June 2010 

Economic Impact Analysis for the 

Mandatory Reporting of 

Greenhouse Gas Emissions: 

Subparts: T, FF, TT, and II

Final Report
i 

CONTENTS

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

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

1.2 Source Category Definitions Covered by the Final Rules................................... 1-1

1.2.1 Subpart T: Magnesium Production .......................................................... 1-2

1.2.2 Subpart FF: Underground Coal Mines................................................... 1-2

1.2.3 Subpart TT: Industrial Waste Landfills ................................................... 1-2

1.2.4 Subpart II: Industrial Wastewater Treatment........................................... 1-3

1.3 Economic Impact Analysis .................................................................................. 1-3

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

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

2.1.1 Stakeholder Outreach to Identify Reporting Issues ................................. 2-1

2.1.2 Analysis of Emissions by Sector.............................................................. 2-3

2.2 Existing Reporting Programs............................................................................... 2-3

Section 3 Development of Subparts....................................................................................... 3-1

3.1 Subpart T – Magnesium Production .................................................................... 3-1

3.1.1 GHGs to Report. ...................................................................................... 3-1

3.1.2 GHG Emissions Calculation and Monitoring.......................................... 3-2

3.1.3 Summary of Major Changes Since Proposal ........................................... 3-2

3.2 Subpart FF – Underground Coal Mines.............................................................. 3-3

3.2.1 GHGs to Report. ...................................................................................... 3-3

3.2.2 GHG Emissions Calculation and Monitoring.......................................... 3-3
ii 

3.2.3 Summary of Major Changes since Proposal............................................ 3-4

3.3 Subpart TT – Industrial Waste Landfills ............................................................. 3-5

3.3.1 GHGs to Report. ...................................................................................... 3-5

3.3.2 GHG Emissions Calculation and Monitoring.......................................... 3-5

3.3.3 Summary of Major Changes Since Proposal ........................................... 3-7

3.4 Subpart II – Industrial Wastewater Treatment..................................................... 3-7

3.4.1 GHGs to Report. ...................................................................................... 3-7

3.4.2 GHG Emissions Calculation and Monitoring.......................................... 3-8

3.4.3 Summary of Major Changes Since Proposal ........................................... 3-9

3.5 Other Proposed Source Categories .................................................................... 3-10

3.5.1 Overview................................................................................................ 3-10

3.5.2 Ethanol Production................................................................................. 3-11

3.5.3 Food Processing..................................................................................... 3-11

3.5.4 Coal Suppliers........................................................................................ 3-12

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

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

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

4.2.1 Baseline Reporting................................................................................... 4-1

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

4.3 Cost Analysis for Subpart T – Magnesium Production ....................................... 4-4

4.3.1 Model Facility Development ................................................................... 4-4

4.3.2 Cost Elements .......................................................................................... 4-5

4.3.3 Assigning Costs ....................................................................................... 4-6

4.4 Cost Analysis for Subpart FF—Underground Coal Mines.................................. 4-8
iii 

4.4.1 Model Facility Development ................................................................. 4-11

4.4.2 Cost Elements ........................................................................................ 4-11

4.4.3 Proportion of Facilities in the Different Model Facility Levels ............ 4-12

4.4.4 Assigning Costs ..................................................................................... 4-15

4.4.5 Emissions in Ventilation Air.................................................................. 4-18

4.4.6 Emissions from Degasification Systems................................................ 4-19

4.4.7 Estimation of Facility Costs for Each Emission Source ........................ 4-22

4.5 Cost Analysis for Subpart TT—Industrial Landfills ......................................... 4-22

4.5.1 Model facility development ................................................................... 4-22

4.5.2 Number of Landfills Reporting.............................................................. 4-26

4.6 Cost Analysis for Subpart II—Industrial Wastewater ....................................... 4-27

4.6.1 Wastewater and biogas monitoring required by 40 CFR Part 

98.354..................................................................................................... 4-28

4.6.2 Monitoring device, labor, and operating costs....................................... 4-28

4.6.3 Estimated facility wastewater flow rates and meter costs ..................... 4-33

4.7 Public Sector Burden ......................................................................................... 4-41

Section 5 Economic Impact Analysis .................................................................................... 5-1

5.1 Selected of Reporting Thresholds........................................................................ 5-1

5.1.1 Subpart T- Magnesium Production.......................................................... 5-1

5.1.2 Subpart FF- Underground Coal Mines ................................................... 5-3

5.1.3 Subpart TT- Industrial Waste Landfills ................................................... 5-4

5.1.4 Subpart II- Industrial Wastewater Treatment .......................................... 5-5

5.1.5 National Emissions Covered Under Selected Thresholds ....................... 5-6

5.2 National Cost Estimates....................................................................................... 5-7
iv 

5.3 Economic Impact Analysis .................................................................................. 5-8

5.3.1 Assessing Economic Impacts on Small Entities ...................................... 5-8

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

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

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

6.3 Regulatory Flexibility Act (RFA)........................................................................ 6-2

6.4 Unfunded Mandates Reform Act (UMRA) ......................................................... 6-4

6.4.1 Executive Order 13132: Federalism ....................................................... 6-5

6.4.2 Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments...................................................................... 6-5

6.4.3 Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks ........................................ 6-5

6.4.4 Executive Order 13211: Actions that Significantly Affect Energy 

Supply, Distribution, or Use .................................................................... 6-6

6.4.5 National Technology Transfer and Advancement Act ............................ 6-6

6.4.6 Executive Order 12898: Federal Actions to Address Environmental 

Justice in Minority Populations and Low-Income Populations ............... 6-7

6.4.7 Congressional Review Act....................................................................... 6-7

Section 7 Conclusions............................................................................................................ 7-1

7.1.1 Subpart T: Magnesium Production .......................................................... 7-1

7.1.2 Subpart FF: Underground Coal Mines................................................... 7-1

7.1.3 Subpart TT: Industrial Waste Landfills ................................................... 7-2

7.1.4 Subpart II: Industrial Wastewater Treatment........................................... 7-2

7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program......... 7-2
v 

Section 8 References.............................................................................................................. 8-1
vi 

LIST OF TABLES

Table 4-1. Number of Representative Affected Entities....................................................... 4-5

Table 4-2. Labor Categories and Hourly Rates..................................................................... 4-6

Table 4-3. Responsibilities for Regulation Compliance by Labor Category........................4-7

Table 4-4 Summary of Monitoring Cost Scenarios................................................................... 4-10

Table 4-5. Labor Costs and Labor Hours Used in the Analysis ............................................... 4-15

Table 4-6. Responsibilities for Regulation Compliance by Labor Category.............................4-16

Table 4-7. Labor Hours Assumed in the Analysis.................................................................... 4-17

Table 4-8. Number of Entities and Emissions Covered by Industrial Landfill Options...........4-27

Table 4-9. Industrial Wastewater Treatment Monitoring Requirements..................................4-28

Table 4-10. Wastewater Flow Meter Installed Costs (2009$).................................................. 4-29

Table 4-11. Monitoring Cost Elements (2009$)....................................................................... 4-33

Table 4-12. Wastewater Flow Meters for Pulp and Paper Mills.............................................. 4-34

Table 4-13. Wastewater Flow Meter Sizes and Costs .............................................................. 4-35

Table 4-14. Industrial Wastewater Treatment Monitoring Costs ............................................. 4-40

Table 5-1. Threshold Analysis for Subpart T – Magnesium Production....................................5-1

Table 5-2. Threshold Analysis for Subpart FF –Underground Coal Mines ...............................5-3

Table 5-3. Threshold Analysis for Subpart TT– Industrial Waste Landfills..............................5-4

Table 5-4. Threshold Analysis for Subpart II– Industrial Wastewater Treatment (Ethanol) .....5-5

Table 5-5. Threshold Analysis for Subpart II– Industrial Wastewater Treatment (Food 

Processing)................................................................................................................................... 5-5

Table 5-6. Threshold Analysis for Subpart II– Industrial Wastewater Treatment (Pulp and Paper)

......................................................................................................................................................5-6

Table 5-7. Threshold Analysis for Subpart II– Industrial Wastewater Treatment (Petroleum 

Refineries)....................................................................................................................................5-6

Table 5-8. Estimates of Emissions (MtCO2e) Reported in 2008 Under the Selected Option ....5-7
vii 

Table 5-9. National Annualized Mandatory Reporting Costs Estimates (2006$): T, FF, TT, and 

II................................................................................................................................................... 5-8

Table 5-10. Number of Establishments by Affected Industry and Enterprisea Size: 2002.......5-12

Table 5-11. Receipts by Affected Industry and Enterprisea Size (million, 2002$) ..................5-14

Table 5-12. Establishment Sales Tests by Industry and Enterprisea Size: First Year Costs.....5-16

Table 5-13. Establishment Sales Tests by Industry and Enterprisea Size: Subsequent Years Costs

....................................................................................................................................................5-18
1-1 

 

SECTION 1

INTRODUCTION AND BACKGROUND 

1.1 Background 

On December 26, 2007, President Bush signed the FY2008 Consolidated Appropriations 

Act which authorized funding for EPA 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 thresholds in all sectors of the economy of the United States.” (Consolidated 

Appropriations Act, 2008, Pub. L. No.110-161, 121 Stat 1844, 2128 (2008)). An accompanying 

joint explanatory statement directed EPA to "use its existing authority under the Clean Air Act" 

to develop a mandatory GHG reporting rule. 

The Final Mandatory Reporting of Greenhouse Gases Rule was signed on September 22, 

2009 by Administrator Lisa Jackson; and published in the Federal Register on October 30, 2009. 

The Final MRR which is effective on December 29, 2009 included reporting of GHGs from the 

facilities and suppliers that EPA determined appropriately responded to the direction in the 2008 

Consolidated Appropriations Act1

. These source categories capture approximately 85 percent of 

U.S. GHG emissions through reporting by direct emitters as well as suppliers of fossil fuels and 

industrial gases. 

1.2 Source Category Definitions Covered by the Final Rules 

EPA is promulgating a regulation to require monitoring and reporting of greenhouse gas 

emissions from magnesium production (Subpart T), underground coal mines (Subpart FF), 

industrial waste landfills (Subpart TT), and industrial wastewater treatment (Subpart II). EPA 

has added four source categories to the list of source categories already required to report 

greenhouse gas emissions under 40 CFC part 98. The regulation requires monitoring and 

reporting of greenhouse gases for these source categories only for sources with CO2 equivalent 

emissions above certain threshold levels but does not require control of greenhouse gases. EPA 

has made the decision not to include ethanol production or food processing as distinct subparts 

1

 Consolidated Appropriations Act, 2008, Public Law 110–161, 121 Stat. 1844, 2128. 
1-2 

under 40 CFR part 98. Lastly, EPA has also made the decision not to include suppliers of coal as 

a subpart under 40 CFR part 98 at this time. 

1.2.1 Subpart T: Magnesium Production 

Magnesium production and processing facilities are defined as any site where magnesium 

metal is produced through smelting (including electrolytic smelting), refining, or remelting 

operations, or any site where molten magnesium is used in alloying, casting, drawing, extruding, 

forming, or rolling operations. Facilities that meet the applicability criteria in the General 

Provisions (40 CFR 98.2(a)) summarized in Section II.B of this preamble must report GHG 

emissions. 

1.2.2 Subpart FF: Underground Coal Mines 

This source category consists of active underground coal mines and any underground 

mines under development that have operational pre-mining degasification systems. An 

underground coal mine is a mine at which coal is produced by tunneling into the earth to a 

subsurface coal seam, where the coal is then mined with equipment such as cutting machines, 

and transported to the surface. Active underground coal mines are underground mines 

categorized by the Mine Safety and Health Administration (MSHA) as active and where coal is 

currently being produced or has been produced within the previous 90 days. This source 

category consists of each ventilation well or shaft, and each degasification system well or shaft, 

and includes degasification systems deployed before, during, or after mining operations are 

conducted in a mine area. This source category does not include abandoned (closed) mines, 

surface coal mines, or post-coal mining activities (e.g., storage or transportation of coal). 

1.2.3 Subpart TT: Industrial Waste Landfills 

This source category consists of industrial waste landfills whose total landfill design 

capacity is greater than or equal to 300,000 metric tons and that accepted waste on or after 

January 1, 1980 and, if present, landfill gas collection systems and landfill gas destruction 

devices (including flares). This source category does not include Resource Conservation and 

Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA) hazardous waste 

landfills, construction and demolition landfills, or landfills that only receive inert waste 

materials, such as coal combustion residue (e.g., fly ash), cement kiln dust, rocks and/or soil, 

glass, non-chemically bound sand (e.g., green foundry sand), clay, gypsum, pottery cull, bricks, 

mortar, cement, furnace slag, refractory material, or plastics. Facilities that meet the applicability 
1-3 

criteria in the General Provisions (40 CFR 98.2(a)) summarized in Section II.B of this preamble 

must report GHG emissions. 

1.2.4 Subpart II: Industrial Wastewater Treatment 

This source category applies to anaerobic processes used to treat industrial wastewater 

and wastewater treatment sludges at pulp and paper mills, food processing facilities, ethanol 

production facilities, and petroleum refineries. It does not include domestic wastewater treatment 

plants or separate treatment of sanitary wastewater at industrial facilities. It does not include 

oil/water separators. This source category consists of the following: anaerobic reactors, 

anaerobic lagoons, anaerobic sludge digesters, and biogas destruction devices. Facilities that 

meet the applicability criteria in the General Provisions (40 CFR 98.2(a)) summarized in Section 

II.B of this preamble must report GHG emissions. 

1.3 Economic Impact Analysis 

As part of the regulatory process of proposing these rules, EPA is required to develop an 

economic impact analysis (EIA). This report documents the EIA methods and results and 

proceeds as follows: Section 2 describes the current regulatory context into which the final rules 

will be integrated. Section 3 explains the development process for each of the four subparts, and 

Section 4 details the individual cost analyses methods used to evaluate each source category. 

Section 5 presents the results of the economic impact analysis. A review of executive orders is 

provided in Section 6, which is followed by a brief EIA summary and conclusion in Section 7. 
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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 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 

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. 

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. 

2.1.1 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 
2-2 

maintained an open door policy for those interested in discussing the rulemaking. Since January 

2008, EPA staff has held more than 100 meetings with stakeholders, including the following: 

 trade associations and firms in potentially affected industries/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, CARB, and Western Climate Initiative (WCI); and 

 environmental groups and other nongovernmental organizations. 

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

Agriculture (USDA), which have programs relevant to GHG emissions. 

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

timetable for developing a rule. Stakeholders were encouraged to provide input on key issues. 

Examples of topics discussed included existing GHG monitoring and reporting programs and 

lessons learned, thresholds for reporting, schedules for reporting, scope of reporting, handling of 

confidential data, data verification, and the role of states in administering the program. As 

needed, the EPA technical workgroups followed up with these stakeholder groups on a variety of 

methodological, technical, and policy issues. EPA staff also provided information to tribes 

through conference calls with different Indian tribal working groups and organizations at EPA 

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-OAR2008-0508). 
2-3 

2.1.2 Analysis of Emissions by Sector 

For each of the source categories considered in these rules, 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 multiples scenarios. The cost estimates and analysis methodologies are 

detailed in Sections 4 and 5 of this report. 

2.2 Existing Reporting Programs 

In addition to the mandatory reporting program, 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. 

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 two sectorspecific partnerships to reduce SF6 emissions: the SF6 Emission Reduction Partnership for 

Electric Power Systems, with over 80 participating utilities, and the SF6 Emission Reduction 

Partnership for the Magnesium Industry. Partners in these programs implement practices to 

reduce SF6 emissions and prepare corporate-wide annual inventories of SF6 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. 

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). 
2-4 

Where possible, we built upon concepts in existing Federal and State programs in developing the 

mandatory GHG reporting rule. For a full summary of the reporting programs reviewed in the 

development of the mandatory reporting rule please see the Regulatory Impact Analysis for the 

Mandatory Reporting of Greenhouse Gas Emissions EPA-HQ-OAR-2008-0508. 
SECTION 3

DEVELOPMENT OF SUBPARTS 

The four source categories included in these final rules are 

 Subpart T –Magnesium Production; 

 Subpart FF - Underground Coal Mines; 

 Subpart TT – Industrial Waste Landfills; and 

 Subpart II – Industrial Wastewater Treatment. 

This section provides additional details about the development of these subparts since 

proposal. For each subpart, this section also provides a brief description of proposed monitoring 

methods; procedures for estimating missing data; as well as data reporting and recordkeeping 

requirements. 

3.1 Subpart T – Magnesium Production 

3.1.1 GHGs to Report. 

Each magnesium production facility must report total emissions at the facility level for 

each of the following gases in kilograms of gas and metric tons of carbon dioxide equivalent 

(CO2e) per year resulting from their use as cover gases or carrier gases in magnesium production 

or processing: 

 SF6

 HFC-134a 

 The fluorinated ketone, FK 5-1-12 

 CO2

 Any other GHG as defined in 40 CFR part 98, subpart A (General Provisions) of 

the rule. 

In addition, each facility must report GHG emissions for other source categories for 

which calculation methods are provided in the rule. For example, facilities must report CO2, 

N2O, and CH4 emissions from each stationary combustion unit on site by following the 

requirements of 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources). 

3-1 
3.1.2 GHG Emissions Calculation and Monitoring. 

Owners or operators of magnesium production facilities must calculate emissions of each 

gas by monitoring the annual consumption of cover gases and carrier gases using one of three 

methods: 

 Use a mass-balance approach that takes into account the following: 

o Decrease in Inventory: The decrease in inventory of cover or carrier gases 

stored in containers from the beginning to the end of the year. 

o Acquisitions: The amount of cover or carrier gas acquired through 

purchases or other transactions. 

o Disbursements: The amount of cover or carrier gases disbursed to sources 

and locations outside the facility through sales or other transactions. 

 Monitor the changes in the masses of individual containers as the gases are used. 

