### June 2010


# Economic Impact Analysis for the Mandatory Reporting of

Greenhouse Gas Emissions: Subparts: T, FF, TT, and II

Final Reporti 

### 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 Iden tify 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.......................................... 3-3ii 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 Wa stewater 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.................................. 4-8iii 4.4.1 Model Facility Development ................................................................. 4-11

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

4.4.3 Proportion of Facilities in the Diffe rent 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 monito ring 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....................................................................................... 5-7iv 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: Regulator y 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: Consultati on 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 Acti ons 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 th e Mandatory GHG Reporting Program......... 7-2v Section 8 References........................................................................................................... ... 8-1vi 

### 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 Emi ssions 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 Fl ow Meter Sizes and Costs .............................................................. 4-35
Table 4-14. Industrial Wastewat er Treatment Monitoring Costs ............................................. 4-40 Table 5-1. Threshold Analysis fo r 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 (MtCO 2 e) Reported in 2008 Unde r the Selected Option ....5-7vii Table 5-9. National Annualized Mandatory Repor ting Costs Estim ates (2006$): T, FF, TT, and
II

............................................................................................................................... .................... 5-8
Table 5-10. Number of Establishments by Affected Industry and Enterprise a Size: 2002 .......5-12 Table 5-11. Receipts by Affect ed Industry and Enterprise a Size (million, 2002$) ..................5-14
Table 5-12. Establishment Sales Tests by Industry and Enterprise a Size: First Year Costs .....5-16
Table 5-13. Establishment Sales Tests by Industry and Enterprise a Size: Subsequent Years Costs

............................................................................................................................... ..................... 5-181-1 SECTION 1 INTRODUCTION AND BACKGROUND

1.1 Background

On Dece mber 26, 2007, President Bush signe d the FY2008 Consolidated Appropriations Act which authorized funding for EPA to “devel op and publish a draft ru le 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 requir e 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 direct ed EPA to "use its existing aut hority 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 Decembe r 29, 2009 included reporting of GHGs from the facilities and suppliers that EP A determined appropriately res ponded to the direction in the 2008 Consolidated Appropriations Act 1 . These source categories capt ure approximately 85 percent of U.S. GHG emissions through reporting by direct emitte rs as well as suppliers of fossil fuels and industrial gases.

1.2 Source Category Definitions Covered by the Final Rules

EPA is promulgating a regula tion to require m onitoring a nd 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 cate gories 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 pr oduction 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 (includi ng electrolytic smelting), refining, or remelting operations, or any site where mo lten magnesium is used in allo ying, casting, drawin g, extruding, forming, or rolling operations. Facilities that m eet the applicability cr iteria in the General Provisions (40 CFR 98.2(a)) summ arized 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 m ines 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 mi ned 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 Admi nistration (MSHA) as active and where coal is currently being produced or has been produced within the prev ious 90 days. This source category consists of each ventilation well or shaf t, 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 activit ies (e.g., storage or transportation of coal).

1.2.3 Subpart TT: Industrial Waste Landfills

This source catego ry consists of industrial waste landfills whose total landfill design capacity is greater than or equal to 300,000 me tric tons and that accepted waste on or after January 1, 1980 and, if present, landfill gas co llection systems and la ndfill gas destruction devices (including flares). This source category does not incl ude Resource Conservation and Recovery Act (RCRA) Subtitle C or Toxic S ubstances 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 foundr y sand), clay, gypsum, pottery cull, bricks, mortar, cement, furnace slag, refractory material, or plastics. Facilities that meet the applicability1-3 criteria in the General Provisi ons (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 pro cesses used to treat industrial wastewater and wastewater treatm ent sludges at pulp and paper mills, food processing facilities, ethanol production facilities, and petroleu m refineries. It does not include domestic wastewater treatment plants or separate treatment of sanitary wastew ater at industrial facili ties. It does not include oil/water separators. This source category consists of the following: anaerobic reactors, anaerobic lagoons, anaerobic sludge digesters, and biogas destruc tion devices. Facilities that meet the applicability criteria in the General Provisions (40 CF R 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

econom ic impact analysis (EIA). This repo rt 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 e xplains the development process for each of the four subparts, and Section 4 details the individual cost analyses me thods used to evaluate each source category. Section 5 presents the results of the economic imp act analysis. A review of executive orders is provided in Section 6, which is followed by a brief EIA summary and c onclusion in Section 7.2-1 SECTION 2 REGULATORY BACKGROUND

The inten t of this rule is to collect accura te and timely GHG emissi ons data that can be used to inform future policies. Although th e mandatory GHG rule is unique, EPA carefully considered other federal and state programs during development of the rule. The reporting program will supplement rather than duplicat e 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 exam ple, the monitoring and GHG calculation methodologies for many source categories are th e same as, or similar to, the methodologies contained in state reporting programs. The rema inder of the section provides an overview of related existing programs and discusses their re levance in the development of this rule.

2.1 EPA’s Overall Rulemaking Approach

The m andatory 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 progr am. Because we do not know at this time the specific policies that wi ll be adopted, the data reported through the mandatory reporting system should be of sufficien t 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 su fficient 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 c onsistent with existing GHG reporting programs by using existing GHG emission es timation and reporting methodologies to reduce reporting burden, where feasible.

2.1.1 Stakeholder Outreach to Identify Reporting Issues

Early in the developm ent process, we c onducted a proactive co mmunications outreach program to inform the public about the rule development effort. We solicited input and2-2 maintained an open door policy for those interest ed in discussing the rulemaking. Since January 2008, EPA staff has held more than 100 meetings with stakeholders, in cluding the following:

 trade associations and firms in poten tially affected industries/sectors;

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

 state and regional organizations alre ady involved in GHG emissions reporting, such as TCR, CARB, and Wester n 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 pr ograms relevant to GHG emissions.

During the meetings, we shared informati on about the statutory requirements and timetable for developing a rule. Stakeholders we re encouraged to provide input on key issues. Examples of topics discussed included exis ting GHG monitoring and re porting programs and lessons learned, thresholds for reporting, schedul es for reporting, scope of reporting, handling of confidential data, data verification, and the role of states in administering the program. As needed, the EPA technical workgroups followed up with these stakeholder groups on a variety of methodological, technical, and policy issues. EPA staff also provided information to tribes through conference calls with diffe rent 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 (M arch 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 con sidered in these rules, EPA compiled information on current conditions in the categor y, including information about ex isting 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 m andatory reporting pr ogram, a number of vol untary 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 invent ories are relevant to the GHG reporting rule. Several of these programs are su mmarized 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 particip ating 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 Partners hip (VAIP) promotes t echnically 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 comp any-specific) annual PFC emissions report.
In developing the rule, we carefully re viewed the existing reporting programs, particularly with respect to emissions s ources 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 re duction programs (e.g., cap and trade) or being used to design and inform measures that re duced GHGs indirectly (e .g., energy efficiency).2-4 Where possible, we built upon concepts in existing Federal and State prog rams in developing the mandatory GHG reporting rule. For a full summary of the reporting programs reviewed in the development of the mandatory reporting rule plea se see the Regulatory Impact Analysis for the Mandatory Reporting of Greenhouse Ga s 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 Treatm ent. This section provides additional details abou t the development of these subparts since proposal. For each subpart, this section also pr ovides a brief description of proposed monitoring methods; procedures for estimating missing data; as well as data reporti ng and recordkeeping requirements.

3.1 Subpart T – Magnesium Production

3.1.1 GHGs to Report.

Each m agnesium 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 (CO 2 e) per year resulting from their use as cove r gases or carrier gases in magnesium production or processing:

 SF 6

 HFC-134a

 The fluorinated ketone, FK 5-1-12

 CO 2

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

In addition, each faci lity must report GHG emissions for other source categories for which calculation methods are provided in the rule. For example, facilities must report CO 2 , N 2 O, and CH 4 emissions from each stationary combustion unit on site by following the requirements of 40 CFR part 98, subpart C (Gener al Stationary Fuel Combustion Sources).

3-13.1.2 GHG Emissions Calculation and Monitoring.

Owners or operators of m agnesium production faci lities must calculate emissions of each gas by monitoring the annual consumption of cove r gases and carrier gase s 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 be ginning 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 indivi dual containers as the gases are used.

 Monitor the mass flow of pure cover ga s 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 G eneral 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 contai ned 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 m ust keep records of additional data used to calculate GHG emissions. A list of specific records that must be re tained for this source category is included in 40 CFR part 98, subpart T.

3.1.3 Summary of Major Changes Since Proposal

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

3-23.2 Subpart FF – Underground Coal Mines

3.2.1 GHGs to Report.

For underground coal mines, report the following:

 Quarterly CH 4 liberated from ventilation and degasification systems.

 Quarterly CH 4 destruction from systems where gas is sold, used onsite, or otherwise destroyed (inc luding by flaring).

 Quarterly net CH 4 emissions from ventilation and degasification systems.

 Quarterly CO 2 emissions from coal mine gas CH 4 destruction occuring at the facility, where the gas is not a fuel input for energy generation or use (e.g., flaring).

 Annual CO 2 , CH 4 , and N 2 O 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 CH 4 liberated from mine ventilation air, facilities are to monitor CH 4 using either quarterly or more frequent sa mpling, or continuous emissions monitoring systems (CEMS).
For the quarterly sampling option, coal mine operators are requi red to either: (a) independently collect quarterly or more frequently samples of CH 4 released from the ventilation system(s), using MSHA procedures, have these samples analyzed for CH 4 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 fo r emissions reporting, they must provide documentation on the process for using data obtai ned from their CEMS to estimate emissions from their mine ventilation systems.

For CH 4 liberated from degasification syst ems, facilities are to monitor CH 4 using either weekly sampling, or CEMS.

3-3The option o f collecting weekly samples in cludes 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 CH 4 concentrations in gas volumes recovered or emitted. Under this option, facilities must determine weekly gas flow rates and CH 4 composition from these degasification wells and shafts, either on an individual well or shaft basis, or in aggregate at one or more central ized collection points. Methane composition could be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasifi cation well site(s) a nd/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 em issions from all wells are addressed, and the methodology for calculating total emissi ons from all wells is documented.
For all systems with CH 4 destruction, CH 4 destruction is monitored through direct measurement of gas flow and CH 4 concentration to combusti on devices with continuous monitoring systems. The resulting CO 2 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 G eneral 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 containe d in 40 CFR 98.326, subpart FF.

