGUs that must report their emissions under the ARP would not be subject to third-party
verification requirement because their CC>2 emissions are already subject to a separate QA/QC
process conducted by EPA.
Table 5-15 presents the private-sector costs by NAICS associated with the third-party
verification at the 25,000 CC^e threshold. At this threshold, total private-sector costs are
estimated to increase by approximately $42 million, with the greatest costs associated with
landfills, pipeline transportation, and stationary combustion.
Public-sector (Agency) costs would be reduced, however, under a third-party verification
scenario, the Agency would bear additional costs due to certifying verification vendors and
managing the verification program. EPA estimates that the cost of managing the verification
program, including running a certification program, would be $3.5 million. Hence, net savings to
the Agency would be $3.5 million.
5-22
-------
EPA verification combines a comprehensive electronic review and a flexible and
adaptive program of on-site auditing will to effectively target verification resources while also
providing the necessary consistency and quality in the data. Utilizing the national data set
developed under this rule will provide unique resources for the review of reports. EPA estimates
that it will be able to annually audit in detail more than 60% of facilities reporting using a
combination of desk audits for facilities initially flagged for additional review and in person site
audits. (EPA-HQ-OAR-2008-0508, Review of Program Costs for Emissions Verification)
A centralized emissions verification system provides greater ability for EPA to identify
trends and outliers in data and thus assist with targeted follow-up review. Our approach can
evolve over time as we gain experience with GHG reporting. This approach also provides
opportunities to work closely with and leverage both the experience and ongoing activities of
States and others already engaged in similar and different types of GHG reporting programs.
The emissions verification approach in this rule is consistent with other EPA emission
reporting programs and follows a model similar to the ARP, which is a highly successful
emissions cap and trade program that consistently produces credible, high-quality data. Facilities
regulated under ARP must have a Designated Representative sign data reports to self-certify that
the reported data are accurate. Then, facilities and EPA use a series of electronic tools to ensure
proper data collection and reporting, including establishing a monitoring plan, calibrating
equipment to certain specifications, frequent testing, and data submittal. Similar to what we are
intending with this program, EPA conducts site audits on those facilities targeted during the
electronic review as having been outliers or had anomalies in their reported data. Audits are done
by EPA personnel, states and/or contractors to EPA. EPA support these audits by providing a
field audit manual to both government and private auditors as well as additional training to state
and federal auditors.
5.1.7 Only Upstream and Downstream Process Reporting
Under this scenario, unspecified stationary sources are not required to report. All other
sectors are included in the definition of upstream. These include the fuel suppliers, industrial gas
suppliers, industrial processes, fugitive emissions, biological processes, and vehicle and engine
manufacturers sectors. Since the reporting thresholds and reporting requirements remain the
same for the upstream sources, the cost estimates for these sectors remain unchanged. Table 5-17
compares this alternative with the selected option and shows that the private costs of the rule fall
from $115 million to $86 million in the first year and fall from $73 million to $54 million in
subsequent years. Under Alternative 10, first year annualized costs per metric ton of downstream
5-23
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emissions rise in the first year from $0.03 to $0.06. In subsequent years, annualized cost per
metric ton rise from $0.02 baseline to $0.04.
Table 5-17. Alternative Option 10
Selected option
Alternative options
10. Reporting from upstream
sources only; selected option
for methodology, frequency,
and verifier.
Absolute difference
Percentage difference
Facilities
Required to
Report
10,152
6,027
-4,125
-41%
Upstream
Emissions
Reported
(MtCO2e/
year)
3,663
3,663
0
0%
Downstream
Emissions
Reported
(MtCO2e/
year)
3,827
1,325
0
0%
First Year
Private Costs
(million
$2006)
$115
$85.8
-29.3
-25.5%
Subsequent
Year Private
Costs
(million $2006)
$72
$53.8
-18.4
-25.5%
As shown in Table 5-18, over 99% of industrial processes emissions are covered at the
25,000 tCO2e threshold for a cost of approximately $36 million. It is assumed that the
uncertainly level of reported GHG emissions is unchanged under the upstream-only reporting
scenario. We also report estimates of the extent to which upstream/downstream emissions may
be counted more than once (Table 5-19). It should be noted that for all sources the coverage is
defined as the percentage of emissions covered for that source category, except for vehicle and
engine manufacturers where the coverage is defined as the percentage of manufacturers reporting
out of all vehicle and engine manufacturers.
The coverage and costs for downstream reporters apply to the specific source category;
therefore, fixed costs are not "double-counted" in both stationary combustion and industrial
processes for the same facility. An important aspect of this scenario is that some process related
emissions may not be captured due to the fact that downstream combustion sources would not be
covered by the rule. A source with process emission plus combustion emissions would only have
to report their process emission, thus the exclusion of downstream combustion could result in
some sources having emissions below the reporting threshold.
Consistent with the appropriations language regarding reporting of emissions from
"upstream production," EPA is proposing reporting requirements from upstream suppliers of
fossil fuel and industrial GHGs. In the context of GHG reporting, "upstream emissions" refers to
the GHG emissions potential of a quantity of industrial gas or fossil fuel supplied into the
5-24
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economy. For fossil fuels, the emissions potential is the amount of CO2 that would be produced
from complete combustion or oxidation of the carbon in the fuel. In many cases, the fossil fuels
and industrial GHGs supplied by producers and importers are used and ultimately emitted by a
Table 5-18. Reporting Costs by Upstream and Downstream Source Categories
Upstream1
Emissions First Year
Source # Coverage Private Cost
Category Reporters (%)10 (million $2006)
Coal Supply 0 0% $0.00
Petroleum 315 100% $3.66
Supply
Natural Gas 1,502 68% $6.76
Supply
Industrial Gas 167 100% $0.52
Supply
Downstream2'3'4
Source Category
Coal5'6
Combustion
Petroleum5
Combustion9
Natural Gas5
Combustion
Sub Total Combustion
Industrial Gas
Consumption
Industrial Processes
Fugitive Emissions
(coal, oil and gas)
Biological Processes
Vehicle8 and Engine
Manufacturers
Notes
1 A/T t t f Tf ( 1 f ' t ". 1 A' t 't+
#
Reporters2
N/A
N/A
N/A
4,108
17
1,068
0
2,658
317
Emissions
Coverage3'7'10
(%)
99%
20%
23%
N/A
14%
99.6%
0%
58%
80%
First Year
Private Cost3
(million $2006)
N/A
N/A
N/A
$29..04
$0.24
$36.23
$0.00
$12.77
$8.61
, j j • ,,
downstream side of the table.
Estimating the total number of downstream reporters by summing the rows will result in double-counting because some
facilities are included in more than one row due to multiple types of emissions (e.g., facilities that burn fossil fuel and have
process/fugitive/biological emissions will be included in each downstream category).
The coverage and costs for downstream reporters apply to the specific source category, i.e., the fixed costs are not "double-
counted" in both stationary combustion and industrial processes for the same facility.
The thresholds used to determine covered facilities are additive, i.e., all of the source categories located at a facility (e.g.,
stationary combustion and process emissions) are added together to determine whether a facility meets the threshold (e.g.,
25,000 metric tons of CO2e/yr).
Estimates for the number of reporters and total cost for downstream stationary combustion do not distinguish between fuels.
National level data on the number of reporters could be estimated. However, estimating the number of reporters by fuel was
not possible because a single facility can combust multiple fuels. For these reasons there is not a reliable estimate of the total
of the emissions coverage from the downstream stationary combustion.
Approximately 90 percent of downstream coal combustion emissions are already reported to EPA through requirements for
electricity generating units under the Acid Rain Program.
Due to data limitations, the coverage for downstream sources for fuel and industrial gas consumption in this table does not take
into account thresholds. Assuming full emissions coverage for each source slightly over-states the actual coverage that will
result from this rule. To estimate total emissions coverage downstream, by fuel, we added total emissions resulting from the
respective fuel combusted in the industrial and electricity generation sectors and divided that by total national GHG emissions
from the combustion of that fuel.
The percent of coverage here is percentage of total heavy-duty highway vehicles and engines, motorcycles, and nonroad
engine sales covered by manufacturer reporting in this proposal rather than emissions coverage. The "threshold" for mobile
sources is based on manufacturer size rather than total emissions. In this rule, all heavy-duty highway and nonroad vehicle and
engine manufacturers, except those that meet EPA's definition of "small business" or "small volume manufacturers", would
report emissions rates of CO2, CH4, and N2O from the products they supply. This source category is neither upstream nor
downstream, but is included in the downstream column for illustrative purposes.
5-25
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The emissions coverage for petroleum combustion includes combustion of fuel by transportation sources as well as other uses
of petroleum (e.g., home heating oil). It cannot be broken out by transportation versus other uses as there are difficulties
associated with tracking which products from petroleum refiners are used for transportation fuel and which were not. We know
that although refiners make these designations for the products leaving their gate, the actual end use can and does change in the
market. For example, designated transportation fuel can always be used as home heating oil.
10 Emissions coverage from the combustion of fossil fuels upstream represents CO2 emissions only. It is not possible to estimate
nitrous oxide and methane emissions without knowing where and how the fuel is combusted. In the case of downstream
emissions from stationary combustion of fossil fuels, nitrous oxide and methane emissions are included in the emissions
coverage estimate. They represent approximately 1 percent of the total emissions.
Table 5-19. Extent of Emissions Reported More than Once
Fuel or Gas
Coal consumption
Petroleum consumption
Natural gas consumption
Industrial gas consumption
Upstream
Downstream
Upstream
Downstream
Upstream
Downstream
Upstream
Downstream
Coverage of U.S.
Emissions (%)'
0%
99%
100%
20%
68%
23%
100%
14%
Number of
Reporters2
0
N/A
315
N/A
1,502
N/A
167
17
Percent of U.S. Emissions
Reported Both Upstream
and Downstream
0%
-20%
-23%
- 14%
1 Due to data limitations, the coverage for downstream sources for fuel and industrial gas consumption in this table does not take
into account thresholds. Assuming full emissions coverage for each source slightly over-states the actual coverage that would
result from this rule.
2 Estimates for the number of reporters and total cost for downstream stationary combustion do not distinguish between fuels.
National level data on the number of reporters could be estimated. However, estimating the number of reporters by fuel was
not possible because a single facility can combust multiple fuels.
3 The total emissions covered from upstream fuel suppliers is based on the applicability requirements in the preamble that all
petroleum and industrial gas, as well as LDCs and natural gas processing plants would be required to report to the rule.
Further, all importers of fossil fuels, and industrial gas importers with potential emissions greater than 25,000 mtCO2e would
be required to report. This means, 100% of potential emissions from petroleum and industrial gas would be included. For
natural gas, potential emissions from LDCs and gas processing plants represent about 68% of the total emissions from natural
gas consumption in the United States.
In the case of downstream coverage, for coal consumption we assume we capture 99% of emissions, because we will get
reporting for all coal consumed in the commercial, industrial, and electricity generating sectors. For natural gas and petroleum
consumption, we assume that we capture all gas consumed in the electricity generation sector, as well as some industrial
consumption. The percentages are based on reviewing data in Table 3-3 of the U.S. GHG Inventory 1990-2008.
For downstream emissions from industrial gases, we believe we are capturing emissions of these industrial gases from HCFC-
22 production, aluminum production, and N2O product uses. The downstream emissions from these sources can be found in
Table ES-2 of the U.S. GHG Inventory 1990-2008 and represent 14% of emissions of these gases.
large number of small sources, particularly in the commercial and residential sectors (e.g., HFCs
emitted from home A/C units or GHG emissions from individual motor vehicles). To cover these
direct emissions would require reporting by hundreds or thousands of small facilities. To avoid
this impact, this rule does not include all of those emitters, but instead requires reporting by the
suppliers of industrial gases and suppliers of fossil fuels. Because the GHGs in these products are
almost always fully emitted during use, reporting these supply data will provide an estimate of
national emissions while substantially reducing the number of reporters. For this reason, the rule
5-26
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requires reporting by suppliers of coal and coal-based products, petroleum products, natural gas
and natural gas liquids (NGLs), CO2 gas, and other industrial GHGs.
5.1.8 Sensitivity of Subsequent Year Cost Estimates
National cost estimates for the selected option were developed based on the current
population of entities. Whereas production in some of the affected sectors may increase or
decrease over time, it was assumed that the number of entities would remain relatively constant.
Thus, the analysis assumes a stable population where all entities bear a single first-year cost and
then repeated subsequent-year costs.
However, in reality, over time some existing entities close or go out of business and new
entities come into existence. This is sometimes referred to as entry and exit in an industry. This
affects the cost of the rule because as entities "turn over" the new entrants will bear first-year
costs that are slightly higher than subsequent year costs. To assess the impact of this dynamic,
we performed a case study analysis on selected industries in order to identify the average share
of new establishments in an industry each year.
To conduct the sensitivity analysis we recomputed subsequent year costs accounting for
the number of new entities census data (SB A, 2008b) suggest come into existence each year (that
face first-year costs). For example, in the oil and gas extraction section, 9% of the firms in any
given year are new to the industry (and hence will bear first-year costs). Thus, the adjusted
subsequent-year costs are computed as
(0.09) x First-Year Costs + (1 - 0.09) x (Subsequent Year Costs)
As shown in Table 5-20, this leads to less than a 0.1% increase in the subsequent-year
cost estimate for the oil and gas extraction section.
We identified an estimate of each industry's new establishment share using data from the
U.S. Census Statistics of U.S. Businesses (SUSB) program (SBA, 2008b). They provide an
annual series that include the number of new establishments by industry.14 Since this data is
organized by NAICS, we utilized the Subpart-to-NAICS mapping provided in Table 5-2 to
determine the appropriate costs to use for each NAICS industry. Using the share data in
Table 5-20, we find that the subsequent-year costs are on average approximately 5% higher
when entry and exit of entities are taken into account. This table also lists the specific subparts
utilized in estimating the costs associated with each NAICS. In some cases, it was difficult to
14
'http://www.sba.gov/advo/research/data.html
5-27
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estimate the total costs associated with each NAICS, because some subparts are mapped to
several different NAICS codes and it was unclear the portion of costs associated with each. In
these cases, a representative subpart was chosen.
Because of uncertainty in the future entry and exit across industries, we also performed
similar calculations assuming the shares in Table 5-20 were 2% higher or lower. Under this
assumption, subsequent-year costs are 6.0% higher and 3.9% higher under each case.
