Document ID: EPA-HQ-OAR-2008-0508-2325
Agency: epa
Document Type: Rule
Title: Mandatory Reporting of Greenhouse Gases From Magnesium Production, Underground Coal Mines, Industrial Wastewater Treatment, and Industrial Waste Landfills; Final Rule
Posted Date: 2010-07-12T04:00Z

[Federal Register: July 12, 2010 (Volume 75, Number 132)]
[Rules and Regulations]               
[Page 39735-39777]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12jy10-9]                         

[[Page 39735]]

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Part II

Environmental Protection Agency

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40 CFR Part 98

Mandatory Reporting of Greenhouse Gases From Magnesium Production, 
Underground Coal Mines, Industrial Wastewater Treatment, and Industrial 
Waste Landfills; Final Rule

[[Page 39736]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2008-0508; FRL-9171-1]
RIN 2060-AQ03

 
Mandatory Reporting of Greenhouse Gases From Magnesium 
Production, Underground Coal Mines, Industrial Wastewater Treatment, 
and Industrial Waste Landfills

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is promulgating a regulation to require monitoring and 
reporting of greenhouse gas emissions from magnesium production, 
underground coal mines, industrial wastewater treatment, and industrial 
waste landfills. This action adds these four source categories to the 
list of source categories already required to report greenhouse gas 
emissions. This action requires monitoring and reporting of greenhouse 
gases for these source categories only for sources with carbon dioxide 
equivalent emissions above certain threshold levels as described in 
this regulation. This action does not require control of greenhouse 
gases.

DATES: The final rule is effective on September 10, 2010. The 
incorporation by reference of certain publications listed in the rule 
is approved by the Director of the Federal Register as of September 10, 
2010.

ADDRESSES: EPA established a single docket under Docket ID No. EPA-HQ-
OAR-2008-0508 for this action and for the previous action promulgated 
October 30, 2009 (74 FR 56260). All documents in the docket are listed 
on the http://www.regulations.gov Web site. Although listed in the 
index, some information is not publicly available, e.g., confidential 
business information (CBI) or other information whose disclosure is 
restricted by statute. Certain other material, such as copyrighted 
material, is not placed on the Internet and will be publicly available 
only in hard copy form. Publicly available docket materials are 
available either electronically through http://www.regulations.gov or 
in hard copy at EPA's Docket Center, Public Reading Room, EPA West 
Building, Room 3334, 1301 Constitution Avenue, NW., Washington, DC 
20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holidays. The telephone number for the 
Public Reading Room is (202) 566-1744, and the telephone number for the 
Air Docket is (202) 566-1741.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, 
Office of Atmospheric Programs (MC-6207J), Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone 
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address: 
GHGReportingRule@epa.gov. For technical information and implementation 
materials, please go to the Web site http://www.epa.gov/climatechange/
emissions/ghgrulemaking.html. To submit a question, select Rule Help 
Center, followed by Contact Us.

SUPPLEMENTARY INFORMATION:
    Regulated Entities. The Administrator determined that this action 
is subject to the provisions of Clean Air Act (CAA) section 307(d). See 
CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to 
``such other actions as the Administrator may determine.''). The final 
rule affects underground coal mines, magnesium production, industrial 
waste landfills, and industrial wastewater treatment facilities that 
are direct emitters of greenhouse gases (GHGs). Regulated categories 
and entities include those listed in Table 1 of this preamble:

                               Table 1--Examples of Affected Entities by Category
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                  Category                      NAICS                 Examples of affected facilities
----------------------------------------------------------------------------------------------------------------
Magnesium Production.......................       331419  Primary refiners of nonferrous metals by electrolytic
                                                           methods.
                                                  331492  Secondary magnesium processing plants.
Underground Coal Mines.....................       212113  Underground anthracite coal mining operations.
                                                  212112  Underground bituminous coal mining operations.
Industrial Waste Landfills.................       562212  Solid waste landfills.
                                                  322110  Pulp mills.
                                                  322121  Paper mills.
                                                  322122  Newsprint mills.
                                                  322130  Paperboard mills.
                                                  311611  Meat processing facilities.
                                                  311411  Frozen fruit, juice, and vegetable manufacturing
                                                           facilities.
                                                  311421  Fruit and vegetable canning facilities.
                                                  221320  Sewage treatment facilities.
Industrial Wastewater Treatment............       322110  Pulp mills.
                                                  322121  Paper mills.
                                                  322122  Newsprint mills.
                                                  322130  Paperboard mills.
                                                  311611  Meat processing facilities.
                                                  311411  Frozen fruit, juice, and vegetable manufacturing
                                                           facilities.
                                                  311421  Fruit and vegetable canning facilities.
                                                  325193  Ethanol manufacturing facilities.
                                                  324110  Petroleum refineries.
----------------------------------------------------------------------------------------------------------------