3.2.2.2 Recordkeeping.

In addition to the records required by the Ge neral Provisions (40 CF R 98.3(g)), reporters must keep records of additional data that are us ed to calculate GHG e missions. A list of specific data to be reported for this source cate gory is contained in 40 CFR 98.327, subpart FF.

3.2.3 Summary of Major Changes since Proposal

The m ajor changes in this rule since the orig inal proposal are identified in the following list. The rationale for these and any other signi ficant 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 m ore CEMS to obtain data on mine ventilation systems is added.

 For CH 4 liberated from degasification systems, the requirement to monitor each well was removed. CEMS may be used to monitor aggregate CH 4 from more than one well, as long as CH 4 from all wells is monitored, and the methodology for estimating total emissions from all wells is documented.

 The requirement for continuous monitoring for total CH 4 liberation at degasification systems was removed. Degasification wells may be monitored with CEMS or through weekly sampling of a ll 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 lan dfills, facilities must report:

 Annual CH 4 generation and CH 4 emissions from the industrial waste landfill.

 Annual CH 4 recovered (for landfills with gas collection and de struction systems).

3.3.2 GHG Emissions Calculation and Monitoring.

All facilities m ust ascertain annual modeled CH 4 generation based on:

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

 Appropriate values for model inputs (i.e., degradable organic carbon fraction in the waste, CH 4 generation rate constant). Defa ult parameter values are specified
for certain industries and for industrial waste generically.

Facilities that do not collect and destroy landfill gas mu st adjust the annual modeled CH 4 generation to account soil oxidation (CH 4 that is converted to CO 2 as it passes through the landfill cover before being emitted) using a defaul t soil oxidation factor. The resulting value must be reported and represents both CH 4 generation (corrected for oxidation) and CH 4 emissions.

3-5Facilities th at collect and destroy landfill gas must calcul ate the annual quantity of CH 4 recovered and destroyed based on either continuous or weekly monitoring of landfill gas flow rate, CH 4 concentration, temperature, pressure, and moisture of th e collected gas prior to the destruction device.
Those facilities that collect and destroy landfill gas must then calculate CH 4 emissions in two ways and report both results. Emissions must be calculated by:

 Subtracting the measured amount of CH 4 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 th e measured amount of CH4 recovered to “back-calculate” CH4 generation, then s ubtracting the measured amount of CH4 recovered (with adjustments for soil oxida tion and destruction efficiency of the destruction device) from th e 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 G eneral 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 contai ned in 40 CFR part 98, subpart TT.

3.3.2.2 Recordkeeping.
In addition to the records required by the Ge neral Provisions (40 CF R 98.3(g)), reporters must keep records of additional data used to ca lculate GHG em issions. A list of specific records that must be retained for this source categor y is included in 40 CF R part 98, subpart TT.

3-63.3.3 Summary of Major Changes Since Proposal

The m ajor 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 Commen ts, Subpart TT: Indust rial Waste landfills.”

 A number of provisions were added to targ et industrial waste landfills that have a potential to generate appreciable quantitie s of methane. These include provisions to exempt landfills that did not accep t any waste after January 1, 1980, exempt
landfills with a total landf ill design capacity of less th an 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 fo r current reporting years.

 Additional model defaults fo r industrial waste are includ ed in the final rule and additional methods are provided to estimat e degradable organic carbon content of
industrial solid waste streams.

 For landfills with landfill ga s recovery, all of the change s 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 fina l requirements in subpart HH). For additional details regarding the changes in the landfill gas recovery monitoring requirements, see the final preamble fo r 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 CH 4 generated, recovered, and emitted from treatment of industrial wastewater using anaerobic lagoon s or anaerobic reactors;

3-7 The am ount of CH 4 recovered and emitted from anaerobic sludge digesters; and

 The amount of CH 4 destroyed by and emitted from biogas collection systems and
destruction devices.

Operators of anaerobic wastewater treatmen t sludge digesters are not required to report the amount of CH 4 generated. EPA believes that all anaer obic sludge digesters are designed for CH 4 recovery. Further, operators of anaerobic sludge digesters are required to report the amount of CH 4 recovered and emitted. For this reason, a sepa rate calculation and report of the amount of CH 4 generated is not necessary.

3.4.2 GHG Emissions Calculation and Monitoring.

Detailed m ethods 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 CH 4 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 (BOD 5 ) of wastewater entering an anaerobic treatment process;

 Maximum CH 4 producing potential of wastew ater (0.25 for COD, 0.6 for BOD 5 );
and

 CH 4 conversion factor for th e 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 CH 4 recovered using the following inputs and data:

 Cumulative volumetric flow of bi ogas for the monitoring period;

 Average CH 4 content of the biogas; and

3-8 Tem perature, pressure, and moisture conten t at which flow is measured, as needed to accurately calculate biogas flow and CH 4 content.

For each anaerobic process (such as reactor, lagoon, or sludge digester) from which biogas is recovered, facilities must calculate the mass of CH 4 emitted using the following inputs and data:

 Mass of CH 4 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 G eneral 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 contai ned in 40 CFR Part 98, subpart II.

3.4.2.2 Recordkeeping.

In addition to the records required by the Ge neral Provisions (40 CF R 98.3(g)) facilities must keep records of additional data used to ca lculate GHG em issions. A list of specific records that must be retained for this source categor y is included in 40 CF R Part 98, subpart II.

3.4.3 Summary of Major Changes Since Proposal

The m ajor changes since proposal are identifi ed 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 Wastewat er Treatment,” and “Technical Support Document for I ndustrial Wastewater Treatment.”

3-9 The source category has been renam ed I ndustrial Wastewater Treatment and the applicability of this subpart has been clarified. Only petroleum refineries and ethanol production, food pro cessing, and pulp and paper facilities that meet the requirements of 98.2(a)(2) ar e required to report CH 4 emissions from anaerobic processes used to treat industrial wastew ater and industrial wastewater treatment sludges and biogas destruction devices. Domestic wastewater treatment and separate treatment of sanitary wastewater at industrial facilitie s are not included in the applicability, nor are facilities th at do not employ wastewater treatment processes listed in the source definiti on (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 CO 2 or other
GHG from these oil/w ater 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 regula tion to allow for either continuous or weekly monitoring of biogas CH 4 concentration. Facil ities may use either installed or portable monitors to measure the CH 4 concentration. Further, EPA
added BOD 5 as an alternative to measuring C OD to determine the organic load of
influent to anaerobic wastew ater treatment systems.

3.5 Other Proposed Source Categories

3.5.1 Overview

EPA has m ade the final decisi on not to include Ethanol Produ ction or Food Processing as distinct subparts in the Mandato ry 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.

3-103.5.2 Ethanol Production

EPA has m ade the final decisi on not to include Ethanol Pr oduction (proposed as 40 CFR part 98, subpart J) as a distinct subpar t 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 proce ss 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 cl ear that ethanol pr oduction facilities will be required to report if they meet the threshold of 25,000 tons CO 2 e by aggregating emissions from all applicable source categorie s in the rule including stationary combustion, industrial wastewater treatment, industrial landf ills, miscellaneous use of carbonates, and any others that may apply. In fact, any facility not specifically iden tified in a subpart must report their GHG emissions if that faci lity contains source categories itemized by the rule and their aggregate emissions meet the threshold.
In the final rule, ethanol pr oduction facilities are among thos e specifically identified in subpart II – Industrial Wastewater Treatment at Certain Industrial F acilities as requ ired 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 m ade the final decision not to in clude Food Processing (proposed as 40 CFR part 98, subpart M) as a distin ct 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 proce ss emissions from food processing facilities. Instead, the proposed subpart simply referred to reporting that those facilities might need to do

3-11under other subparts, nam ely, 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 clea r 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 m eet the threshold of 25,000 tons CO 2 e by aggregating emissions from all applicable source cat egories in the rule including st ationary combustion, industrial wastewater treatment, industrial landfills, miscel laneous use of carbonates, and any others that may apply. In fact, any faciliti es not specifically identified in a subpart must report their GHG emissions if that facility cont ains 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 be ing required to report if they meet the applicab ility 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 m ade a final decision no t to include Suppliers of Co al (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 supplie rs and downstream emitters is almost 100% indicating that double-repor ting 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 repor ting from coal suppliers in the future in light of new information or identif ication of policy or program needs. If EPA were to decide in the future to add coal supplie rs to the Mandatory GHG Reporting Rule it would initiate a new rulemaking process.

3-123-13SECTION 4 ENGINEERING COST ANALYSIS

4.1 Introduction

EPA estim ated costs of complying with th e 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 monitori ng, 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 w ill vary from one facility to another, depending on the types of emissions, the numbe r of affected sources at the facility, existing monitoring, recordkeeping, and reporting activities at the facility, etc. The costs include labor costs for performing the mon itoring, recordkeeping, a nd reporting activities necessary to comply with th e rule. For affected facilities, costs include monitoring, recording, and reporting of GHG emissi ons from production processes and from stationary combustion units. All costs referred to in th is 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

W hen data are available to determ ine how many companies are currently implementing approaches consistent with the met hods at the facility le vel to meet internal GHG management programs or st ate or voluntary reporting pr ograms 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 re porting requirements. Specificall y, EPA is assuming that there

4-1will be add itional costs for any sampling and te sting in the requirements in methods (i.e., carbon contents of process inputs, such c oke, coal, carbonate composition, or actual emissions). EPA is also assuming that additi onal costs will be incurred for preparing monitoring and QA/QC plans, performing th e calculations, reporting the results, and maintaining records.

4.2.2 Reporting Costs

To ensure consistency in the developm en t of cost estimates across all sources, EPA developed a cost spreadsheet template th at each subpart used to compile, document, and calculate per unit reporting costs. Detailed instructions were provided along with the cost spreadsheet template that clearly expl ained the data to be compiled and calculated. The template included three tables; analys is of reporting thresholds, analysis of monitoring and reporting opti ons, and unit costs for monitoring and reporting. Key variables and data fields were clearly define d 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, a nd administrative staff in both the private sector and the public sector. Staff hours are estim ated for activities including:

 monitoring (private): staff hours to opera te and maintain emissions monitoring systems;

 reporting (private): staff hours to gath er and process available data and reporting it to EPA through electronic systems; and

 assuring and releasing data (public): staff hours to quali ty assure, analyze, and release reports.