Table 5-20. Estimates of the Share of New Facilities in Subsequent Years and
Adjustment to Subsequent Year Costs
NAICS
211
221
322
324
325
327
331
486
562
Industry
Oil and gas extraction
Utilities
Pulp and paper
manufacturing
Petroleum and coal
products
Chemical
manufacturing
Cement and other
mineral production
Primary metal
manufacturing
Oil and natural gas
transportation
Waste management and
remediation services
Average:
Subpart
PP
NN
AA
Y, MM
CC, E, EE,
G, Y, MM,
0, 00, P,
V, X,Z
BB, H
F, GG, K,
Q,R,
NN
HH
First Year
Private Costs
Share ($2006)
9% $31,676
7% $6,762,859
4% $8,640,366
9% $9,770,899
6% $5,509,508
7% $12,574,063
8% $4,150,465
12% $6,794,535
12% $12,438,746
$7,408,124
Subsequent
Year Private
Costs
($2006)
$31,676
$5,016,593
$8,640,366
$5,143,671
$4,235,545
$7,483,483
$2,378,636
$5,048,269
$5,508,601
$4,831,871
Revised
Subsequent
Year Private
Costs
($2006)
$31,676
$5,139,169
$8,640,366
$5,559,441
$4,315,690
$7,817,356
$2,512,562
$5,263,058
$6,361,000
$5,071,146
Difference
($2006)
$0
$122,576
$0
$415,770
$80,144
$333,874
$133,926
$214,788
$852,399
$239,275
%
Difference
<0.1%
2.4%
<0.1%
8.1%
1.9%
4.5%
5.6%
4.3%
15.5%
4.7%
5.1.9 Summary of Alternative Threshold Options
Although, the selected option is not the least cost option (option 3, 6, 7, and 10 are less
expensive), the option provides additional benefits in terms of coverage and certainty of
emissions reporting that these other options do not (see Table 5-21). For example, the higher
reporting threshold under option 3 provides less downstream emissions coverage than the
selected option. Option 5 offers similar coverage but analysis presented in 5.1.2 suggests
emission estimation will be less precise. Option 6 provides only small labor cost savings
(approximately $0.2 million). However, the increased cost to the public sector resulting
5-28
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integrating the data with the fuel quality information and issues related to maintaining data
confidentiality makes it unclear whether this option will result in a net decrease in total national
costs of the program. Under Option 7, the fuel suppliers' first year costs would decrease from
$10 million to zero but uncertainty of the upstream emissions estimate increases from 4% to 6%.
Under option 10, some process related emissions may not be captured if downstream combustion
sources are not be covered by the rule. This is because facilities with process emission plus
combustion emissions would only have to report their process emission, thus the exclusion of
downstream combustion could result in some sources being under the threshold.
Table 5-21. Summary of Results by Option
Number of
Reporters
Option (covered)
Selected option 10,152
Alternative options
1. Al,OOOtC02e 54,229
threshold; selected
options for
methodology,
frequency, and
verifier
2. A 10,000 tCO2e 16,718
threshold; selected
options for
methodology,
frequency, and
verifier.
3. A 100,000 tC02e 6,269
threshold; selected
options for
methodology,
frequency, and
verifier.
4. The measurement 10,152
variable is
changed to direct
measurement;
selected option for
threshold,
frequency, and
verifier.
5. The measurement 10,152
variable is
changed to default
emissions factors;
selected option for
threshold,
frequency, and
verifier.
Upstream Downstream Subsequent Subsequent
Emissions Emissions First Year First Year Year Private Year Public
Reported Reported Private Costs Public Costs Costs Costs
(MtCO2e/ (MtCO2e/ (million (million (million (million
year) year) $2006) $2006) $2006) $2006)
3,663 3,827 $132 $17 $89 $17
3,663 3,926 $398 $17 $286 $17
3,663 3,861 $160 $17 $120 $17
3,660 3,738 $88 $17 $69 $17
3,663 3,827 $1,014 $17 $410 $17
3,663 3,827 $56 $17 $29 $17
5-29
-------
6. Existing federal 10,152 3,663 3,827 $115 $17 $72 $17
data used for
measurement of
fuel suppliers;
selected option for
threshold,
frequency,
verifier, and
methodology for
other sources.
(continued)
5-30
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Table 5-21. Summary of Results by Option (continued)
Upstream Downstream Subsequent Subsequent
Emissions Emissions First Year First Year Year Private Year Public
Number of Reported Reported Private Costs Public Costs Costs Costs
Reporters (MtCO2e/ (MtCO2e/ (million (million (million (million
Option (covered) year) year) $2006) $2006) $2006) $2006)
7. EPA uses default 10,152 3,663 3,827
carbon content for
fuel suppliers;
selected option for
threshold,
frequency,
verifier, and
methodology for
other sources.
8. Reporting is 10,152 3,663 3,827
quarterly; selected
option for
threshold,
methodology, and
verifier.
9. Verification is 10,152 3,663 3,827
done by a third
party; selected
option for
threshold,
methodology, and
frequency.
10. Reporting from 6,027 3,663 1,325
upstream sources
only; selected
option for
methodology,
frequency, and
verifier.
$105
$17
$230
$17
$158
$17
86
17
$66
$17
$144
$17
$115
$17
54
17
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). To make this determination, EPA
used a screening analysis that allows us to indicate whether EPA can certify the rule as not
having a SISNOSE. The elements of this analysis included
• identifying affected sectors and entities,
• selecting and describing the measures and economic impact thresholds used in the
analysis, and
• determining SISNOSE certification category.
5-31
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5.2.1 Identify Affected Sectors and Entities
The industry sectors covered by the rule were identified during the development of the
cost analysis for the reporting rule. The SUSB data provide national information on the
distribution of economic variables by industry and size.15 These data were developed in
cooperation with, and partially funded by, the Office of Advocacy of the Small Business
Administration (SB A) (SB A, 2008a). The data include the number of establishments
(Table 5-22), employment (Table 5-23), and receipts (Table 5-24) and present information on all
entities in an industry covered by the rule; however, many of these entities would not be
expected to report under the preferred option because they would fall below the 25,000 hybrid
threshold. SUSB also provides this data by enterprise employment size. The census definitions in
this data set are as follows:
• establishment: An establishment is a single physical location where business is
conducted or where services or industrial operations are performed.
• employment: Paid employment consists of full- and part-time employees, including
salaried officers and executives of corporations, who were on the payroll in the pay
period including March 12, 2002. Included are employees on sick leave, holidays, and
vacations; not included are proprietors and partners of unincorporated businesses.
• receipts: Receipts (net of taxes) are defined as the revenue for goods produced,
distributed, or services provided, including revenue earned from premiums,
commissions and fees, rents, interest, dividends, and royalties. Receipts exclude all
revenue collected for local, state, and federal taxes.
• enterprise: An enterprise is a business organization consisting of one or more
domestic establishments that were specified under common ownership or control. The
enterprise and the establishment are the same for single-establishment firms. Each
multi-establishment company forms one enterprise—the enterprise employment and
annual payroll are summed from the associated establishments. Enterprise size
designations are determined by the summed employment of all associated
establishments.
Because the SBA's business size definitions (SBA, 2008c) apply to an establishment's "ultimate
parent company," we assume in this analysis that the "enterprise" definition above is consistent
with the concept of ultimate parent company that is typically used for Small Business Regulatory
Enforcement Fairness Act (SBREFA) screening analyses and the terms are used interchangeably.
We also report the SB A size standard(s) for each industry group in order to facilitate
comparisons and different thresholds.
15The SUSB data does not provide establishment information for agricultural NAICS codes (e.g., NAICS 112 which
covers Manure Management). However, the per entity costs are relatively small (less than $3,000 per year) and
EPA believes the ultimate parent companies of entities covered are not small businesses.
5-32
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Table 5-22. Number of Establishments by Affected Industry and Enterprise" Size: 2002
Industry
Oil and Gas Extraction
SF6 from Electrical Systems
and LDCs
Pulp & Paper Manufacturing
Petroleum and Coal Products
Chemical Manufacturing
Cement & Other Mineral
Production
Primary Metal Manufacturing
Oil & Natural Gas
Transportation
Waste Management and
Remediation Services
Adipic Acid
Ammonia
Cement
Ferroalloys
Glass
Hydrogen Production
Iron and Steel
Lead Production
Lime Manufacturing
Nitric Acid
Petrochemical
Phosphoric Acid
Pulp and Paper
Refineries
NAICS
211
221
322
324
325
327
331
486
562
325199
325311
327310
331112
3272
325120
331112
3314
327410
325311
324110
325312
322110
324110
NAICS Description
Oil & gas extraction
Utilities
Paper mfg
Petroleum & coal products
mfg
Chemical mfg
Nonmetallic mineral product
mfg
Primary metal mfg
Pipeline transportation
Waste management &
remediation services
All other basic organic
chemical mfg
Nitrogenous fertilizer mfg
Cement mfg
Electrometallurgical
ferroalloy product mfg
Glass & glass product mfg
Industrial gas mfg
Electrometallurgical
ferroalloy product mfg
Nonferrous metal (except
aluminum) production &
processing
Lime mfg
Nitrogenous fertilizer mfg
Petroleum refineries
Phosphatic fertilizer mfg
Pulp mills
Petroleum refineries
SBA Size
Standard
(effective
March 11,
2008)
500
c
500 to 750
d
500 to 1,000
500 to 1,000
500 to 1,000
e
f
1,000
1,000
750
750
500 to 1,000
1,000
750
750 to 1,000
500
1,000
d
500
750
d
Total
Estab-
lish-
ments
7,629
18,432
5,546
2,296
13,096
16,674
6,229
2,701
17,698
640
157
253
17
2,190
551
17
958
77
157
349
50
44
349
Owned by Enterprises with:
Ito20
Employees'"
5,239
5,715
1,488
596
5,433
7,161
2,652
110
10,775
157
78
67
3
1,290
45
3
386
18
78
85
12
8
85
20 to 99
Employees
456
1,423
1,271
323
2,208
3,302
1,278
59
1,839
99
18
29
NA
276
20
NA
174
13
18
29
5
4
29
100 to 499
Employees
292
1,126
755
292
1,352
1,788
765
79
612
78
15
22
7
113
20
7
108
6
15
28
6
7
28
500 to 749
Employees
60
282
83
72
250
306
124
115
86
24
5
11
NA
13
NA
NA
24
7
5
10
2
2
10
750 to 999
Employees
64
144
69
82
185
438
90
5
63
4
1
9
1
24
30
1
14
19
1
7
NA
2
7
1,000 to
1,499
Employees
31
209
138
20
276
337
100
42
58
17
12
20
1
16
55
1
11
4
12
3
2
4
3
(continued)
-------
Table 5-22. Number of Establishments by Affected Industry and Enterprise" Size: 2002 (continued)
Industry
Silicon Carbide
Soda Ash Manufacturing
Titanium Dioxide
Zinc Production
NAICS
327910
3251
325188
3314
NAICS Description
Abrasive product mfg
Basic chemical mfg
All other basic inorganic
chemical mfg
Nonferrous metal (except
aluminum) production &
processing
SBA Size
Standard
(effective
March 11,
2008)
500
500 to 1,000
1,000
750 to 1,000
Estab-
lish-
ments
347
2,287
611
958
Owned by Enterprises with:
Ito20
Employees'"
161
478
141
386
20 to 99
Employees
100
316
111
174
100 to 499
Employees
42
231
69
108
500 to 749
Employees
2
68
38
24
750 to 999
Employees
NA
63
25
14
1,000 to
1,499
Employees
NA
97
6
11
a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control.
The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and
annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition
above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
b Given the Agency's selected thresholds, enterprises with fewer than 20 employees are likely to be excluded from the reporting program.
0 NAICS codes 221 111, 221112, 221113, 221119, 221121, 221122—A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours. NAICS 221210= 500 employees.
d 500 to 1,500. For NAICS code 324110—For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more
than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as facilities under a
processing agreement or an arrangement such as an exchange agreement or a throughput. The total product to be delivered under the contract must be at least 90% refined by the
successful bidder from either crude oil or bona fide feedstocks.
e NAICS codes 486110 = 1,500 employees; NAICS 486210=$6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 =$11.5 million annual receipts.
f Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910—
Environmental Remediation Services:
a) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern must be engaged
primarily in furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to, preliminary assessment,
site inspection, testing, remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated materials, storage of contaminated
materials and security and site closeouts. If one of such activities accounts for 50% or more of a concern's total revenues, employees, or other related factors, the concern's
primary industry is that of the particular industry and not the Environmental Remediation Services Industry.
b) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a contaminated
environment and also the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering),
smaller sub-components of NAICS codes with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as:
Heavy Construction; Special Trade Construction; Engineering Services; Architectural Services; Management Services; Refuse Systems; Sanitary Services, Not Elsewhere
Classified; Local Trucking Without Storage; Testing Laboratories; and Commercial, Physical and Biological Research. If any activity in the procurement can be identified with
a separate NAICS code, or component of a code with a separate distinct size standard, and that industry accounts for 50% or more of the value of the entire procurement, then
the proper size standard is the one for that particular industry, and not the Environmental Remediation Service size standard.
NA: Not available. SUSB did not report this data for disclosure or other reasons.
-------
Table 5-23. Number of Employees by Affected Industry and Enterprise3 Size: 2002
Industry
Oil and Gas Extraction
SF6 from Electrical Systems and
LDCS
Pulp & Paper Manufacturing
Petroleum and Coal Products
Chemical Manufacturing
Cement & Other Mineral
Production
Primary Metal Manufacturing
Oil & Natural Gas Transportation
Waste Management and
Remediation Services
Adipic Acid
Ammonia
Cement
Ferroalloys
Glass
Hydrogen Production
Iron and Steel
Lead Production
Lime Manufacturing
Nitric Acid
Petrochemical
Phosphoric Acid
Pulp and Paper
NAICS
211
221
322
324
325
327
331
486
562
325199
325311
327310
331112
3272
325120
331112
3314
327410
325311
324110
325312
322110
NAICS Description
Oil & gas extraction
Utilities
Paper mfg
Petroleum & coal products
mfg
Chemical mfg
Nonmetallic mineral
product mfg
Primary metal mfg
Pipeline transportation
Waste management &
remediation services
All other basic organic
chemical mfg
Nitrogenous fertilizer mfg
Cement mfg
Electrometallurgical
ferroalloy product mfg
Glass & glass product mfg
Industrial gas mfg
Electrometallurgical
ferroalloy product mfg
Nonferrous metal (except
aluminum) production &
processing
Lime mfg
Nitrogenous fertilizer mfg
Petroleum refineries
Phosphatic fertilizer mfg
Pulp mills
SBA Size
Standard
(effective
March 11,
2008)
500
c
500 to 750
d
500 to 1,000
500 to 1,000
500 to 1,000
e
f
1,000
1,000
750
750
500 to 1,000
1,000
750
750 to 1,000
500
1,000
d
500
750
Owned by Enterprises with:
Total
Employees
88,280
648,254
495,990
100,403
827,430
475,476
501,038
50,362
300,580
73,342
4,949
16,905
2,266
114,794
9,557
2,266
64,203
4,393
4,949
62,132
6,288
8,373
Ito20
Employees'"
19,336
24,257
11,325
3,709
34,838
47,315
18,299
588
56,529
1,023
363
493
NA
6,563
88
NA
2,421
33
363
454
27
22
20 to 99
Employees
12,113
39,391
52,334
8,319
78,090
98,637
52,242
227
59,245
2,412
210
418
NA
10,569
294
NA
6,680
227
210
942
NA
NA
100 to 499
Employees
11,656
46,942
78,402
10,337
113,326
85,569
94,040
569
37,530
3,232
NA
1,157
NA
13,186
510
NA
10,407
NA
NA
2,870
NA
NA
500 to 749
Employees
2,421
12,042
13,293
3,606
28,025
17,516
21,868
NA
5,122
NA
NA
NA
NA
1,741
NA
NA
NA
NA
NA
2,903
NA
NA
750 to 999
Employees
3,551
6,519
12,496
1,268
18,119
17,946
18,062
NA
3,401
754
NA
NA
NA
2,622
NA
NA
NA
NA
NA
NA
NA
NA
1,000 to
1,499
Employees
1,061
14,653
23,283
1,521
28,338
17,512
17,252
NA
3,645
NA
NA
2,051
NA
2,877
NA
NA
1,337
NA
NA
NA
NA
NA
(continued)
-------
Table 5-23. Number of Employees by Affected Industry and Enterprise3 Size: 2002 (continued)
Industry
Refineries
Silicon Carbide
Soda Ash Manufacturing
Titanium Dioxide
Zinc Production
NAICS
324110
327910
3251
325188
3314
NAICS Description
Petroleum refineries
Abrasive product mfg
Basic chemical mfg
All other basic inorganic
chemical mfg
Nonferrous metal (except
aluminum) production &
processing
SBA Size
Standard
(effective
March 11,
2008)
d
500
500 to 1,000
1,000
750 to 1,000
Owned by Enterprises with:
Total
Employees
62,132
16,079
172,964
49,845
64,203
Ito20
Employees'"
454
1,237
3,171
566
2,421
20 to 99
Employees
942
3,637
10,392
881
6,680
100 to 499
Employees
2,870
3,536
16,525
1,839
10,407
500 to 749
Employees
2,903
NA
5,548
NA
NA
750 to 999
Employees
NA
NA
3,354
NA
NA
1,000 to
1,499
Employees
NA
NA
5,001
NA
1,337
a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control.