 Monitor the mass flow of pure cover gas and carrier gas into the cover gas 

distribution system. 

3.1.2.1 Data Reporting. 

In addition to the information required to be reported by the General Provisions (40 CFR 

98.3(c)), reporters must submit additional data that are used to calculate GHG emissions. A list 

of the specific data to be reported for this source category is contained in 40 CFR part 98, 

subpart T. 

3.1.2.2 Recordkeeping. 

In addition to the information required by the General Provisions (40 CFR 98.3(g)), 

reporters must keep records of additional data used to calculate GHG emissions. A list of 

specific records that must be retained for this source category is included in 40 CFR part 98, 

subpart T. 

3.1.3 Summary of Major Changes Since Proposal 

No major changes since proposal have been made to the magnesium production sector. 

3-2 
3.2 Subpart FF – Underground Coal Mines 

3.2.1 GHGs to Report. 

For underground coal mines, report the following: 

 Quarterly CH4 liberated from ventilation and degasification systems. 

 Quarterly CH4 destruction from systems where gas is sold, used onsite, or 

otherwise destroyed (including by flaring). 

 Quarterly net CH4 emissions from ventilation and degasification systems. 

 Quarterly CO2 emissions from coal mine gas CH4 destruction occuring at the 

facility, where the gas is not a fuel input for energy generation or use (e.g., 

flaring). 

 Annual CO2, CH4, and N2O emissions from stationary fuel combustion devices 

under 40 CFR part 98, subpart C (General Stationary Combustion Sources). 

3.2.2 GHG Emissions Calculation and Monitoring. 

For CH4 liberated from mine ventilation air, facilities are to monitor CH4 using either 

quarterly or more frequent sampling, or continuous emissions monitoring systems (CEMS). 

For the quarterly sampling option, coal mine operators are required to either: (a) 

independently collect quarterly or more frequently samples of CH4 released from the ventilation 

system(s), using MSHA procedures, have these samples analyzed for CH4 composition, and 

report the results to EPA, or (b) to obtain the results from the quarterly testing that MSHA 

already conducts, and report those to EPA. 

If operators use CEMS as the basis for emissions reporting, they must provide 

documentation on the process for using data obtained from their CEMS to estimate emissions 

from their mine ventilation systems. 

For CH4 liberated from degasification systems, facilities are to monitor CH4 using either 

weekly sampling, or CEMS. 

3-3 
The option of collecting weekly samples includes both measurement of the total gas 

volume liberated (including that which is emitted or sold, used onsite, or otherwise destroyed 

(including by flaring)), along with measurements of CH4 concentrations in gas volumes 

recovered or emitted. Under this option, facilities must determine weekly gas flow rates and CH4

composition from these degasification wells and shafts, either on an individual well or shaft 

basis, or in aggregate at one or more centralized collection points. Methane composition could 

be determined either by submitting samples to a lab for analysis, or from the use of 

methanometers at the degasification well site(s) and/or centralized collection point. 

For the CEMS option, facilities must monitor either individual wellbores, or can monitor 

gas at points of aggregation, as long as emissions from all wells are addressed, and the 

methodology for calculating total emissions from all wells is documented. 

For all systems with CH4 destruction, CH4 destruction is monitored through direct 

measurement of gas flow and CH4 concentration to combustion devices with continuous 

monitoring systems. The resulting CO2 emissions are to be calculated from these monitored 

values. 

3.2.2.1 Data Reporting. 

In addition to the information required to be reported by the General Provisions (40 CFR 

98.3(c)), reporters must submit additional data that are used to calculate GHG emissions. A list 

of specific data to be reported for this source category is contained in 40 CFR 98.326, subpart 

FF. 

3.2.2.2 Recordkeeping. 

In addition to the records required by the General Provisions (40 CFR 98.3(g)), reporters 

must keep records of additional data that are used to calculate GHG emissions. A list of specific 

data to be reported for this source category is contained in 40 CFR 98.327, subpart FF. 

3.2.3 Summary of Major Changes since Proposal 

The major changes in this rule since the original proposal are identified in the following 

list. The rationale for these and any other significant changes to subpart FF can be found below 

or in “Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 

Subpart FF: Underground Coal Mines.” 

3-4 
 An option of using one or more CEMS to obtain data on mine ventilation systems 

is added. 

 For CH4 liberated from degasification systems, the requirement to monitor each 

well was removed. CEMS may be used to monitor aggregate CH4 from more 

than one well, as long as CH4 from all wells is monitored, and the methodology 

for estimating total emissions from all wells is documented. 

 The requirement for continuous monitoring for total CH4 liberation at 

degasification systems was removed. Degasification wells may be monitored with 

CEMS or through weekly sampling of all degasification wells, including gob gas 

vent holes and other degasification wells. 

3.3 Subpart TT – Industrial Waste Landfills 

3.3.1 GHGs to Report. 

For industrial waste landfills, facilities must report: 

 Annual CH4 generation and CH4 emissions from the industrial waste landfill. 

 Annual CH4 recovered (for landfills with gas collection and destruction systems). 

3.3.2 GHG Emissions Calculation and Monitoring. 

All facilities must ascertain annual modeled CH4 generation based on: 

 Measured or estimated values of historic annual waste disposal quantities; and 

 Appropriate values for model inputs (i.e., degradable organic carbon fraction in 

the waste, CH4 generation rate constant). Default parameter values are specified 

for certain industries and for industrial waste generically. 

Facilities that do not collect and destroy landfill gas must adjust the annual modeled CH4 

generation to account soil oxidation (CH4 that is converted to CO2 as it passes through the 

landfill cover before being emitted) using a default soil oxidation factor. The resulting value 

must be reported and represents both CH4 generation (corrected for oxidation) and CH4

emissions. 

3-5 
Facilities that collect and destroy landfill gas must calculate the annual quantity of CH4

recovered and destroyed based on either continuous or weekly monitoring of landfill gas flow 

rate, CH4 concentration, temperature, pressure, and moisture of the collected gas prior to the 

destruction device. 

Those facilities that collect and destroy landfill gas must then calculate CH4 emissions in 

two ways and report both results. Emissions must be calculated by: 

 Subtracting the measured amount of CH4 recovered from the modeled annual 

CH4 generation (with adjustments for soil oxidation and destruction efficiency of 

the destruction device) using the equations provided; and 

 Applying a gas collection efficiency to the measured amount of CH4 recovered to 

“back-calculate” CH4 generation, then subtracting the measured amount of CH4 

recovered (with adjustments for soil oxidation and destruction efficiency of the 

destruction device) from the back-calculated CH4 generation using the equations 

provided. A default collection efficiency of 75 percent is specified, but landfills 

should use a collection efficiency that takes into account collection system 

coverage, operation, and landfill cover materials. 

3.3.2.1 Data Reporting. 

In addition to the information required to be reported by the General Provisions (40 CFR 

98.3(c)), reporters must submit additional data that are used to calculate GHG emissions. A list 

of the specific data to be reported for this source category is contained in 40 CFR part 98, 

subpart TT. 

3.3.2.2 Recordkeeping. 

In addition to the records required by the General Provisions (40 CFR 98.3(g)), reporters 

must keep records of additional data used to calculate GHG emissions. A list of specific records 

that must be retained for this source category is included in 40 CFR part 98, subpart TT. 

3-6 
3.3.3 Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the following list. The rationale for 

these and any other significant changes can be found below or in “Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to Public Comments, Subpart TT: Industrial Waste landfills.” 

 A number of provisions were added to target industrial waste landfills that have a 

potential to generate appreciable quantities of methane. These include provisions 

to exempt landfills that did not accept any waste after January 1, 1980, exempt 

landfills with a total landfill design capacity of less than 300,000 metric tons, and 

exempt landfills that only receive inert waste materials. 

 Company records are now allowed instead of direct mass measurements for 

determining waste quantities for current reporting years. 

 Additional model defaults for industrial waste are included in the final rule and 

additional methods are provided to estimate degradable organic carbon content of 

industrial solid waste streams. 

 For landfills with landfill gas recovery, all of the changes that were incorporated 

in the final subpart HH rule (allowing weekly sampling and direct flame 

ionization methods) are also included in this final rule for industrial waste 

landfills (by cross-referencing the final requirements in subpart HH). For 

additional details regarding the changes in the landfill gas recovery monitoring 

requirements, see the final preamble for the subpart HH [Municipal Solid Waste 

Landfills] rule at 74 FR 56336. 

3.4 Subpart II – Industrial Wastewater Treatment 

3.4.1 GHGs to Report. 

Operators of anaerobic processes used to treat industrial wastewater and industrial 

wastewater treatment sludge must report the following: 

 The amount of CH4 generated, recovered, and emitted from treatment of industrial 

wastewater using anaerobic lagoons or anaerobic reactors; 

3-7 
 The amount of CH4 recovered and emitted from anaerobic sludge digesters; and 

 The amount of CH4 destroyed by and emitted from biogas collection systems and 

destruction devices. 

Operators of anaerobic wastewater treatment sludge digesters are not required to report 

the amount of CH4 generated. EPA believes that all anaerobic sludge digesters are designed for 

CH4 recovery. Further, operators of anaerobic sludge digesters are required to report the amount 

of CH4 recovered and emitted. For this reason, a separate calculation and report of the amount of 

CH4 generated is not necessary. 

3.4.2 GHG Emissions Calculation and Monitoring. 

Detailed methods for calculating GHG emissions are included in the rule and are briefly 

described below. For each anaerobic wastewater treatment process, facilities must calculate the 

mass of CH4 generated using the following inputs and data: 

 Volume of wastewater sent to an anaerobic treatment process; 

 Average concentration of chemical oxygen demand (COD) or 5-day biochemical 

oxygen demand (BOD5) of wastewater entering an anaerobic treatment process; 

 Maximum CH4 producing potential of wastewater (0.25 for COD, 0.6 for BOD5); 

and 

 CH4 conversion factor for the type of wastewater treatment process used. 

For each anaerobic process (such as reactor, lagoon, or sludge digester) from which 

biogas is recovered, facilities must calculate the mass of CH4 recovered using the following 

inputs and data: 

 Cumulative volumetric flow of biogas for the monitoring period; 

 Average CH4 content of the biogas; and 

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 Temperature, pressure, and moisture content at which flow is measured, as needed 

to accurately calculate biogas flow and CH4 content. 

For each anaerobic process (such as reactor, lagoon, or sludge digester) from which 

biogas is recovered, facilities must calculate the mass of CH4 emitted using the following inputs 

and data: 

 Mass of CH4 recovered; 

 Collection efficiency for the anaerobic process, based on the type of anaerobic 

process; 

 Destruction efficiency of the biogas collection and combustion system; and 

 Fraction of hours the destruction device was operating in the reporting year. 

3.4.2.1 Data Reporting. 

In addition to the information required to be reported by the General Provisions (40 CFR 

98.3(c)), facilities must submit additional data that are used to calculate GHG emissions. A list 

of the specific data to be reported for this source category is contained in 40 CFR Part 98, 

subpart II. 

3.4.2.2 Recordkeeping. 

In addition to the records required by the General Provisions (40 CFR 98.3(g)) facilities 

must keep records of additional data used to calculate GHG emissions. A list of specific records 

that must be retained for this source category is included in 40 CFR Part 98, subpart II. 

3.4.3 Summary of Major Changes Since Proposal 

The major changes since proposal are identified below. The rationale for these and any 

other significant changes can be found below or in “Mandatory Greenhouse Gas Reporting Rule: 

EPA’s Response to Public Comments, Subpart II: Industrial Wastewater Treatment,” and 

“Technical Support Document for Industrial Wastewater Treatment.” 

3-9 
 The source category has been renamed Industrial Wastewater Treatment and the 

applicability of this subpart has been clarified. Only petroleum refineries and 

ethanol production, food processing, and pulp and paper facilities that meet the 

requirements of 98.2(a)(2) are required to report CH4 emissions from anaerobic 

processes used to treat industrial wastewater and industrial wastewater treatment 

sludges and biogas destruction devices. Domestic wastewater treatment and 

separate treatment of sanitary wastewater at industrial facilities are not included in 

the applicability, nor are facilities that do not employ wastewater treatment 

processes listed in the source definition (i.e., employ only aerobic or anoxic 

processes). 

 The requirement to report emissions from oil/water separators at petroleum 

refineries has been removed. EPA expects no direct emissions of CO2 or other 

GHG from these oil/water separators. 

 Because petrochemical facilities are not known to employ anaerobic wastewater 

treatment, this sector has been removed from the final version of the rule. 

 For ease of reporting, EPA revised the regulation to allow for either continuous or 

weekly monitoring of biogas CH4 concentration. Facilities may use either 

installed or portable monitors to measure the CH4 concentration. Further, EPA 

added BOD5 as an alternative to measuring COD to determine the organic load of 

influent to anaerobic wastewater treatment systems. 

3.5 Other Proposed Source Categories 

3.5.1 Overview 

EPA has made the final decision not to include Ethanol Production or Food Processing as 

distinct subparts in the Mandatory Greenhouse Gas Reporting Rule. EPA has also made the final 

decision to not include Suppliers of Coal in the Mandatory Greenhouse Has Reporting Rule at 

this time. Further explanation of these decisions are included below. 

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3.5.2 Ethanol Production 

EPA has made the final decision not to include Ethanol Production (proposed as 40 CFR 

part 98, subpart J) as a distinct subpart in the Mandatory GHG Reporting Rule. 

The proposal for this subpart (74 FR 16448, April 10, 2009) did not include any unique 

requirements for monitoring or reporting of process emissions from ethanol production facilities. 

Instead, the proposed subpart simply referred to reporting that those facilities might need to do 

under other subparts, namely, 40 CFR part 98, subpart C-Stationary Combustion, subpart TTLandfills, and subpart II-Wastewater Treatment. 

Subpart J was originally included as a distinct subpart to make clear that these facilities 

must meet the threshold by aggregating emissions from all source categories. As structured, the 

proposed subpart specifically required that emissions from stationary combustion, on-site 

landfills, and on-site wastewater treatment were to be included in determining the reporting 

threshold and reporting emissions from these facilities. 

Upon closer examination of 40 CFR 98.2(a), it is clear that ethanol production facilities 

will be required to report if they meet the threshold of 25,000 tons CO2e by aggregating 

emissions from all applicable source categories in the rule including stationary combustion, 

industrial wastewater treatment, industrial landfills, miscellaneous use of carbonates, and any 

others that may apply. In fact, any facility not specifically identified in a subpart must report 

their GHG emissions if that facility contains source categories itemized by the rule and their 

aggregate emissions meet the threshold. 

In the final rule, ethanol production facilities are among those specifically identified in 

subpart II – Industrial Wastewater Treatment at Certain Industrial Facilities as required to report 

if they meet the applicability provisions in 40 CFR 98.2(a)(2). For clarity, the definition of 

ethanol production facility is included in 40 CFR 98.6. 

3.5.3 Food Processing 

EPA has made the final decision not to include Food Processing (proposed as 40 CFR 

part 98, subpart M) as a distinct subpart in the Mandatory Greenhouse Gas Reporting Rule. 

The proposal for this subpart (74 FR 16448, April 10, 2009) did not include any unique 

requirements for monitoring or reporting of process emissions from food processing facilities. 

Instead, the proposed subpart simply referred to reporting that those facilities might need to do 

3-11 
under other subparts, namely, 40 CFR part 98, subpart C-Stationary Combustion, subpart HHLandfills, and subpart II-Wastewater Treatment. 

Subpart M was originally included as a distinct subpart to make clear that these facilities 

must meet the threshold by aggregating emissions from all source categories. As structured, the 

proposed subpart specifically required that emissions from stationary combustion, on-site 

landfills, and on-site wastewater treatment were to be included in determining the reporting 

threshold and reporting emissions from these facilities. 

Upon closer examination of 40 CFR 98.2(a), it is clear that food processing facilities will 

be required to report if they meet the threshold of 25,000 tons CO2e by aggregating emissions 

from all applicable source categories in the rule including stationary combustion, industrial 

wastewater treatment, industrial landfills, miscellaneous use of carbonates, and any others that 

may apply. In fact, any facilities not specifically identified in a subpart must report their GHG 

emissions if that facility contains source categories itemized by the rule and their aggregate 

emissions meet the threshold. 

In the final rule, food processing facilities are among those specifically identified in 

subpart II – Industrial Wastewater Treatment at Certain Industrial Facilities as being required to 

report if they meet the applicability provisions in 40 CFR 98.2(a)(2). For clarity, a definition of 

food processing facility is included in 40 CFR 98.6. 

3.5.4 Coal Suppliers 

EPA has made a final decision not to include Suppliers of Coal (proposed as 40 CFR part 

98, subpart KK) in the Mandatory Greenhouse Gas Reporting Rule at this time. 

EPA’s rationale for not requiring reporting from coal suppliers at this time is that (i) the 

overlap in reporting from upstream coal suppliers and downstream emitters is almost 100% 

indicating that double-reporting does not provide more complete information to EPA, unlike 

with other upstream supplier subparts (e.g., MM and NN), and (ii) the high accuracy of the 

downstream reporting provisions in the final MRR provide more than adequate emissions data 

for anticipated near-term uses. 

 EPA will continue to assess the need for reporting from coal suppliers in the future in 

light of new information or identification of policy or program needs. If EPA were to decide in 

the future to add coal suppliers to the Mandatory GHG Reporting Rule it would initiate a new 

rulemaking process. 

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3-13 
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 magnesium production facilities. 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 affected facilities, costs include monitoring, 

recording, and reporting of GHG emissions from production processes and from 

stationary combustion units. 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). 

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, EPA is assuming that none of the facilities in these source categories 

are currently reporting emissions and that many of the requirements will result in “new” 

or “full” costs to meet reporting requirements. Specifically, EPA is assuming that there 

4-1 
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). EPA is also assuming that additional costs will be incurred for preparing 

monitoring and QA/QC plans, performing the calculations, reporting the results, and 

maintaining records. 