    Table 1 of this preamble is not intended to be exhaustive, but 
rather provides a guide for readers regarding facilities likely to be 
affected by this action. Although Table 1 of this preamble lists the 
types of facilities that EPA is now aware could be potentially affected 
by the reporting requirements, other types of facilities not listed in 
the table could also be subject to reporting requirements. To determine 
whether you are affected by this action, you should carefully examine 
the applicability criteria found in 40 CFR part 98, subpart A as 
amended by this action. If you have questions regarding the 
applicability of this action to a particular facility, consult the 
person

[[Page 39737]]

listed in the preceding FOR FURTHER INFORMATION CONTACT section.
    Many facilities affected by this final rule have GHG emissions from 
other source categories listed in 40 CFR part 98. Table 2 of this 
preamble has been developed as a guide to help reporters affected by 
this action identify other source categories (by subpart) that they may 
need to (1) consider in their facility applicability determination, and 
(2) include in their reporting. Table 2 of this preamble identifies the 
subparts that are likely to be relevant to sources with magnesium 
production, underground coal mines, industrial wastewater treatment, 
and industrial waste landfills. The table should only be seen as a 
guide. Additional subparts in 40 CFR part 98 may be relevant for a 
given reporter, while some subparts listed in Table 2 of this preamble 
may not be relevant to all reporters in these source categories.

            Table 2--Source Categories and Relevant Subparts
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                                    Other Subparts in 40 CFR part 98
  Source category (and main       recommended for review to determine
     applicable subpart)                     applicability
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Magnesium Production.........  Subpart C: General Stationary Fuel
                                Combustion.
Underground Coal Mines.......  Subpart C: General Stationary Fuel
                                Combustion.
Industrial Waste Landfills     Subpart C: General Stationary Fuel
 \a\.                           Combustion.
                               Subpart Y: Petroleum Refineries.
                               Subpart AA: Pulp and Paper Manufacturing.
                               Subpart II: Industrial Wastewater
                                Treatment.
Industrial Wastewater          Subpart C: General Stationary Fuel
 Treatment.                     Combustion.
                               Subpart Y: Petroleum Refineries.
                               Subpart AA: Pulp and Paper Manufacturing.
                               Subpart TT: Industrial Waste Landfills.
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\a\ The industrial landfills source category was proposed with municipal
  solid waste landfills under 40 CFR part 98, subpart HH in the April
  10, 2009 proposal (74 FR 16448). However, EPA has since decided to
  separate landfills into two subparts: subpart HH for municipal solid
  waste landfills (promulgated October 30, 2009 (74 FR 56374) and
  subpart TT for industrial waste landfills.

    Judicial Review. Under CAA section 307(b)(1), judicial review of 
this final rule is available only by filing a petition for review in 
the U.S. Court of Appeals for the District of Columbia Circuit by 
September 10, 2010. Under CAA section 307(d)(7)(B), only an objection 
to this final rule that was raised with reasonable specificity during 
the period for public comment can be raised during judicial review. 
This section also provides a mechanism for us to convene a proceeding 
for reconsideration, ``[i]f the person raising an objection can 
demonstrate to EPA that it was impracticable to raise such objection 
within [the period for public comment] or if the grounds for such 
objection arose after the period for public comment (but within the 
time specified for judicial review) and if such objection is of central 
relevance to the outcome of this rule.'' Any person seeking to make 
such a demonstration to us should submit a Petition for Reconsideration 
to the Office of the Administrator, Environmental Protection Agency, 
Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., 
Washington, DC 20004, with a copy to the person listed in the preceding 
FOR FURTHER INFORMATION CONTACT section, and the Associate General 
Counsel for the Air and Radiation Law Office, Office of General Counsel 
(Mail Code 2344A), Environmental Protection Agency, 1200 Pennsylvania 
Ave., NW., Washington, DC 20004. Note, under CAA section 307(b)(2), the 
requirements established by this final rule may not be challenged 
separately in any civil or criminal proceedings brought by EPA to 
enforce these requirements.
    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BAMM Best Available Monitoring Methods
BOD5 5-day biochemical oxygen demand
CAA Clean Air Act
CBI confidential business information
CEMS continuous emission monitoring system(s)
    CERCLA Comprehensive Environmental Response, Compensation, and 
Liability Act
cf cubic feet
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
COD chemical oxygen demand
DOC Degradable organic carbon
EIA economic impact analysis
EO Executive Order
EPA U.S. Environmental Protection Agency
FK 5-1-12 dodecafluoro-2-methylpentan-3-one (or Novec\TM\ 612)
GHG greenhouse gas
HCFC-22 chlorodifluoromethane (or CHClF2)
HFC-23 trifluoromethane (or CHF3)
HFCs hydrofluorocarbons
HFEs hydrofluorinated ethers
ICR information collection request
kg kilograms
MSHA Mine Safety and Health Administration
MSW municipal solid waste
N2O nitrous oxide
NAICS North American Industry Classification System
NPDES National Pollution Discharge Elimination System
NTTAA National Technology Transfer and Advancement Act of 1995
OMB Office of Management and Budget
PFCs perfluorocarbons
QA/QC quality assurance/quality control
RCRA Resource Conservation and Recovery Act
RFA Regulatory Flexibility Act
RIA regulatory impact analysis
SBREFA Small Business Regulatory Enforcement Fairness Act
scf standard cubic feet
scfm standard cubic feet per minute
SF6 sulfur hexafluoride
TSCA Toxic Substances Control Act
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VOC volatile organic compound(s)