The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and
annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition
above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
b Given the Agency's selected thresholds, enterprises with fewer than 20 employees are likely to be excluded from the reporting program.
0 NAICS codes 221111, 221112, 221113, 221119, 221121, 221122—A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours. NAICS 221210=500 employees.
d 500 to 1,500. For NAICS code 324110—For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more
than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as facilities under a
processing agreement or an arrangement such as an exchange agreement or a throughput. The total product to be delivered under the contract must be at least 90% refined by the
successful bidder
from either crude oil or bona fide feedstocks.
e NAICS codes 486110 = 1,500 employees; NAICS 486210=$6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 =$11.5 million annual receipts.
f Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910—
Environmental Remediation Services:
a) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern must be engaged
primarily in furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to, preliminary assessment,
site inspection, testing, remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated materials, storage of contaminated
materials and security and site closeouts. If one of such activities accounts for 50% or more of a concern's total revenues, employees, or other related factors, the concern's
primary industry is that of the particular industry and not the Environmental Remediation Services Industry.
b) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a contaminated
environment and also the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering),
smaller sub-components of NAICS codes with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as:
Heavy Construction; Special Trade Construction; Engineering Services; Architectural Services; Management Services; Refuse Systems; Sanitary Services, Not Elsewhere
Classified; Local Trucking Without Storage; Testing Laboratories; and Commercial, Physical and Biological Research. If any activity in the procurement can be identified with
a separate NAICS code, or component of a code with a separate distinct size standard, and that industry accounts for 50% or more of the value of the entire procurement, then
the proper size standard is the one for that particular industry, and not the Environmental Remediation Service size standard.
NA: Not available. SUSB did not report this data for disclosure or other reasons.
-------
Table 5-24. Receipts by Affected Industry and Enterprise" Size: 2002
Industry
Oil and Gas Extraction
SF6 from Electrical Systems
and LDCs
Pulp & Paper Manufacturing
Petroleum and Coal Products
Chemical Manufacturing
Cement & Other Mineral
Production
Primary Metal Manufacturing
Oil & Natural Gas
Transportation
Waste Management and
Remediation Services
Adipic Acid
Ammonia
Cement
Ferroalloys
Glass
Hydrogen Production
Iron and Steel
Lead Production
Lime Manufacturing
Nitric Acid
Petrochemical
Phosphoric Acid
NAICS
211
221
322
324
325
327
331
486
562
325199
325311
327310
331112
3272
325120
331112
3314
327410
325311
324110
325312
NAICS Description
Oil & gas extraction
Utilities
Paper mfg
Petroleum & coal
products mfg
Chemical mfg
Nonmetallic mineral
product mfg
Primary metal mfg
Pipeline transportation
Waste management &
remediation services
All other basic organic
chemical mfg
Nitrogenous fertilizer
mfg
Cement mfg
Electrometallurgical
ferroalloy product mfg
Glass & glass product
mfg
Industrial gas mfg
Electrometallurgical
ferroalloy product mfg
Nonferrous metal
(except aluminum)
production &
processing
Lime mfg
Nitrogenous fertilizer
mfg
Petroleum refineries
Phosphatic fertilizer mfg
SBA Size
Standard
(effective
March 11,
2008)
500
C
500 to 750
i
500 to 1,000
500 to 1,000
500 to 1,000
C
f
1,000
1,000
750
750
500 to 1,000
1,000
750
750 to 1,000
500
1,000
i
500
Owned by Enterprises with:
Total
Receipts
(million)
$160,879
$396,077
$154,746
$216,624
$468,211
$95,443
$139,461
$45,053
$48,204
$46,874
$3,335
$7,252
$875
$22,180
$5,780
$875
$21,330
$1,018
$3,335
$195,752
$3,997
Ito20
Employees'"
$7,345
$8,958
$2,218
$1,837
$9,631
$6,446
$2,847
$1,009
$6,465
$379
$132
$180
NA
$689
$22
NA
$505
$6
$132
$467
$6
20 to 99
Employees
$6,790
$24,519
$9,483
$5,528
$21,394
$15,357
$8,931
$137
$7,259
$764
$52
$104
NA
$1,252
$292
NA
$2,075
$55
$52
$2,519
NA
100 to 499
Employees
$9,609
$25,258
$17,620
$7,754
$39,111
$14,722
$18,904
$224
$5,153
$1,837
NA
$456
NA
$1,786
$71
NA
$2,609
NA
NA
$4,500
NA
500 to 749
Employees
$4,609
$7,394
$3,034
$9,279
$12,217
$3,604
$4,829
NA
$837
NA
NA
NA
NA
$321
NA
NA
NA
NA
NA
$8,758
NA
750 to 999
Employees
$3,991
$4,521
$3,951
$975
$7,324
$3,470
$6,201
NA
$745
$854
NA
NA
NA
$313
NA
NA
NA
NA
NA
NA
NA
1,000 to
1,499
Employees
$2,805
$9,567
$6,798
$1,115
$14,762
$3,789
$5,254
NA
$509
NA
NA
$861
NA
$382
NA
NA
$315
NA
NA
NA
NA
(continued)
-------
Table 5-24. Receipts by Affected Industry and Enterprise3 Size: 2002 (continued)
oo
Industry
Pulp and Paper
Refineries
Silicon Carbide
Soda Ash Manufacturing
Titanium Dioxide
Zinc Production
NAICS
322110
324110
327910
3251
325188
3314
NAICS Description
Pulp mills
Petroleum refineries
Abrasive product mfg
Basic chemical mfg
All other basic inorganic
chemical mfg
Nonferrous metal
(except aluminum)
production &
processing
SBA Size
Standard
(effective
March 11,
2008)
750
d
500
500 to 1,000
1,000
750 to 1,000
Owned by Enterprises with:
Total
Receipts
(million)
$3,791
$195,752
$3,350
$107,018
$16,314
$21,330
Ito20
Employees'"
$10
$467
$179
$1,391
$173
$505
20 to 99
Employees
NA
$2,519
$486
$4,097
$232
$2,075
100 to 499
Employees
NA
$4,500
$621
$6,918
$594
$2,609
500 to 749
Employees
NA
$8,758
NA
$3,462
NA
NA
750 to 999
Employees
NA
NA
NA
$1,777
NA
NA
1,000 to
1,499
Employees
NA
NA
NA
$3,313
NA
$315
a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control.
The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and
annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition
above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
b Given the Agency's selected thresholds, enterprises with fewer than 20 employees are likely to be excluded from the reporting program.
0 NAICS codes 221 111, 221112, 221113, 221119, 221121, 221122—A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours. NAICS 221210=500 employees.
d 500 to 1,500. For NAICS code 324110—For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more
than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as facilities under a
processing agreement or an arrangement such as an exchange agreement or a throughput. The total product to be delivered under the contract must be at least 90% refined by the
successful bidder from either crude oil or bona fide feedstocks.
e NAICS codes 486110 = 1,500 employees; NAICS 486210=$6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 =$11.5 million annual receipts.
f Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910—
Environmental Remediation Services:
a) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern must be engaged
primarily in furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to, preliminary assessment,
site inspection, testing, remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated materials, storage of contaminated
materials and security and site closeouts. If one of such activities accounts for 50% or more of a concern's total revenues, employees, or other related factors, the concern's
primary industry is that of the particular industry and not the Environmental Remediation Services Industry.
b) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a contaminated
environment and also the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering),
smaller sub-components of NAICS codes with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as:
Heavy Construction; Special Trade Construction; Engineering Services; Architectural Services; Management Services; Refuse Systems; Sanitary Services, Not Elsewhere
Classified; Local Trucking Without Storage; Testing Laboratories; and Commercial, Physical and Biological Research. If any activity in the procurement can be identified with
a separate NAICS code, or component of a code with a separate distinct size standard, and that industry accounts for 50% or more of the value of the entire procurement, then
the proper size standard is the one for that particular industry, and not the Environmental Remediation Service size standard.
NA: Not available. SUSB did not report this data disclosure or other reasons.
-------
5.2.2 Develop Small Entity Economic Impact Measures
Because the rule covers a large number of sectors and primarily covers businesses, the
analysis generated a set of sales tests (represented as cost-to-receipt ratios)16 for NAICS codes
associated with the affected sectors. Although the appropriate SB A 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 six enterprise size ranges (i.e., all categories,
enterprises with 1 to 20 employees, 20 to 99 employees, 100 to 499 employees, 500 to 999
employees, and 1,000 to 1,499 employees. This approach allows us to account for differences in
establishment receipts between large and small enterprises and differences in small business
definitions across affected 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.
These sales tests examine the average establishment's total annualized mandatory
reporting costs to the average establishment receipts for enterprises within several employment
categories17 (first year costs: Table 5-25; subsequent year costs: Table 5-26). The average entity
costs used to compute the sales test are the same across all of these enterprise size categories. As a
result, the sales-test will overstate the cost-to-receipt ratio for establishments owned by small
businesses, because the reporting costs are likely lower than average entity estimates provided by
the engineering cost analysis.
16The following metrics for other small entity economic impact measures (if applicable) would potentially include
• Small governments (if applicable): "Revenue" test; annualized compliance cost as a percentage of annual
government revenues
• Small non-profits (if applicable): "Expenditure" test; annualized compliance cost as a percentage of annual
operating expenses
17For the one to 20 employee category, we exclude SUSB data for enterprises with zero employees. These
enterprises did not operate the entire year.
5-39
-------
Table 5-25. Establishment Sales Tests by Industry and Enterprise" Size: First Year Costs
Industry
Oil and Gas Extraction
SF6 from Electrical Systems
and LDCs
Pulp & Paper Manufacturing
Petroleum and Coal Products
Chemical Manufacturing
Cement & Other Mineral
Production
Primary Metal Manufacturing
Oil & Natural Gas
Transportation
Waste Management and
Remediation Services
Adipic Acid
Ammonia
Cement
Ferroalloys
Glass
Hydrogen Production
Iron and Steel
Lead Production
Lime Manufacturing
Nitric Acid
Petrochemical
Phosphoric Acid
Pulp and Paper
Refineries
NAICS
211
221
322
324
325
327
331
486
562
325199
325311
327310
331112
3272
325120
331112
3314
327410
325311
324110
325312
322110
324110
NAICS Description
Oil & gas extraction
Utilities
Paper mfg
Petroleum & coal products
mfg
Chemical mfg
Nonmetallic mineral
product mfg
Primary metal mfg
Pipeline transportation
Waste management &
remediation services
All other basic organic
chemical mfg
Nitrogenous fertilizer mfg
Cement mfg
Electrometallurgical
ferroalloy product mfg
Glass & glass product mfg
Industrial gas mfg
Electrometallurgical
ferroalloy product mfg
Nonferrous metal (except
aluminum) production &
processing
Lime mfg
Nitrogenous fertilizer mfg
Petroleum refineries
Phosphatic fertilizer mfg
Pulp mills
Petroleum refineries
SBA Size
Standard
(effective
March 11,
2008)
500
C
500 to 750
d
500 to 1,000
500 to 1,000
500 to 1,000
e
f
1,000
1,000
750
750
500 to 1,000
1,000
750
750 to 1,000
500
1,000
d
500
750
d
Average
Cost Per
Entity
($1,0007
entity)
$2
$5
$20
$21
$14
$50
$26
$4
$5
$24
$17
$63
$9
$8
$3
$30
$10
$60
$20
$27
$60
$20
$41
Owned by Enterprises with:
All
Enter-
prises
0.0%
0.0%
0.1%
0.0%
0.0%
0.8%
0.1%
0.0%
0.2%
0.0%
0.1%
0.2%
0.0%
0.1%
0.0%
0.1%
0.0%
0.4%
0.1%
0.0%
0.1%
0.0%
0.0%
Ito20
Employees'"
0.2%
0.2%
1.2%
0.6%
0.7%
4.8%
2.1%
0.0%
0.7%
0.9%
0.9%
2.0%
NA
1.4%
0.6%
NA
0.6%
16.5%
1.0%
0.4%
10.1%
1.4%
0.6%
20 to 99
Employees
0.0%
0.0%
0.2%
0.1%
0.1%
0.9%
0.3%
0.2%
0.1%
0.3%
0.5%
1.5%
NA
0.2%
0.0%
NA
0.1%
1.2%
0.6%
0.0%
NA
NA
0.0%
100 to 499
Employees
0.0%
0.0%
0.1%
0.1%
0.0%
0.5%
0.1%
0. 1%
0.1%
0.1%
NA
0.3%
NA
0.0%
0. 1%
NA
0.0%
NA
NA
0.0%
NA
NA
0.0%
500 to 749
Employees
0.0%
0.0%
0.0%
0.0%
0.0%
0.4%
0.1%
NA
0.0%
NA
NA
NA
NA
0.0%
NA
NA
NA
NA
NA
0.0%
NA
NA
0.0%
750 to 999
Employees
0.0%
0.0%
0.0%
0.2%
0.0%
0.5%
0.0%
NA
0.0%
0.0%
NA
NA
NA
0.1%
NA
NA
NA
NA
NA
NA
NA
NA
NA
1,000 to
1,499
Employees
0.0%
0.0%
0.0%
0.0%
0.0%
0.4%
0.0%
NA
0.0%
NA
NA
0.1%
NA
0.0%
NA
NA
0.0%
NA
NA
NA
NA
NA
NA
(continued)
-------
Table 5-25. Establishment Sales Tests by Industry and Enterprise" Size: First Year Costs (continued)
Industry
Silicon Carbide
Soda Ash Manufacturing
Titanium Dioxide
Zinc Production
NAICS
327910
3251
325188
3314
NAICS Description
Abrasive product mfg
Basic chemical mfg
All other basic inorganic
chemical mfg
Nonferrous metal (except
aluminum) production &
processing
SBA Size
Standard
(effective
March 11,
2008)
500
500 to 1,000
1,000
750 to 1,000
Average
Cost Per
Entity
($1,0007
entity)
$10
$16
$10
$13
Owned by Enterprises with:
All
Enter-
prises
0.1%
0.0%
0.0%
0.05%
Ito20
Employees'"
0.8%
0.5%
0.7%
0.9%
20 to 99
Employees
0.2%
0.1%
0.4%
0. 1%
100 to 499
Employees
0. 1%
0.0%
0.1%
0.0%
500 to 749
Employees
NA
0.0%
NA
NA
750 to 999
Employees
NA
0.0%
NA
NA
1,000 to
1,499
Employees
NA
0.0%
NA
0.0%
a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control.