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. 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 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. 

4-2 
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 employer.

2

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. 

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 

 

2

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

space, computer hardware and software, telecommunication and other equipments, organizational 

support, etc.) required for and used by the employee to effectively fulfill his/her job responsibilities. 

These costs are over and above the employee compensation costs. 

4-3 
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. Each subpart is assigned recordkeeping 

($1,700 per entity) and reporting ($500) costs. 

Stationary Combustion Costs. Secondary estimates for Magnesium Production 

(Subpart T) were assigned based on Tier 2 methods ($5,500 per entity). 

Detailed Cost Analysis by Subpart. The balance of section 4 provides the 

additional cost data details by 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 Cost Analysis for Subpart T – Magnesium Production 

4.3.1 Model Facility Development 

Costs and measurement uncertainties for estimating greenhouse gas (GHG) 

emissions from magnesium production and processing facilities were estimated for 

emissions of SF6, other GHG cover gases, and CO2 carrier gas. We report the population 

of affected entities in Table 4-1.The cost estimation methodology for this sector is based 

on information from the 2000 Information Collection Request for EPA’s SF6 Emission 

Reduction Partnership for the Magnesium Industry (EPA 2000). Burden estimates were 

gathered from four Partners (three die casters and one die cast/remelt facility) and were 

averaged to represent a typical facility. Because the burden estimates in the ICR 

represented the costs of tracking only the cover gas, the estimated labor hours for 

monitoring were increased by 25 percent to account for tracking of CO2, which is 

sometimes used as a carrier gas (the medium in which the cover gas is delivered to the 

melt surface). Thus the model facility for cost development purposes is a magnesium 

production and processing facility that incurs average costs. 

4-4 
Table 4-1. Number of Representative Affected Entities 

Threshold 

Number of 

Representative Entities 

1,000 13 

10,000 11 

25,000 11 

100,000 9 

4.3.2 Cost Elements 

The total costs associated with complying with the proposed rulemaking were 

broken into 4 elements, each of which was taken into consideration for this sector. 

4.3.2.1 Monitoring costs 

Monitoring costs are associated with data collection and tracking of cover and 

carrier gas usage at the facility. This effort includes determining gas total usage, 

estimating the average usage rate based on metal production, and tracking activities taken 

to reduce emissions. Collection of gas consumption data is typically facilitated through 

existing cylinder weight tracking or bulk storage inventory at the facility. 

4.3.2.2 Reporting costs 

Reporting costs consist of labor necessary to document collected emissions data 

and to submit the official report in each cycle (i.e., annually). 

4.3.2.3 Archiving and recordkeeping costs 

Archiving and recordkeeping costs include the labor necessary to adequately 

archive each cycle’s report and associated working documents. For archiving reports and 

associated working documents, the costs of a physical storage system such as a file 

cabinet and miscellaneous supplies are included. 

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4-6 

4.3.3 Assigning Costs 

4.3.3.1 Determining Labor Categories 

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

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

perform each task. For this analysis, four labor categories were used as shown in Table 

4-2. 

Table 4-2. Labor Categories and Hourly Rates 

Labor Category Description Loaded Hourly Rate ($/hour) 

Legal Oversees legal aspects of 

company reports and datareporting forms. 

$101.00/hour 

Managerial Oversees work at a high level 

and is the final authority on all 

reporting requirements. 

$71.03/hour 

Technical Conducts monitoring of 

emissions sources, checks for 

accuracy, performs gas 

chromatography measurements 

$55.20/hour 

Clerical Assists with documentation and 

recording information 

$29.65/hour 

4.3.3.2 Allocating Responsibilities 

As noted above, labor hours for all cost elements were assigned based on the 2000 

Information Collection Request for EPA’s SF6 Emission Reduction Partnership for the 

Magnesium Industry (EPA 2000), and expert judgment. Hours assigned are based on an 

average facility using burden information as described in Step 1. Table 4-3 summarizes 

these roles.
Table 4-3. Responsibilities for Regulation Compliance by Labor Category 

Responsibilities and Hours by Labor Category 

Legal Managerial Technical Clerical 

Cost Element Responsibilities Hours Responsibilities Hours Responsibilities Hours Responsibilities Hou

MonitoringCollection of cylinder tracking or bulk storage data 

Review the collection plan 

5 Develop a collection 

plan 

27.5 

ReportingCompile data, enter into reporting system, and submit report 

Review the reporting documentation 

2 Review the 

reporting documentation and submit report 

2 Prepare reporting 

documentation 

6 

Archiving and Recordkeeping 

Archiving reports Archive the 

reporting documentation 

4 

4-7 
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 other costs for archiving and record keeping. 

4.3.3.3 Other costs 

Magnesium production and processing facilities were assumed to incur other costs related 

to archiving and recordkeeping of information. These costs consist of purchases of 

miscellaneous supplies and information storage. Startup costs are estimated to be $117 for 

miscellaneous supplies and are reported in 2006 U.S. dollars using an annualization assumed 

over an equipment life of 3 years with a 7 percent interest rate. From these factors, a capital 

recovery factor of 31 percent was calculated resulting in an annualized cost of $36. Annual other 

costs are estimated to be $105 for file storage, recordkeeping, and postage, and $12 for upkeep of 

supplies. The total for annualized other costs is $153. 

4.3.3.4 Estimate per Facility Costs for Each Threshold Level 

The total reporting costs per facility are constant at each threshold level because reporting 

costs are estimated to be identical for all facilities. Total costs per facility were calculated by 

multiplying that labor costs times the labor hours, and adding in the other costs for each facility. 

4.4 Cost Analysis for Subpart FF—Underground Coal Mines 

This source category consists of active underground coal mines, and other underground 

mines having operational pre-mining degasification systems. An underground coal mine is a 

mine at which coal is produced by tunneling into the earth to a subsurface coal seam, where the 

coal is then mined with equipment such as cutting machines, and transported to the surface. 

Active underground coal mines are mines where coal is currently being produced or has been 

produced within the previous 90 days. This source category is comprised of emission points of 

fugitive methane emissions for each coal mine exceeding an emissions threshold established by a 

current emissions monitoring program in place by the Mine Safety and Health Administration 

(MSHA):3

 The number of mines exceeding the MSHA threshold was determined based on 

 

3

 EPA proposes that all active underground coal mines for which methane from the ventilation system is sampled 

quarterly by MSHA be required to report total methane emissions (from ventilation and degasification systems) 

under this rule. MSHA conducts quarterly testing of methane concentration and flow at mines emitting more 

than 100,000 cubic feet methane per day. EPA selected this threshold because subjecting underground mine 

operators to a new emissions-based threshold is unnecessarily burdensome, as many of these mines are already 

subject to MSHA regulations. The MSHA threshold for reporting of 100,000 cubic feet methane per day covers 
4-9 

 

MSHA data. In 2006, 114 mines exceeded the MSHA threshold for ventilation systems of 

100,000 cubic feet per day. 

The specific emissions points targeted in this rulemaking are: 

 Each ventilation well or shaft, including those where the recovered gas is sold, used on 

site, or otherwise destroyed. 

 Each degasification system well or shaft, including degasification systems deployed 

before, during, or after mining operations are conducted in a mine area. These include 

degasification wells where the recovered gas is sold, used on site, or otherwise destroyed; 

and those where the recovered gas is vented to the atmosphere. 

This source category does not include abandoned (closed) mines, as defined by MSHA, 

surface coal mines, or post-coal mining activities. 

For coal mine ventilation shafts, there are two monitoring options: 

 The first is quarterly sampling of methane content and gas flow, essentially duplicating 

the current MSHA process of collecting air samples and ventilation rates, submitting the 

samples to a lab for analysis, and developing estimates of emissions based on this 

sampling. 

 The second is the use of one or more continuous emission monitoring systems (CEMS) 

within the mine as a source of emissions reporting. If operators use CEMS as the basis 

for emissions reporting, they must provide documentation on the process for using data 

obtained from their CEMS to estimate emissions from their mine ventilation systems, as 

specified in the regulations. 

 Some mines may use a combination of these two methods. For example, some 

ventilation shafts at a mine may have CEMS and others may be sampled quarterly at the 

same mine. 

For coal mine degasification systems, there are two monitoring options: 

 One option for fugitive emissions monitoring from degasification systems is by using 

continuous wellbore monitors of gas liberated from mine degasification systems, 

approximately 94% of the methane emitted from underground coal mine ventilation systems and about 86% of 

total emissions from underground mining operations (including stationary combustion emissions at mine sites). 
4-10 

especially where such systems are already in place. This includes measurement of the gas 

volume liberated, along with measurements of methane concentrations in liberated gas 

volumes. 

 The second option is to collect weekly samples for all degasification wells, including gob 

gas vent holes and other degasification wells that are currently not continuously 

monitored. 

For coal mines with gas destruction systems, there is one monitoring option: 

 If gas from degasification system wells or ventilation shafts is sold, used onsite, or 

otherwise destroyed (including by flaring), Quantity of gas destroyed is monitored by 

using continuous monitors. This includes measurement of the gas volume to the 

destruction device along with measurements of methane concentrations in gas volumes. 

These options are summarized in Table 4-4. 

Table 4-4 Summary of Monitoring Cost Scenarios

Scenario Comment

Coal Mining: Underground Coal 

Mines; Ventilation Systems

1) Annual reporting of emissions from ventilation systems 

based on sampling conducted by trained mine personnel as part 

of quarterly mine safety inspections for gassy mines, 2) annual 

company reporting of estimated emissions derived from existing 

continuous monitoring systems deployed in the mines, or 3) 

annual reporting of produced gas volumes and disposition of 

gas produced from degasification systems at coal mines – using 

continuous wellbore monitors.

Coal Mining: Underground Coal 

Mines; Mine Degasification 

Systems 

1) Annual reporting of produced gas volumes and disposition of 

gas produced from degasification systems at coal mines – using 

continuous wellbore monitors, or 2) weekly sampling. Applies 

to both active degasification systems where the gas is sold, used 

on site, or otherwise destroyed, as well as other degasification 

wells, such as gob gas vent holes and horizontal pre-mining 

drainage wells, where the gas is vented to the atmosphere.
4-11 

4.4.1 Model Facility Development 

For purposes of this RIA, data from actual coal mines were used for cost development. 

Each mine exceeding the MSHA threshold was assumed to have two ventilation shafts where 

quarterly sampling would be conducted. 

For mine degasification systems, only those systems where degasification systems are 

currently in place were considered.. For existing degasification systems, including gob gas vent 

wells/holes and other degasification wells that do not currently monitor degasified gas volumes 

produced, incremental costs were considered for two monitoring options: installing continuous 

monitoring equipment on these remote gob gas vent holes, or for conducting weekly sampling. 

4.4.2 Cost Elements 

4.4.2.1 Regulation compliance determination costs 

Start-up registration costs consist entirely of the labor necessary to study and review the 

regulations to assure compliance, gather data on the facility, and fill out the appropriate 

registration forms. Recurring registration costs will be small and due entirely to labor. Small 

amounts of time will be required for the company to stay aware of any updates to regulations and 

to alter the facility information to reflect any new equipment or facilities brought into operation 

or taken offline. 

4.4.2.2 Monitoring costs 

All costs associated with complying with the rulemaking for monitoring fugitive 

emissions from coal mines were considered, including both labor and non-labor (capital and 

O&M) costs, for both startup and recurring costs. Specifically, this includes costs, as appropriate 

to the option considered, associated with pre-compliance planning and preparation, system 

planning and equipment selection and purchase, installing and testing new equipment, and 

ensuring monitoring equipment are properly maintained and functioning. 

Where sampling is the basis for emissions estimation, costs include those associated with 

oversight, auditing, and conducting periodic inspections to estimate annual ventilation air 

emissions and emissions from degasification systems, internally developing the methodology for 

estimating emissions, training personnel in the process, having mine personnel conduct periodic 

sampling and, where appropriate, sending samples to a lab for analysis (including the costs of the 

lab testing of the samples), and developing estimates of emissions based on these samples. 
4-12 

 Where using data from continuous monitoring systems is the basis for emissions 

estimation, costs include those associated with oversight, auditing, and processing data to 

estimate annual ventilation air emissions and produced gas volumes from degasification systems, 

internally developing the methodology for estimating emissions, training personnel in the 

process, and having mine personnel monitor and maintain monitoring equipment (where such 

equipment do not already exist). 

 

4.4.2.3 Reporting costs 

There will be no start-up reporting costs; that is covered in registration. Recurring 

reporting costs consist of labor necessary to document collected emissions data from fugitive 

emissions monitoring and to submit the official report in each cycle (i.e. annually). 

4.4.2.4 Archiving and recordkeeping costs 

Start-up archiving and recordkeeping costs consist of labor and annualized capital 

purchase of storage space. For archiving reports and associated working documents, physical 

storage systems such as file cabinets and electronic storage systems such as external hard drives 

will be required. Recurring archiving and recordkeeping costs consist entirely of labor necessary 

to adequately archive each cycle’s report and associated working documents. 

4.4.2.5 Auditing costs 

There is no start-up cost associated with auditing. Recurring auditing costs consists of 

labor required to validate to the EPA results from the monitoring of emissions and the follow-up 

of rectifying any weaknesses found through the audit. The EPA audit is expected to occur once 

every several years, not on an annual basis. 

4.4.3 Proportion of Facilities in the Different Model Facility Levels 

In general, MSHA samples (quarterly or more frequently) and electronically keeps track 

of methane emissions for mines liberating more than 100,000 cubic feet of methane per day from 

ventilation systems, which is equivalent to about 15,000 metric tons CO2e per year. However, 

emissions rates from some mines emitting less than that threshold are included in the MSHA 

database. Of the over 600 underground coal mines operating in the U.S. according to EIA, 

ventilation air emissions based on MSHA inspections were reported and electronically accounted 

for in 128 mines in 2006. 
4-13 

 

The number of mines exceeding the MSHA threshold was determined based on MSHA 

data. In 2006, 114 mines exceeded the MSHA threshold for ventilation systems of 100,000 

cubic feet of methane per day. 

The number of mines with active mine degasification systems where the recovered gas is 

sold, used on site, or otherwise destroyed was also determined based on data collected by MSHA 

and EPA. In 2006, 15 U.S. coal mines supplemented their ventilation systems with active 

degasification systems where the recovered gas was sold, used on site, or otherwise destroyed. In 

addition, 21 mines have drainage systems where the methane is not captured or recovered, but 

vented to the atmosphere.4

No inventory of the total number of such degasification wells in the U.S. exists, so 

estimates had to be made of the number of these wells. Degasification wells could possibly be 

subject to new monitoring and reporting requirements. This includes both degasification wells 

where the recovered methane is sold, used on site, or otherwise destroyed, as well as methane 

drainage wells, deployed before, during, or after mining activities, where the drained methane is 

vented. 

The number and performance of such wells varies considerably from mine-to-mine. In 

the U.S., most methane drainage systems involve horizontal, in-seam boreholes and vertical gob 

gas vent holes.5

 In general, these methane drainage boreholes undergo a peak production period 

shortly after undermining, after which methane flow rates then decline (often quickly) and reach 

a production tail at a lower rate. The conventional design of vertical gob gas vent holes often 

includes surface exhausters that produce a negative pressure on the boreholes to enhance coalbed 

gas production. Such wells are most commonly used in longwall mining operations. 

For cost estimation purposes, an estimate of the number of these degasification wells in 

the U.S. was developed based on the following: 

4

 Climate Action Reserve, Coal Mine Methane Project Protocol: Destroying Methane from Underground Coal 

Mines, Version 1.0, October 7, 2009 (http://www.climateactionreserve.org/how/protocols/adopted/coal-minemethane/current/http://www.climateactionreserve.org/how/protocols/adopted/coal-mine-methane/current/) 

5

 Thakur, P., “Coalbed Methane Drainage: The Past, Present, and Future,” in R. Ganguli & S. Bandopadhyay, 

(eds),, Proceedings, 10th US/NA Mine Ventilation Symposium, Anchorage, Alaska, May 16-19, 2004 
4-14 

 

 As part of developing the EPA greenhouse gas emissions inventory6 for the coal mining 

sector, for some mines, well-by-well data are compiled. This includes most of the mines 

in Alabama, and a few elsewhere. Where available, well counts based on these data were 

used. 

 For mines where well count information were available, these counts were used, in 

combination with estimated gas volumes recovered from the degasification systems 

associated with these wells, to develop estimated average state-specific annual production 

rates and typical well lives for these degasification wells. In some cases, these data were 

supplemented with degasification well recovery rates reported in the literature. 

 For states with known degasification projects, estimates are developed by EPA of the 

volume of methane recovered from degasification systems that is sold, used on site, or 

otherwise destroyed; as well as that drained but not sold, used on site, or otherwise 

destroyed.7 Where estimates of well counts were not available for a particular mine 

known to have a degasification project in place, the estimated number of active 

degasification wells was estimated by dividing the estimate of methane emissions 

recovered by the estimated state-specific average production rate per degasification well. 

The degasification wells were allocated to individual mines according to the estimated 

volumes vented versus that sold, used on site, or destroyed. 

 Where estimates of degasification well counts were not available for a particular mine 

known to produce some amount of methane that is not recovered by an existing 

degasification project, as well as all other longwall mines, the estimated number of active 

degasification wells where gas is currently vented was estimated by assuming that 40% 

of the methane vented was the result of degasification. This estimate of total fugitive 

methane emissions at the mine was then divided by the estimated average state-specific 

production rate per degasification well. 

6

 Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006, USEPA 

#430-R-08-005, April 2008 (http://www.epa.gov/climatechange/emissions/usinventoryreport.html) 

7

 Environmental Protection Agency, Identifying Opportunities for Methane Recovery at U.S. Coal Mines: Profiles of 

Selected Gassy Underground Coal Mines: 2002-2006, EPA 430-K-04-003, September 2008 (Revised January 

2009) 
4-15 

Based on this approach, it was estimated that about 1,400 degasification wells were 

associated with mines with degasification systems where the recovered methane is sold, used on 

site, or otherwise destroyed. For cost estimation purposes, it was assumed that these wells had 

an average 5 year life, resulting in an average of 280 new wells that are brought on line each year 

(as a comparable number are retired). 