Staff activities and associated labor costs may vary over time. Thus, cost estimates are developed for start-up, firs t-time reporting, and subsequent reporting.
Loaded hourly labor rates (a lso referred to as “wage rates”) were developed for several labor categor ies to represent the employer costs to use an hour of employees’ time in each of the manufacturing sector labor ca tegories used in this analysis. The labor categories correspond to the job responsibilities of the perso nnel that are likely to be involved in GHG emissions monitoring activitie s at the manufacturi ng facility level to comply with the rulemaking.

4-2For purposes of this study, EPA adopted the m ethodology 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 ($/h r.) = Basic Wages ($/hr.) * (1 + Benefits Loading Factor + Overhead Loading Factor).

The benefits loading factor corresponds to the rela tive share of benefits compensation in the total employee compensatio n (comprising basic wages and benefits). Although the benefits factor tends to vary by labor cate gory and by industry (0.37 to 0.50), for purposes of this analysis, we have a ssumed the benefits load ing factor (1.7) to remain the same for each labor category acros s all industries within the manufacturing sector due to a lack of availability of nece ssary 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 compen sation. 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 load ing factor that we used in the wage rate calculations remains the same for all labor ca tegories and across all industry types within the manufacturing sector. The overhead lo ading factor was assumed to be 0.17.
Capital and O&M Costs . This includes the cost of purchasing and installing monitoring equipment or contractor cost s associated with providing the required information. Selected subparts do not require capital expend itures because the selected monitoring option does not requ ire capital equipment or the reporter already owns the necessary monitoring equipment. Equipment co sts 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, teleco mmunication 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.

4-3of m onitoring equipment and any facility/p rocess modification that may be required. For example, the cost estimation method for mob ile 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 th e 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 measurem ent uncertainties for estimating greenhouse gas (GHG) emissions from magnesium production and pr ocessing facilities were estimated for emissions of SF 6 , other GHG cover gases, and CO 2 carrier gas. We report the population of affected entities in Table 4-1.The cost estimation methodol ogy for this sector is based on information from the 2000 Information Collection Request for EPA’s SF 6 Emission Reduction Partnership for the Magnesium Indus try (EPA 2000). Burden estimates were gathered from four Partners (three die caste rs and one die cast/rem elt facility) and were averaged to represent a typical facilit y. Because the burden estimates in the ICR represented the costs of track ing only the cover gas, th e estimated labor hours for monitoring were increased by 25 percent to account for tracking of CO 2 , 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.

4-4Table 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 com ply ing with the proposed rulemaking were broken into 4 elements, each of which was ta ken into consideration for this sector.

4.3.2.1 Monitoring costs
Monitoring costs are ass ociated with da ta collection and tracking of cover and carrier gas usage at the facility. This e ffort includes determining gas total usage, estimating the average usage rate based on me tal production, and tracki ng activities taken to reduce emissions. Collection of gas consum ption data is typica lly 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 docum ent 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 recordk eeping 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.

4-54-6 4.3.3 Assigning Costs

4.3.3.1 Determining Labor Categories

To evaluate labor costs, it was not on ly 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 Load ed Hourly Rate ($/hour)
Legal Oversees legal aspects ofcompany 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 elem ents were assigned based on the 2000 Information Collection Request for EPA’s SF 6 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 ro les.Table 4-3.Responsibilities for Regulation Compliance by Labor CategoryResponsibilities and Hours by Labor CategoryLegalManagerialTechnicalClericalCost ElementResponsibilitiesHoursResponsibilitiesHoursResponsibilitiesHoursResponsibilitiesHoursPerFacility/PerCompany*MonitoringCollection ofcylinder trackingor bulk storagedataReview thecollection plan5Develop a collectionplan27.5Per FacilityReportingCompile data,enter intoreporting system,and submit reportReview thereportingdocumentation2Review thereportingdocumentation andsubmit report2Prepare reportingdocumentation6Per FacilityArchivingandRecordkeepingArchiving reportsArchive thereportingdocumentation4Per Facility4-7Once 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 co sts 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 reco rdkeeping 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 percen t interest rate. From these factors, a capital recovery factor of 31 percent wa s calculated resulting in an an nualized 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 a nnualized other costs is $153.

4.3.3.4 Estimate per Facility Costs for Each Threshold Level

The total rep orting costs per f acility are constant at each th reshold level because reporting costs are estimated to be identical for all facili ties. 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 m ines, and other underground mines having operational pre-mining degasificati on 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 cu tting machines, and transp orted 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 sour ce category is comprised of emission points of fugitive methane emissions for each coal mine ex ceeding 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 fo r which methane from the ventilation system is sampled quarterly by MSHA be required to report total methan e 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 unnecessa rily 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 covers4-9 MSHA data. In 2006, 114 mines exceeded the MSHA threshold for ventilation systems of 100,000 cubic feet per day.

The specific emissions points targ eted in this rulemaking are:

 Each ventilation well or shaft, including t hose 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 ar e 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 c ontinuous emission monitoring systems (CEMS) within the mine as a source of emissions re porting. If operators us e 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 th ese 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 liber ated from mine dega sification systems,

approximately 94% of the methane em itted from underground coal mine ve ntilation 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 dega sification wells, including gob gas vent holes and other de gasification wells that are currently not continuously monitored.
For coal mines with gas destruction sy stems, 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 ga s destroyed is monitored by using continuous monitors. This include s 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 system s 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 co al mines were used for cost development. Each mine exceeding the MSHA threshold was assu med to have two ventilation shafts where quarterly sampling would be conducted.
For mine degasification systems, only thos e systems where degasification systems are currently in place were considered.. For existing degasification systems, including gob gas vent wells/holes and other degasificati on wells that do not currently monitor degasified gas volumes produced, incremental costs were considered fo r two monitoring options: installing continuous monitoring equipment on these remote gob gas ve nt holes, or for conducting weekly sampling.

4.4.2 Cost Elements

4.4.2.1 Regulation compliance determination costs

Start-up registration costs consis t entirely of the labor nece ssary to study and review the regula tions 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 informati on to reflect any new equipment or facilities brought into operation or taken offline.

4.4.2.2 Monitoring costs

All costs ass ociated with complying w ith 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 pr e-compliance planning and preparation, system planning and equipment selection and purchase, installing and testi ng new equipment, and ensuring monitoring equipment are pr operly maintained and functioning.
Where sampling is the basis for emissions estim ation, costs include those associated with oversight, auditing, and conducting periodic inspections to es timate annual ventilation air emissions and emissions from degasification sy stems, internally developing the methodology for estimating emissions, training personnel in the pr ocess, 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 esti mates of emissions based on these samples.4-12 Where using data from continuous monito ring systems is the basis for emissions estimation, costs include those associated with oversight, auditing, a nd processing data to estimate annual ventilation air emissions and pro duced gas volumes from degasification systems, internally developing the me thodology 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 re porting costs; that is covere d in registration. Recurring reporting co sts consist of labor necessary to document collected emissions data from fugitive emissions monitoring and to submit the offi cial report in each cycle (i.e. annually).

4.4.2.4 Archiving and recordkeeping costs

Start-up archiving and recor dkeeping costs consist of la bor and annualized capital purchase of storage space. For archiving reports and associated working docum ents, physical storage systems such as file cabin ets and electronic storage systems such as external hard drives will be required. Recurring archiving and recordkeep ing costs consist entirely of labor necessary to adequately archive each cycle’s re port and associated working documents.

4.4.2.5 Auditing costs
There is no start-up cos t associated with a uditing. Recurring auditing costs consists of labor required to validate to the EPA results fr om the monitoring of emissions and the follow-up of rectifying any weaknesses found through the audit. The EPA aud it is expected to occur once every several years, not on an annual basis.

4.4.3 Proportion of Facilities in the Di fferent Model Facility Levels
In general, MSHA samples (quarterly or more frequently) and elec tronically keeps track of methane emissions for mines liberating more than 100,000 cubic feet of methane per day from ventilation systems, which is equi valent to about 15,000 metric tons CO 2 e 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 mi nes operating in the U.S. according to EIA,
ventilation air emissions base d on MSHA inspections were repor ted 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 th reshold for ventilation systems of 100,000 cubic feet of methane per day.

The number of mines with activ e 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 supplemen ted their ventilation systems with active degasification systems where the re covered gas was sold, used on si te, 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 thes e wells. Degasification wells could possibly be subject to new monitoring and reporting requireme nts. This includes both degasification wells where the recovered methane is sold, used on si te, 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 va ries 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 conventio nal 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 de gasification 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.climateac tionreserve.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, 10 th US/NA Mine Ventilation Symposium, Anchorage, Alaska, May 16-19, 20044-14  As part of developing the EPA greenhouse gas emissions inventory 6 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 availa ble, 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 r ecovered from the degasification systems associated with these wells, to develop es timated average state-sp ecific annual production rates and typical well lives for these degasifi cation wells. In some cases, these data were supplemented with degasification well reco very rates reported in the literature.