The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and
annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition
above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
b Given the Agency's selected thresholds, enterprises with fewer than 20 employees are likely to be excluded from the reporting program.
0 NAICS codes 221 111, 221112, 221113, 221119, 221121, 221122—A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours. NAICS 221210=500 employees.
d 500 to 1,500. For NAICS code 324110—For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more
than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as facilities under a
processing agreement or an arrangement such as an exchange agreement or a throughput. The total product to be delivered under the contract must be at least 90% refined by the
successful bidder from either crude oil or bona fide feedstocks.
e NAICS codes 486110 = 1,500 employees; NAICS 486210=$6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 =$11.5 million annual receipts.
f Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910—
Environmental Remediation Services:
a) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern must be engaged
primarily in furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to, preliminary assessment,
site inspection, testing, remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated materials, storage of contaminated
materials and security and site closeouts. If one of such activities accounts for 50% or more of a concern's total revenues, employees, or other related factors, the concern's
primary industry is that of the particular industry and not the Environmental Remediation Services Industry.
b) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a contaminated
environment and also the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering),
smaller sub-components of NAICS codes with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as:
Heavy Construction; Special Trade Construction; Engineering Services; Architectural Services; Management Services; Refuse Systems; Sanitary Services, Not Elsewhere
Classified; Local Trucking Without Storage; Testing Laboratories; and Commercial, Physical and Biological Research. If any activity in the procurement can be identified with
a separate NAICS code, or component of a code with a separate distinct size standard, and that industry accounts for 50% or more of the value of the entire procurement, then
the proper size standard is the one for that particular industry, and not the Environmental Remediation Service size standard.
NA: Not available. SUSB did not report the data necessary to calculate this ratio.
-------
Table 5-26. Establishment Sales Tests by Industry and Enterprise" Size: Subsequent Year Costs
to
Industry
Oil and Gas Extraction
SF6 from Electrical Systems
and LDCs
Pulp & Paper Manufacturing
Petroleum and Coal Products
Chemical Manufacturing
Cement & Other Mineral
Production
Primary Metal Manufacturing
Oil & Natural Gas
Transportation
Waste Management and
Remediation Services
Adipic Acid
Ammonia
Cement
Ferroalloys
Glass
Hydrogen Production
Iron and Steel
Lead Production
Lime Manufacturing
Nitric Acid
Petrochemical
Phosphoric Acid
Pulp and Paper
Refineries
NAICS
211
221
322
324
325
327
331
486
562
325199
325311
327310
331112
3272
325120
331112
3314
327410
325311
324110
325312
322110
324110
NAICS Description
Oil & gas extraction
Utilities
Paper mfg
Petroleum & coal products
mfg
Chemical mfg
Nonmetallic mineral
product mfg
Primary metal mfg
Pipeline transportation
Waste management &
remediation services
All other basic organic
chemical mfg
Nitrogenous fertilizer mfg
Cement mfg
Electrometallurgical
ferroalloy product mfg
Glass & glass product mfg
Industrial gas mfg
Electrometallurgical
ferroalloy product mfg
Nonferrous metal (except
aluminum) production
& processing
Lime mfg
Nitrogenous fertilizer mfg
Petroleum refineries
Phosphatic fertilizer mfg
Pulp mills
Petroleum refineries
SBA Size
Standard
(effective
March 11,
2008)
500
C
500 to 750
d
500 to 1,000
500 to 1,000
500 to 1,000
e
f
1,000
1,000
750
750
500 to 1,000
1,000
750
750 to 1,000
500
1,000
i
500
750
d
Average
Cost Per
Entity
($/entity)
$2
$3
$20
$11
$11
$30
$15
$3
$2
$19
$12
$39
$6
$5
$3
$16
$6
$34
$16
$21
$34
$20
$21
Owned by Enterprises with:
All
Enter-
prises
0.0%
0.0%
0.1%
0.0%
0.0%
0.5%
0.1%
0.0%
0.1%
0.0%
0.0%
0. 1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.2%
0.1%
0.0%
0.0%
0.0%
0.0%
Ito20
Employees'"
0.2%
0.2%
1.2%
0.3%
0.5%
2.9%
1.2%
0.0%
0.3%
0.7%
0.6%
1.3%
NA
0.9%
0.6%
NA
0.4%
9.4%
0.8%
0.3%
5.7%
1.4%
0.3%
20 to 99
Employees
0.0%
0.0%
0.2%
0.1%
0.1%
0.6%
0.2%
0.1%
0.0%
0.2%
0.3%
0.9%
NA
0.1%
0.0%
NA
0.0%
0.7%
0.5%
0.0%
NA
NA
0.0%
100 to 499
Employees
0.0%
0.0%
0.1%
0.0%
0.0%
0.3%
0.1%
0.1%
0.0%
0.1%
NA
0.2%
NA
0.0%
0.1%
NA
0.0%
NA
NA
0.0%
NA
NA
0.0%
500 to 749
Employees
0.0%
0.0%
0.0%
0.0%
0.0%
0.2%
0.0%
NA
0.0%
NA
NA
NA
NA
0.0%
NA
NA
NA
NA
NA
0.0%
NA
NA
0.0%
750 to 999
Employees
0.0%
0.0%
0.0%
0.1%
0.0%
0.3%
0.0%
NA
0.0%
0.0%
NA
NA
NA
0.0%
NA
NA
NA
NA
NA
NA
NA
NA
NA
1,000 to
1,499
Employees
0.0%
0.0%
0.0%
0.0%
0.0%
0.2%
0.0%
NA
0.0%
NA
NA
0.1%
NA
0.0%
NA
NA
0.0%
NA
NA
NA
NA
NA
NA
(continued)
-------
Table 5-26. Establishment Sales Tests by Industry and Enterprise" Size: Subsequent Year Costs (continued)
Industry
Silicon Carbide
Soda Ash Manufacturing
Titanium Dioxide
Zinc Production
NAICS
327910
3251
325188
3314
SBA Size
(effective
March 11,
NAICS Description 2008)
Abrasive product mfg
Basic chemical mfg 500 to 1,000
All other basic inorganic 1,000
chemical mfg 599
Nonferrous metal (except 750 to 1,000
aluminum) production
& processing
Cost Per
Entity
($/entity)
$9
$15
$9
$8
Owned by Enterprises with:
All
Enter-
prises
0. 1%
0.0%
0.0%
0.0%
Ito20
Employees'"
0.7%
0.4%
0.6%
0.6%
20 to 99
Employees
0.2%
0.1%
0.4%
0.1%
100 to 499
Employees
0.1%
0.0%
0.1%
0.0%
500 to 749
Employees
NA
0.0%
NA
NA
750 to 999
Employees
NA
0.0%
NA
NA
1,000 to
1,499
Employees
NA
0.0%
NA
0.0%
a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control.
The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and
annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition
above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
b Given the Agency's selected thresholds, enterprises with fewer than 20 employees are likely to be excluded from the reporting program.
0 NAICS codes 221 111, 221112, 221113, 221119, 221121, 221122—A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours. NAICS 221210 = 500 employees.
d 500 to 1,500. For NAICS code 324110—For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more
than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as facilities under a
processing agreement or an arrangement such as an exchange agreement or a throughput. The total product to be delivered under the contract must be at least 90% refined by the
successful bidder from either crude oil or bona fide feedstocks.
e NAICS codes 486110 = 1,500 employees; NAICS 486210 = $6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 = $11.5 million annual
receipts.
f Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910—
Environmental Remediation Services:
a) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern must be engaged
primarily in furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to, preliminary assessment,
site inspection, testing, remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated materials, storage of contaminated
materials and security and site closeouts. If one of such activities accounts for 50% or more of a concern's total revenues, employees, or other related factors, the concern's
primary industry is that of the particular industry and not the Environmental Remediation Services Industry.
b) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a contaminated
environment and also the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering),
smaller sub-components of NAICS codes with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as:
Heavy Construction; Special Trade Construction; Engineering Services; Architectural Services; Management Services; Refuse Systems; Sanitary Services, Not Elsewhere
Classified; Local Trucking Without Storage; Testing Laboratories; and Commercial, Physical and Biological Research. If any activity in the procurement can be identified with
a separate NAICS code, or component of a code with a separate distinct size standard, and that industry accounts for 50% or more of the value of the entire procurement, then
the proper size standard is the one for that particular industry, and not the Environmental Remediation Service size standard.
NA: Not available. SUSB did not report the data necessary to calculate this ratio.
-------
The rule also covers sectors that could conceptually include entities owned by small
governments. However, given the uncertainty and data limitations associated with identifying
and appropriately classifying these entities, we computed a "revenue" test for a model small
government, where the annualized compliance cost is a percentage of annual government
revenues (U.S. Census, 2005a and b). For example, from the 2002 Census (in $2006), revenues
for small governments (counties and municipalities) with populations fewer than 10,000 are $3
million, and revenues for local governments with populations fewer than 50,000 is $7 million.
As an upper bound estimate, summing typical per-respondent costs of combustion plus landfills
plus natural gas suppliers yields a cost of approximately $18,000 per local government in the
first year. Thus, for the smallest group of local governments (<10,000 people), cost-to-revenue
ratio would be 0.7%. For the larger group of governments (<50,000 people), the cost-to-revenue
ratio is 0.2%.
5.2.3 Results of Screening Analysis
The Regulatory Flexibility Act generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment rulemaking requirements under the
Administrative Procedure Act or any other statute, unless the agency certifies that the rule will
not have a significant economic impact on a substantial number of small entities. Small entities
include small businesses, small governmental jurisdictions, and small not-for-profit enterprises.
For the purposes of assessing the impacts of the rule on small entities, we defined a small
entity as (1) a small business, as defined by SBA's regulations at 13 CFR Part 121.201; (2) a
small governmental jurisdiction that is a government of a city, county, town, school district, or
special district with a population of less than 50,000; or (3) a small organization that is any not-
for-profit enterprise that is independently owned and operated and is not dominant in its field.
EPA believes the selected thresholds maximize the rule coverage with over 80% of U.S.
emissions reported by approximately 10,152 reporters, while keeping reporting burden to a
minimum and excluding small emitters. Furthermore, many industry stakeholders with whom
EPA met expressed support for a 25,000 metric ton of CC^e threshold because it sufficiently
captures the majority of GHG emissions in the United States while excluding smaller facilities
and sources. For small facilities that are captured by the rule, EPA has simplified emission
estimation methods where feasible (e.g., stationary combustion equipment under a certain rating
can use a simplified mass balance approach as opposed to more rigorous direct monitoring) to
keep the burden of reporting as low as possible. For further detail on the rationale for excluding
small entities through threshold selection, please see the TSD (EPA-HQ-OAR-2008-0508-0046).
5-44
-------
After considering the economic impact of the rule on small entities, EPA has concluded
that this action will not have a significant economic impact on a substantial number of small
entities. As shown in Tables 5-25 and 5-26, the average ratio of annualized reporting program
costs to receipts of establishments owned by model small enterprises was less than 1% for
industries presumed likely to have small businesses covered by the reporting program.
We acknowledge that several enterprise categories have ratios that exceed this threshold
(e.g., enterprise with one to 20 employees). The following enterprise categories have sales test
results between 1% and 3% for entities with less than 20 employees: Pulp & Paper
Manufacturing (322), Cement & Other Mineral Production(327), Primary Metal Manufacturing
(331), Cement (32731), Glass (3272), Lime Manufacturing (327410), Nitric Acid (325311),
Phosphoric Acid (325312), and Pulp & Paper—Pulp Mills (322110).
Below we take a more detailed look at the categories noted above as having sales test
ratios above 1%. EPA collected information on the entities likely to be covered by the rule for
the hybrid 25,000 ton threshold as part of the expert sub-group process. This can be broken down
by a more detailed threshold-based analysis and a more detailed employee-based analysis.
5.2.3.1 Threshold-based Analysis of Categories Having Sales Test Ratios Above 1%
Cement (32731)
Comparing facility counts in the rule with Census data can be misleading. The Census
data almost without exception include a larger number of "establishments" than we know to be
manufacturing the product, based on EPA bottom up industry analyses. For example, the 2002
Economic Census suggests that for cement there are 246 establishments, however, according to
the Portland Cement Association Plant Information Summaries, there are 107 Portland cement
facilities manufacturing cement, and these are the facilities for inclusion in the rule. The
differences between the Census and the industry publications may be due to the way in which
Census defines an "establishment." For example, one cement facility, as identified by the PCA
that crosses several miles, may actually be multiple "establishments" according to Census.
The cement facilities for inclusion in the rule would be the largest facilities as identified
by the Census. This can be seen through a comparison of the value of shipments (i.e., the value
of cement produced). Greater than 96% of the product is produced by facilities with more than
20 employees. Further, all facilities cross a 25,000 mtCO2 threshold; all but one exceed a
100,000 mtCO2 threshold.
5-45
-------
Lime (327410)
Data on the number of lime facilities comes from the USGS Directory of Lime Plants in
the United States in 2005 (USGS 2006). The Census data identifies fewer lime facilities, likely
because of the differences in defining a lime facility. Some facilities produce just lime and they
can be easily identified as part of the lime manufacturing industry. However, a number of
facilities produced lime as an intermediate product, which is then used as an input to the final
product (this also happens in the iron and steel industry and pulp and paper). Lime has very
similar characteristics to cement described above, because of similar manufacturing processes.