Similarly, it was estimated that 500 degasification wells were venting methane to the 

atmosphere. For cost estimation purposes, it was assumed that these wells had an average 3 year 

life, resulting in an average of 167 new wells that are brought on line each year (as a comparable 

number are retired). 

4.4.4 Assigning Costs 

4.4.4.1 Determining Labor Categories 

Three labor categories were used in these cost estimates, as shown in Table 4-5. 

Table 4-5. Labor Costs and Labor Hours Used in the Analysis 

Labor Category Loaded Hourly Rate (2006 $) 

Industrial Manager $71.03 

Industrial Engineer/Technician $55.20 

Administrative Support $29.65 

Notes: These rates reflect adjustments of manufacturing sector’s average productivity increase of 3.7% per year for 6 quarters 

between 2006 Q2 and 2007 Q4, based on the estimate released by the Bureau of Labor Statistics in March 2008. 2006 Q2 labor 

rates were obtained from the ICF Nov, 2007 report. Refer to ICF Nov. 2007 Report’s supporting documentation for details on the 

wage rate calculation methodology. 

Source: Supporting Document for “Mandatory GHG Reporting Burden Assessment—Preliminary Draft,” ICF, 2007. 

Productivity and Costs, Fourth Quarter and Annual Averages, 2007. Revised, Bureau of Labor Statistics, March 5, 2008 

4.4.4.2 Allocating Responsibilities 

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

assigning hours, role of the labor categories were taken into consideration. Table 4-6 summarizes 

these roles. Table 4-7 summarizes the labor hours per labor category. These are presented for the 

two monitoring and reporting options (periodic sampling or the use of CEMS) for each of the 

two emission sources (ventilation shafts or degasification wells). 
4-16 

Table 4-6. Responsibilities for Regulation Compliance by Labor Category 

Responsibilities by Labor Category 

Cost Element 

Industrial 

Manager Lawyer 

Industrial 

Engineer/Technician

Administrative 

Support 

Per Facility/ 

Per 

Registration 

Facility Data 

To Be Provided by 

EPA - - - Per Facility 

Regulation Review 

To Be Provided by 

EPA - - - Per Facility 

Monitoring 

Plan Development 

To develop and 

review the 

monitoring plan 

To develop a 

monitoring plan Per Facility 

Equipment Purchase 

To approve the 

equipment purchase 

To identify and 

purchase the equipment Per Facility 

Material Sampling 

To review sampling 

data To conduct sampling Per Facility 

Start-up/Training 

To provide and 

acquire training To acquire training To acquire training Per Facility 

Reporting 

Data Documentation 

To Be Provided by 

EPA - - - Per Facility 

Report Submission 

To Be Provided by 

EPA - - - Per Facility 

Archiving and Recordkeeping 

Archiving Reports 

To Be Provided by 

EPA - - - Per Facility 

Auditing 

Audit 

To Be Provided by 

EPA - - - Per Facility 

Audit Follow-up 

To Be Provided by 

EPA - - - Per Facility 

 
Table 4-7. Labor Hours Assumed in the Analysis 

Total Annual Labor Hours Industrial 

Source 

Category Operating Period 

Industrial 

Manager Lawyer Industrial Engineer 

Admin 

Support 

Coal – Monitoring Ventilation Air

Coal Mining –

Sampling 

First Year 67 344 26 

Subsequent Years 20 256 20 

Coal Mining - First Year 188 428 128 

CEMS Subsequent Years 48 128 64 

Coal –Degasification Systems

Coal Mining – First Year 20 650 18 

Weekly 

Sampling 

Subsequent Years 20 616 12 

Coal Mining - First Year 62 190 8 

CEMS Subsequent Years 16 104 8 

4.4.4.3 Capital Cost Annualization and O&M Costs 

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

purchasing equipment for emissions detection and emissions measurement. This could include 

either equipment for continuous monitoring, or equipment for use in the periodic sampling. All 

costs are reported in 2006 U.S. dollars. Capital cost annualization was determined assuming a 7 

percent discount rate. Ventilation shaft and degasification well air sampling devices are assumed 

to have a 3 year lifetime (in the case of degasification wells, because well lives are assumed to 

average 3 years). Continuous monitoring equipment for gob gas vent hole degasification systems 

for longwall mines is also assumed to have a 3 year lifetime based on the same reasoning. From 

these factors, a capital recovery factor was calculated using the formula provided below: 

1)1(

)1(



  n

n

r

rr CRF

4-17 
4-18 

 

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

years. 

4.4.5 Emissions in Ventilation Air 

In the case of quarterly sampling of methane content and gas flow, coal mine operators 

would be required to duplicate the MSHA process of collecting air samples and ventilation rates, 

submitting the samples to a lab for analysis or making determinations on site, and developing 

estimates of emissions on their own. This process would require mine operators to purchase 

sampling equipment, train personnel in their use, develop emissions estimates based on the data 

collected, and report the results. Under this option, the operator would incur the capital and 

O&M costs involved in purchasing and maintaining the air sampling and testing equipment, and 

in sending air samples to an independent lab for analysis. 

Operators would be required to measure both the ventilation flow rates from the mine and 

collect samples for the determination of the methane composition of the ventilated air. A basic 

air sampling kit costs on the order of $300 per kit, and the price for gas analysis is estimated to 

be approximately $500 per sample. For purposes of estimating the costs of compliance 

associated with this rulemaking, each mine is assumed to acquire four mine air sample kits on 

site, and that these kits are assumed to have a three-year life. On average, two samples are 

assumed to be sent each quarter for analysis for each mine. Each mine was also assumed to 

acquire two air flow meters/anemometers. While the costs of these devices can range from as 

little as $50 to as much as $2,000,8

 for purposes of this assessment, a cost of $200 per meter was 

assumed 

Under this option: 

 Each facility would need to internally develop procedures for independently estimating 

ventilation air emissions. Facility managers would be required to review such procedures 

and results annually. Initial training would be required of personnel performing sampling, 

along with additional supplemental training over time of new personnel given this 

responsibility.

 Mine personnel would be required to take their own samples, determine ventilation air 

emissions, and report results to EPA annually. 

8

 http://www.omega.com/guides/Results.html 
4-19 

If operators use CEMS as the basis for emissions reporting for ventilation air emissions, 

they would be required to provide documentation on how emissions estimates were developed, 

as well as justification as to why the reported emissions are at least as accurate as that which 

would be obtained from quarterly sampling. If this option is pursued, the mine operator would 

not need to purchase sampling equipment. However, operators may want to have such equipment 

and conduct such sampling anyway, to verify and compare emissions estimates from the two 

approaches. 

Under this option: 

 Each facility would need to internally develop procedures for estimating ventilation air 

emissions based on the continuous monitoring data. Facility managers would be required 

to review such procedures and report results to EPA annually.

 Mine personnel would be required to operate and maintain continuous monitoring 

equipment for purposes of complying with these emissions reporting requirements. 

In this assessment, operators choosing this option were assumed to be only those with 

such systems already in place, and thus those that would incur minimal incremental costs for 

equipment. 

These activities would involve labor hours for industrial managers, industrial engineers or 

technicians, and administrative support, as summarized in Tables 4-6 and 4-7. 

4.4.6 Emissions from Degasification Systems 

Operators deploying degasification systems in underground mines would monitor 

emissions through continuous monitoring, conduct weekly sampling, or carry out some 

combination of both. If pre-mining degasification wells are either selling, destroying (flaring), or 

using the gas produced from such degasification systems, produced gas volumes are presumably 

already being measured, so additional capital costs would not be incurred. However, additional 

costs would be associated with system planning and implementation, including internally 

develop the methodology for estimating emissions avoided from coal mine degasification 

systems; and for acquiring results from monitoring systems quarterly, developing annual 

estimates, and reporting results to EPA. Methane liberated from these degasification systems 

would not be emitted where the methane is sold, used on site, or otherwise destroyed. 
4-20 

 

Gob gas vent hole wells and other wells where methane is vented, rather than recovered, 

are less likely to be currently monitored, so incremental costs for either installing meters on these 

wells, or for planning and implementing a sampling program, would be incurred. In addition all 

of the other system planning, implementation and reporting costs would also be incurred. 

A vast range of continuous flow meters are available for gas production wells;9

 and such 

flow meters are a standard feature of most gas production wellhead designs. Measurement 

packages are evolving to develop systems specifically appropriate for the characteristics of coal 

bed and coal mine degasification wells,10 with low production volumes, low pressures, and high 

water production rates. A wide variety of options are available, with costs ranging from $500 to 

$3,000 per instrument, depending on application and operating environment.11 Such 

instrumentation provides the capability for continuous monitoring. 

For degasification wells already deploying continuous monitoring, the incremental costs 

would only involve annual reporting of the degasified gas volumes produced and the disposition 

of this gas (sold, vented, consumed on site). 

Under the periodic sampling option, similar to that for ventilation air sampling, coal mine 

operators would be required to weekly determine flow rates and methane composition from 

degasification wells. Methane composition could be determined either by submitting samples to 

a lab for analysis, or from the use of methanometers as the degasification well site. (For purposes 

of this assessment, it was assumed that these costs were comparable, so no allocation between 

the two options was necessary.) This process would require mine operators to purchase air flow 

meters, methanometers, and/or sampling equipment, train personnel in their use, develop 

emissions estimates based on the data collected, and report the results. Under this option, the 

operator would have to incur the capital and O&M costs involved in purchasing and maintaining 

this equipment, and, if necessary, in sending air samples to an independent lab for analysis. 

In either case, the steps involved in this process include: 

9

 See, for example, http://www.gesensing.com/downloads/datasheets/br_126a.pdf

10 http://www.crimtech.com/manufactured/p-CBM.pdf 

11 http://www.instrumart.com/ProductList.aspx?CategoryID=3056, 
4-21 

 Each facility would need to internally develop procedures for estimating produced 

volumes and disposition of emissions from underground mine degasification systems.

Facility managers would be required to review such procedures and results annually.

 Mine personnel would be required to ensure that all monitoring equipment used is 

properly maintained and functioning. 

 Mine personnel would need to acquire results from monitoring activities, develop 

estimates of fugitive methane emissions based on these data, and report results to EPA. 

No incremental capital costs were assumed to be incurred by mine operators to monitor 

and/estimate the volume and disposition of methane produced from active underground coal 

mining degasification systems where the methane recovered is either sold, used on site, or 

otherwise destroyed, since these systems are presumably already being monitored. Additional 

costs would be incurred if emissions from such systems were based on the results of periodic 

sampling, since the sampling equipment needs to be purchased. In addition, as stated above, 

additional costs would be associated with system planning and implementation, and for acquiring 

results from monitoring systems quarterly, developing annual estimates, and reporting results to 

EPA 

For gob gas vent wells holes and any other degasification wells that do not currently 

continuously monitor degasified gas volumes produced, incremental costs would also be 

associated with either installing simple monitoring equipment on these remote gob gas vent 

holes, or in purchasing air flow meters/anemometers, methanometers, and/or sampling 

equipment. For purposes of this assessment, a cost of $200 per flow meter was assumed. The 

costs of methanometers range from $50 to $1,600. For purposes of this assessment, a capital 

cost of $300 was assumed. 

For cost estimation purposes, each mine is assumed to have one flow meter per well and 

one methanometers per well, and that these devices have a 3 year life. 

Comparing these costs with those reported above for periodic sampling with grab 

samples analyzed at a lab (the process assumed for estimating emissions from ventilation 

systems) shows that the use of gas flow meters and methanometers would be generally more cost 
4-22 

effective. Thus, this was the option assumed for all gob gas vent wells holes and any other 

degasification wells that do not currently continuously monitor degasified gas volumes produced. 

For continuous monitoring systems on degasification wells, incremental costs of $10,000 

per gob gas vent hole (including one meter installed and one backup) can be assumed where gas 

production is currently not monitored. At a 7% interest rate, this amounts to incremental 

annualized costs of $2,439 per well, assuming that the life of each gob gas vent hole is 3 years. 

4.4.7 Estimation of Facility Costs for Each Emission Source 

The total monitoring costs for monitoring fugitive emissions in mine ventilation systems 

was determined by multiplying the unit costs by the number of mines estimated by MSHA that 

exceed the reporting threshold of 100,000 cubic feet of methane per day. Estimated costs were 

considered for two monitoring and reporting options. However, given the high costs associated 

with installing new CEMS systems to monitor fugitive emissions in mine ventilation systems, it 

is assumed that only those facilities with such systems already in place would choose that option. 

Capital costs associated with monitoring emissions (and emissions collected) from mine 

degasification systems currently not being monitored (longwall mines using gob gas vent holes) 

was determined by multiplying the unit costs for such degasification well times the estimated 

number of degasification wells that are venting gas to the atmosphere (an estimated 500 wells 

initially, and 167 new wells per year thereafter). Operating costs were associated with the 21 

mines determined to be deploying degasification systems where the methane was vented. 

The incremental capital costs were assumed to be incurred by mine operators to monitor 

and/estimate the volume and disposition of methane from active underground coal mining 

degasification systems where the methane recovered is either sold, used on site, or otherwise 

destroyed from , since these systems are presumably already being monitored. Only the costs 

associated with system planning and implementation, and for acquiring results from monitoring 

systems quarterly, developing annual estimates, and reporting results to EPA were considered. 

These costs were applied to the 15 mines assumed to have such degasification systems. 

4.5 Cost Analysis for Subpart TT—Industrial Landfills 

4.5.1 Model facility development 

It was anticipated that most industrial landfills would be co-located at facilities that 

already are required to report based on the 25,000 tonnes CO2 equivalent (tCO2e) emissions 
4-23 

 

threshold. As such, four different options were evaluated to assess the impacts associated with 

different applicability requirements specific to industrial landfills. Option 1 is to have all 

industrial landfills report regardless of their size or emissions provided they were located at a 

facility that exceeds the 25,000 tCO2e reporting threshold. Option 2 is to limit the reporting 

requirements for industrial landfills to industrial “organic waste” landfills (at a facility that 

exceeds the 25,000 tCO2e reporting threshold). Option 3 is to limit the reporting requirements to 

industrial “organic waste” landfills that have a design capacity of 300,000 Mg or more (and that 

are located at facilities that exceed the 25,000 tCO2e reporting threshold). Option 4 is to limit 

the reporting requirements to industrial “organic waste” landfills that dispose of 20,000 Mg or 

more of waste annually (and that are located at facilities that exceed the 25,000 tCO2e reporting 

threshold). Option 1 through 4 include costs to determine the organic content of the waste 

materials; Option 4 also includes costs for mass weighing equipment both to determine 

applicability and to reduce uncertainty in the quantity of waste disposed. For the Industrial 

Landfill subpart, no costs were projected for monitoring gas collection systems because no 

industrial landfills are known to contain active gas collection systems.12 

For all options, costs were developed using the fully-burdened, “industrial” labor rates 

presented previously (generic EPA labor rate table). Labor estimates for various requirements 

were developed based on the anticipated number of technical/engineering labor hours required 

for each task. Labor hour estimates were developed separately for “landfill facility costs” 

(setting up the model, overall QA plan, reporting) and “waste stream costs” (determining DOC 

content and mass disposed). It was assumed that there are, on average, two waste streams that 

must be monitored per industrial landfill; the waste stream costs were added to the landfill 

facility costs to estimate the total labor estimates per landfill. 

Industrial management hours were estimated to be 5 percent of the technical labor hours 

and administrative support hours were estimated to be 10 percent of the technical labor hours. 

First year costs are higher than subsequent year costs due to the need to set-up the model, collect 

historical data for the first year, and to develop (or revise) quality assurance plans to cover the 

industrial landfill sources. 

12No industrial landfills were identified that have gas collection systems. If an industrial landfill has a gas collection 

system, additional monitoring costs would be incurred. These additional costs would be identical to the 

additional costs developed for municipal solid waste (MSW) landfills that have gas collection and recovery 

systems (see RIA for MSW Landfill subpart HH). 
4-24 

For all options, a small capital equipment cost was included for recordkeeping to cover 

the costs of a filing cabinet and electronic data storage media. Additionally, operating and 

material costs associated with sample analyses and reporting (copies, mailing charges) were also 

considered for each industrial landfill. 

For Option 4, capital equipment costs for weighing equipment were estimated to $20,000 

per affected facility based on data submitted by a public commenter on the proposed rule 

indicating that the installation of two industrial truck scales would cost $40,000. The capital 

costs were annualized based on 15 year equipment life and an annual interest rate of 7 percent. 

The operating and maintenance costs associated with the truck scales were assumed to be 

negligible. 

a. All costs associated with complying with the rulemaking both labor and non-labor 

(capital and O&M) for both startup and recurring costs for Options 1, 2, and 3. 

i. Initial planning costs were estimated for the time needed to read the rule 

and internally determine the reporting needs for the landfills. On average, 

it would take 10 industrial engineer/technician hours per industrial landfill. 