 For states with known degasification projec ts, estimates are developed by EPA of the volume of methane recovered from degasificati on systems that is sold, used on site, or otherwise destroyed; as well as that drained but not sol d, 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 di viding the estimate of methane emissions recovered by the estimated state-specific av erage production rate pe r degasification well. The degasification wells were allocated to individual mines according to the estimated
volumes vented versus that sol d, 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 de gasification. This estimate of total fugitive
methane emissions at the mine was then divi ded 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 system s where the recovered methane is sold, used on site, or otherwise destroyed. For cost estimati on purposes, it was assume d that these wells had an average 5 year life, resulting in an average of 280 new wells th at are brought on line each year (as a comparable number are retired).
Similarly, it was estimated that 500 degasifi cation 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 labo r 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 IC F Nov. 2007 Report’s supporting documentation for details on the wage rate calculation methodology. Source: Supporting Document for “Mandatory GHG Reporti ng Burden Assessment—Preliminary Draft,” ICF, 2007. Productivity and Costs, Fourth Quarter and Annual Averages, 200 7. Revised, Bureau of Labor Statistics, March 5, 2008
4.4.4.2 Allocating Responsibilities

Assigning labor hours for all cost elem ents was based on expert judgment. When assigning hours, role of the labor categories were taken into cons ideration. 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 opti ons (periodic sampling or the use of CEMS) for each of the two emission sources (ventilation sh afts 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 FacilityTable 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

First Year 188 428 128 Coal Mining -
CEMS Subsequent Years 48 128 64
Coal –Degasification Systems

First Year 20 650 18 Coal Mining – Weekly Sampling Subsequent Years 20 616 12

First Year 62 190 8 Coal Mining -
CEMS Subsequent Years 16 104 8

4.4.4.3 Capital Cost Annualization and O&M Costs

The capital costs r elated 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 e quipment for use in the periodic sampling. All costs are reported in 2006 U.S. dollars. Capita l 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 degasifi cation wells, because well lives are assumed to average 3 years). Continuous monitoring equipmen t 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 wa s calculated using the fo rmula provided below:

1)1( )1(

 

 n n

r rr CRF

4-174-18 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 sam pling of methan e content and gas flow, coal mine operators would be required to duplicate th e 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 pro cess 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 operato r would incur the capital and O&M costs involved in purchasing and maintaini ng the air sampling and testing equipment, and in sending air samples to an independent lab for analysis.
Operators would be required to measure both th e 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 purpos es of estimating the costs of compliance associated with this rulemaking, each mine is as sumed 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 requi red 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 th eir own samples, determine ventilation air emissions, and report results to EPA annually.

8 http://www.omega.com/guides/Results.html4-19 If operators use CEMS as the basis for emi ssions reporting for ventilation air emissions, they would be required to provide documenta tion on how emissions estimates were developed, as well as justification as to why the reported em issions 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 ope rate and maintain continuous monitoring equipment for purposes of complying with these emissions re porting 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 syst em s in underground mines would monitor emissions through continuous monitoring, conduc t weekly sampling, or carry out some combination of both. If pre-mining degasification we lls 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 cost s would not be incurred. However, additional costs would be associated with system pl anning and implementation, including internally develop the methodology for estimating emissions avoided from coal mine degasification systems; and for acquiring results from mon itoring systems quarterly, developing annual estimates, and reporting results to EPA. Methan e 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 sampli ng program, would be in curred. In addition all of the other system planning, implementation and reporting costs would also be incurred.

A vast range of continuous flow mete rs 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 specifical ly 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 va riety of options are available, with costs ranging from $500 to $3,000 per instrument, depending on app lication and operating environment. 11 Such instrumentation provides the capability for continuous monitoring.

For degasification wells already deploying c ontinuous monitoring, the incremental costs would only involve annual report ing of the degasified gas volum es 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 rate s 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 methanomet ers 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 woul d require mine operators to purchase air flow meters, methanometers, and/or sampling equipm ent, 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 th e 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/Produ ctList.aspx ?CategoryID=3056
,4-21  Each facility would need to internally develop procedures for estimating produced volumes and disposition of emissions fr om underground mine degasification systems. Facility managers would be required to re view 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 resu lts 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 dispos ition 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 syst em planning and implementation, and for acquiring results from monitoring systems quarterly, develo ping 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 m onitoring equipment on these remote gob gas vent holes, or in purchasing air fl ow 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 a ssumed 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 methanometer s would be generally more cost4-22 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 degasi fication 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 th e 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 fugiti ve 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 a nd reporting options. However, gi ven the high costs associated with installing new CEMS systems to monitor fug itive emissions in mine ventilation systems, it is assumed that only those facil ities with such system s already in place w ould 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 degasifica tion 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 presum ably already being monitored. Only the costs associated with system planning and implement ation, and for acquiring results from monitoring systems quarterly, developing annual estimates, a nd reporting results to EPA were considered. These costs were applied to the 15 mines assu med 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 w ould be co -located at facilities that already are required to repor t based on the 25,000 tonnes CO 2 equivalent (tCO 2 e) emissions4-23 threshold. As such, four differe nt options were evaluated to a ssess 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 tCO 2 e 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 tCO 2 e reporting threshold). Op tion 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 tCO 2 e reporting threshold). Option 4 is to limit the reporting requirements to industrial “organ ic waste” landfills that dispose of 20,000 Mg or more of waste annually (and that are located at facilities that exceed the 25,000 tCO 2 e reporting threshold). Option 1 through 4 include costs to determine the organic content of the waste materials; Option 4 also includes costs fo r mass weighing equipment both to determine applicability and to reduce uncertainty in the qua ntity of waste disposed. For the Industrial Landfill subpart, no costs were projected for monitoring gas collection systems because no industrial landfills are known to c ontain active gas collection systems. 12

For all options, costs were de veloped using the fully-burde ned, “industrial” labor rates presented previously (generic EPA labor rate table). Labor estimates for various requirements were developed based on the anticipated numbe r of technical/engineer ing 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 tota l 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 s ubsequent year costs due to the n eed to set-up the model, collect historical data for the first year, and to devel op (or revise) quality assurance plans to cover the industrial landfill sources.

12 No industrial landfills were identified that have gas collec tion 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 da ta storage media. Additionally, operating and material costs associated with sample analyses and reporting (copies, maili ng charges) were also considered for each i ndustrial 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 truc k scales would cost $40,000. The capital costs were annualized based on 15 ye ar equipment life and an annual in terest 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 bot h startup and recurring co sts for Options 1, 2, and 3.

i. Initial planning costs were estimated fo r the time needed to read the rule and internally determine the reporting needs for the landfills. On average, it would take 10 industrial engineer/techni cian hours per indu strial 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/te chnician 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 we re also estimated to be 9 industrial engineer/technician hours per indus trial landfill on an annual basis. iv. First year calculation costs for industr ial landfills were estimated to be 16 industrial engineer/techni cian 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 industria l landfills were estimated to be 4 industrial engineer/technici an hours per indus trial landfill, and subsequent year recordkeeping costs were al so estimated to be 4 industrial engineer/technician hours per indus trial landfill on an annual basis. vi. Industrial management hours were es timated to be 5 percent of the technical labor hours and administrativ e support hours were estimated to be 10 percent of the technical la bor hours for all planning, QA/QC, recordkeeping, calculating, and reporting activities. vii. Operating and material costs for wast e analyses (volatile solids analysis for estimating degradable organic cont ent) were estimated to be $50 per sample. Assuming 4 samples per year per industrial waste stream and 24-25 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 reco rdkeeping (filing cabinet and data storage device) were estimated to be $500 per industrial landfill, yielding a $55/year annualized cost of equipmen t (based on 15 year equipment life and an annual interest ra te 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 fo r the time needed to read the rule and internally determine the reporting needs for the landfills. On average, it would take 10 industrial engineer/techni cian hours per indu strial 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/te chnician 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 ho urs per industrial landfill, and subsequent year recordkeeping costs were also estimated to be 15 industrial engineer/techni cian hours per industria l landfill on an annual basis. iv. First year calculation costs for industr ial landfills were estimated to be 16 industrial engineer/techni cian 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 industria l landfills were estimated to be 4 industrial engineer/technici an hours per indus trial landfill, and subsequent year recordkeeping costs were al so estimated to be 4 industrial engineer/technician hours per indus trial landfill on an annual basis. vi. Industrial management hours were es timated to be 5 percent of the technical labor hours and administrativ e support hours were estimated to be 10 percent of the technical la bor hours for all planning, QA/QC, recordkeeping, calculating, and reporting activities. vii. Capital costs associated with monito ring equipment (industrial truck scale) were estimated to be $20,000 per indu strial 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 wast e analyses (volatile solids analysis for estimating degradable organic cont ent) were estimated to be $50 per sample. Assuming 4 samples per year per industrial waste stream and 24-26 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 reco rdkeeping (filing cabinet and data storage device) were estimated to be $500 per industrial landfill, yielding a $55/year annualized cost of equipmen t (based on 15 year equipment life and an annual interest ra te 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 dif ference 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 Emissi ons Covered by Industrial Landfill Options

Option Description Number
of Entities

Covered (#) Percentage
of Entities
Covered

(%) MTCO 2 e/

year Covered Percentage of
MTCO 2 e/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 app lies to the Industrial Wastewat er Treatm ent Source Category. This subpart applies to certain processes used to treat industrial wast ewater and wastewater treatment sludges at pulp and paper mills, food pr ocessing facilities, ethanol production facilities, and petroleum refineries. These processes are: anaerobic reactor s, anaerobic lagoons, anaerobic digesters for sludge, and biogas de struction devices. Operators are required to report the amount of methane (CH 4 ) these processes emit each year. The re gulation specifies how operators must estimate methane emissions. These estimation me thodologies require opera tors to monitor the amount of wastewater entering th e 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 an nualized costs) or $1.4 million for the 358 facilities estimated to incur m onitoring costs. This section describes how EPA estimated Subpart II monitoring costs and describes:

 wastewater and biogas monito ring 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 fac ilities required to monitor and source category monitoring costs; and

 changes from proposal.

4.6.1 Wastewater and biogas monitori ng required by 40 CFR Par t 98.354

Facilities that meet the reporting threshol d specified in §98.351 are required to monitor the amount of wastewater treated in anaerobic processes, the concen tration of organic material in the wastewater prior to this treatment, the amount of biogas recovered, an d the concentration of methane in the recovered biogas. These monito ring requirements are summarized in Table 1.

Table 4-9. Industrial Wastewater T reatment Monitoring Requirements

Material Measured Monitoring Requirement Frequency

Wastewater flow rate Once each cale ndar week that the system operates, with at least three days between measurements Wastewater influent to anaerobic

lagoons and anaerobic reactors

Wastewater COD or
BOD 5 concentration Once each calendar week that the system operates, with at least three days between measurements
Biogas flow rate Continuously Biogas recovered from anaerobic

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 f acilities are curre ntly following the Subpart II monitoring requirements. For requirements th at 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 ope rating, 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 measuremen ts. The flow measurement location4-29 and collection period must correspond to the location and period used to collect samples analyzed for COD or BOD 5 concentration.