Glass (3272)
For the glass industry, 55 facilities are above a 25,000 ton CC^e threshold. All of these
facilities are from companies with over 20 employees. All but three facilities are from companies
with greater than 100 employees. Data for the glass industry were based on the Glass Factory
Directory 2004 (GFD 2004) and EPA's National Emissions Inventory (NEI) 1998 (EPA 2002).
Nitric Acid (325311). Phosphoric Acid (325312). Iron and Steel (331112)
There are 45 nitric acid facilities based on a bottom-up industry database under
development by EPA. This dataset shows that all of these facilities are from companies with over
20 employees. All but two facilities are from companies with greater than 100 employees.
Similarly, there are 14 phosphoric acid facilities, all of which are from companies with over 20
employees. There are 121 iron and steel facilities that exceed the 25,000 metric ton threshold
(130 total) based on the same database. All of these facilities are from companies with over 20
employees. Three facilities have fewer than 500 employees.
Pulp and Paper (322/322110)
The pulp and paper industry encompasses over 5,000 facilities. The thresholds in this rule
are expected to include less than 10% of the total industry. The rule would cover about 425 of
the most emissions intensive facilities. Considering that emissions may be assumed to be
positively correlated to number of employees, it is highly likely that these facilities are all over
100 employees. According to the Census, about 27% of facilities are over 100 employees.
According to the preamble all 425 facilities exceed all reviewed thresholds, including 100,000
mtCO2e.
5-46
-------
Zinc Production (3314)
For the zinc industry, there are 5 facilities that exceed the 25,000 ton threshold. These
facilities are from companies with greater than 500 employees. Data for on the number of zinc
facilities and production capacity at these facilities were based on the US Geologic Survey
Mineral Yearbook: Annual Zinc Report and other publicly available information from zinc
producers.
5.2.3.2 Employee-based Analysis of Categories Having Sales Test Ratios Above 1%
Two recent studies by the Pew Center on Global Climate Change and the Nicholas
Institute for Environmental Policy Solutions at Duke University (Pew, 2002; Nicholas Institute,
2008) show there is a recognized positive correlation between GHG emissions and the number of
employees: the largest facilities will have the largest amount of emissions. A number of studies
use the number of employees to help quantify emissions. According to these studies, most small
manufacturers do not burn sufficient fuel to cross a 10,000 metric ton CC^e threshold. By the
time a facility uses sufficient energy to exceed these types of thresholds, they are large.
According to the Nicholas Institute study, "If the facility has fewer than 50 employees,
and no smoke-stack, it will be virtually guaranteed safe passage around any reporting
requirement, regardless of what the industry may be. The vast majority of manufacturing
industries are not expected to cross a 10,000-ton reporting threshold until the employee count is
in the hundreds" (Nicholas Institute, 2008). The final conclusion of this study was that a 10,000
ton threshold for participation would focus on large industry, and would not directly impact the
majority of small and medium-sized businesses. Therefore, it is a reasonable assumption that the
25,000 ton CO26 would include relatively few small entities. This is confirmed by the threshold
analysis discussed [above], which found that small production facilities are largely exempt from
the rule.
As shown in Table 5-27, the screening analysis suggested several sectors may have 1% to
3% cost-to-receipt ratios for model establishments owned by businesses with less than 20
employees. To assess the likelihood that these small businesses would be covered by the rule, we
performed several case studies for manufacturing industries where the cost-to-receipt ratio
exceeded 1% (see Table 5-27). For each industry, we used and applied emission data from a
recent study examining emission thresholds (Nicholas Institute, 2008). This study provides
industry-average CC>2 emission rates (e.g., tons per employee) for the manufacturing industries
that correspond to the industries listed in Table 5-22.
5-47
-------
Table 5-27. Case Studies of Manufacturing Industries to Determine the Likelihood of
Small Businesses Would Be Covered by the Rule
327310
3272
3314
327410
325311
325312
322110
NAICS Description
Cement mfg
Glass & glass
product mfg
Nonferrous metal
(except
aluminum)
production &
processing
Lime mfg
Nitrogenous
fertilizer mfg
Phosphatic fertilizer
mfg
Pulp mills
SBA Size
Standard
(effective
March 11,
2008)
750
500 to 1,000
750 to 1,000
500
1,000
500
750
Average Cost
Per Entity
(Sl,000/entity)
$63
$8
$10
$60
$20
$60
$20
Cost-to Receipt
Ratio for an
Establishment
Owned By an
Enterprise with 1
to 20 Employees
2.05%
1.37%
0.64%
16.48%
1.01%
10.05%
1.40%
Emissions
Per
Employee
(metric tons)
1,631
258
65
4,124
Facility
measure used
Facility
measure used
Facility
measure used
Average
Annual
Facility
Emissions
(metric
tons)3
32,620
5,160
1,300
82,480
2,151
2,200
1,235
Emission
Data Source:
Duke
University
(2008)
p.53
p.52
p.57
p.53
p.48
p.48
p.39
aln cases where an emission rate was reported (tons per employee), we multiplied this rate by 20 employees to estimate annual
emissions. In cases where the appropriate emissions rate was not available, we used the reported annual emissions for an
establishment with 50 or fewer employees.
As shown in Table 5-27, there are two industries (cement and lime manufacturing) where
emission rates suggest small businesses with less than 20 employees could potentially be covered
by the rule. As a result, EPA examined in more detail screening analysis using small business
information compiled from the latest EPA analyses for these industries (EPA, 2003; RTI, 2008).
In these analyses, the cement and lime plants' corporate structures are carefully examined and
their ultimate parent companies were identified using industry surveys and the latest private
databases such as Dun & Bradstreet. For the Portland cement industry, four ultimate parent
companies are classified as small using the SBA firm size standards. The smallest company has
one plant and reported revenues of approximately $26 million. Using the average entity cost of
$65,000, the cost-sales ratio is less than 1%. For the lime manufacturing industry, 19 ultimate
parent companies were classified as small using the SBA firm size standards. The smallest
company has one plant and reported revenues of approximately $7 million. Using the average
entity cost of $60,000, the cost-sales ratio is also less than 1%.
Additional analysis for a model small government also showed that the annualized
reporting program costs were less than 1% of revenue. These impacts are likely representative of
5-48
-------
ratios in industries where data limitations do not allow EPA to compute sales tests (e.g., general
stationary combustion and manure management).
Although this rule would not have a significant economic impact on a substantial number
of small entities, the Agency nonetheless tried to reduce the impact of this rule on small entities,
including seeking input from a wide range of private- and public-sector stakeholders. When
developing the rule, the Agency took special steps to ensure that the burdens imposed on small
entities were minimal. The Agency conducted several meetings with industry trade associations
to discuss regulatory options and the corresponding burden on industry, such as recordkeeping
and reporting. The Agency investigated alternative thresholds and analyzed the marginal costs
associated with requiring smaller entities with lower emissions to report. The Agency also
selected a hybrid method for reporting, which provides flexibility to entities and helps minimize
reporting costs. A final summary of the emissions covered and the costs imposed by this rule is
provided in Table 5-28. As this table indicates, the total national emissions covered under the
rule are 3.9 billion MtCO2e, total capital costs for the rule are approximately $47 million, and
the national annualized cost for the rule in the first year is approximately $116 million.
5-49
-------
Table 5-28. Estimated Emissions and Costs by Subpart (2006$)
Subpart A — General Provisions
Subpart B — Electricity Use
Subpart C — General Stationary Fuel
Combustion Sources
Subpart D — Electricity Generation
Subpart E — Adipic Acid Production
Subpart F — Aluminum Production
Subpart G — Ammonia Manufacturing
Subpart H — Cement Production
Subpart K — Ferroalloy Production
Subpart N — Glass Production
Subpart O— HCFC-22 Production
Subpart P — Hydrogen Production
Subpart Q — Iron and Steel Production
Subpart R — Lead Production
Subpart S — Lime Manufacturing
Subpart U — Miscellaneous Uses of
Carbonates
Subpart V — Nitric Acid Production
Subpart X — Petrochemical Production
Subpart Y — Petroleum Refineries
Subpart Z — Phosphoric Acid Production
Subpart AA — Pulp and Paper
Manufacturing
Subpart BB — Silicon Carbide Production
Subpart CC — Soda Ash Manufacturing
Subpart EE — Titanium Dioxide
Production
Subpart GG — Zinc Production
Subpart HH— Landfills
Subpart JJ — Manure Management
Subpart LL — Suppliers of Coal-based
Liquid Fuels & Subpart MM — Suppliers
of Petroleum Products
Subpart NN — Suppliers of Natural Gas
and Natural Gas Liquids
Subpart OO — Suppliers of Industrial
Greenhouse Gases
Subpart PP — Suppliers of Carbon
Dioxide (CO2)
Subpart QQ — Motor Vehicle and Engine
Manufacturers
Coverage Determination Costs for
Non-Reporters
Total
Downstream
Emissions
Estimates
(millions of
MtC02e)a
0.0
0.0
220.0
2,262.0
9.3
6.4
12.9
86.8
2.3
2.2
13.8
15.0
85.0
0.8
25.4
0.0
17.7
54.4
204.7
3.8
57.7
0.1
3.1
3.7
0.8
91.1
4.5
643.4
N/A
3,827.1
% of Total
Emissions
0%
0%
6%
59%
0%
0%
0%
2%
0%
0%
0%
0%
2%
0%
1%
0%
0%
1%
5%
0%
2%
0%
0%
0%
0%
2%
0%
0%
0%
17%
0%
N/A
Total
Capital
Costs
(Smillions)
0.0
0.0
10.5
0.0
0.0
0.0
0.0
5.4
0.0
0.0
0.0
0.0
0.0
0.0
4.9
0.0
0.2
0.0
1.6
0.8
14.8
0.0
0.0
0.0
0.0
1.3
<0.1
0.0
0.0
0.0
0.0
0.0
39.6
% of Total
Capital
Costs
0%
0%
27%
0%
0%
0%
0%
14%
0%
0%
0%
0%
0%
0%
12%
0%
1%
0%
4%
2%
38%
0%
0%
0%
0%
3%
0%
0%
0%
0%
0%
0%
100%
Total First
Year
Annualized
Costs"
(Smillions)
$0.0
$0.0
$25.8
$3.3
$0.1
$0.2
$0.4
$6.8
$0.1
$0.5
$0.0
$0.4
$3.7
$0.1
$5.3
$0.0
$0.9
$2.2
$6.1
$0.8
$8.6
$0.0
$0.1
$0.1
$0.1
$12.4
$0.3
$3.7
$6.8
$0.5
$0.0
$8.6
$17.2
$115.0
% of Total
First Year
Costs
0%
0%
22%
3%
0%
0%
0%
6%
0%
0%
0%
0%
3%
0%
5%
0%
1%
2%
5%
1%
8%
0%
0%
0%
0%
11%
0%
3%
6%
0%
0%
7%
15%
100%
Emissions from upstream facilities are excluded from these estimates to avoid double counting.
5-50
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SECTION 6
BENEFITS REVIEW
6.1 Synopsis
The mandatory GHG reporting rule will collect and verify emissions data from facilities
and make the information publicly available. This section reviews the benefits of mandatory
reporting programs based on previous experience with emissions inventory programs in the
United States and abroad.
Recent policy discussions have highlighted potential benefits to society of the mandatory
GHG reporting program (Pew, 2008). Benefits to the public include building public confidence
through clear and transparent emission measures and reports and the ability of the public to make
facilities accountable for their emissions. A GHG reporting system will also have the benefit of
providing policy makers and analysts with a data set that is comprehensive and reduces the
potential for policy bias due to non-reporting by certain sectors.18 Benefits to industry include the
identification of cost-effective GHG reduction opportunities and disclosure that provides firms
with incentives to reduce emissions voluntarily, and provides emissions data to service
industries, such as insurance and financial markets. Availability of emissions information to the
public, consumers, investors, corporations and government regulators provides a sound basis for
future policy analysis. This benefits society as a whole. Accurate and transparent information is
necessary for the implementation of efficient approaches that meet environmental goals with the
lowest cost to the economy.
6.2 Background
6.2.1 Background on Existing GHG Reporting Rules
Currently, there are a variety of reporting programs in the United States. The U.S. Acid
Rain Program requires electricity-generating units that are regulated for 862 to also report CC>2
emissions. In addition, there are a variety of mandatory state-level programs in 12 states, such as
Maine, New Jersey, Connecticut, California, New Mexico, Nevada, and Oregon. A number of
voluntary corporate-level systems exist as well, including Climate Leaders, the California
Climate Action Registry, and 1605(b) program. These programs were designed for many
different purposes and are not harmonized. These efforts also may not provide a sufficient basis
for future federal GHG reduction policies, because their systems do not provide a comprehensive
and coherent picture of all GHG emission sources at the facility level. The majority of emissions
18The rule has broad coverage of GHG emitting sectors, but does exclude sectors such as international bunker fuels,
enteric fermentation, wastewater treatment, among other smaller sources and sinks.
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in the United States are not tracked under these systems. The federal mandatory reporting system
would build upon these efforts and provide policy makers with data to inform future national
climate policies.
6.2.2 Benefits Analysis Methodology
This section describes the benefits of a mandatory reporting system. Because quantifying
the benefits of a policy that monitors but does not reduce GHG emissions would be very
difficult, the benefits laid out in this chapter are strictly qualitative. This qualitative review is
based on a systematic literature review of previous mandatory reporting systems, voluntary
reporting systems, and a sampling of emissions reduction policies with and without mandatory
reporting. Ideally, empirical estimates of the accrued benefits from access to information based
on pollution registries would be used to estimate the benefits of the greenhouse gas registry.
While the academic literature provides robust estimates for the benefits of policies which reduce
pollution directly, it provides little empirical data of the benefits of reporting emissions data.
Benefit studies of environmental information disclosure focus primarily on the structure or
rationale for examining the benefits of information disclosure (Beierle, 2003). Therefore, this
study focuses on a qualitative review of the benefits of a greenhouse gas reporting policy.
The purpose of this qualitative literature review is to relate the ongoing policy dialogue
about reporting systems and past policies to the mandatory GHG reporting rule. This literature
reviews current air pollution and toxic emission reporting rules and their outcomes on
stakeholders, while acknowledging that the differences between these pollutants and greenhouse
gases are significant.19 The following is a description of all benefits discussed in the academic
literature of a pollution reporting rule.
6.3 Discussion of Benefits
6.3.1 Benefits of a Mandatory Program
A mandatory GHG emissions reporting system would enable the creation of a
comprehensive, accessible database. Such a database would yield benefits to society in myriad
ways by lowering the information costs associated with determining emissions. Both the
Organization for Economic Co-Operation and Development (OECD) (2005) and the EPA (2003)
have documented ways in which the public, industry, government, investment community and
academic community have utilized pollutant release and transfer registers (PRTRs) to
accomplish tasks that would be costly or unattainable without such available information. Below,
19See World Bank (2000) for a discussion of the main advantages and disadvantages of using information disclosure
as a policy tool generally.