These planning costs are incurred only in the first year; no planning costs 

are anticipated in subsequent years. 

ii. First year costs for developing a QA/QC plan were estimated to be 8 

industrial engineer/technician hours per landfill. Subsequent year costs to 

implement the QA/QC plan were estimated to be 2 industrial 

engineer/technician hours per landfill on an annual basis. These costs 

apply to both MSW landfills and industrial landfills. 

iii. First year recordkeeping costs for industrial landfills were estimated to be 

9 industrial engineer/technician hours per industrial landfill, and 

subsequent year recordkeeping costs were also estimated to be 9 industrial 

engineer/technician hours per industrial landfill on an annual basis. 

iv. First year calculation costs for industrial landfills were estimated to be 16 

industrial engineer/technician hours per landfill. Subsequent year 

recordkeeping costs for were estimated to be 8 industrial 

engineer/technician hours per landfill on an annual basis. 

v. First year reporting costs for industrial landfills were estimated to be 4 

industrial engineer/technician hours per industrial landfill, and subsequent 

year recordkeeping costs were also estimated to be 4 industrial 

engineer/technician hours per industrial landfill on an annual basis. 

vi. Industrial management hours were estimated to be 5 percent of the 

technical labor hours and administrative support hours were estimated to 

be 10 percent of the technical labor hours for all planning, QA/QC, 

recordkeeping, calculating, and reporting activities. 

vii. Operating and material costs for waste analyses (volatile solids analysis 

for estimating degradable organic content) were estimated to be $50 per 

sample. Assuming 4 samples per year per industrial waste stream and 2 
4-25 

waste streams per industrial landfill, the operating and material costs for 

waste analyses were estimated at $400/year per landfill. 

viii. Capital costs associated with recordkeeping (filing cabinet and data 

storage device) were estimated to be $500 per industrial landfill, yielding a 

$55/year annualized cost of equipment (based on 15 year equipment life 

and an annual interest rate of 7 percent). Operating and material costs 

associated with recordkeeping and reporting (paper, copies, mailings) 

were estimated to be $40 per landfill per year. 

b. All costs associated with complying with the rulemaking both labor and non-labor 

(capital and O&M) for both startup and recurring costs for Option 4. 

i. Initial planning costs were estimated for the time needed to read the rule 

and internally determine the reporting needs for the landfills. On average, 

it would take 10 industrial engineer/technician hours per industrial landfill. 

These planning costs are incurred only in the first year; no planning costs 

are anticipated in subsequent years. 

ii. First year costs for developing a QA/QC plan were estimated to be 10 

industrial engineer/technician hours per landfill. Subsequent year costs to 

implement the QA/QC plan were estimated to be 2 industrial 

engineer/technician hours per landfill on an annual basis. These costs 

apply to both MSW landfills and industrial landfills. 

iii. First year recordkeeping costs for industrial landfills were estimated to be 

15 industrial engineer/technician hours per industrial landfill, and 

subsequent year recordkeeping costs were also estimated to be 15 

industrial engineer/technician hours per industrial landfill on an annual 

basis. 

iv. First year calculation costs for industrial landfills were estimated to be 16 

industrial engineer/technician hours per landfill. Subsequent year 

recordkeeping costs for were estimated to be 8 industrial 

engineer/technician hours per landfill on an annual basis. 

v. First year reporting costs for industrial landfills were estimated to be 4 

industrial engineer/technician hours per industrial landfill, and subsequent 

year recordkeeping costs were also estimated to be 4 industrial 

engineer/technician hours per industrial landfill on an annual basis. 

vi. Industrial management hours were estimated to be 5 percent of the 

technical labor hours and administrative support hours were estimated to 

be 10 percent of the technical labor hours for all planning, QA/QC, 

recordkeeping, calculating, and reporting activities. 

vii. Capital costs associated with monitoring equipment (industrial truck scale) 

were estimated to be $20,000 per industrial landfill, yielding a $2,196/year 

annualized cost of equipment (based on 15 year equipment life and an 

annual interest rate of 7 percent). 

viii. Operating and material costs for waste analyses (volatile solids analysis 

for estimating degradable organic content) were estimated to be $50 per 

sample. Assuming 4 samples per year per industrial waste stream and 2 
4-26 

waste streams per industrial landfill, the operating and material costs for 

waste analyses were estimated at $400/year per landfill. 

ix. Capital costs associated with recordkeeping (filing cabinet and data 

storage device) were estimated to be $500 per industrial landfill, yielding a 

$55/year annualized cost of equipment (based on 15 year equipment life 

and an annual interest rate of 7 percent). Operating and material costs 

associated with recordkeeping and reporting (paper, copies, mailings) 

were estimated to be $40 per landfill per year. 

4.5.2 Number of Landfills Reporting 

A key difference in the options is the number of landfills that need to report for each 

option. Based on data from the 1988 Report to Congress: Solid Waste Disposal in the United 

States (EPA, 1988), the number of landfills and the emissions covered by each of the options 

were estimated. These estimates are summarized in Table 4-8. 
4-27 

Table 4-8. Number of Entities and Emissions Covered by Industrial Landfill Options 

Option Description 

Number 

of Entities 

Covered 

(#) 

Percentage 

of Entities 

Covered 

(%) 

MTCO2e/ 

year 

Covered 

Percentage of 

MTCO2e/year 

Covered (%) 

1 All industrial landfills report 2,310 100% 15.4 100% 

2 Only “organic” waste industrial 

landfills report 

607 26.3% 14.8 96.1% 

3 

Only “organic” waste industrial 

landfills with design capacity of 

300,00 Mg or more report 

200 8.7% 13.7 89.0% 

4 

Only “organic” waste industrial 

landfills that accept 20,000 tons/yr or 

more of waste report 

100 4.3% 13.0 84.4% 

4.6 Cost Analysis for Subpart II—Industrial Wastewater 

Subpart II of this rule applies to the Industrial Wastewater Treatment Source Category. 

This subpart applies to certain processes used to treat industrial wastewater and wastewater 

treatment sludges at pulp and paper mills, food processing facilities, ethanol production facilities, 

and petroleum refineries. These processes are: anaerobic reactors, anaerobic lagoons, anaerobic 

digesters for sludge, and biogas destruction devices. Operators are required to report the amount 

of methane (CH4) these processes emit each year. The regulation specifies how operators must 

estimate methane emissions. These estimation methodologies require operators to monitor the 

amount of wastewater entering the anaerobic treatment process, the concentration of organic 

material in the wastewater prior to treatment, the amount of biogas recovered, and the 

concentration of methane in the recovered biogas. EPA estimated that these monitoring 

requirements would cost, on average, $4,083 per year per facility (total annualized costs) or $1.4 

million for the 358 facilities estimated to incur monitoring costs. This section describes how 

EPA estimated Subpart II monitoring costs and describes: 

 wastewater and biogas monitoring required by 40 CFR 98.354; 

 monitoring device, labor, and operating costs; 

 estimated facility wastewater flow rates and meter costs; 
4-28 

 annualized cost calculation; 

 EPA’s estimates of the number of facilities required to monitor and source 

category monitoring costs; and 

 changes from proposal. 

4.6.1 Wastewater and biogas monitoring required by 40 CFR Part 98.354 

Facilities that meet the reporting threshold specified in §98.351 are required to monitor 

the amount of wastewater treated in anaerobic processes, the concentration of organic material in 

the wastewater prior to this treatment, the amount of biogas recovered, and the concentration of 

methane in the recovered biogas. These monitoring requirements are summarized in Table 1. 

Table 4-9. Industrial Wastewater Treatment Monitoring Requirements 

Material Measured 

Monitoring 

Requirement Frequency 

Wastewater flow rate Once each calendar week that the system operates, 

with at least three days between measurements 

Wastewater influent to anaerobic 

lagoons and anaerobic reactors 

Wastewater COD or 

BOD5 concentration 

Once each calendar week that the system operates, 

with at least three days between measurements 

Biogas recovered from anaerobic Biogas flow rate Continuously 

lagoons, anaerobic reactors, and 

anaerobic sludge digesters 

Biogas methane 

concentration 

Once each calendar week that the system operates, 

with at least three days between measurements 

4.6.2 Monitoring device, labor, and operating costs 

EPA evaluated whether facilities are currently following the Subpart II monitoring 

requirements. For requirements that are not routinely followed, EPA estimated the costs that a 

typical facility would incur to meet the requirement. The estimates include one-time costs to 

purchase and install monitoring devices and recurring costs for analytical services, supplies, and 

labor. The one-time costs are capital costs, while recurring costs are annual costs. 

Wastewater Flow Rate. When the treatment system is operating, facilities are required to 

measure the flow rate of wastewater entering anaerobic wastewater treatment process once each 

calendar week, with at least three days between measurements. The flow measurement location 
4-29 

and collection period must correspond to the location and period used to collect samples 

analyzed for COD or BOD5 concentration. 

EPA assumed that facilities do not currently measure the flow of wastewater into the 

anaerobic treatment process. Thus, facilities would be required to install meters to meet the GHG 

Reporting Rule monitoring requirements. EPA assumed that each facility would install a flow 

meter, such as the McCrometer Ultra Mag® electromagnetic flow meter, equipped with a 

standard keypad display, or equivalent. Because these meters are designed to measure flow in 

full pipes, EPA assumed the wastewater from the industrial facility drops into a wet well/lift 

station and is pumped from there into the anaerobic treatment unit. The flow meter is placed on 

the positive pressure pipe from the lift station at a point near the lagoon or reactor where influent 

sampling would occur. Installation costs include welded flanges to attach meters to existing 

piping, plumbing and electrical (based on cost factors obtained from R.S. Means Building 

Construction Cost Data, 59th Edition, 2001), and costs for permits, scheduling, and contractor 

markup (handling, procuring, subcontracting, change orders, overhead and profit). These meters 

are factory calibrated, have no moving parts, and require minimal maintenance. For these 

reasons, EPA did not include costs for flow meter maintenance or calibration. Flow meter cost is 

based on the pipe size and flow measured, as presented in Table 2. 

Table 4-10. Wastewater Flow Meter Installed Costs (2009$) 

Pipe diameter 

(inches) 

Flow 

(MGD) 

Meter Cost 

($ ) Installation Cost 

Total Installed Cost 

($) 

4 0.01 to 2.8 4,266 a 

8 0.05 to 11 3,685 3,550 7,235 

16 0.16 to 44 5,830 5,922 11,752 

24 0.4 to 99 8,910 9,064 17,974 

a

 – Installed costs for the 4 inch meter were extrapolated from a cost curve developed from costs for the 8, 16, and 

24 inch meters. 

EPA assumed that facilities would incur labor costs for collecting and organizing flow 

rate measurement data. EPA assumed that this activity would require two hours per month of a 

Grade 8 wastewater treatment plant operator. EPA further assumed the labor cost for a Grade 8 

operator is $20/hour, so that the annual labor costs for flow measurement are estimated as 2 

hour/month x $20/hour x 12 month/year = $480/year. (See further discussion of labor costs 

below.) 
4-30 

Concentration of Organic Material in the Wastewater Prior to Treatment. Facilities are 

required to collect samples of the wastewater entering the anaerobic wastewater treatment 

process. The samples must be collected after all preliminary and primary treatment steps (e.g., 

after grit removal, primary clarification, oil-water separation, dissolved air flotation, or similar 

solids and oil separation processes). When the treatment system is operating, facilities are 

required to collect and analyze wastewater samples for COD or BOD5 concentration once each 

calendar week, with at least three days between measurements. 

EPA assumed that facilities that treat wastewater with anaerobic lagoons or reactors 

currently sample and analyze their treated wastewater discharges according to their permit 

requirements. These requirements may be imposed by a National Pollution Discharge 

Elimination System (NPDES) permit (for facilities that discharge to lakes or streams) or 

pretreatment permits (for facilities that discharge to municipal sewer systems). Because facilities 

currently sample and analyze their treated wastewater, EPA assumed that they have all necessary 

capital equipment, such as automatic compositors, to conduct wastewater sampling activities. 

EPA assumed that facilities would contract with an analytical laboratory for analysis of 

their samples. EPA assumed the cost for analysis for COD or BOD5 were the same, $30/sample. 

Costs for sample analysis were thus estimated as $30/sample x 1 sample/week x 52 weeks/year = 

$1,560/year. 

EPA further assumed that facilities would incur labor costs for collecting the sample. 

EPA assumed that this activity would require one hour per sample of a Grade 8 wastewater 

treatment plant operator. EPA further assumed the labor cost for a Grade 8 operator is $20/hour, 

so that the annual labor costs for sample collection are estimated as 1 hour/week x $20/hour x 52 

weeks/year = $1,040/year. Total annual costs for wastewater sampling and analysis were 

estimated as $1,560 + $1,040 = $2,600/year. 

Biogas Flow Rate. For each anaerobic process (such as anaerobic reactor, digester, or 

lagoon) from which biogas is recovered, facilities must continuously measure the gas flow rate 

and determine the cumulative volume of gas recovered. Facilities must also determine the 

methane concentration at a location near or representative of the location of the gas flow meter. 

Facilities must install, operate, maintain, and calibrate a gas flow meter capable of continuously 

measuring the volumetric flow rate of the recovered biogas using one of the methods specified in 

paragraphs §98.354 (g)(1) through (g)(8) or as specified by the manufacturer. 

EPA assumed that facilities that recover biogas from wastewater treatment processes 

such as anaerobic reactors, digesters, or lagoons currently operate continuous gas flow rate 
4-31 

measurement devices that meet the requirements of §98.354 (g) and thus would incur no 

additional capital or operating costs to comply with this monitoring requirement. 

Biogas Methane Concentration. For each anaerobic process (such as an anaerobic 

reactor, digester, or lagoon) from which biogas is recovered, facilities must measure the methane 

concentration either continuously or intermittently at least once each calendar week that the 

system operates, with at least three days between measurements. As specified in §98.353(c), they 

must also determine the temperature, pressure, and moisture content of the recovered biogas as 

necessary to accurately determine the gas flow rate and methane concentration. Facilities are also 

required to calibrate the gas composition monitors prior to the first reporting year and recalibrate 

the monitors either annually or at the minimum frequency specified by the manufacturer. 

For the purpose of estimating costs for compliance with Subpart II of the GHG Reporting 

Rule, EPA assumed that facilities that recover biogas from wastewater treatment processes do 

not currently monitor the gas composition and would incur costs to install and operate gas 

composition monitors. EPA assumed that facilities would conduct semi-continuous monitoring, 

such that they determine methane concentration once per week. There are many different 

methods for measuring biogas methane concentration. To estimate compliance costs, EPA 

assumed that facilities would install and operate an Inova 1316-1 multi-gas nondispersive 

infrared (NDIR) monitor, or equivalent, at an installed cost of $5,900. NDIR monitors do not 

require temperature or moisture compensation. EPA assumed that the monitor would be housed 

in a temperature-controlled, NEMA enclosure, protected from the elements. EPA further 

assumed that the monitor would be installed following in-line devices that control the moisture 

and hydrogen sulfide content of the biogas stream. 

EPA assumed that facilities would purchase gas calibration supplies at a cost of 

$200/year. EPA further assumed that facilities would incur labor costs for calibration of the gas 

analyzer and reporting annual methane recovery and emissions. EPA assumed that this activity 

would require 14 hours per year at a labor rate of $50/hour, so that the annual labor costs for 

monitoring methane concentration and reporting methane emissions were estimated as 14 

hours/year x $50/hour = $700/year. 

Labor Costs. EPA assumed that wastewater samples and emission calculations will be 

performed by a Grade 8 Wastewater Treatment Plant Operator. Grade 8 wastewater treatment 

plant operators provide secondary treatment of wastewater in addition to the pretreatment and 

primary treatment performed at Grade 7. Grade 8 operators do more extensive testing than Grade 

7 operators to determine such things as BOD5, suspended and dissolved solids, and dissolved 

oxygen. Operators at this level record the results in standardized reports designed to meet 
4-32 

 

Federal and State regulations.13 Labor costs for a Grade 8 wastewater treatment plant 

operator are estimated to be $20 an hour on average.14 EPA assumed that labor costs for a 

treatment plant supervisor is $40 per hour. EPA also assumed that operation of biogas 

monitoring equipment requires more skilled staff. These tasks are assumed to require labor at a 

cost of $50 per hour. 

Monitoring Cost Elements. Unit costs EPA assumed that facilities would incur to comply 

with Subpart II of the GHG Reporting Rule are summarized in Table 3. 

13 Federal Wage System Job Grading Standard for Wastewater Treatment Plant Operating, 5408, TS-64 May 1992. 

14 U.S. Office of Personnel Management, Salaries and Wages, SALARY TABLE 2009-GS, January 2009. 
4-33 

Table 4-11. Monitoring Cost Elements (2009$) 

Monitoring Element Equipment Assumptions Capital Cost Operation Assumptions 

Annual 

Costs 

Wastewater influent to anaerobic lagoons and anaerobic reactors

Wastewater flow rate no baseline flow meters

costs for McCrometer Ultra-Mag, 

plus installation;

cost based on flow

$4,266 to $10,116a no calibration required 

no maintenance required 

collect and organize flow data 

1x/month 

2 hr/month of Grade 8 WWTP 

operator @ $20/hr 

$480

Wastewater COD or BOD5

concentration 

all plants have needed sampling 

equipment

0 analysis cost $30/sample 

52 samples/year 

1 hr labor/sample @ $20/hr 

$2,600

Calculations and reporting na 0 8 hr/yr of Grade 8 WWTP 

operator @ $20/hr 

+ 1 hr review, supervisor @ 

$40/hr 

$200

Biogas recovered from anaerobic lagoons, anaerobic reactors, and anaerobic sludge digesters

Biogas flow rate all plants that recover biogas have 

continuous flow meters installed

0 no additional calibration and 

maintenance 

$0

Biogas methane concentration No baseline gas composition 

monitors. Costs for Inova 1316-1 

multi-gas NDIR monitor, 

includes installation

$5,900 gas analyzer calibration supplies $200

Calculations and reporting na $0 labor to report annual methane 

recovery and emissions and to 

calibrate the gas analyzer: 14 

hr/yr 

@ $50/hr 

$700

a

 – Flow meter cost is a function of flow, see Table 5.