EPA assumed that facilities do not currently measure the fl ow of wastewater into the anaerobic treatment process. Thus, facilities would be required to install meters to meet the GHG Reporting Rule monitoring requirements. EPA assu med 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 th e industrial facility dr ops into a wet well/lift station and is pumped from there into the anaero bic 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. Installati on costs include welded flanges to attach meters to existing piping, plumbing and electrical (bas ed on cost factors obtained from R.S. Means Building Construction Cost Data , 59th Edition, 2001), and costs for pe rmits, 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 calibrati on. Flow meter cost is based on the pipe size and flow m easured, 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 fr om a cost curve developed from costs for the 8, 16, and
24 inch meters.
EPA assumed that facilities would incur la bor costs for collecti ng 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. EP A further assumed the labor cost for a Grade 8 operator is $20/hour, so that th e 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, primar y clarification, oil-water separation, dissolved ai r flotation, or similar solids and oil separation processes). When the treatment system is operating, facilities are required to collect and analyze wa stewater samples for COD or BOD 5 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 wast ewater discharges according to their permit requirements. These requirements may be imposed by a National Pollution Discharge Elimination System (NPDES) perm it (for facilities that discharge to lakes or streams) or pretreatment permits (for facilities that discharg e to municipal sewer systems). Because facilities currently sample and analyze their treated wastew ater, EPA assumed that they have all necessary capital equipment, such as automatic composito rs, to conduct wastewater sampling activities.

EPA assumed that facilities w ould contract with an analytic al laboratory for analysis of their samples. EPA assumed the cost for analysis for COD or BOD 5 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 samp le of a Grade 8 wastewater treatment plant operator. EPA further assumed th e labor cost for a Grade 8 operator is $20/hour, so that the annual labor costs for sample collection are estimat ed as 1 hour/week x $20/hour x 52 weeks/year = $1,040/year. Total annual costs fo r wastewater sampling and analysis were estimated as $1,560 + $1,040 = $2,600/year.

Biogas Flow Rate. For each anaerobic process (such as anaerobic react or, digester, or lagoon) from which biogas is recovered, facilities must continuously measure the gas flow rate and determine the cumulative volume of gas r ecovered. 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 mete r capable of continuously measuring the volumetric flow rate of the recove red 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 rate4-31 measurement devices that meet the require ments 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 proce ss (such as an anaerobic reactor, digester, or lagoon) fr om which biogas is recovered, faci lities must measure the methane concentration either continuously or intermitten tly at least once each calendar week that the system operates, with at least three days betw een measurements. As speci fied 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 concentrati on. Facilities are also required to calibrate the gas composition monitors pr ior to the first reporting year and recalibrate the monitors either annually or at the mi nimum frequency specified by the manufacturer.
For the purpose of estimating costs for comp liance 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 w ould incur costs to install and operate gas composition monitors. EPA assumed that faci lities would conduct semi-continuous monitoring, such that they determine methane concentr ation once per week. There are many different methods for measuring biogas methane concentr ation. To estimate compliance costs, EPA assumed that facilities woul d install and operate an Inova 1316-1 multi-gas nondispersive infrared (NDIR) monitor, or equivalent, at an installed co st 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 foll owing in-line devices that control the moisture and hydrogen sulfide content of the biogas stream.
EPA assumed that facilities would purchas e gas calibration supplies at a cost of $200/year. EPA further assumed that facilities woul d 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 sample s 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 a ddition to the pretreatment and primary treatment performed at Grade 7. Grade 8 ope rators do more extensive testing than Grade 7 operators to determine such things as BOD 5 , suspended and dissolved solids, and dissolved oxygen. Operators at this level r ecord the results in standardized reports designed to meet4-32 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 $10,116 a 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 BOD 5 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 assum ed that facilities do not currently measure the fl ow of wastewater into the anaerobic treatment process and thus would be re quired to install meters. Flow meter cost is based on the pipe size and flow measured (see Ta ble 2). For this reason, EPA estimated facility wastewater flow rates. EPA estimated wastew ater flow rates for pulp and paper mills, food processing facilities, etha nol production facilities, a nd 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 th e flow rate of wastewater treated in 16 aerated stabilization basins. The fl ow rates ranged from 1 to 50 million gallons/day (MDG) with median approximately 10 MGD. EPA a ssumed that flow rates of wastewater treated in anaerobic lagoons are similar to the flow rates treated in ae robic stabilization basis. EPA further notes that pulp and pa per 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 cost s 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 cate gory in 2004. Information collected in support of this rulemaking, is available in the Technical Development Docume nt 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 wastewat er. EPA also found wastewater treatment design flow data reported in its NPDE S monitoring databases for fac ilities 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 pr ocessing flows are typically less than 11 MGD. Further, for purposes of estimating monitoring costs, EPA assu med food processing faci lities 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 ope rations 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 gene rally smaller than dry milling operations. EPA concluded that ethanol production facility flows are typicall y less than 3 MGD. Further, for purposes of estimating monitoring costs, EP A 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 th at petroleum refinery flows are typically less than 11 MGD. Further, fo r 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 7,2354-36 Annualized costs
EPA assumed that the capital equipment life time was 20 years and used that lifetime and an interest rate of 7 percent to annualize capital costs. Annuali zed 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 m onitor and source category monitoring costs
Only facilities that meet the reporting thresholds speci fied in §98.351 are required to report the methane emitted from their industria l 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 re quired 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 esti mate, EPA assumed that there are 565 pulp and paper mills ( Development Document for Proposed Ef fluent Limitations Guidelines and Standards for the Pulp, paper, a nd Paperboard Point Source Category , EPA-821-R-93-019, October 1993). Based on assumptions presente d 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 secondar y treatment would be required to report their methane emissions 15 . 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 colle cting and analyzing sa mples for COD or BOD 5 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 monitori ng 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 CO 2e per year in combined emissions from stationary fuel combustion units, industrial la ndfills, 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 em issions from industrial wastewater treatment would incur monitoring costs.
EPA’s estimates of the number of food pr ocessing facilities meeting the reporting threshold are presented in the Technical Support Document for I ndustrial 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 me thane 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 metr ic 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 f acilities 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 w ould not be required to report.
Thus, EPA assumed that 63 food processing faci lities (13 meat processors and 50 poultry processors) would be required to report the me thane 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 ra te and for collecting and analyzing samples for COD or BOD 5 concentration. EPA estimated that no f ood processing facilities would incur costs for monitoring biogas flow rate or biogas me thane concentration. EPA estimated that food processing facilities would incur $250,000 in to tal annualized costs to meet the monitoring requirements of the GHG reporting rule.

Ethanol Production Facilities. Ethanol production facilities ar e 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 la ndfills, and industrial wastewater treatment. However, for the purpose of this cost estimate, EPA assumed only etha nol 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 faci lities as of January 2009. EPA estimated that 85% (145) of these facilities used dry milli ng operations and 15% (25) used wet milling. Based on assumptions4-38 presented in Table 8-11 of the 2007 Inventory, EPA estimated that anaerobic wastewater treatment is used by 75% (108) of the dry m illing 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 I ndustrial Wastewater Treatment

. EPA assumed that four (4) of the 116 ethanol pr oduction facilities that us e anaerobic wastewater treatment emits methane in exce ss of the 25,000 metric tons CO2e per year threshold. EPA also assumed that these four facilities recover bioga s from its anaerobic wastewater treatment. EPA estimated ethanol production faci lities 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 petr oleum 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 treat ment. Further, EPA notes that all petroleum refineries are required to report their methane emissions 16 . 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 wast ewater flow rate and for collecting and analyzing samples for COD or BOD 5 concentration. EPA estimated that no refineries would incur costs for monitoring biog as flow rate or biogas methane concentration. EPA estimated that petroleum refineries would incur $594,000 in total annua lized 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 estim ated costs presented in this memora ndum differ from the estimated costs of the proposed Subpart II as follows:
At proposal, EPA assumed that all facilities were equippe d with flow meters to measure the flow of wastewater into the anaerobic treatm ent 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 re port emissions from all source cate gories 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 cu rrently meter the wastew ater flow into their anaerobic treatment units.4-40Table 4-14. Industrial Wastewater Treatment Monitoring CostsNational (Scaled-Up) Estimated CostsNational (Scaled-Up) Estimated CostsNational (ScaledUp) EstimatedCostsCategoryNo. ofPlantsRequiredto Report%PlantswithAnaerobicTreatmentNo. ofPlantswithAnaerobicTreatmentNo. ofPlantswith CH4RecoveryWWMonitoringCosts -CapWWMonitoringCosts -AnnualizedCapWWMonitoringCosts -AnnualWWMonitoringCosts -TACCH4RecoveryMonitoringCosts -CapCH4RecoveryMonitoringCosts -AnnualizedCapCH4RecoveryMonitoringCosts -AnnualCH4RecoveryMonitoringCosts -TACTotal(WW +CH4recovery)Monitoring TACPulp and paper56525%141.250$1,428,843$134,873$463,300$598,1730$0$0$0.00$598,173Food Processing63100%630$455,805$43,025$206,640$249,665$0$0$0$0.00$249,665Ethanol - wet mill15% of 170 mills4100%44$17,064$1,611$13,120$14,731$23,600$2,228$3,600$5,827.67$20,558Ethanol - dry mill85% of 170 mills075%00$0$0$0$0$0$0$0$0.00$0PetroleumRefineries150100%1500$1,085,250$102,440$492,000$594,440$0$0$0$0.00$594,440Total355.25$1,447,417Cap – capital costsTAC – total annualized costs (annualizedcapital costs plus annual costs)At proposal, EPA assumed th at non-continuous monitoring of biogas recovered from anaerobic digestion syst em s 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 inst alled cost of a multi-gas NDIR monitor (temperature and pressure compensation are no t 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 an alysis would be conducted once per month. The final regulation requires sa mpling and analysis once each calendar week that the system operates, with at least thr ee days between measurements. EPA increased the estimated costs for wastewater sampling and anal ysis 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 estim ates the public sector burden to be $343,582 per year for verification activities, program implementation, and developing and main taining the data coll ection system. Program implementation activities include, but are no t limited to, developi ng guidance and training materials to assist the regulated community, re sponding to inquires from affected facilities on monitoring and applicability re quirements, and developing tool s to assist in determining applicability.