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the benefits of uses relevant to a GHG emissions reporting system are explored qualitatively for
the respective stakeholder groups.
6.3.2 Benefits to the Public
6.3.2.1 Policy Development
The greatest benefit of mandatory reporting of industry GHG emissions to government
would be realized in developing future GHG policies. For example, in the European Union's
Emissions Trading Scheme (ETS), a lack of accurate monitoring at the facility level before
establishing CC>2 allowance permits resulted in allocation of permits for emissions levels an
average of 15% above actual levels in every country except the United Kingdom. Consequently,
the allowance market experienced a price drop when the first year of emissions data were
published (Bailey, 2007). The U.S. mandatory reporting rule would creates a foundation of
reliable baseline emission estimates for the purpose of informing future policies and avoiding
unexpected consequences of those policies.
6.3.2.2 Builds Public Confidence and Trust
A mandatory reporting system will increase transparency of facility emissions data. A
qualitative study in the United Kingdom compared similar communities surrounding chemical
complexes with and without right-to-know laws, and found that the community with the right-to-
know law and corresponding available data on toxic emissions experienced increased levels of
trust towards government and industry to ensure the environmental protection and public health
(Gouldson, 2004). While greenhouse gases do not immediately and acutely affect human health
like toxics, increased environmental stewardship is becoming a higher priority among Americans
(PEW, 2007). Public confidence in understanding and addressing climate change if necessary is
expected to increase with a transparent accounting of GHG emissions.
6.3.2.3 Direct Actions
Transparent, public data on emissions allows for accountability of polluters to the public
stakeholders who bear the cost of the pollution. Citizens, community groups and labor unions
have made use of data from PRTRs to negotiate directly with polluters to lower emissions,
circumventing greater government regulation. There are several examples in the literature of
environmental organizations and community groups negotiating with facilities directly based on
their publicly available pollution data (EPA, 2003). While many of these groups were local,
grassroots organizations, focused geographically on environmental health issues, it is likely that
environmental organizations focused on climate change will use the data in a similar manner.
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The Mandatory Reporting Rule for GHG emissions would allow groups interested in pressuring
industry to reduce their emissions to negotiate with the top emitters.
6.3.2.4 Voluntary Programs
Voluntary agreements to promote energy efficiency in industry or promote specific types
of technologies are used widely in the industrial sector. The U.S. government currently has
several ongoing voluntary programs to help reduce GHGs including, the Voluntary Aluminum
Industrial Partnership to reduce perfluorocarbon (PFC) emissions, and the Landfill Methane
Outreach Program, the Coal Mine Methane Outreach Program, Natural GasStar and AgStar
which promote the capture-and-use of methane in these sectors. In addition, some industries have
voluntary plans or roadmaps to help the industry achieve an emissions reduction goal. The
American Iron and Steel Institute introduced an energy efficiency goal and a research and
development plan for the industry.
While no study has been done on whether or not voluntary programs with mandatory
reporting are more effective than those without, evaluations of several major voluntary programs
have noted that need for a strong reporting mechanism is necessary (Worrell and Price, 2001). A
transparent reporting system increases the credibility of the voluntary program and the reductions
attributed to the program. A standardized reporting system also allows program mangers to
readjust the programs strategy to meet the evolving needs of a program. In the case of the GHG
reporting rule, the data collected would help evaluate the achievements of the current programs
and provide verification of voluntary actions by industry, strengthening the effectiveness of the
programs.
6.3.2.5 Consumers of GHG-Intensive Goods and Labeling
Publicly available emissions data would allow individuals to alter their consumption
habits based on the GHG emissions of producers. Green labeling programs may use the verified
GHG emissions data from this mandatory rule to provide comprehensive information to the
public, particularly on durable goods such as appliances, electronics, etc. However, as with all
eco-labeling projects, the process takes a committed effort to build recognition and market
products as having a low carbon footprint.20 Uncertainty over the willingness to pay for low
carbon products makes this benefit to consumers difficult to predict.
20For a thorough review of evaluations conducted for eco-labeling programs, see Thogerson, 2002.
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6.3.3 Benefits to Industry and Investors
6.3.3.1 Public Relations
For industrial sources, one benefit of GHG emissions monitoring is the value of having
independent, verifiable data to present to the public to demonstrate appropriate environmental
stewardship. For example, General Motors issues its Corporate Responsibility and Sustainability
Report, which makes use of TRI data and the Canadian National Pollutant Release Inventory to
support its environmental achievements. Such monitoring also allows for inclusion of
standardized GHG data into environmental management systems (EMS), providing the necessary
information to achieve and disseminate their environmental achievements. Using data from a
verified, standard methodology as under the GHG reporting rule gives the facilities credibility
when claiming environmental improvements. Hamilton (1995) and Konar and Cohen (1997) are
two examples of empirical studies that have investigated how the TRI has affected firm behavior
and stock market valuation. Hamilton (1995) finds a stock price return of-0.03% due to TRI
release. Firms that experienced the largest drop in their stock prices also reacted by reducing
their reported emissions most in subsequent years.
6.3.3.2 Standardization
Once industrial facilities invest in the institutional knowledge and systems to report
emissions, the cost of monitoring should fall and the accuracy of the accounting should improve.
A standardized reporting program will also allow for facilities to benchmark themselves against
similar facilities to understand better their relative standing within their industry.
6.3.3.3 Potential Cost Savings
Mandatory reporting of GHG emissions could illuminate previously unmeasured wasteful
industrial processes, yielding cost-saving conservation measures that would offset some of the
costs associated with the monitoring. Acushnet Rubber Company, Inc. saves approximately
$100,000 annually after eliminating use of the potential carcinogen trichloroethylene, identified
using TRI, from its facility as part of its EMS (EPA, 2007). Under a mandatory reporting rule for
GHG emissions, facilities may discover their facilities could feasibly install cost saving,
emission reduction technologies such as energy efficiency improvements, co-generation
opportunities, or methane capture-and-use technologies.
6.3.3.4 Data Valuable to Service Industries
In addition to the benefits for the industrial facilities being monitored, the data can be
valuable to companies doing business with GHG-emitting firms. Firms have sold pollution-
prevention technologies to customers found using TRI data (Pew, 2008). In addition, insurance
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companies may find these data valuable in assessing risk. In general, improved information
lowers search and transaction costs for providers of mitigation products and services.
6.3.4 Reducing Uncertainty: Benefits to all Stakeholders
Reducing uncertainty in GHG emission estimates is an underlying benefit that increases
benefits to all stakeholders. Policy development, direct action by the public and consumers,
standardization, and reliable data for firms, shareholders and service industries to use in
decision-making all require certainty in emission estimates in order to make environmentally
sound and cost-effective decisions. Increased certainty in the emission estimates facilitates the
comparison across reduction options, companies and sectors where different data or approaches
have been used. Some emission sources covered under this rule are more uncertain than others
because of the nature of the greenhouse gas generation (biological vs. chemical reaction) and the
lack of basic data collection (i.e., the amount and content of waste being disposed at each
landfill). Finalizing this rule will increase the certainty of these emissions due to increased
information about each source and may spur additional research into sources that are not as well
understood or documented (IIASA, 2007).
In addition, increased certainty in emission estimates increase the probability that
commitments to reductions have been credibly met. This allows for a stable emissions trading
market, whether voluntary or mandatory, and reinforces the credibility of an emissions credit.
Without increased certainty within a sector, company or a specific project, the emission credit
produced may be considered risky and not trade for full value. Increasing the certainty of each
credit benefits the buyer, the seller, and the overall market place (PWC, 2007).
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SECTION 7
STATUTORY AND EXECUTIVE ORDER REVIEWS
This section describes EPA's compliance with several applicable executive orders and
statutes during the development of the mandatory GHG reporting rule.
7.1 Executive Order 12866: Regulatory Planning and Review
Under Section 3(f)(l) of Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is an "economically significant regulatory action" because it is likely to have an annual
economic effect of $100 million or more. EPA's cost analysis, presented in Section 4, estimates
that under the regulatory option, the total annualized cost of the rule will be approximately $132
million during the first year of the program and $89 million in subsequent years (including $17
million of programmatic costs to the Agency). Accordingly, EPA submitted this action to the
Office of Management and Budget (OMB) for review under Executive Order 12866, and any
changes made in response to OMB recommendations have been documented in the docket for
this action.
In addition, EPA prepared this RIA, an analysis of the potential costs and benefits
associated with this action. In this report, EPA has identified the regulatory options considered,
their costs, the emissions that would likely be reported under each option, and explained the
selection of the option chosen for the rule. The costs of the rule are reported in Section 4. In
addition, EPA has conducted a qualitative assessment of the benefits of the rule, which are
reported in Section 6. Overall, EPA has concluded that the costs of the mandatory GHG
reporting rule, while substantial, are outweighed by the potential benefits of more comprehensive
information about GHG emissions.
7.2 Paperwork Reduction Act
The information collection requirements in this rule have been submitted for approval to
the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C.
3501 et seq. The information collection requirements are not enforceable until OMB approves
them.
EPA plans to collect complete and accurate economy-wide data on facility-level GHG
emissions. Accurate and timely information on GHG emissions is essential for informing future
climate change policy decisions. Through data collected under this rule, EPA will gain a better
understanding of the relative emissions of specific industries, and the distribution of emissions
from individual facilities within those industries. The facility-specific data will also improve our
7-1
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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 industries and facilities within industries 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 industries would be affected, and
how these industries would be affected by the options.
This information collection is mandatory and will be carried out under CAA Sections 114
and 208. Information identified and marked as Confidential Business Information (CBI) will not
be disclosed except in accordance with procedures set forth in 40 CFR Part 2. However,
emissions information collected under CAA Sections 114 and 208 generally cannot be claimed
as CBI and will be made public.21
The projected cost and hour respondent burden in the ICR is $86.3 million and 1.21
million hours per year. The estimated average burden per response is 2 hours; the frequency of
response is annual for all respondents that must comply with the rule's reporting requirements,
except for electricity-generating units that are already required to report quarterly under 40 CFR
Part 75 (ARP); and the estimated average number of likely respondents per year, excluding 43
federal facilities, is 16,725.22 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 $9.1 million per year) a total operation and maintenance component
(averaging $11.0 million per year), and a labor cost component (averaging $66.1 million per
year). Burden is defined at 5 CFR Part 1320.3(b). These cost numbers differ from those shown
elsewhere in the RIA because ICR costs represent the average cost over the first three years of
the rule, but costs are reported elsewhere in the RIA for the first year of the rule and for
subsequent years of the rule. Also, the total cost estimate of the rule in the RIA includes the cost
to the Agency to administer the program. The ICR differentiates between respondent burden and
cost to the Agency.
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,
February 21, 1991). As discussed in Section II.R of the preamble to the rule, EPA will be initiating a separate
notice and comment process to make CBI determinations for the data collected under this rulemaking.
22 EPA estimates that 30,000 facilities are potentially affected. Of these, EPA estimates that 10,152 facilities across
various sectors will be over their sector-specific reporting threshold and thus required to report; the remaining
19,848 will determine during the first year that they are beneath the threshold and do not need to report. The
average number of respondents is thus (30,000+10,152+10,152)73 = 16,768; excluding 43 Federal facilities, the
number of private respondents is 16,725.
7-2
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An agency may not conduct or sponsor, and a person is not required to respond to, a
collection of information unless it displays a currently valid OMB control number. The OMB
control numbers for EPA's regulations in 40 CFR are listed in 40 CFR Part 9. When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the
Federal Register to display the OMB control number for the approved information collection
requirements contained in the final rule.
7.3 Regulatory Flexibility Act
The Regulatory Flexibility Act generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment rulemaking requirements under the
Administrative Procedure Act or any other statute, unless the agency certifies that the rule will
not have a significant economic impact on a substantial number of small entities. Small entities
include small businesses, small governmental jurisdictions, and small not-for-profit enterprises.
For the purposes of assessing the impacts of the rule on small entities, we defined a small
entity as (1) a small business, as defined by SBA's regulations at 13 CFR Part 121.201; (2) a
small governmental jurisdiction that is a government of a city, county, town, school district, or
special district with a population of less than 50,000; or (3) a small organization that is any not-
for-profit enterprise that is independently owned and operated and is not dominant in its field.
For affected small entities, EPA conducted a screening assessment comparing
compliance costs for affected industry sectors to industry-specific receipts data for
establishments owned by small businesses. This ratio constitutes a "sales" test that computes the
per-entity annualized compliance costs of this rule as a percentage of sales and determines
whether the ratio exceeds some level (e.g., 1% or 3%).23 The cost-to-sales ratios were
constructed at the establishment level (average reporting program costs per
establishment/average establishment receipts) for several business size ranges. This allowed EPA
to account for receipt differences between establishments owned by large and small businesses
and differences in small business definitions across affected industries. EPA used average per-
entity annualized costs for each industry sector, which tends to overstate costs incurred by the
smallest entities. The results of the screening assessment are reported in Section 5 (Tables 5-25
and 5-26). The cost-to-sales ratios are less than 1% for establishments owned by small
businesses that EPA considers most likely to be covered by the reporting program (e.g.,
establishments owned by businesses with 20 or more employees). The screening analysis thus
23EPA's Regulatory Flexibility Act (RFA) guidance for rule writers suggests the "sales" test continues to be the
preferred quantitative metric for economic impact screening analysis.
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indicates that the rule will not have a significant economic impact on a substantial number of
small entities. The screening assessment for small governments compared the sum of average
costs of compliance for combustion, local distribution companies, and landfills to average
revenues for small governments. Even for a small government owning all three source types, the
costs constitute less than 1 percent of average revenues for the smallest category of governments
(those with fewer than 10,000 people).
For several source categories, enterprises with fewer than 20 employees have cost-to-
sales ratios exceeding 1%. EPA examined these in greater detail, and concluded that few if any
firms with fewer than 20 employees would be subject to the rule; of those that might be subject
to the rule, firm-specific sales data indicate that cost-to-sales ratios would be below 1%. Thus,
EPA's screening assessment indicates that the rule will not have a significant impact on a
substantial number of small entities.
Although this rule will not have a significant economic impact on a substantial number of
small entities, EPA nonetheless took several steps to reduce the impact of this rule on small
entities. For example, EPA determined appropriate thresholds that reduce the number of small
businesses reporting. In addition, EPA is not requiring facilities to install CEMS if they do not
already have them. Facilities without CEMS can calculate emissions using readily available data
or data that is less expensive to collect, such as process data or material consumption data. For
some source categories, EPA developed tiered methods that have options for smaller entities that
are simpler and less burdensome. Also, EPA is requiring annual reporting instead of more
frequent reporting.
Through comprehensive outreach activities, EPA held approximately 100 meetings
and/or conference calls with representatives of the primary audience groups, including numerous
trade associations and industries that include small business members For a full list of
organizations EPA met with when developing this rule please see the memo found at EPA-HQ-
OAR-2008-0508-055.