4.6.3 Estimated facility wastewater flow rates and meter costs 

EPA assumed that facilities do not currently measure the flow of wastewater into the 

anaerobic treatment process and thus would be required to install meters. Flow meter cost is 

based on the pipe size and flow measured (see Table 2). For this reason, EPA estimated facility 

wastewater flow rates. EPA estimated wastewater flow rates for pulp and paper mills, food 

processing facilities, ethanol production facilities, and petroleum refineries. 
4-34 

Pulp and Paper Mills. EPA most recently revised the regulations limiting pollutant 

discharges for the pulp, paper, and paperboard industry in 1998. Information collected in support 

of this rulemaking, is available in the Development Document for Proposed Effluent Limitations 

Guidelines and Standards for the Pulp, paper, and Paperboard Point Source Category, EPA821-R-93-019, October 1993. Table 11-24 of this document presents the flow rate of wastewater 

treated in 16 aerated stabilization basins. The flow rates ranged from 1 to 50 million gallons/day 

(MDG) with median approximately 10 MGD. EPA assumed that flow rates of wastewater treated 

in anaerobic lagoons are similar to the flow rates treated in aerobic stabilization basis. EPA 

further notes that pulp and paper mills are among the largest industrial water users and many 

mills have flow rates greater than 50 MGD. For estimating costs of wastewater flow meters, EPA 

assumed the meter sizes presented in Table 4 would be required. 

Table 4-12. Wastewater Flow Meters for Pulp and Paper Mills 

Percent of Pulp and Paper Mills 

Meter Size 

(pipe diameter, inches) 

Flow Range 

(MGD) 

50 8 0.05 to 11 

40 16 0.16 to 44 

10 24 0.4 to 99 

Based on this distribution and the meter costs presented in Table 2, EPA estimated the 

average wastewater flow meter cost for a pulp and paper mill would be $10,116. 

Food Processing Facilities. EPA most recently revised regulations limiting pollutant 

discharges for meat and poultry products category in 2004. Information collected in support of 

this rulemaking, is available in the Technical Development Document for the Final Effluent 

Limitations Guidelines and Standards for the Meat and Poultry Products Point Source Category 

(40 CFR 432), EPA-821-R-04-011, 2004. Table 6-3 of this document reports that a hog plant and 

a cattle plant each generated 4 MGD of wastewater. EPA also found wastewater treatment design 

flow data reported in its NPDES monitoring databases for facilities in SIC 2011 (meat packing 

plants) or 2013 (sausages and other prepared meat products). The average design flow was 0.8 

MGD. EPA concluded that food processing flows are typically less than 11 MGD. Further, for 

purposes of estimating monitoring costs, EPA assumed food processing facilities would require 

an 8 inch flow meter, at an installed cost of $7,235. 
4-35 

Ethanol Production Facilities. In support of EPA’s inventory of greenhouse gas 

emissions, EPA reviewed ethanol production in the United States and made initial estimates of 

the GHG emissions from wastewater treatment operations conducted at these facilities. The 

results of this review are presented in Memorandum: Assessment of Greenhouse Gas Emissions 

from Wastewater Treatment of U.S. Ethanol Production Wastewaters, ERG, 2006. EPA found 

that wastewater discharges from dry milling ethanol plants ranged from 0.04 to 0.6 MGD. 

Although flow rates for wet milling plants were not presented in the memorandum, the authors 

noted that wet milling operations were generally smaller than dry milling operations. EPA 

concluded that ethanol production facility flows are typically less than 3 MGD. Further, for 

purposes of estimating monitoring costs, EPA assumed ethanol production facilities would 

require a 4 inch flow meter, at an installed cost of $4,266.

Petroleum Refineries. EPA’s Office of Water reviewed petroleum refinery pollutant 

discharges in 1992 – 1993, and published the results in the Preliminary Data Summary for the 

Petroleum Refining Category, April 1996. At that time, EPA found that wastewater flows ranged 

from 0.4 to 8 MGD, with median flow rate of 1.5 MGD. EPA concluded that petroleum refinery 

flows are typically less than 11 MGD. Further, for purposes of estimating monitoring costs, EPA 

assumed petroleum refineries would require an 8 inch flow meter, at an installed cost of $7,235. 

Meter Capital Costs. The flow rates and meter sizes and costs that EPA assumed that 

facilities would incur to comply with Subpart II of the GHG Reporting Rule are summarized in 

Table 5 

Table 4-13. Wastewater Flow Meter Sizes and Costs 

Source Category 

Flow Range 

(MGD) 

Meter Size 

(pipe diameter, inches) 

Meter Installed Cost 

 (2009 $) 

Pulp and Paper Mills 1 to 100 8 to 24 10,116 

Food Processing Facilities less than 11 8 7,235 

Ethanol Production Facilities less than 3 4 4,266 

Petroleum Refineries less than 11 8 7,235 
4-36 

Annualized costs

EPA assumed that the capital equipment lifetime was 20 years and used that lifetime and 

an interest rate of 7 percent to annualize capital costs. Annualized capital costs were calculated 

using the formula: 

Annual cost = capital cost*{[0.07*(1+0.07)20]/[(1+0.07)20-1]}

Estimated number of facilities required to monitor and source category monitoring costs

Only facilities that meet the reporting thresholds specified in §98.351 are required to 

report the methane emitted from their industrial wastewater treatment operations. Thus, only a 

subset of pulp and paper mills, food processing facilities, ethanol production facilities, and 

petroleum refineries must meet the monitoring requirements in §98.354. Further, only this subset 

of facilities will incur monitoring costs. 

EPA estimated the number of pulp and paper mills, food processing facilities, ethanol 

production facilities, and petroleum refineries that would be required to report in order to 

estimate monitoring costs. EPA’s estimates follow the assumptions used in EPA’s Inventory of 

U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2007. April 2009 (the 2007 Inventory). 

Pulp and Paper Mills. For the purpose of this cost estimate, EPA assumed that there are 

565 pulp and paper mills (Development Document for Proposed Effluent Limitations Guidelines 

and Standards for the Pulp, paper, and Paperboard Point Source Category, EPA-821-R-93-019, 

October 1993). Based on assumptions presented in Table 8-11 of the 2007 Inventory, EPA 

estimated that 25% (141) of these mills have anaerobic secondary treatment. Further, EPA 

assumed that all 141 mills with anaerobic secondary treatment would be required to report their 

methane emissions15. EPA estimated that none of these mills recover biogas from their anaerobic 

wastewater treatment. Thus, EPA assumed that 141 pulp and paper mills would incur costs for 

monitoring wastewater flow rate and for collecting and analyzing samples for COD or BOD5

concentration. EPA estimated that no mills would incur costs for monitoring biogas flow rate or 

biogas methane concentration. EPA estimated that pulp and paper mills would incur $598,000 in 

total annualized costs to meet the monitoring requirements of the GHG reporting rule. 

 

15 Pulp and paper mills are required to report if they emit 25,000 metric tons CO2e or more per year in combined 

emissions. See §98.2(a)(2). 
4-37 

Food Processing Facilities. Food processing facilities are required to report their GHG 

emissions if they exceed 25,000 metric tons CO2e per year in combined emissions from 

stationary fuel combustion units, industrial landfills, and industrial wastewater treatment. 

However, for the purpose of this cost estimate, EPA assumed only food processing facilities that 

exceed 25,000 metric tons CO2e per year in emissions from industrial wastewater treatment 

would incur monitoring costs. 

EPA’s estimates of the number of food processing facilities meeting the reporting 

threshold are presented in the Technical Support Document for Industrial Wastewater Treatment. 

EPA estimated that 13 meat processing facilities exceed the 25,000 metric tons CO2e per year 

threshold and would be required to report the methane emitted from their industrial wastewater 

treatment operations. EPA did not have sufficient information to estimate the number of poultry 

processing facilities that exceed the 25,000 metric ton threshold, but estimated that up to 50 

facilities emitted more than 10,000 metric tons CO2e per year. For the purpose of this cost 

estimate, EPA assumed that all 50 of these facilities would incur monitoring costs. EPA 

estimated that no fruit and vegetable processing facilities exceed the 25,000 metric tons CO2e 

per year threshold and thus they would not be required to report. 

Thus, EPA assumed that 63 food processing facilities (13 meat processors and 50 poultry 

processors) would be required to report the methane emitted from their industrial wastewater 

treatment operations. EPA estimated that none of these plants recover biogas from their 

anaerobic wastewater treatment. Thus, EPA assumed that 63 food processing facilities would 

incur costs for monitoring wastewater flow rate and for collecting and analyzing samples for 

COD or BOD5 concentration. EPA estimated that no food processing facilities would incur costs 

for monitoring biogas flow rate or biogas methane concentration. EPA estimated that food 

processing facilities would incur $250,000 in total annualized costs to meet the monitoring 

requirements of the GHG reporting rule. 

Ethanol Production Facilities. Ethanol production facilities are required to report their 

GHG emissions if they exceed 25,000 metric tons CO2e per year in combined emissions from 

stationary fuel combustion units, industrial landfills, and industrial wastewater treatment. 

However, for the purpose of this cost estimate, EPA assumed only ethanol production facilities 

that exceed 25,000 metric tons CO2e per year in emissions from industrial wastewater treatment 

would incur monitoring costs. 

Using data reported by the Renewable Fuels Association, EPA estimated there were 170 

operating ethanol production facilities as of January 2009. EPA estimated that 85% (145) of 

these facilities used dry milling operations and 15% (25) used wet milling. Based on assumptions 
4-38 

 

presented in Table 8-11 of the 2007 Inventory, EPA estimated that anaerobic wastewater 

treatment is used by 75% (108) of the dry milling facilities and 33% (8) of the wet milling 

facilities, or a total of 116 ethanol production facilities. 

EPA’s estimates of the number of ethanol production facilities meeting the reporting 

threshold are presented in the Technical Support Document for Industrial Wastewater Treatment. 

EPA assumed that four (4) of the 116 ethanol production facilities that use anaerobic wastewater 

treatment emits methane in excess of the 25,000 metric tons CO2e per year threshold. EPA also 

assumed that these four facilities recover biogas from its anaerobic wastewater treatment. EPA 

estimated ethanol production facilities would incur $20,600 in total annualized costs to meet the 

monitoring requirements of the GHG reporting rule. 

Petroleum Refineries. Based on data from the Energy Information Administration, EPA 

determined that there were 150 operable petroleum refineries as of January 2009. Using 

assumptions presented in Table 8-11 of the 2007 Inventory, EPA estimated that 100% (150) of 

these refineries have anaerobic secondary treatment. Further, EPA notes that all petroleum 

refineries are required to report their methane emissions16. EPA estimated that none of the 

refineries recover biogas from their anaerobic wastewater treatment. Thus, EPA assumed that 

150 petroleum refineries would incur costs for monitoring wastewater flow rate and for 

collecting and analyzing samples for COD or BOD5 concentration. EPA estimated that no 

refineries would incur costs for monitoring biogas flow rate or biogas methane concentration. 

EPA estimated that petroleum refineries would incur $594,000 in total annualized costs to meet 

the monitoring requirements of the GHG reporting rule.

Estimated Monitoring Costs. The total estimated monitoring costs are presented in Table 

6. 

Changes from proposal 

The estimated costs presented in this memorandum differ from the estimated costs of the 

proposed Subpart II as follows: 

At proposal, EPA assumed that all facilities were equipped with flow meters to measure 

the flow of wastewater into the anaerobic treatment units. In response to comments on the 

proposed rule, EPA revised this assumption. The estimated costs presented in this memorandum 

16 All petroleum refineries must report emissions from all source categories and GHGs for which calculation 

methodologies are provided in the rule. See §98.2(a)(1). 
4-39 

are based on the assumption that no facilities currently meter the wastewater flow into their 

anaerobic treatment units. 
4-40 

Table 4-14. Industrial Wastewater Treatment Monitoring Costs 

National (Scaled-Up) Estimated Costs National (Scaled-Up) Esti

Category

No. of 

Plants 

Required 

to Report

%Plants 

with 

Anaerobic 

Treatment

No. of 

Plants 

with 

Anaerobic 

Treatment

No. of 

Plants 

with CH4 

Recovery

WW 

Monitoring 

Costs -Cap

WW 

Monitoring 

Costs -

Annualized 

Cap 

WW 

Monitoring 

Costs -

Annual 

WW 

Monitoring 

Costs -TAC 

CH4 

Recovery 

Monitoring 

Costs -Cap

CH4 

Recovery 

Monitoring 

Costs -

Annualized 

Cap 

CH

Recov

Monit

Cos

Ann

Pulp and paper 565 25% 141.25 0 $1,428,843 $134,873 $463,300 $598,173 0 $0 $0 Food Processing 63 100% 63 0 $455,805 $43,025 $206,640 $249,665 $0 $0 $0 Ethanol - wet mill 15% of 170 mills 

4 100% 4 4 $17,064 $1,611 $13,120 $14,731 $23,600 $2,228 $3,6

Ethanol - dry mill 85% of 170 mills 

0 75% 0 0 $0 $0 $0 $0 $0 $0 $0 

Petroleum Refineries 

150 100% 150 0 $1,085,250 $102,440 $492,000 $594,440 $0 $0 $0 

Total 355.25 

Cap – capital costs TAC – total annualized costs (annualized capital costs plus annual costs) 
At proposal, EPA assumed that non-continuous monitoring of biogas recovered from 

anaerobic digestion systems would require a hand held gas composition analyzer, a temperature 

sensor, and a gas pressure sensor. EPA estimated the total cost for these devices to be $1,000. 

EPA obtained updated information on the installed cost of a multi-gas NDIR monitor 

(temperature and pressure compensation are not required for this type of monitor). EPA 

estimated the installed cost for this monitor to be $5,900. 

At proposal, EPA assumed that wastewater sampling and analysis would be conducted 

once per month. The final regulation requires sampling and analysis once each calendar week 

that the system operates, with at least three days between measurements. EPA increased the 

estimated costs for wastewater sampling and analysis to reflect this increased frequency. EPA 

did not change its estimates of the costs and labor required per sample. 

EPA did not change its estimates of the labor and materials required to conduct the 

monitoring program and report methane emissions to EPA. 

4.7 Public Sector Burden 

EPA estimates the public sector burden to be $343,582 per year for verification activities, 

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. 

4-41 
SECTION 5

ECONOMIC IMPACT ANALYSIS 

EPA has prepared an EIA to provide decision makers with a measure of the social costs 

of using resources to comply with the proposed GHG reporting requirements. As noted in EPA’s 

(2000) Guidelines for Preparing Economic Analyses, several tools are available to estimate 

social costs and range from simple direct compliance cost methods to the development of a more 

complex market analysis that estimates market changes (e.g., price and consumption) and 

economic welfare changes (e.g., changes in consumer and producer surplus). Given data 

limitations and the size scope of the proposed rule, EPA has used the direct compliance cost 

method as a measure of social costs. 

5.1 Selected of Reporting Thresholds 

5.1.1 Subpart T- Magnesium Production 

EPA considered and selected emissions thresholds of 1,000 metric tons CO2e, 10,000 

metric tons CO2e, 25,000 metric tons CO2e,, and 100,000 metric tons CO2e, as shown in Tables 

5-1. Under the rule, magnesium metal production and parts casting facilities would have to 

report their total GHG emissions if those emissions exceeded 25,000 metric tons CO2e. This 

threshold covers all currently identified operating U.S. primary and secondary magnesium 

producers and most die casters, accounting for over 99 percent of emissions from these source 

categories. The proposed emissions threshold of 25,000 metric tons CO2e, is equal to emissions 

of 1,046 kg of SF6 ; 19,231 kg of HFC–134a; or 25,000,000 kg of CO2 or FK 5–1–2. Other 

emission threshold options that we considered were 1,000 metric tons CO 2 e, 10,000 metric tons 

CO2e, and 100,000 metric tons CO2e. The 10,000 metric tons CO2e, emission threshold yielded 

results identical to those of the selected option. 

Table 5-1. Threshold Analysis for Subpart T – Magnesium Production 

Emissions Covered Facilities Covered 

Emission 

Threshold 

Level (metric 

tons CO2e/yr) 

Total 

National 

Emissions 

(metric tons 

CO2e/yr) 

Total 

Number of 

Facilities 

metric tons 

CO2e/yr Percent Facilities Percent 

1,000 3,200,000 13 2,954,559 92% 13 100.0% 

10,000 3,200,000 13 2,939,741 92% 11 85.0% 

25,000 3,200,000 13 2,939,741 92% 11 85.0% 

100,000 3,200,000 13 2,872,982 90% 9 69.0% 

5-1 
The emissions based threshold was selected over the capacity based threshold for several 

reasons. The emissions based threshold is simple to evaluate because magnesium production and 

processing facilities can use readily available data regarding consumption of SF6 and would also 

possess similar data for alternatives such as HFC–134a as these are phased-in over time. To 

determine whether they exceeded the thresholds, magnesium facilities would multiply the total 

consumption of each of these gases by a GWP-unit conversion factor that could be compared to 

the 25,000 metric ton threshold. The equation for this calculation is provided in the proposed 

regulatory text. 

The emissions-based threshold of 25,000 metric tons CO2e also takes into account the 

variability in cover gas identities, usage rates, and process conditions. Alternatives to SF6 have 

considerably lower GWPs than SF6. In facilities where SF6 is used, the usage rate can vary by an 

order of magnitude depending on the casting process and operating conditions. Therefore, cover 

gas emissions are not well predicted by production capacity. Because emissions of each cover 

gas are assumed to equal use, and facilities are expected to track gas use in the ordinary course of 

business, facilities should have little difficulty determining whether or not they must report under 

this rule. For a full discussion of the threshold analysis, please refer to the Magnesium 

Production TSD (EPA–HQ–OAR–2008– 0508–020). 

5-2 
5-3 

5.1.2 Subpart FF- Underground Coal Mines 

All active underground coal mines for which CH4 from the ventilation system is sampled 

quarterly by MSHA (or on a more frequent basis), are required to report under this rule. MSHA 

conducts quarterly testing of CH4 concentration and flow at mines emitting more than 100,000 cf 

CH4 per day. We selected this threshold because subjecting underground mine operators to a 

new emissions-based threshold is unnecessarily burdensome, as many of these mines are already 

subject to MSHA regulations. The MSHA threshold for reporting of 100,000 cf CH4 per day 

covers approximately 94 percent of the CH4 emitted from underground coal mine ventilation 

systems and about 86 percent of total emissions from underground mining (including stationary 

fuel combustion emissions at mine sites, as shown in Table 5-2). 