4-41SECTION 5 ECONOMIC IMPACT ANALYSIS

EPA has prepared an EIA to provide decision m akers with a measure of the social costs of using resources to comply with the proposed GHG reporting requi rements. As noted in EPA’s (2000) Guidelines for Preparing Economic Analyses , several tools are av ailable to estimate social costs and range from simple direct complia nce 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 cons umer 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 em issions thresholds of 1,000 metric tons CO 2 e, 10,000 metric tons CO 2 e, 25,000 metric tons CO 2 e,, and 100,000 metric tons CO 2 e, as shown in Tables 5-1. Under the rule, magnesium metal production and parts casting facili ties would have to report their total GHG emissions if thos e emissions exceeded 25,000 metric tons CO 2 e. This threshold covers all currently identified ope rating U.S. primary and secondary magnesium producers and most die casters, ac counting for over 99 percent of emissions from these source categories. The proposed emissions threshold of 25,000 metric tons CO 2 e, is equal to emissions of 1,046 kg of SF 6 ; 19,231 kg of HFC–134a; or 25,000,000 kg of CO 2 or FK 5–1–2. Other emission threshold options that we considered were 1,000 metric tons CO 2 e, 10,000 metric tons CO 2 e, and 100,000 metric tons CO 2 e. The 10,000 metric tons CO 2 e, emission threshold yielded results identical to thos e of the selected option.
Table 5-1. Threshold Analysis for Subpart T – Magnesium Production

Emissions Covered Facilities Covered Emission Threshold Level (metric tons CO 2 e/yr) Total National Emissions (metric tons

CO 2 e/yr) Total Number of Facilities metric tons CO 2 e/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%

5-1The em issions 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 ava ilable data regarding consumption of SF 6 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 thres hold of 25,000 metric tons CO 2 e also takes into account the variability in cover gas identities, usage rate s, and process conditions. Alternatives to SF 6 have considerably lower GWPs than SF 6 . In facilities where SF 6 is used, the usage rate can vary by an order of magnitude depending on the casting pro cess and operating conditions. Therefore, cover gas emissions are not well predicted by producti on capacity. Because emissions of each cover gas are assumed to equal use, and fa cilities are expected to track gas use in the ordinary course of business, facilities should have li ttle difficulty determining whethe r or not they must report under
this rule. For a full discussion of the thresh old analysis, please re fer to the Magnesium Production TSD (EPA–HQ–OAR–2008– 0508–020).

5-25-3 5.1.2 Subpart FF- Underground Coal Mines

All active underground coal m ines for which CH 4 from the ventilation system is sampled quarterly by MSHA (or on a more frequent basis) , are required to report under this rule. MSHA conducts quarterl y testing of CH 4 concentration and flow at mines emitting more than 100,000 cf CH 4 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 CH 4 per day covers approximately 94 percent of the CH 4 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 fo r Subpart FF –Underground Coal Mines

Emissions Covered Facilities Covered Emission Threshold Level (metric tons CO 2 e/yr) Total National Emissions (metric tons

CO 2 e/yr) Total Number of Facilities metric tons CO 2 e/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%5.1.3Subpart TT- Industrial Waste LandfillsTable 5-3. Threshold Analysis for Subpart TT– Industrial Waste LandfillsEmissions CoveredFacilities CoveredDescription of OptionTotal NationalEmissions(metric tonsCO2e/yr)Total Number ofFacilitiesmetric tonsCO2e/yrPercentFacilitiesPercentAll industriallandfills report15.42,31015.4100.0%2,310100.0%Only “organic”waste industriallandfills report15.42,31014.896.1%60726.3%Only “organic”waste industriallandfills with designcapacity of300,00 Mg or morereport15.42,31013.789.0%2008.7%Only “organic”waste industriallandfills that accept20,000 tons/yr ormore of waste report15.42,31013.084.4%1004.3%All industriallandfills report15.42,31015.4100.0%2,310100.0%5-45.1.4 Subpart II- Industrial Wastewater Treatment

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

Emissions Covered Facilities Covered Emission Threshold Level (metric tons CO 2 e/yr) Total National Emissions (metric tons

CO 2 e/yr) Total Number of Facilities metric tons CO 2 e/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 CO 2 e/yr) Total National Emissions (metric tons

CO 2 e/yr) Total Number of Facilities metric tons CO 2 e/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%

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

Emissions Covered Facilities Covered Emission Threshold Level (metric tons CO 2 e/yr) Total National Emissions (metric tons

CO 2 e/yr) Total Number of Facilities metric tons CO 2 e/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 CO 2 e/yr) Total National Emissions (metric tons

CO 2 e/yr) Total Number of Facilities metric tons CO 2 e/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 em issions covered under the selected options are 190.6 MtCO 2 e (Table 5-8). The majority of these c overed emissions are from pulp and paper covered by Subpart AA (140 MtCO 2 e). 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 Industr y Classification System (NAICS); the mapping allows the cost data to be used in co njunction with other economic census data.

5-6Table 5-8. Estimates of Emissions (MtCO 2 e) Reported in 2008 Unde r the Selected Option

Subpart Emissions Coverage (MtCO 2 e) 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 262.4 a

Total 313.4

a Includes total covered emissions es timates for pulp and paper and refinery indus tries. Ethanol and food processing emissions were not estimated.
5.2 National Cost Estimates

As shown in Table 5-6, the total national costs f or the selected option are estimated to be $7.0 million in the first year and $5.5 million in s ubsequent years ($2006). This includes a public sector burden estimate of $0.3 for program impl ementation and verificati on activities. Subparts bearing the greatest share of the ongoing private cost s of the rule are the coal mining industry (51 percent).

5-7Table 5-9. National Annuali zed Mandatory Repo rting 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 a nd focus on small entities. We provide additional details of the analysis below.

5.3.1 Assessing Economic Impac ts on Small Entities

The f irst step in this assessment was to dete rmine whether the rule will have a significant impact on a substantial number of small entities (SIS NOSE). To make this determination, EPA

5-8used a screening analysis that allows us to indicate whether EPA can certify the rule as not having a SIS NOSE. 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 du ring the developm ent of the cost analysis for the reporting rule. The SU SB data provide national information on the distribution of economic variable s by industry and size (U.S. Bureau of the Census, 2008). These data were developed in coopera tion 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 entitie s would not be expected to report under the preferred option because they would fall belo w the 25,000 hybrid threshold. SUSB also provides this data by enterprise employme nt size. The census definitions in this data set are as follows:

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

 employment : Paid employment consists of full- and part-time employees, including salaried officers and executives of corpor ations, who were on the payroll in the pay period including March 12, 2002. Included are em ployees on sick leave, holidays, and vacations; not included are proprietors and partners of unincorporated businesses.

 receipts : Receipts (net of taxes) are define d as the revenue for goods produced, distributed, or services provided, in cluding revenue earned from premiums, commissions and fees, rents, interest, divi dends, and royalties. Receipts exclude all revenue collected for local, state, and federal taxes.

 enterprise : An enterprise is a business organi zation consisting of one or more domestic establishments that were specifi ed 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

5-9Because the SBA’s business size definitions (SBA, 2008) apply to an establishm ent’s “ultimate parent company,” we assume in this an alysis 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 st andard(s) for each industry group in order to facilitate comparisons a nd different thresholds.

5.3.1.2 Develop Small Entity Economic Impact Measures

Because the rule cov ers a large number of s ubparts and primarily covers businesses, the analysis generated a set of sales test s (represented as cost-to-receipt ratios) 17 for NAICS codes associated with the affected subparts. Alt hough the appropriate SBA size definition should be applied at the parent company (ent erprise) 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 (t he “enterprise”) may have othe r economic resources that could be used to cover the cost s of the reporting program.
These sales tests examine the average es tablishment’s total annualized mandatory reporting costs to the average establishment recei pts for enterprises within several employment categories 18 (first year costs: Table 5- 12; subsequent year costs: Ta ble 5-13). The average entity costs used to compute the sales test are the same across all of these enterpri se size categories. As a result, the sales-test will overstate the cost-to- receipt ratio for establishments owned by small businesses, because the reporting costs are likely lower than average entity estimates provided by the engineering cost analysis.

17 The following metrics for other small entity economic impact measures (if applicable) would potentially include

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

government revenues

 Small non-profits (if applicable): “Expenditure” test; annualized compliance cost as a percentage of annual

operating expenses 18 For the one to 20 employee category, we exclude SU SB data for enterprises with zero employees. These enterprises did not operate the entire year.