On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting rule. EPA held two
public hearings, and received over 16,000 written public comments. The public comment period
ended on June 9, 2009.
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 3,500 people
and 100 groups between proposal signature (March 10, 2009) and the close of the comment
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period (June 9, 2009). Details of these meetings are available in the docket (EPA-HQ-OAR-
2008-0508)
7.4 Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104-4, establishes
requirements for federal agencies to assess the effects of their regulatory actions on state, local,
and tribal governments and the private sector. Under Section 202 of the UMRA, EPA generally
must prepare a written statement, including a cost-benefit analysis, for final rules with "federal
mandates" that may result in expenditures to state, local, and tribal governments, in the
aggregate, or to the private sector, of $100 million or more in any one year. Before promulgating
an EPA rule for which a written statement is needed, Section 205 of the UMRA generally
requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective, or least burdensome alternative that achieves the objectives
of the rule. The provisions of Section 205 do not apply when they are inconsistent with
applicable law. Moreover, Section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective, or least burdensome alternative if the Administrator publishes, with
the final rule, an explanation of why that alternative is not being adopted. Before EPA
establishes any regulatory requirements that may significantly or uniquely affect small
governments, including tribal governments, it must develop a small government agency plan
under Section 203 of the UMRA. The plan must provide for notifying potentially affected small
governments; enabling officials of affected small governments to have meaningful and timely
input in developing EPA regulatory proposals with significant federal intergovernmental
mandates; and informing, educating, and advising small governments on compliance with the
regulatory requirements.
EPA has determined that this rule contains a federal mandate that may result in
expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, or
the private sector in any one year. Accordingly, EPA has prepared, under Section 202 of the
UMRA, a written statement that is presented below. The statement addresses the following
items:
1. The authorizing legislation (7.4.1).
2. Benefit-cost analysis, including an analysis of the distribution of costs among
ownership types, sectors of the economy, and regions of the country; and an
assessment of the extent to which the costs of state, local, and tribal governments
could be paid for by the federal government (Section 4.1, Section 5, and
Section 7.4.2).
7-5
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3. Estimates of future compliance costs and disproportionate budgetary effects
(Section 4.1,7.4.3).
4. Macroeconomic impacts (Section 7.4.4).
5. A summary of EPA's consultation with state, local, and tribal governments and their
concerns, including a summary of the Agency's evaluation of those comments and
concerns (Section 2.3.4, Section 7.4.5).
6. Identification and consideration of regulatory alternatives and the selection of the
least costly, most cost-effective, or least burdensome alternative that achieves the
objectives of the rule (Section 4.4, Section 7.4.6).
7.4.1 Authorizing Legislation
On December 26, 2007, President Bush signed the FY2008 Consolidated Appropriations
Amendment, which authorized funding for the U.S. Environmental Protection Agency (EPA) to
develop and publish a draft rule on an accelerated schedule:
[N]ot less than $3,500,000 shall be provided for activities to develop and publish
a draft rule not later than 9 months after the date of enactment of this Act, and a
final rule not later than 18 months after the date of enactment of this Act, to
require mandatory reporting of GHG emissions above appropriate threshold in all
sectors of the economy.
The accompanying explanatory statement stated that EPA shall "use its existing authority
under the Clean Air Act" to develop a mandatory GHG reporting rule.
The agency is further directed to include in its rule reporting of emission resulting
from upstream production and downstream sources, to the extent that the
Administrator deems it appropriate. The Administrator shall determine
appropriate thresholds of emissions above which reporting is required, and how
frequently reports shall be submitted to EPA. The Administrator shall have
discretion to use existing reporting requirements for electric generating units
under Section 821 of the Clean Air Act.
EPA has developed this regulation under authority of Sections 114 and 208 of the Clean
Air Act. The required activities under this federal mandate include monitoring, recordkeeping,
and reporting of GHGs.
7.4.2 Benefit-Cost Analysis
EPA has considered the costs and benefits of the GHG reporting rule. The engineering
costs of the rule for both stationary sources and mobile sources are described in Section 4. Costs
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for stationary sources, excluding EPA's programmatic costs, are estimated to be approximately
$106 million in the first year; for subsequent years, costs for stationary sources are estimated to
be approximately $64 million. For mobile sources, the costs are estimated to be approximately
$9 million for the first year and for subsequent years.
7.4.2.1 Distribution of Costs
Costs were estimated for each of the subparts of the rule, which include stationary
combustion, electricity generation, various industrial processes and biological processes, as well
as mobile sources. Among the various subparts of the rule, most affect only privately owned
sources. The exceptions are stationary combustion, landfills, electricity generators, and natural
gas suppliers, or local distribution companies (LDCs).
Table 7-1 presents the distribution of ownership (private owners and state, local, and
tribal government owners) for the sectors that include both privately owned and publicly owned
facilities. EPA estimated the number of landfills, stationary combustion facilities, electric
generation units, and LDCs that are privately owned, owned by state, local, or tribal
governments, or federally-owned; based on these estimates, EPA estimated the corresponding
costs associated with each subpart for each owner category. Information on landfill ownership
was identified from a database created by EPA's Landfill Methane Outreach Program. Data on
Subpart C and D Electricity Generating Units and Cogeneration Facilities was obtained from a
proprietary commercial database maintained by Ventyx, Inc. and purchased by EPA. Data on
LDC ownership was obtained from the Energy Information Administration's "Annual Report of
Natural and Supplemental Gas Supply and Disposition, Form EIA-176". Based on this
information, EPA estimated the share of total costs for each subpart that would be incurred by
each owner category, as shown in Table 7-1.
This regulation applies directly to both public- and private-sector facilities that directly
emit GHGs and to those that supply fuel or chemicals that emit GHGs when used. However, this
rule does not impose any implementation responsibilities on state, local, or tribal governments,
and it is not expected to increase the cost of existing regulatory programs managed by those
governments. The rule imposes burdens on state, local, or tribal governments only when they
own affected facilities that must comply with the rule. Overall, EPA estimates that
approximately 2,600 facilities owned by state, local, or tribal governments will be required to
report their greenhouse gas emissions by the rule. EPA estimates that an additional 2,345
facilities owned by state, local, or tribal governments will incur some costs during the first year
of the rule to make a reporting determination and subsequently determine that their emissions are
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Table 7-1. Estimated Private and Government Costs in Selected Sectors (103 $2006)
Public/Private Respondent Breakdown
Costs of private respondents
Costs of state/local/tribal government
(SLTG) respondents
Costs of federal respondents (fed
owned/operated)
Total costs by sector
Landfills
$2,893
$4,843
$83
$7,819
Stationary
Combustion
$19,626
$3,325
$0
$22,951
Electricity
Generation
$2,826
$400
$53
$3,279
LDCs
$599
$1,515
$0
$2,114
Note: Columns may not sum to totals due to rounding.
Sources: Landfills: EPA Landfill Methane Outreach Program (LMOP) database.
Stationary Combustion and Electricity Generation: Ventyx, Inc. Velocity Suite 2008. Proprietary commercial database purchased
by EPA.
LDCs: U.S. Department of Energy. Energy Information Administration. Annual Report of Natrual and Supplemental Gas Supply
and Disposition, Form EIA-176. http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2008/ldc2008/ldc2008.pdf
below the threshold and thus, they are not required to report their emissions. EPA does not
anticipate that substantial numbers of either public- or private-sector entities will incur
significant economic impacts as a result of this rule making. Overall, EPA estimates that for
most sectors, the costs represent at most 0.1% of sales or receipts. Even for small entities, EPA
estimates that the costs are on average less than 0.5% of sales or receipts. The impacts associated
with such costs are not generally considered significant. UMRA requires an analysis of possible
federal assistance to state, local, or tribal governments affected by the rule. Because the rule
imposes no implementation or regulatory responsibilities and only imposes compliance costs on
government-owned GHG emitting facilities, EPA is unaware of any federal assistance available
to these governments to subsidize their compliance costs.
In addition to examining the distribution of ownership between private entities and
governments for these sectors, EPA also examined the distribution of respondents and costs
across industry sectors. Table 7-2 shows the distribution of costs for the first year after
promulgation and for subsequent years for subparts with the highest costs for the 25,000 MT
threshold. Of the $132 million in costs estimated for the first year of the regulation, general
stationary combustion sources account for nearly 20% of national costs. Cement production,
petroleum refineries, landfills, pulp and paper manufacturing, motor vehicle and engine
manufacturers, and suppliers of natural gas and natural gas liquids each represent between 5%
and 10% of national costs. All other sectors account for less than 5% of national costs. In
subsequent years, the overall distribution is similar, although the cost shares of general stationary
combustion, pulp and paper manufacturing, motor vehicle and engine manufacturers, and oil and
natural gas suppliers' increase slightly, while other subparts' shares fall somewhat.
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Table 7-2. National Cost Estimates for Selected Sectors: Recommended Option
($ million)
Sector
Subpart A — General Provisions
Subpart B — Electricity Use
Subpart C — General Stationary Fuel Combustion Sources
Subpart D — Electricity Generation
Subpart H — Cement Production
Subpart Q — Iron and Steel Production
Subpart S — Lime Manufacturing
Subpart X — Petrochemical Manufacturing
Subpart Y — Petroleum Refineries
Subpart AA — Pulp and Paper Manufacturing
Subpart HH— Landfills
Subpart MM — Suppliers of Petroleum Products
Subpart NN — Suppliers of Natural Gas and Natural Gas Liquids
Subpart QQ — Motor Vehicle and Engine Manufacturers
Private Sector, Total
Public Sector, Total
Total
First
Year
$ Share
$25.8
$3.3
$6.8
$3.7
$5.3
$2.2
$6.1
$8.6
$12.4
$3.7
$6.8
$8.6
$115.0
$17.0
$132.0
19%
2%
5%
3%
4%
2%
5%
7%
9%
3%
5%
6%
87%
13%
100%
Subsequent
Years
$ Share
$21.5
$3.3
$4.2
$2.0
$3.0
$1.7
$4.1
$8.6
$5.5
$1.1
$5.0
$8.6
$72.1
$17.0
$89.1
24%
4%
5%
2%
3%
2%
5%
10%
6%
1%
6%
10%
81%
19%
100%
Note: An additional $3.5 million is incurred annually by the public sector during the rulemaking process, which will last between
1 and 2 years.
EPA does not have sufficient information to characterize the regional distribution of
affected sources.
7.4.2.2 Characterization of Benefits of Mandatory Reporting Programs
EPA also examined the benefits of the rule through a qualitative benefits assessment.
EPA conducted a literature review to identify and characterize the benefits of programs that
require mandatory reporting of environmental information. These programs convey benefits to
the public, to investors, to industry, and to government. The benefits, described in Section 6 of
this document, include improved information about GHG emissions that would enhance
America's ability to develop sound future climate policies and that may encourage GHG emitters
to develop voluntary plans to reduce their emissions. Although EPA was unable to quantify or
value these benefits, they may be substantial.
7.4.3 Future Costs and Disproportionate Budget Effects
Although EPA acknowledges that, over time, changes in the patterns of economic activity
may mean that GHG generation, and thus reporting costs, will change, data are inadequate for
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projecting these changes. Thus, EPA assumes that costs averaged over the first three years are
typical of ongoing costs of compliance. EPA estimates that future compliance costs, including
approximately $17.0 million in federal programmatic costs, will total approximately $103
million per year. These costs are broadly distributed to a variety of economic sectors and
represent less than 0.1% of revenues for most affected sectors. Thus, EPA does not believe that
the costs are large enough, in general, to impose disproportionate budgetary effects.
7.4.4 Impacts on the National Economy
EPA estimates that future compliance costs (based on average costs over the first 3 years)
will total approximately $103 million per year. These costs are broadly distributed to a variety of
economic sectors and represent approximately 0.001% of 2008 gross domestic product; overall,
EPA does not believe the rule will have a significant macroeconomic impact on the national
economy.
7.4.5 Consultation with State, Local, and Tribal Governments
Consistent with the intergovernmental consultation provisions of Section 204 of the
UMRA and Executive Order 12875, "Enhancing the Intergovernmental Partnership," EPA
initiated an unprecedented outreach effort with the governmental entities affected by this rule,
including state, local, and tribal officials. The outreach audience included state environmental
protection agencies, regional and tribal air pollution control agencies, and other state and local
government organizations. EPA contacted several states and state and regional organizations
already involved in GHG emissions reporting. EPA also conducted several conference calls with
tribal organizations. For example, EPA staff solicited input and maintained an open door policy
for those interested in discussing the rulemaking. Since January 2008, EPA staff have held more
than 100 meetings with stakeholders, including the following:
• trade associations and firms in potentially affected industries/sectors;
• state, local, and tribal environmental control agencies and regional air quality
planning organizations;
• state and regional organizations already involved in GHG emissions reporting, such
as TCR, CARS, and WCI;
• other federal agencies, such as the U.S. Department of Energy and U.S. Department
of Agriculture, which operate reporting systems relevant to GHG emissions; and
• environmental groups and other nongovernmental organizations.
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,
either at the meetings or by submitting comments. Examples of topics discussed included
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existing GHG monitoring and reporting programs and lessons learned, thresholds and schedules
for reporting, scope of reporting, handling of confidential data, data verification, and the role of
states in administering the program. As needed, the EPA technical workgroups followed up with
these stakeholder groups on a variety of methodological, technical, and policy issues. EPA staff
also provided information to tribes through conference calls with different Indian tribal working
groups and organizations at EPA and through individual calls with tribal board members of TCR.
For a full list of organizations EPA met with when developing this rule please see the
memo found at EPA-HQ-OAR-2008-0508-055.
On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting rule. EPA held two
public hearings, and received over 16,000 written public comments. The public comment period
ended on June 9, 2009.
In addition to the public hearings, EPA had an open door policy, similar to the outreach
conducted during the development of the proposal. As a result, EPA met with over 4,000 people
and 135 groups between proposal signature (March 10, 2009) and the close of the comment
period (June 9, 2009). Details of these meetings are available in the docket (EPA-HQ-OAR-
2008-0508)
7.4.6 Consideration of Regulatory Alternatives
EPA carefully examined regulatory alternatives and selected the lowest cost/least
burdensome alternative deemed by EPA to be adequate to address congressional concerns and to
provide a comprehensive source of information about emissions of GHGs. Section 3 discusses
the recommended option. The evaluation of the alternative and the other alternatives considered
is described in Section 4.
As described above, EPA evaluated a variety of options for each dimension of the GHG
reporting program, and selected a preferred or recommended option for each dimension.
7.4.6.1 Recommended Options
We summarize the recommended option for each dimension below.
• Threshold: Hybrid approach
- The thresholds fall generally into three groups: capacity, emissions, or entire
source category ("All in"). Typically, a facility that emits 25,000 metric tons
CO2e/year or more reports all sources for which there are methods.
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The capacity and "all-in" thresholds are roughly equivalent to 25,000 metric tons
CO2e/year.