Table 5-2. Threshold Analysis for Subpart FF –Underground Coal Mines 

Emissions Covered Facilities Covered 

Emission 

Threshold 

Level (metric 

tons CO2e/yr) 

Total 

National 

Emissions 

(metric tons 

CO2e/yr) 

Total 

Number of 

Facilities 

metric tons 

CO2e/yr Percent Facilities Percent 

MSHA 

reporting 

 

39,520,000 

 

612 

 

33,823,404 85.6% 114 18.6% 

1,000 

 

39,520,000 

 

612 

 

33,945,446 85.9% 125 20.4% 

10,000 

 

39,520,000 

 

612 

 

33,926,526 85.8% 122 19.9% 

25,000 

 

39,520,000 

 

612 

 

33,536,385 84.9% 100 16.3% 
5.1.3 Subpart TT- Industrial Waste Landfills 

Table 5-3. Threshold Analysis for Subpart TT– Industrial Waste Landfills 

Emissions Covered Facilities C

Description of Option 

Total National 

Emissions 

(metric tons 

CO2e/yr) 

Total Number of 

Facilities 

metric tons 

CO2e/yr Percent Facilities 

All industrial landfills report 15.4 2,310 15.4 100.0% 2,310 Only “organic” waste industrial landfills report 15.4 2,310 14.8 96.1% 607 Only “organic” waste industrial landfills with design capacity of 300,00 Mg or more report 15.4 2,310 13.7 89.0% 200 Only “organic” waste industrial landfills that accept 20,000 tons/yr or more of waste report 15.4 2,310 13.0 84.4% 100 All industrial landfills report 15.4 2,310 15.4 100.0% 2,310 

5-4 
5.1.4 Subpart II- Industrial Wastewater Treatment 

Table 5-4. Threshold Analysis for Subpart II– Industrial Wastewater Treatment (Ethanol) 

Emissions Covered Facilities Covered 

Emission 

Threshold 

Level (metric 

tons CO2e/yr) 

Total 

National 

Emissions 

(metric tons 

CO2e/yr) 

Total 

Number of 

Facilities 

metric tons 

CO2e/yr Percent Facilities Percent 

1,000 

Not 

Estimated 140 Not Estimated >100 >72 

10,000 

Not 

Estimated 140 Not Estimated >94 >67 

25,000 

Not 

Estimated 140 Not Estimated >86 >61 

100,000 

Not 

Estimated 140 Not Estimated >43 >31 

Table 5-5. Threshold Analysis for Subpart II– Industrial Wastewater Treatment (Food 

Processing) 

Emissions Covered Facilities Covered 

Emission 

Threshold 

Level (metric 

tons CO2e/yr) 

Total 

National 

Emissions 

(metric tons 

CO2e/yr) 

Total 

Number of 

Facilities 

metric tons 

CO2e/yr Percent Facilities Percent 

1,000 

Not 

Estimated 5,719 Not Estimated 802 14.0% 

10,000 

Not 

Estimated 5,719 Not Estimated 170 3.0% 

25,000 

Not 

Estimated 5,719 Not Estimated 100 1.7% 

100,000 

Not 

Estimated 5,719 Not Estimated 10 0.2% 

5-5 
Table 5-6. Threshold Analysis for Subpart II– Industrial Wastewater Treatment (Pulp and 

Paper) 

Emissions Covered Facilities Covered 

Emission 

Threshold 

Level (metric 

tons CO2e/yr) 

Total 

National 

Emissions 

(metric tons 

CO2e/yr) 

Total 

Number of 

Facilities 

metric tons 

CO2e/yr Percent Facilities Percent 

1,000 57,700,000 425 57,700,000 100.0% 425 100.0% 

10,000 57,700,000 425 57,700,000 100.0% 425 100.0% 

25,000 57,700,000 425 57,700,000 100.0% 425 100.0% 

100,000 57,700,000 425 57,527,000 99.7% 410 96.5% 

Table 5-7. Threshold Analysis for Subpart II– Industrial Wastewater Treatment 

(Petroleum Refineries) 

Emissions Covered Facilities Covered 

Emission 

Threshold 

Level (metric 

tons CO2e/yr) 

Total 

National 

Emissions 

(metric tons 

CO2e/yr) 

Total 

Number of 

Facilities 

metric tons 

CO2e/yr Percent Facilities Percent 

1,000 204,750,000 150 204,750,000 100.00% 150 100.0% 

10,000 204,750,000 150 204,740,000 99.995% 149 99.3% 

25,000 204,750,000 150 204,690,000 99.971% 146 97.3% 

100,000 204,750,000 150 203,750,000 99.512% 128 85.3% 

5.1.5 National Emissions Covered Under Selected Thresholds 

The total national emissions covered under the selected options are 190.6 MtCO2e (Table 

5-8). The majority of these covered emissions are from pulp and paper covered by Subpart AA 

(140 MtCO2e). Although the majority of cost and emissions information reported in this 

economic and small entity analysis is organized by subpart, EPA also mapped each subpart to an 

industry included in the North American Industry Classification System (NAICS); the mapping 

allows the cost data to be used in conjunction with other economic census data. 

5-6 
Table 5-8. Estimates of Emissions (MtCO2e) Reported in 2008 Under the Selected Option 

Subpart Emissions Coverage (MtCO2e) 

Subpart T- Magnesium Production 2.9 

Subpart FF – Underground Coal Mines 33.9 

Subpart TT – Industrial Waste Landfills 13.7 

Subpart II – Industrial Wastewater Treatment 262.4a

Total 313.4 

a

Includes total covered emissions estimates for pulp and paper and refinery industries. Ethanol and food processing emissions 

were not estimated. 

5.2 National Cost Estimates 

As shown in Table 5-6, the total national costs for the selected option are estimated to be 

$7.0 million in the first year and $5.5 million in subsequent years ($2006). This includes a public 

sector burden estimate of $0.3 for program implementation and verification activities. Subparts 

bearing the greatest share of the ongoing private costs of the rule are the coal mining industry (51 

percent). 

5-7 
Table 5-9. National Annualized Mandatory Reporting Costs Estimates (2006$): T, FF, TT, 

and II 

First Year Subsequent Years 

Subpart 

2007 

NAICS Millions Share Millions Share 

Subpart T – Magnesium 

Production 331419 and 331492 $0.1 2% $0.1 2% 

Subpart FFUnderground Coal 

Mines 212112 $4.0 57% $2.8 51% 

Subpart TT – Industrial 

Waste Landfills 

322110,322121, 

322122,322130, 

311611,311411, and 

311421 $1.1 16% $0.8 15% 

Subpart II – Industrial 

Wastewater Treatment 

322110,322121, 

322122,322130, 

311611,311411, 

311421,325193, and 

324110 $1.5 21% $1.5 26% 

Private Sector, Total $6.7 96% $5.2 95% 

Public Sector, Total $0.3 4% $0.3 5% 

Total $7.0 100% $5.5 100% 

 

5.3 Economic Impact Analysis 

EPA assessed how the regulatory program may influence the profitability of companies 

by comparing the monitoring program costs to total sales (i.e., a “sales” test). The techniques 

and data we use are identical to the MRR rule and focus on small entities. We provide additional 

details of the analysis below. 

5.3.1 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 

5-8 
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 subparts and entities, 

 selecting and describing the measures and economic impact thresholds used in the 

analysis, and 

 determining SISNOSE certification category. 

5.3.1.1 Identify Affected Subparts and Entities 

The industry subparts 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 (U.S. Bureau of the Census, 2008). These 

data were developed in cooperation with, and partially funded by, the Office of Advocacy of the 

Small Business Administration (SBA). The data include the number of establishments 

(Table 5-7), and receipts (Table 5-8) 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 

5-9 
Because the SBA’s business size definitions (SBA, 2008) apply to an establishment’s 

“ultimate parent company,” we assume in this analysis that the “enterprise” definition above is 

consistent with the concept of ultimate parent company that is typically used for Small Business 

Regulatory Enforcement Fairness Act (SBREFA) screening analyses and the terms are used 

interchangeably. We also report the SBA size standard(s) for each industry group in order to 

facilitate comparisons and different thresholds. 

5.3.1.2 Develop Small Entity Economic Impact Measures 

Because the rule covers a large number of subparts and primarily covers businesses, the 

analysis generated a set of sales tests (represented as cost-to-receipt ratios)17 for NAICS codes 

associated with the affected subparts. Although the appropriate SBA size definition should be 

applied at the parent company (enterprise) level, data limitations allowed us only to compute and 

compare ratios for a model establishment for 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 

categories18 (first year costs: Table 5-12; subsequent year costs: Table 5-13). 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. 

 

17The 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 18For the one to 20 employee category, we exclude SUSB data for enterprises with zero employees. These 

enterprises did not operate the entire year. 

5-10 
5-11 

5.3.1.3 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 notfor-profit enterprise that is independently owned and operated and is not dominant in its field. 

The results of the screening analysis show that for most NAICS, the costs are estimated 

to be less than 1% of sales in all firm size categories. For one NAICS (322130 Paperboard 

Mills), the costs exceed 1% of sales for the 1-20 employee size category; for another NAICS 

(212112 Bituminous Coal Underground Mining), the costs exceed 1% of sales for the 1-20 and 

20-100 employee size category. Previous Regulatory Impact Analysis for the Mandatory 

Reporting of Greenhouse Gas Emissions (EPA-HQ-OAR-2008-0508) illustrated that pulp and 

paper industry enterprises with less than 20 employees were unlikely to be covered by the rule. 

For mining facilities, EPA’s initial review of facility data suggests that mines owned by 

enterprises with less than 100 employees would also unlikely to be covered by the rule. 
5-12

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

Owned by Enterprises with

2007 

 NAICS NAICS Description Subpart 

SBA Size Standard 

(effective August 22, 

2008)

Total 

Establishments 1 to 20 Employeesb 20 to 99 Employees 100 to 499 Employees 500 to 74

Employee

331419 

Primary Smelting and Refining of Nonferrous Metal (except Copper and Aluminum) T 750 employees 150 69 23 17 

331492 

Secondary Smelting, Refining, and Alloying of Nonferrous Metal (except Copper and Aluminum) T 750 employees 230 95 49 40 

212112 

Bituminous Coal Underground Mining FF 500 employees 499 146 117 56 

322110 Pulp Mills TT 750 employees 44 8 4 7 322121 

Paper (except Newsprint) Mills TT 750 employees 322 56 32 57 

322122 Newsprint Mills TT 750 employees 31 4 3 7 322130 Paperboard Mills TT 750 employees 231 29 16 17 311611 

Animal (except Poultry) Slaughtering TT 500 employees 1,816 1,254 203 78 

311411 

Frozen Fruit, Juice, and Vegetable Manufacturing TT 500 employees 243 44 41 52 

311421 Fruit and Vegetable Canning TT 500 employees 781 324 144 96 322110 Pulp Mills II 750 employees 44 8 4 7 322121 

Paper (except Newsprint) Mills II 750 employees 322 56 32 57 

322122 Newsprint Mills II 750 employees 31 4 3 7 
5-13

322130 Paperboard Mills II 750 employees 231 29 16 17 311611 

Animal (except Poultry) Slaughtering II 500 employees 1,816 1,254 203 78 

311411 

Frozen Fruit, Juice, and Vegetable Manufacturing II 500 employees 243 44 41 52 

311421 Fruit and Vegetable Canning II 500 employees 781 324 144 96 325193 

Ethyl Alcohol Manufacturing II 1,000 employees 66 20 16 5 

324110 Petroleum Refineries II 1,500 employeesc 349 85 29 28 

Note: NA denotes that the enterprise category is not applicable (i.e., no enterprises were reported within this category). a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under com

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the ente

annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all assocthe SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SB

b Excludes Statistics of U.S. Businesses (SUSB) employment category for zero employees. These entities only operated for a fraction of the year. c NAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total Operable Atmospheric Crud

Capacity includes owned or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or 

product to be delivered under the contract must be at least 90 percent refined by the successful bidder from either crude oil or bona fide feedstocks. 
5-14

Table 5-11. Receipts by Affected Industry and Enterprisea Size (million, 2002$) 

Owned by Enterprises with

NAICS NAICS Description Subpart 

SBA Size Standard 

(effective August 22, 

2009)

Total Establishments 1 to 20 Employeesb 20 to 99 Employees 100 to 499 Employees 500 to 74

Employee

331419 

Primary Smelting and Refining of Nonferrous Metal (except Copper and Aluminum) T 750 employees $2,306 $81 $100 $162 

331492 

Secondary Smelting, Refining, and Alloying of Nonferrous Metal (except Copper and Aluminum) T 750 employees $2,997 $143 $683 $216 

212112 

Bituminous Coal Underground Mining FF 500 employees $9,633 $166 $125 $953 

322110 Pulp Mills TT 750 employees $3,791 $10 D D 322121 

Paper (except Newsprint) Mills TT 750 employees $42,660 D $296 D 

322122 Newsprint Mills TT 750 employees $3,115 D D D 322130 Paperboard Mills TT 750 employees $21,379 $15 $173 $407 311611 

Animal (except Poultry) Slaughtering TT 500 employees $55,775 $1,344 $1,615 $4,121 

311411 

Frozen Fruit, Juice, and Vegetable Manufacturing TT 500 employees $9,490 $87 $388 $1,504 $4

311421 Fruit and Vegetable Canning TT 500 employees $18,976 $462 $1,381 $2,392 $1,322110 Pulp Mills II 750 employees $3,791 $10 D D 322121 

Paper (except Newsprint) Mills II 750 employees $42,660 D $296 D 

322122 Newsprint Mills II 750 employees $3,115 D D D 322130 Paperboard Mills II 750 employees $21,379 $15 $173 $407 311611 

Animal (except Poultry) Slaughtering II 500 employees $55,775 $1,344 $1,615 $4,121 

311411 

Frozen Fruit, Juice, and Vegetable Manufacturing II 500 employees $9,490 $87 $388 $1,504 $4

311421 Fruit and Vegetable Canning II 500 employees $18,976 $462 $1,381 $2,392 $1,
5-15

325193 

Ethyl Alcohol Manufacturing II 1,000 employees $2,097 D D D 

324110 Petroleum Refineries II 1,500 employeesc $195,752 $467 $2,519 $4,500 $8,7

Note: D denotes that receipt data was not disclosed. NA denotes that the enterprise category is not applicable (i.e., no enterprises were reported withia The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under com

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the ente

annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all assocthe SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SB

b Excludes Statistics of U.S. Businesses (SUSB) employment category for zero employees. These entities only operated for a fraction of the year. c NAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total Operable Atmospheric Crud

Capacity includes owned or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or 

product to be delivered under the contract must be at least 90 percent refined by the successful bidder from either crude oil or bona fide feedstocks. 
5-16

Table 5-12. Establishment Sales Tests by Industry and Enterprisea Size: First Year Costs 

Owned by Enterprises 

2007 

NAICS NAICS Description Sub-part 

SBA Size 

Standard 

(effective August 

22, 2008)

Average 

Cost Per 

Entity 

($/entity) 

All 

Enterprises 1 to 20 Employeesb 20 to 99 Employees 100 to 499 Employees 500 to 

Emplo

331419 

Primary Smelting and Refining of Nonferrous Metal (except Copper and Aluminum) T 750 employees $10,520 0.1% 0.9% 0.2% 0.1% 

331492 

Secondary Smelting, Refining, and Alloying of Nonferrous Metal (except Copper and Aluminum) T 750 employees $10,520 0.1% 0.7% 0.1% 0.2% 

212112 Bituminous Coal Underground Mining FF 500 employees $34,717 0.2% 3.0% 3.4% 0.2% 322110 Pulp Mills TT 750 employees $5,583 0.0% 0.4% D D 322121 Paper (except Newsprint) Mills TT 750 employees $5,583 0.0% D 0.1% D 322122 Newsprint Mills TT 750 employees $5,583 0.0% D D D 322130 Paperboard Mills TT 750 employees $5,583 0.0% 1.1% 0.1% 0.0% 311611 Animal (except Poultry) Slaughtering TT 500 employees $5,583 0.0% 0.5% 0.1% 0.0% 311411 

Frozen Fruit, Juice, and Vegetable Manufacturing TT 500 employees $5,583 0.0% 0.3% 0.1% 0.0% 

311421 Fruit and Vegetable Canning TT 500 employees $5,583 0.0% 0.4% 0.1% 0.0% 322110 Pulp Mills II 750 employees $4,235 0.0% 0.3% D D 322121 Paper (except Newsprint) Mills II 750 employees $4,235 0.0% D 0.0% D 322122 Newsprint Mills II 750 employees $4,235 0.0% D D D 322130 Paperboard Mills II 750 employees $4,235 0.0% 0.8% 0.0% 0.0% 311611 Animal (except Poultry) Slaughtering II 500 employees $3,963 0.0% 0.4% 0.0% 0.0% 311411 

Frozen Fruit, Juice, and Vegetable Manufacturing II 500 employees $3,963 0.0% 0.2% 0.0% 0.0% 
5-17

311421 Fruit and Vegetable Canning II 500 employees $3,963 0.0% 0.3% 0.0% 0.0% 325193 Ethyl Alcohol Manufacturing II 1,000 employees $5,140 0.0% D D D 324110 Petroleum Refineries II 1,500 employeesc $3,963 0.0% 0.1% 0.0% 0.0% 

Note: D denotes that receipt data was not disclosed. NA denotes that the enterprise category is not applicable (i.e., no enterprises were reported withi

in Table 5-7 has been adjusted to 2006$ using the latest GDP implicit price deflator reported by the U.S. Bureau of Economic Analysis (103.257/92

http://www.bea.gov/national/nipaweb/Index.asp (accessed December 21, 2009). 