5-105-11 5.3.1.3 Results of Screening Analysis

The Regulatory Flexibility Act generally re quires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substa ntial number of small entities. Small entities include small businesses, small governmental jurisdictions, and sm all not-for-profit enterprises.
For the purposes of assessing the impacts of th e 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 governme nt 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 owne d 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 si ze categories. For one NAI CS (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 Regulat ory Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions (EPA- HQ-OAR-2008-0508) illust rated that pulp and paper industry enterprises with less than 20 employ ees 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.5-12Table 5-10. Number of Establishments by Affected Industry and EnterpriseaSize: 2002Owned by Enterprises with:2007NAICSNAICS DescriptionSubpartSBA Size Standard(effective August 22,2008)TotalEstablishments1 to 20Employeesb20 to 99Employees100 to 499Employees500 to 749Employees750 to 999Employees1,000 to1,499Employees331419Primary Smelting andRefining of NonferrousMetal (except Copper andAluminum)T750 employees150692317513331492Secondary Smelting,Refining, and Alloying ofNonferrous Metal (exceptCopper and Aluminum)T750 employees230954940163212112Bituminous CoalUnderground MiningFF500 employees49914611756918322110Pulp MillsTT750 employees44847224322121Paper (except Newsprint)MillsTT750 employees32256325711237322122Newsprint MillsTT750 employees31437NA34322130Paperboard MillsTT750 employees231291617NA66311611Animal (except Poultry)SlaughteringTT500 employees1,8161,2542037813213311411Frozen Fruit, Juice, andVegetable ManufacturingTT500 employees24344415211517311421Fruit and Vegetable CanningTT500 employees78132414496261225322110Pulp MillsII750 employees44847224322121Paper (except Newsprint)MillsII750 employees32256325711237322122Newsprint MillsII750 employees31437NA345-13322130Paperboard MillsII750 employees231291617NA66311611Animal (except Poultry)SlaughteringII500 employees1,8161,2542037813213311411Frozen Fruit, Juice, andVegetable ManufacturingII500 employees24344415211517311421Fruit and Vegetable CanningII500 employees78132414496261225325193Ethyl AlcoholManufacturingII1,000 employees66201651NA4324110Petroleum RefineriesII1,500 employeesc3498529281073Note: NA denotes that the enterprise category is not applicable(i.e., no enterprises were reported within this category).aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified under common ownership or control.The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment andannual payroll are summed from the associatedestablishments. Enterprisesize designations are determined by the summed employment of all associated establishments.Sincethe SBA’s business size definitions (http://www.sba.gov/size) apply toan establishment’s ultimate parent company, we assume inthis analysis that the enterprise definitionabove is consistent with the concept of ultimate parent company thatis typically used for SmallBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bExcludesStatistics of U.S. Businesses(SUSB) employment category for zero employees. These entities only operated for a fraction of the year.cNAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total OperableAtmospheric 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 totalproduct 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.5-14Table 5-11. Receipts by Affected Industry and EnterpriseaSize (million, 2002$)Owned by Enterprises with:NAICSNAICS DescriptionSubpartSBA Size Standard(effective August 22,2009)Total Establishments1 to 20Employeesb20 to 99Employees100 to 499Employees500 to 749Employees750 to 999Employees1,000 to1,499Employees331419Primary Smelting andRefining of NonferrousMetal (except Copper andAluminum)T750 employees$2,306$81$100$162DDD331492Secondary Smelting,Refining, and Alloying ofNonferrous Metal (exceptCopper and Aluminum)T750 employees$2,997$143$683$216DDD212112Bituminous CoalUnderground MiningFF500 employees$9,633$166$125$953DDD322110Pulp MillsTT750 employees$3,791$10DDDDD322121Paper (except Newsprint)MillsTT750 employees$42,660D$296DDDD322122Newsprint MillsTT750 employees$3,115DDDNADD322130Paperboard MillsTT750employees$21,379$15$173$407NADD311611Animal (except Poultry)SlaughteringTT500 employees$55,775$1,344$1,615$4,121DD$2,259311411Frozen Fruit, Juice, andVegetable ManufacturingTT500 employees$9,490$87$388$1,504$435D$939311421Fruit and Vegetable CanningTT500 employees$18,976$462$1,381$2,392$1,134$1,142$1,334322110Pulp MillsII750 employees$3,791$10DDDDD322121Paper (except Newsprint)MillsII750 employees$42,660D$296DDDD322122Newsprint MillsII750 employees$3,115DDDNADD322130Paperboard MillsII750employees$21,379$15$173$407NADD311611Animal (except Poultry)SlaughteringII500 employees$55,775$1,344$1,615$4,121DD$2,259311411Frozen Fruit, Juice, andVegetable ManufacturingII500 employees$9,490$87$388$1,504$435D$939311421Fruit and Vegetable CanningII500 employees$18,976$462$1,381$2,392$1,134$1,142$1,3345-15325193Ethyl AlcoholManufacturingII1,000 employees$2,097DDDDNAD324110Petroleum RefineriesII1,500 employeesc$195,752$467$2,519$4,500$8,758DDNote: D denotes that receipt data was notdisclosed. NA denotes that the enterprise category is not applicable (i.e., no enterprises were reported within this category).aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified under common ownership or control.The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment andannual payroll are summed from the associatedestablishments. Enterprisesize designations are determined by the summed employment of all associated establishments. Sincethe SBA’s business size definitions (http://www.sba.gov/size) apply toan establishment’s ultimate parent company, we assume inthis analysis that the enterprise definitionabove is consistent with the concept of ultimate parent company thatis typically used for SmallBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bExcludesStatistics of U.S. Businesses(SUSB) employment category for zero employees. These entities only operated for a fraction of the year.cNAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total OperableAtmospheric Crude Oil Distillation capacity.Capacity includes owned or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or a throughput. The totalproduct to be delivered under the contract must be at least 90 percent refined by the successful bidder from either crude oil or bona fide feedstocks.5-16Table 5-12. Establishment Sales Tests by Industry and EnterpriseaSize: First Year CostsOwned by Enterprises with:2007NAICSNAICS DescriptionSub-partSBA SizeStandard(effective August22, 2008)AverageCost PerEntity($/entity)AllEnterprises1 to 20Employeesb20 to 99Employees100 to 499Employees500 to 749Employees750 to 999Employees1,000 to1,499Employees331419Primary Smelting and Refining ofNonferrous Metal (except Copper andAluminum)T750 employees$10,5200.1%0.9%0.2%0.1%DDD331492Secondary Smelting, Refining, andAlloying of Nonferrous Metal (exceptCopper and Aluminum)T750 employees$10,5200.1%0.7%0.1%0.2%DDD212112Bituminous Coal Underground MiningFF500 employees$34,7170.2%3.0%3.4%0.2%DDD322110Pulp MillsTT750 employees$5,5830.0%0.4%D D D DD322121Paper (except Newsprint) MillsTT750employees$5,5830.0%D0.1%DDDD322122Newsprint MillsTT750 employees$5,5830.0%DDDNADD322130Paperboard MillsTT750 employees$5,5830.0%1.1%0.1%0.0%NADD311611Animal (except Poultry) SlaughteringTT500 employees$5,5830.0%0.5%0.1%0.0%DD0.0%311411Frozen Fruit, Juice, and VegetableManufacturingTT500 employees$5,5830.0%0.3%0.1%0.0%0.0%D0.0%311421Fruit and Vegetable CanningTT500 employees$5,5830.0%0.4%0.1%0.0%0.0%0.0%0.0%322110Pulp MillsII750 employees$4,2350.0%0.3%D D D DD322121Paper (except Newsprint) MillsII750employees$4,2350.0%D0.0%DDDD322122Newsprint MillsII750 employees$4,2350.0%DDDNADD322130Paperboard MillsII750 employees$4,2350.0%0.8%0.0%0.0%NADD311611Animal (except Poultry) SlaughteringII500 employees$3,9630.0%0.4%0.0%0.0%DD0.0%311411Frozen Fruit, Juice, and VegetableManufacturingII500 employees$3,9630.0%0.2%0.0%0.0%0.0%D0.0%5-17311421Fruit and Vegetable CanningII500 employees$3,9630.0%0.3%0.0%0.0%0.0%0.0%0.0%325193Ethyl Alcohol ManufacturingII1,000 employees$5,1400.0%DDDDNAD324110Petroleum RefineriesII1,500 employeesc$3,9630.0%0.1%0.0%0.0%0.0%DDNote: D denotes that receipt data was notdisclosed. NA denotes that the enterprise category is not applicable (i.e., no enterprises were reported within this category). Receipt datain Table 5-7 has been adjusted to 2006$ using the latest GDP implicit price deflator reported bythe U.S. Bureau of Economic Analysis (103.257/92.118=1.121)http://www.bea.gov/national/nipaweb/Index.asp(accessed December 21, 2009).aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified under common ownership or control.The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment andannual payroll are summed from the associatedestablishments. Enterprisesize designations are determined by the summed employment of all associated establishments. Sincethe SBA’s business size definitions (http://www.sba.gov/size) apply toan establishment’s ultimate parent company, we assume inthis analysis that the enterprise definitionabove is consistent with the concept of ultimate parent company thatis typically used for SmallBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bExcludesStatistics of U.S. Businesses(SUSB) employment category for zero employees. These entities only operated for a fraction of the year.cNAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total OperableAtmospheric 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 totalproduct 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.5-18Table 5-13. Establishment Sales Tests by Industry and EnterpriseaSize: Subsequent Years CostsOwned by Enterprises with:2007NAICSNAICS DescriptionSubpartSBA SizeStandard(effectiveAugust 22,2008)AverageCost PerEntity($/entity)AllEnterprises1 to 20Employeesb20 to 99Employees100 to 499Employees500 to 749Employees750 to 999Employees1,000 to1,499Employees331419Primary Smelting and Refining ofNonferrous Metal (except Copper andAluminum)T750 employees$10,5200.1%0.9%0.2%0.1%DDD331492Secondary Smelting, Refining, andAlloying of Nonferrous Metal (exceptCopper and Aluminum)T750 employees$10,5200.1%0.7%0.1%0.2%DDD212112Bituminous Coal Underground MiningFF500 employees$24,9650.1%2.2%2.3%0.1%DDD322110Pulp MillsTT750 employees$4,1020.0%0.3%D D D DD322121Paper (except Newsprint) MillsTT750employees$4,1020.0%D0.0%DDDD322122Newsprint MillsTT750 employees$4,1020.0%DDDNADD322130Paperboard MillsTT750 employees$4,1020.0%0.8%0.0%0.0%NADD311611Animal (except Poultry) SlaughteringTT500 employees$4,1020.0%0.4%0.1%0.0%DD0.0%311411Frozen Fruit, Juice, and VegetableManufacturingTT500 employees$4,1020.0%0.2%0.0%0.0%0.0%D0.0%311421Fruit and Vegetable CanningTT500 employees$4,1020.0%0.3%0.0%0.0%0.0%0.0%0.0%322110Pulp MillsII750 employees$4,2350.0%0.3%D D D DD322121Paper (except Newsprint) MillsII750employees$4,2350.0%D0.0%DDDD5-19322122Newsprint MillsII750 employees$4,2350.0%DDDNADD322130Paperboard MillsII750 employees$4,2350.0%0.8%0.0%0.0%NADD311611Animal (except Poultry) SlaughteringII500 employees$3,9630.0%0.4%0.0%0.0%DD0.0%311411Frozen Fruit, Juice, and VegetableManufacturingII500 employees$3,9630.0%0.2%0.0%0.0%0.0%D0.0%311421Fruit and Vegetable CanningII500 employees$3,9630.0%0.3%0.0%0.0%0.0%0.0%0.0%325193Ethyl Alcohol ManufacturingII1,000employees$5,1400.0%DDDDNAD324110Petroleum RefineriesII1,500employeesc$3,9630.0%0.1%0.0%0.0%0.0%DDNote: D denotes that receipt data was notdisclosed. NA denotes that the enterprise category is not applicable (i.e., no enterprises were reported within this category). Receipt datain Table 5-7 has been adjusted to 2006$ using the latest GDP implicit price deflator reported bythe U.S. Bureau of Economic Analysis (103.257/92.118=1.121)http://www.bea.gov/national/nipaweb/Index.asp(accessed December 21, 2009).aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that werespecified under common ownership or control.The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment andannual payroll are summed from the associatedestablishments. Enterprisesize designations are determined by the summed employment of all associated establishments. Sincethe SBA’s business size definitions (http://www.sba.gov/size) apply toan establishment’s ultimate parent company, we assume inthis analysis that the enterprise definitionabove is consistent with the concept of ultimate parent company thatis typically used for SmallBusiness Regulatory Enforcement Fairness Act (SBREFA) screening analyses.bExcludesStatistics of U.S. Businesses(SUSB) employment category for zero employees. These entities only operated for a fraction of the year.cNAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total OperableAtmospheric 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 totalproduct 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 EXECUT IVE ORDE R 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 regulator y action" under the term s of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) and is th erefore 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 subseque nt 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 An alysis 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 inf ormation collection requirements in this rule have been submitted for approval to the Office of Management and Budget (OMB) u nder the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The information collection requirem ents are not enforceable until OMB approves them.
EPA plans to collect complete and accura te 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 co llected under this rule, EPA will gain a better understanding of the relative emi ssions of specific industries, a nd 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, partic ularly in response to policies and potential regulations. The data collected by this rule will improve EPA’s ability to