- A facility may be subject to a capacity threshold when already reporting (e.g.,
ARP) or to another type of threshold due to unique issues or where an emissions-
based threshold is not practical (e.g., GHG generation threshold for landfills).
• Methodology: Combination of direct measurement and source-specific calculation
methodologies
- Direct measurement of emissions from units at facilities that are already required
to collect and report data using continuous emission monitoring systems under
other Federally enforceable programs, including for other regulatory programs
(e.g., CO2 emissions from Electricity Generating Units [EGUs] in ARP;
requirements of NSPS, NESHAP, SIP)
— Source-specific calculation methods using facility-specific information for other
sources at the facility
• Frequency: Annual
— All reporters would report their emissions annually.
- Exception: those already reporting quarterly for existing mandatory programs
(e.g., Acid Rain Program, Energy Information Administration)
• Verification: Self-certification with EPA verification
— A facility would report emissions data and supporting information directly to
EPA; EPA will use the information to verify the data.
7.4.6.2 Scenarios Evaluated
EPA developed alternative reporting scenarios and assessed the costs and emissions
associated with each. Alternative scenarios were developed by creating the recommended
scenario (the recommended option for each dimension, as shown in Table 3-1), then varying the
levels in one dimension while keeping the other three dimensions at the recommended options.
The alternative reporting scenarios evaluated are listed below:
1. A 1,000 tCO2e threshold; recommended options for methodology, frequency, and
verifier.
2. A 10,000 tCO2e threshold; recommended options for methodology, frequency, and
verifier.
3. A 100,000 tCO2e threshold; recommended options for methodology, frequency, and
verifier.
4. The measurement variable is changed to direct measurement; recommended option
for threshold, frequency, and verifier.
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5. The measurement variable is changed to default emissions factors; recommended
option for threshold, frequency, and verifier.
6. Existing federal data used for measurement of fuel suppliers; recommended option
for threshold, frequency, verifier, and methodology for other sources.
7. EPA uses default carbon content for fuel suppliers; recommended option for
threshold, frequency, verifier, and methodology for other sources.
8. Reporting is quarterly; recommended option for threshold, methodology, and verifier.
9. Verification is done by a third party; recommended option for threshold,
methodology, and frequency.
10. Reporting from upstream sources only; recommended option for methodology,
frequency, and verifier.
Although some of the alternatives considered may result in lower costs, EPA believes that the
recommended option is the lowest-cost option available that would provide adequate information
on GHG emissions to inform future policy making.
7.5 Executive Order 13132: Federalism
Executive Order 13132, entitled "Federalism" (64 FR 43255, August 10, 1999), requires
EPA to develop an accountable process to ensure "meaningful and timely input by state and local
officials in the development of regulatory policies that have federalism implications." "Policies
that have federalism implications" is defined in the executive order to include regulations that
have "substantial direct effects on the states, on the relationship between the national government
and the states, or on the distribution of power and responsibilities among the various levels of
government."
This rule does not have federalism implications. It will not have substantial direct effects
on the states, on the relationship between the national government and the states, or on the
distribution of power and responsibilities among the various levels of government, as specified in
Executive Order 13132.
This regulation applies to public- or private-sector facilities that directly emit GHGs and
to those that supply fuel or chemicals that emit GHGs when used. Relatively few government
facilities would be affected. This regulation also does not limit the power of states or localities to
collect GHG data and/or regulate GHG emissions. Thus, Executive Order 13132 does not apply
to this rule.
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7.6 Executive Order 13175: Consultation and Coordination with Indian Tribal
Governments
Executive Order 13175, entitled "Consultation and Coordination with Indian Tribal
Governments" (59 FR 22951, November 6, 2000), requires EPA to develop an accountable
process to ensure "meaningful and timely input by tribal officials in the development of
regulatory policies that have tribal implications."
This rule is not expected to have tribal implications, as specified in Executive Order
13175. This regulation applies to facilities that directly emit GHGs and to those that supply fuel
or chemicals that emit GHG when used. Few facilities expected to be affected by the rule are
likely to be owned by tribal governments. Thus, Executive Order 13175 does not apply to this
rule.
Although Executive Order 13175 does not apply to this rule, EPA sought opportunities to
provide information to tribal governments and representatives during development of the rule. In
consultation with EPA's American Indian Environment Office, EPA's outreach plan included
tribes. During the proposal phase, EPA staff provided information to tribes through conference
calls with multiple Indian working groups and organizations at EPA that interact with tribes and
through individual calls with two tribal board members of TCR. In addition, EPA prepared a
short article on the GHG reporting rule that appeared on the front page of a tribal newsletter—
Tribal Air News—that was distributed to EPA/OAQPS's network of tribal organizations. EPA
gave a presentation on various climate efforts, including the mandatory reporting rule, at the
National Tribal Conference on Environmental Management in June, 2008. In addition, EPA had
copies of a short information sheet distributed at a meeting of the National Tribal Caucus. EPA
participated in a conference call with tribal air coordinators in April 2009 and prepared a
guidance sheet for Tribal governments on the proposed rule. It was posted on the MRR website
and published in the Tribal Air Newsletter. For a complete list of tribal contacts, see the
"Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule," in
the Docket for this rulemaking (EPA-HQ-OAR-2008-0508-055).
7.7 Executive Order 13045: Protection of Children from Environmental Health and
Safety Risks
EPA interprets Executive Order 13045 (62 F.R. 19885, April 23, 1997) as applying only
to those regulatory actions that concern health or safety risks, such that the analysis required
under Section 5-501 of the executive order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it does not establish an environmental
standard intended to mitigate health or safety risks.
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7.8 Executive Order 13211: Actions that Significantly Affect Energy Supply,
Distribution, or Use
This rule is not a "significant energy action" as defined in Executive Order 13211 (66 FR
28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply,
distribution, or use of energy. Further, we have concluded that this rule is not likely to have any
adverse energy effects.
This proposal relates to monitoring, reporting, and recordkeeping at facilities that directly
emit GHGs and to those that supply fuel or chemicals that emit GHGs when used; it does not
impact energy supply, distribution or use. Therefore, we conclude that this rule is not likely to
have any adverse effects on energy supply, distribution, or use.
7.9 National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement Act of 1995
(NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs EPA to use voluntary
consensus standards in its regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and business practices) that are
developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, with explanations when the Agency decides not to use available and
applicable voluntary consensus standards.
This rulemaking involves technical standards. EPA proposes to use more than 40
voluntary consensus standards from six different voluntary consensus standards bodies:
American Society for Testing and Material (ASTM), American Society of Mechanical Engineers
(ASME), International Organization for Standardization (ISO), Gas Processors Association
(GPA), American Gas Association (AGA), and American Petroleum Institute (API). These
voluntary consensus standards will help facilities monitor, report, and keep records of GHG
emissions. No new test methods were developed for this rule. Instead, from existing rules for
source categories and voluntary GHG programs, EPA identified existing means of monitoring,
reporting, and keeping records of GHG emissions The existing methods (voluntary consensus
standards) include a broad range of measurement techniques, including many for combustion
sources, such as methods to analyze fuel and measure its heating value, methods to measure gas
or liquid flow, and methods to gauge and measure petroleum and petroleum products. The test
methods are incorporated by reference into the rule and are available as specified in Section 98.6
of subpart A.
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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.
7.10 Executive Order 12898: Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive
policy on environmental justice. Its main provision directs federal agencies, to the greatest extent
practicable and permitted by law, to make environmental justice part of their mission by
identifying and addressing, as appropriate, disproportionately high and adverse human health or
environmental effects of their programs, policies, and activities on minority populations and low-
income populations in the United States.
EPA has determined that this rule will not have disproportionately high and adverse
human health or environmental effects on minority or low-income populations because it does
not affect the level of protection provided to human health or the environment; it is a rule
addressing information collection and reporting procedures.
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SECTION 8
CONCLUSIONS AND IMPLICATIONS
In this RIA, EPA has examined the regulatory background, the development of the
mandatory GHG reporting rule, and estimated its costs and benefits. This section presents our
overall conclusions.
8.1 Discussion of Results
EPA has developed this rule in response to language contained in the FY 2008
Consolidated Appropriations amendment (December 26, 2007), which authorized funding for
EPA to publish the rule on an accelerated schedule. The major market failure that the rule is
designed to address is one of inadequate or asymmetric information: while existing state and
federal programs collect similar data, the resulting data are neither comprehensive nor consistent.
As such, they are an inadequate basis for the formation or evaluation of future climate policy.
8.1.1 Development of the Rule
EPA examined several regulatory alternative scenarios that were developed by varying
options across several program dimensions, including Threshold, Methodology, Frequency, and
Verification. The selected regulatory alternative calls for:
• a hybrid threshold, including a 25,000 tCC^e threshold for all facilities except certain
sectors where a capacity-based threshold is appropriate;
• a hybrid methodology, including facility-specific calculations for all facilities except
those with CEMS monitoring in place under other programs;
• annual frequency except for those sources already reporting quarterly; and
• EPA as the verifier.
Other scenarios evaluated included the following:
1. A 1,000 tCO2e threshold; selected options for methodology, frequency, and verifier.
2. A 10,000 tCO2e threshold; selected options for methodology, frequency, and verifier.
3. A 100,000 tCO2e threshold; selected options for methodology, frequency, and
verifier.
4. The measurement variable is changed to direct measurement; selected option for
threshold, frequency, and verifier.
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5. The measurement variable is changed to default emissions factors; selected option for
threshold, frequency, and verifier.
6. Existing federal data used for measurement of fuel suppliers; selected option for
threshold, frequency, verifier, and methodology for other sources.
7. EPA uses default carbon content for fuel suppliers; selected option for threshold,
frequency, verifier, and methodology for other sources.
8. Reporting is quarterly; selected option for threshold, methodology, and verifier.
9. Verification is done by a third party; selected option for threshold, methodology, and
frequency.
10. Reporting from upstream sources only; selected option for methodology, frequency,
and verifier.
8.1.2 Affected Source Categories
EPA considered both direct emitters of GHGs (stationary combustion sources, industrial
processes, fugitive emissions, and biological processes); upstream emitters (fuel suppliers and
industrial gas suppliers); and mobile sources. From these sources, EPA identified 18 source
categories for which costs and impacts were examined.
8.2 Assessment of Costs and Benefits of the Mandatory GHG Reporting Rule
8.2.1 Estimated Costs and Impacts of the Mandatory GHG Reporting Program
Under the rule, EPA estimates that 10,152 entities would be covered by the rule, directly
emitting 3,827 MtCC^e per year, with 3,663 MtCC^e per year reported from upstream sources.
The total annualized costs incurred under the rule by these entities would be $132 million for the
first year and $82 million for subsequent years. Costs for general stationary combustion sources
would be approximately $26 million in the first year and $22 million in subsequent years. The
Landfills sector would incur $12 million in the first year and $6 million in subsequent years.
Pulp and Paper Manufacturing would incur sector-wide costs of approximately $9 million per
year for both the first and subsequent years. Other sectors are all estimated to incur costs less
than $9 million per year.
Overall, economic impacts on industry sectors are measured by comparing per-entity
costs with average per entity receipts. These cost-to-sales ratios are less than 1% for
establishments owned by small businesses that EPA considers most likely to be covered by the
reporting program (e.g., establishments owned by a business with 20 or more employees) and
small government entities. This analysis enables EPA to determine that the rule will not have a
8-2
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significant economic impact on a substantial number of small entities. Overall, the rule will
impose national costs exceeding $132 million in the first year and 89 million in subsequent
years; the costs will be widely dispersed throughout the economy and relatively low on a per-
entity basis. The estimated national costs represent approximately 0.001% of 2007 Gross
Domestic Product. Thus, EPA does not estimate that there will be significant impacts on the
economy in general or on individual sectors or small entities within those sectors.
8.2.2 Summary of Qualitative Benefits Assessment
EPA was unable to quantify the estimated benefits of the rule. Instead, a qualitative
assessment was performed, based on information from the literature and previous benefits
assessments of existing emissions inventory programs.
Recent policy discussions have highlighted potential benefits to society of the GHG
reporting program (Pew, 2008). Benefits to the public include building public confidence
through clear and transparent emission measures and reports and the ability of the public to make
facilities accountable for their emissions. Benefits to industry include the identification of GHG
reduction opportunities and disclosure, which provides firms with incentives to reduce emissions
voluntarily, and provides emissions data to service industries, such as insurance and financial
markets. A GHG reporting system will also have the benefit of providing policy makers and
analysts with a comparable data set that is comprehensive and reduces the potential for policy
bias due to non-reporting by certain sectors. In addition, a mandatory reporting system is a key
element to an overall GHG policy; no effort can succeed without it.
Studies published by OECD (2005) and EPA (2003) have documented benefits to various
stakeholders, including the public, industry, investors, and government, of existing PRTRs.
These benefits are likely similar to the benefits that would be experienced as a result of the
mandatory GHG reporting rule, and thus they provide a basis for a qualitative characterization of
those benefits. The studies examined in Section 5 of this RIA 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
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- Public relations: having independent, verifiable data to present to the public
would demonstrate appropriate environmental stewardship.
- Standardization: uniform industry standards would reduce the cost of reporting
relative to non-uniform, jurisdiction-specific, and allow facilities to benchmark
their performance against other similar facilities.
- Potential cost savings: mandatory monitoring may uncover previously
unmeasured wasteful processes, yielding cost-saving conservation opportunities
that would offset some of the costs of monitoring.
- Potential customer data for service industries: information about GHG-emitting
firms will be useful for firms that market emissions-reduction technologies, and to
insurance companies for assessing risk.
• Investors
— Information about emissions will enable investors to implement socially
responsible investing using GHG emission information if they so choose.
• Government
— Policy development: The greatest benefit to government of mandatory GHG
reporting is the comprehensive, consistent data it would provide, enabling
government to develop accurate, informed future GHG policy.
- Comparability: A mandatory system would reduce the difficulties associated with
comparing across different reporting standards across states or programs.
— Compliance and policy evaluation: Publicly available nationwide data on GHG
emissions will enable government to develop and robustly evaluate environmental
policies, and to ensure compliance with the policies once implemented.
8.3 What Did We Learn through This Analysis?
EPA's examination of the costs and benefits of the mandatory GHG reporting rule
revealed that the rule will impose an estimated $132 million (based on average costs over the
first three years) in monitoring, recordkeeping, and reporting costs on generators of GHGs that
are widely distributed throughout the U.S. economy. Impacts of the costs on individual sectors
and entities are expected to be generally small, comprising less than 1% of entity receipts and
approximately 0.001% of 2007 GDP. Thus, in spite of the overall national costs, macroeconomic
impacts are not anticipated, and EPA does not believe that the rule will impose significant
economic impacts on a substantial number of small entities.
A review of the literature enabled us to characterize the expected types of benefits, which
will be experienced by stakeholders, including the public, industry, investors, and government.
Based on this qualitative assessment and evidence from other existing programs, EPA expects
the benefits of the rule to be substantial.
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SECTION 9
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