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under com

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the ente

annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all assocthe SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SB

b Excludes Statistics of U.S. Businesses (SUSB) employment category for zero employees. These entities only operated for a fraction of the year. c NAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total Operable Atmospheric Crud

Capacity includes owned or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or 

product to be delivered under the contract must be at least 90 percent refined by the successful bidder from either crude oil or bona fide feedstocks. 
5-18

Table 5-13. Establishment Sales Tests by Industry and Enterprisea Size: Subsequent Years Costs 

Owned by Enterprises 

2007 

NAICS NAICS Description Subpart 

SBA Size 

Standard 

(effective 

August 22, 

2008)

Average 

Cost Per 

Entity 

($/entity) 

All 

Enterprises 1 to 20 Employeesb 20 to 99 Employees 100 to 499 Employees 500 to 

Emplo

331419 

Primary Smelting and Refining of Nonferrous Metal (except Copper and Aluminum) T 750 employees $10,520 0.1% 0.9% 0.2% 0.1% 

331492 

Secondary Smelting, Refining, and Alloying of Nonferrous Metal (except Copper and Aluminum) T 750 employees $10,520 0.1% 0.7% 0.1% 0.2% 

212112 Bituminous Coal Underground Mining FF 500 employees $24,965 0.1% 2.2% 2.3% 0.1% 322110 Pulp Mills TT 750 employees $4,102 0.0% 0.3% D D 322121 Paper (except Newsprint) Mills TT 750 employees $4,102 0.0% D 0.0% D 322122 Newsprint Mills TT 750 employees $4,102 0.0% D D D 322130 Paperboard Mills TT 750 employees $4,102 0.0% 0.8% 0.0% 0.0% 311611 Animal (except Poultry) Slaughtering TT 500 employees $4,102 0.0% 0.4% 0.1% 0.0% 311411 

Frozen Fruit, Juice, and Vegetable Manufacturing TT 500 employees $4,102 0.0% 0.2% 0.0% 0.0% 

311421 Fruit and Vegetable Canning TT 500 employees $4,102 0.0% 0.3% 0.0% 0.0% 322110 Pulp Mills II 750 employees $4,235 0.0% 0.3% D D 322121 Paper (except Newsprint) Mills II 750 employees $4,235 0.0% D 0.0% D 
5-19

322122 Newsprint Mills II 750 employees $4,235 0.0% D D D 322130 Paperboard Mills II 750 employees $4,235 0.0% 0.8% 0.0% 0.0% 311611 Animal (except Poultry) Slaughtering II 500 employees $3,963 0.0% 0.4% 0.0% 0.0% 311411 

Frozen Fruit, Juice, and Vegetable Manufacturing II 500 employees $3,963 0.0% 0.2% 0.0% 0.0% 

311421 Fruit and Vegetable Canning II 500 employees $3,963 0.0% 0.3% 0.0% 0.0% 325193 Ethyl Alcohol Manufacturing II 

1,000 

employees $5,140 0.0% D D D 

324110 Petroleum Refineries II 

1,500 

employeesc $3,963 0.0% 0.1% 0.0% 0.0% 

Note: D denotes that receipt data was not disclosed. NA denotes that the enterprise category is not applicable (i.e., no enterprises were reported withi

in Table 5-7 has been adjusted to 2006$ using the latest GDP implicit price deflator reported by the U.S. Bureau of Economic Analysis (103.257/92

http://www.bea.gov/national/nipaweb/Index.asp (accessed December 21, 2009). 

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under com

The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the ente

annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all assocthe SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that 

above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SB

b Excludes Statistics of U.S. Businesses (SUSB) employment category for zero employees. These entities only operated for a fraction of the year. c NAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total Operable Atmospheric Crud

Capacity includes owned or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or 

product to be delivered under the contract must be at least 90 percent refined by the successful bidder from either crude oil or bona fide feedstocks.
SECTION 6

STATUTORY AND EXECUTIVE ORDER REVIEWS 

This section describes EPA’s compliance with several applicable executive orders and 

statutes. 

6.1 Executive Order 12866: Regulatory Planning and Review 

This action is not a "significant regulatory action" under the terms of Executive Order 

(EO) 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under the 

Executive Order. EPA’s cost analysis, presented in Section 4 of the Economic Impact Analysis 

(EIA), estimates the total annualized cost of the rule will be approximately $7.0 million (in 

2006$) during the first year of the program and $5.5 million in subsequent years (including $0.3 

million of programmatic costs to the Agency). In addition, EPA prepared an analysis of the 

potential costs associated with this proposed action. This analysis is contained in the Economic 

Impact Analysis (EIA), “Economic Impact Analysis for the Mandatory Reporting of Greenhouse 

Gas Emissions: Subparts: T, FF, TT, and II” (EPA-HQ-OAR-2010-XXXX). A copy of the 

analysis is available in the docket for this action. 

6.2 Paperwork Reduction Act 

The information collection requirements in this rule have been submitted for approval to 

the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The information collection requirements are not enforceable until OMB approves 

them. 

EPA plans to collect complete and accurate economy-wide data on facility-level GHG 

emissions. Accurate and timely information on GHG emissions is essential for informing future 

climate change policy decisions. Through data collected under this rule, EPA will gain a better 

understanding of the relative emissions of 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. 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 

6-1 
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 section 114. 

Information identified and marked as CBI will not be disclosed except in accordance with 

procedures set forth in 40 CFR part 2. However, emissions data collected under CAA section 

114 cannot generally be claimed as CBI and will be made public. 

For these final subparts, the projected cost and hour burden for non-Federal respondents 

is $5.13 million and 66.0 million hours per year. The estimated average burden per response is 

29.1 hours; the frequency of response is annual for all respondents that must comply with the 

rule’s reporting requirements and the estimated average number of likely respondents per year is 

683. The cost burden to respondents resulting from the collection of information includes the 

total capital cost annualized over the equipment’s expected useful life (averaging $0.5 million), a 

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

component (averaging $3.6 million per year). 

Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown 

elsewhere in the Regulatory Impacts Analysis (RIA) for the proposed subparts because the 

information collection request (ICR) costs represent the average cost over the first three years of 

the rule, but costs are reported elsewhere in the RIA for the proposed subparts for the first year 

of the rule and for subsequent years of the rule. In addition, the ICR focuses on respondent 

burden, while the RIA for the final rule includes EPA Agency costs. 

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 this final rule. 

6.3 Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any 

rule subject to notice and comment rulemaking requirements under the Administrative Procedure 

Act or any other statute unless the agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small entities include small 

businesses, small organizations, and small governmental jurisdictions. 

6-2 
For purposes of assessing the impacts on small entities, a small entity is defined as a 

small business as defined by the Small Business Administration’s regulations at 13 CFR 

121.201; according to these size standards, criteria for determining if ultimate parent companies 

owning affected facilities are categorized as small vary by NAICS. Small entity criteria range 

from total number of employees at the firm fewer than 500 to number of employees fewer than 

1,500; one affected NAICS, 324110, the petroleum refiner must have 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 percent refined by the 

successful bidder from either crude oil or bona fide feedstocks. EIA tables 5-10 and 5-11 present 

small business criteria and enterprise size distribution data for affected NAICS. 

EPA assessed the potential impacts of the proposed rule on small entities using a sales 

test, defined as the ratio of total annualized compliance costs to firm sales. Details are provided 

in section 5.3 of the EIA. These sales tests examine the average establishment’s total annualized 

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

employment categories. The average entity costs used to compute the sales test are the same 

across all of these enterprise size categories. As a result, the sales-test will overstate the cost-toreceipt ratio for establishments owned by small businesses, because the reporting costs are likely 

lower than average entity estimates provided by the engineering cost analysis 

The results of the screening analysis show that for most NAICS, the costs are estimated 

to be less than 1% of sales in all firm size categories. For one NAICS (322130 Paperboard 

Mills), the costs exceed 1% of sales for the 1-20 employee size category; for another NAICS 

(212112 Bituminous Coal Underground Mining), the costs exceed 1% of sales for the 1-20 and 

20-100 employee size category. Previous Regulatory Impact Analysis for the Mandatory 

Reporting of Greenhouse Gas Emissions (EPA-HQ-OAR-2008-0508) illustrated that pulp and 

paper industry enterprises with less than 20 employees were unlikely to be covered by the rule. 

For mining facilities, EPA’s initial review of facility data suggests that mines owned by 

enterprises with less than 100 employees would also unlikely to be covered by the rule. 

After considering the economic impacts of today’s proposed rule on small entities, I 

therefore certify that this proposed rule will not have a significant economic impact on a 

substantial number of small entities. 

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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. 

In addition to the public hearing that EPA plans to hold, EPA has an open door policy, 

similar to the outreach conducted during the development of the proposed and final Mandatory 

GHG Reporting Rule. Details of these meetings are available in the docket (EPA-HQ-OAR2009-0927). 

6.4 Unfunded Mandates Reform Act (UMRA) 

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. 

This proposed rule does not contain a Federal mandate that may result in expenditures of 

$100 million or more for State, local, and tribal governments, in the aggregate, or the private 

sector in any one year. Overall, EPA estimates that the total annualized costs of this proposed 

rule are approximately $7.0 million in the first year, and $5.5 million per year in subsequent 

years. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of 

UMRA. 

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

because it contains no regulatory requirements that might significantly or uniquely affect small 

governments. None of the facilities currently known to undertake these activities are owned by 

small governments. 

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6.4.1 Executive Order 13132: Federalism 

These final subparts do not have federalism implications. They 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. 

Entities affected by these final subparts are facilities that directly emit greenhouses gases. 

These final subparts do not apply to governmental entities unless the government entity owns a 

facility that directly emits greenhouse gases above threshold levels such as a landfill or large 

stationary combustion source, so 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, EO 13132 does not apply to this rule. 

In the spirit of Executive Order 13132, and consistent with EPA policy to promote 

communications between EPA and State and local governments, EPA specifically solicited 

comments on these subparts from State and local officials. For a discussion of outreach activities 

to State, local, or Tribal organizations, see Section IX of the preamble to the proposed 

Mandatory GHG Reporting Rule (74 FR 16602). 

6.4.2 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments 

This action does not have Tribal implications, as specified in Executive Order 13175 (65 

FR 67249, November 9, 2000). This regulation applies directly to facilities that directly emit 

greenhouse gases. Facilities expected to be affected by these final subparts are not expected to 

be owned by Tribal governments. Thus, Executive Order 13175 does not apply to this action. 

Although EO 13175 does not apply to these final subparts, EPA sought opportunities to 

provide information to Tribal governments and representatives during development of the 

proposed Mandatory GHG Reporting Rule, which included these subparts being finalized today. 

See Section IX of the preamble to the proposed Mandatory GHG Reporting Rule (74 FR 16602). 

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

Safety Risks 

EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

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section 5-501 of the EO has the potential to influence the regulation. This action is not subject to 

EO 13045 because it does not establish an environmental standard intended to mitigate health or 

safety risks. 

6.4.4 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, 

or Use 

This action 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 rule relates to monitoring, reporting and recordkeeping at 

facilities that directly emit greenhouses gases and does not impact energy supply, distribution or 

use. Therefore, we conclude that this rule is not likely to have any adverse effects on energy 

supply, distribution, or use. 

6.4.5 National Technology Transfer and Advancement Act 

Section 12(d) of the National Technology Transfer and Section 12(d) of the National 

Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) 

(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, 

explanations when the Agency decides not to use available and applicable voluntary consensus 

standards. 

This rulemaking involves technical standards. For these final subparts, EPA has decided 

to use more than a dozen voluntary consensus standards from four different voluntary consensus 

standards bodies, including American Society for Testing and Materials (ASTM) and ASME. 

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 methods to 

measure gas or liquid flow and methods to analyze gases by gas chromatography. All except 

two of these methods have already been incorporated by reference in the final Mandatory GHG 

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Reporting Rule. Thus, we are adding entries to 40 CFR 98.7 for new voluntary consensus 

standards and modifying the entries for other voluntary consensus standards to reflect their usage 

in these final subparts. Thus, the test methods are incorporated by reference into the final 

Mandatory GHG Reporting Rule and are available as specified in 40 CFR 98.7. 

By incorporating voluntary consensus standards into the subparts, EPA is both meeting 

the requirements of the NTTAA and presenting multiple options and flexibility for measuring 

GHG emissions. 

6.4.6 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations 

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive 

policy on environmental justice. Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States. 

EPA has determined that these final subparts 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. These final 

subparts do not affect the level of protection provided to human health or the environment 

because they address information collection and reporting procedures. 

6.4.7 Congressional Review Act 

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business 

Regulatory Enforcement Fairness Act of 1996 (SBREFA), generally provides that before a rule 

may take effect, the agency promulgating the rule must submit a rule report, which includes a 

copy of the rule, to each House of the Congress and to the Comptroller General of the United 

States. EPA will submit a report containing this rule and other required information to the U.S. 

Senate, the U.S. House of Representatives, and the Comptroller General of the U.S. prior to 

publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after 

it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 

804(2). 
SECTION 7

CONCLUSIONS 

EPA is promulgating a regulation to require monitoring and reporting of greenhouse gas 

emissions from magnesium production (Subpart T), underground coal mines (Subpart FF), 

industrial waste landfills (Subpart TT), and industrial wastewater treatment (Subpart II). EPA 

has added four source categories to the list of source categories already required to report 

greenhouse gas emissions under 40 CFC part 98. The regulation requires monitoring and 

reporting of greenhouse gases for these source categories only for sources with CO2 equivalent 

emissions above certain threshold levels but does not require control of greenhouse gases. EPA 

has made the decision not to include ethanol production or food processing as distinct subparts 

under 40 CFR part 98. Lastly, EPA has also made the decision not to include suppliers of coal as 

a subpart under 40 CFR part 98 at this time. 

7.1.1 Subpart T: Magnesium Production 

Magnesium production and processing facilities are defined as any site where magnesium 

metal is produced through smelting (including electrolytic smelting), refining, or remelting 

operations, or any site where molten magnesium is used in alloying, casting, drawing, extruding, 

forming, or rolling operations. Facilities that meet the applicability criteria in the General 

Provisions (40 CFR 98.2(a)) summarized in Section II.B of this preamble must report GHG 

emissions. 

7.1.2 Subpart FF: Underground Coal Mines 

This source category consists of active underground coal mines and any underground 

mines under development that have operational pre-mining degasification systems. An 

underground coal mine is a mine at which coal is produced by tunneling into the earth to a 

subsurface coal seam, where the coal is then mined with equipment such as cutting machines, 

and transported to the surface. Active underground coal mines are underground mines 

categorized by the Mine Safety and Health Administration (MSHA) as active and where coal is 

currently being produced or has been produced within the previous 90 days. This source 

category consists of each ventilation well or shaft, and each degasification system well or shaft, 

and includes degasification systems deployed before, during, or after mining operations are 

conducted in a mine area. This source category does not include abandoned (closed) mines, 

surface coal mines, or post-coal mining activities (e.g., storage or transportation of coal). 

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7.1.3 Subpart TT: Industrial Waste Landfills 

This source category consists of industrial waste landfills whose total landfill design 

capacity is greater than or equal to 300,000 metric tons and that accepted waste on or after 

January 1, 1980 and, if present, landfill gas collection systems and landfill gas destruction 

devices (including flares). This source category does not include Resource Conservation and 

Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA) hazardous waste 

landfills, construction and demolition landfills, or landfills that only receive inert waste 

materials, such as coal combustion residue (e.g., fly ash), cement kiln dust, rocks and/or soil, 

glass, non-chemically bound sand (e.g., green foundry sand), clay, gypsum, pottery cull, bricks, 

mortar, cement, furnace slag, refractory material, or plastics. Facilities that meet the applicability 

criteria in the General Provisions (40 CFR 98.2(a)) summarized in Section II.B of this preamble 

must report GHG emissions. 

7.1.4 Subpart II: Industrial Wastewater Treatment 

This source category applies to anaerobic processes used to treat industrial wastewater and 

wastewater treatment sludges at pulp and paper mills, food processing facilities, ethanol 

production facilities, and petroleum refineries. It does not include domestic wastewater treatment 

plants or separate treatment of sanitary wastewater at industrial facilities. It does not include 

oil/water separators. This source category consists of the following: anaerobic reactors, 

anaerobic lagoons, anaerobic sludge digesters, and biogas destruction devices. Facilities that 

meet the applicability criteria in the General Provisions (40 CFR 98.2(a)) summarized in Section 

II.B of this preamble must report GHG emissions. 

7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program 

The total national costs for the selected option are estimated to be $7.0 million in the first 

year and $5.5 million in subsequent years. This includes a public sector burden estimate of $0.3 

million for program implementation and verification activities. The national costs are distributed 

to several economic sectors and represent approximately less than 0.01% of 2008 gross domestic 

product; overall, EPA does not believe the rule will have a significant macroeconomic impact on 

the national economy or on small entities within those sectors. 
SECTION 8

REFERENCES 

U.S. Environmental Protection Agency (EPA). 2000. Guidelines for Preparing Economic 

Analyses. EPA 240-R-00-003. Washington, DC: EPA. Available at 

<http://yosemite.epa.gov/ee/epa/eed.nsf/webpages/Guidelines.html>. 

U.S. Environmental Protection Agency. 2009. U.S. Inventory of Greenhouse Gas Emissions 

and Sinks: 1990-2007. 

U.S. Bureau of the Census. 2008. Firm Size Data from the Statistics of U.S. Businesses: U.S. 

Detail Employment Sizes: 2002. http://www.census.gov/csd/susb/download_susb02.htm. 

U.S. Small Business Administration (SBA). 2008. Table of Small Business Size Standards 

Matched to North American Industry Classification System Codes. Effective August 22, 

2008. http://www.sba.gov/services/contractingopportunities/sizestandardstopics/ 

size/index.html. 

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