6-1for mulate 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. Howe ver, 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. Th e 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 respondent s resulting from the collection of information includes the total capital cost annualized ove r the equipment’s expected useful life (averaging $0.5 million), a total operation and maintenance component (averaging $1.6 million pe r year), and a labor cost component (averaging $3.6 million per year).

Burden is defined at 5 CFR 1320.3(b). Thes e cost numbers differ from those shown elsewhere in the Regulatory Impacts Analysis (RIA) for the proposed subparts because the information collection request (ICR) costs represen t the average cost over th e first three years of the rule, but costs are reported elsewhere in the RIA for the propos ed 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, a nd a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA’s regulations in 40 CFR ar e listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a te chnical amendment to 40 CFR part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in this final rule.

6.3 Regulatory Flexibility Act (RFA)

The RFA ge nerally requires an agency to prep are a regulatory flexibil ity analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifie s that the rule will not have a significant economic impact on a substantial number of sm all entities. Small en tities include small businesses, small organizations, a nd small governmental jurisdictions.

6-2For purposes of assessing the im pacts on small entities, a small enti ty is defined as a small business as defined by the Small Busi ness Administration’s regulations at 13 CFR 121.201; according to these size standa rds, criteria for determining if ultimate parent companies owning affected facilities are categorized as sm all vary by NAICS. Small entity criteria range from total number of employees at the firm fe wer than 500 to number of employees fewer than 1,500; one affected NAICS, 324110, the petroleu m refiner must have no more than 1,500 employees nor more than 125,000 barrels per cale ndar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased faciliti es 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 unde r the contract must be at least 90 percent refined by the successful bidder from either crude oil or bona fi de feedstocks. EIA tables 5-10 and 5-11 present small business criteria and enterprise si ze distribution data for affected NAICS.
EPA assessed the potential impacts of the pr oposed rule on small entities using a sales test, defined as the ratio of total annualized co mpliance costs to firm sa les. Details are provided in section 5.3 of the EIA. These sales tests ex amine 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 provi ded 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 si ze categories. For one NAI CS (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 Regulat ory Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions (EPA- HQ-OAR-2008-0508) illust rated that pulp and paper industry enterprises with less than 20 employ ees 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 economi c impacts of today’s proposed rule on small entities, I therefore certify that this pr oposed rule will not have a significant economic impact on a substantial number of small entities.

6-3Although this rule would not have a signifi cant econom ic 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 pub lic-sector stakeholders. When developing the rule, the Agency took special steps to ensure th at the burdens imposed on small entities were minimal. The Agency conducted several meetings with industry trade associations to discuss regulatory options a nd the corresponding burden on i ndustry, such as recordkeeping and reporting. The Agency investig ated 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 provi des flexibility to enti ties 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 conducte d during the development of th e 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 th e Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104-4, establishes requirements for federal agencies to assess the eff ects of their regulatory actions on state, local, and tribal governments and the private sector . Under Section 202 of th e UMRA, EPA generally must prepare a written statement, including a cost-b enefit 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 a nnualized 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 requireme nts 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 facili ties currently known to undertake these ac tivities are owned by small governments.

6-46.4.1 Executive Order 13132: Federalism

These final s ubparts 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 vari ous 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 govern ment entity owns a facility that directly emits gr eenhouse 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 Stat es 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 Or der 13132, and consistent with EPA policy to promote communications between EPA and State and lo cal governments, EPA specifically solicited comments on these subparts from State and local offi cials. For a discussion of outreach activities to State, local, or Tribal organizations, s ee Section IX of the preamble to the proposed Mandatory GHG Reporting Rule (74 FR 16602).

6.4.2 Executive Order 13175: Consultation and Coor dination with Indian Tribal
Governments

This action does not have Tribal implicati ons, 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 aff ected by these final subpart s are not expected to be owned by Tribal governments. Thus, Execu tive Order 13175 does not apply to this action.
Although EO 13175 does not apply to these fi nal subparts, EPA sought opportunities to provide information to Tribal governments a nd representatives during development of the proposed Mandatory GHG Reporting Rule, which incl uded these subparts being finalized today. See Section IX of the preamble to the propos ed Mandatory GHG Reporti ng 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 c oncern health or safety risks, such that the analysis required under

6-5section 5-501 of the EO has the po tential to influence the regulation. This action is not subject to EO 13045 because it do es not establish an environmen tal standard intended to mitigate health or safety risks.

6.4.4 Executive Order 13211: Actions that Significan tly Affect Energy Supply, Distribution , or Use

This action is not a “significant energy ac tion” 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 monitori ng, reporting and recordkeeping at facilities that directly emit greenhouses gases and does not im pact 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 S ection 12(d) of the National Technology Transfer and Advancem ent Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standard s in its regulatory activities unless to do so would be inconsistent with appl icable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifi cations, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA direct s EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applic able voluntary consensus standards.
This rulemaking involves techni cal standards. For these final subparts, EPA has decided to use more than a dozen voluntary consensus st andards from four different voluntary consensus standards bodies, including American Society fo r Testing and Materials (ASTM) and ASME.
These voluntary consensus standards will help f acilities 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 GH G emissions. The existing methods (voluntary consensus standards) include a broad range of measurement te chniques, including methods to measure gas or liquid flow and methods to an alyze gases by gas chromatography. All except two of these methods have alr eady been incorporated by refere nce in the final Mandatory GHG

6-66-7 Reporting Rule. Thus, we are adding entrie s to 40 CFR 98.7 for new voluntary consensus standards and modifying the entrie s for other voluntary consensus st andards 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 av ailable as specified in 40 CFR 98.7.
By incorporating voluntary consensus standa rds 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 Addr ess Environ mental Justice in Minority Populations and Low-Income Populations

Executive Order (EO) 12898 (59 FR 7629 (Fe b. 16, 1994)) establishes federal executive policy on environmental justice. Its main provi sion directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disp roportionately high and adverse human health or environmental effects of their programs, policie s, and activities on minority populations and lowincome populations in the United States.
EPA has determined that these final subpart s 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 prot ection provided to human health or the environment. These final subparts do not affect the level of protection provided to huma n health or the environment because they address information co llection 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 Enforcem ent Fairness Act of 1996 (SBREFA ), generally provides that before a rule may take effect, the agency pr omulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congre ss and to the Comptroller General of the United States. EPA will submit a report containing this ru le 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 Fede ral Register. A major rule cannot take effect until 60 days after it is published in the Federal Register. This act ion is not a “major rul e” as defined by 5 U.S.C. 804(2).SECTION 7 CONCLUSIONS
EPA is promulgating a regula tion to require m onitoring a nd 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 sour ce categories only fo r sources with CO 2 equivalent emissions above certain threshold levels but does not require control of greenhouse gases. EPA has made the decision not to include ethanol pr oduction 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 (includi ng electrolytic smelting), refining, or remelting operations, or any site where mo lten magnesium is used in allo ying, casting, drawin g, extruding, forming, or rolling operations. Facilities that m eet the applicability cr iteria in the General Provisions (40 CFR 98.2(a)) summ arized 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 m ines 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 mi ned 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 Admi nistration (MSHA) as active and where coal is currently being produced or has been produced within the prev ious 90 days. This source category consists of each ventilation well or shaf t, 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 activit ies (e.g., storage or transportation of coal).

7-17-2 7.1.3 Subpart TT: Industrial Waste Landfills

This source catego ry consists of industrial waste landfills whose total landfill design capacity is greater than or equal to 300,000 metr ic tons and that accepted waste on or after January 1, 1980 and, if present, landfill gas co llection systems and la ndfill gas destruction devices (including flares). This source category does not incl ude Resource Conservation and Recovery Act (RCRA) Subtitle C or Toxic S ubstances 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 foundr y sand), clay, gypsum, pottery cull, bricks, mortar, cement, furnace slag, refractory material, or plastics. Facilities that meet the applicability criteria in the General Provisi ons (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 tr eat industrial wastewater and

wastewater treatm ent sludges at pulp and pa per mills, food processing facilities, ethanol production facilities, and petroleu m refineries. It does not include domestic wastewater treatment plants or separate treatment of sanitary wastew ater at industrial facili ties. It does not include oil/water separators. This source category consists of the following: anaerobic reactors, anaerobic lagoons, anaerobic sludge digesters, and biogas destruc tion devices. Facilities that meet the applicability criteria in the General Provisions (40 CF R 98.2(a)) summarized in Section II.B of this preamble must report GHG emissions.

7.2 Estimated Costs and Impacts of th e Mandatory GHG Reporting Program

The total national co sts for the selected opti on 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 appr oximately less than 0.01% of 2008 gross domestic product; overall, EPA does not believe the rule wi ll have a significant macroeconomic impact on the national economy or on small entities within those sectors.SECTION 8 REFERENCES

U.S. Environm ental 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 Classi fication System Codes. Effective August 22, 2008. http://www.sba.gov/services/contrac tingopportunities/size standardstopics/
size/index.html.

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