Table of Contents

I. Background
    A. Organization of this Preamble
    B. Background on the Final Rule
    C. Legal Authority
II. Reporting Requirements for Magnesium Production, Underground 
Coal Mines, Industrial Wastewater Treatment, and Industrial Waste 
Landfills
    A. Overview
    B. Summary of Changes to the General Provisions of 40 CFR part 
98
    C. Magnesium Production (40 CFR part 98, subpart T)
    D. Underground Coal Mines (40 CFR part 98, subpart FF)
    E. Industrial Wastewater Treatment (40 CFR part 98, subpart II)
    F. Industrial Wastewater Treatment (40 CFR part 98, subpart II)
III. Other Source Categories Proposed in 2009
    A. Overview
    B. Ethanol Production
    C. Food Processing
    D. Suppliers of Coal
IV. Economic Impacts of the Rule

[[Page 39738]]

    A. How were compliance costs estimated?
    B. What are the costs of the rule?
    C. What are the economic impacts of the rule?
    D. What are the impacts of the rule on small businesses?
    E. What are the benefits of the rule for society?
V. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coodination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions that Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. Background

A. Organization of This Preamble

    This preamble consists of five sections. The first section provides 
a brief history of 40 CFR part 98 and describes the purpose and legal 
authority for today's action.
    The second section of this preamble summarizes the revisions made 
to the general provisions in 40 CFR part 98, subpart A and outlines the 
specific requirements for the four new source categories being 
incorporated into 40 CFR part 98 by this action. It also describes the 
major changes made to these source categories since proposal and 
provides a brief summary of significant public comments and EPA's 
responses on issues specific to each source category.
    The third section of this preamble summarizes and provides our 
rationale for the decisions not to include two source categories as 
distinct subparts in 40 CFR part 98 and not to include reporting 
requirements for one additional proposed source category under 40 CFR 
part 98 at this time.
    The fourth section of this preamble provides the summary of the 
cost impacts, economic impacts, and benefits of the final rule and 
discusses comments on the regulatory impacts analyses for the four 
additional source categories.
    Finally, the last section discusses the various statutory and 
executive order requirements applicable to this rulemaking.

B. Background on the Final Rule

    Today's action finalizes monitoring and reporting requirements for 
the following four source categories: magnesium production, underground 
coal mines, industrial waste landfills,\1\ and industrial wastewater 
treatment. With today's action EPA has decided not to include ethanol 
production and food processing as distinct subparts. Lastly, EPA has 
made the final decision not to include any reporting requirements for 
suppliers of coal at this time.
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    \1\ The industrial landfills source category was proposed with 
municipal solid waste landfills under 40 CFR part 98, subpart HH in 
the April 10, 2009 proposal (74 FR 16448). However, EPA has since 
decided to separate landfills into two subparts: subpart HH for 
municipal solid waste landfills (promulgated October 30, 2009 (74 FR 
56374)) and subpart TT for industrial landfills.
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    These source categories were proposed on April 10, 2009 (74 FR 
16448) as part of a larger rulemaking effort to establish a GHG 
reporting program for all sectors of the economy. This rulemaking was 
initiated by EPA in response to the fiscal year 2008 Consolidated 
Appropriations Act (Appropriations Act).\2\ This Act authorized funding 
for EPA to develop and publish a rule ``* * *to require mandatory 
reporting of greenhouse gas emissions above appropriate thresholds in 
all sectors of the economy of the United States.'' An accompanying 
joint explanatory statement directed EPA to ``use its existing 
authority under the Clean Air Act'' to develop a mandatory GHG 
reporting rule.
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    \2\ Consolidated Appropriations Act, 2008, Public Law 110-161, 
121 Stat. 1844, 2128. Congress reaffirmed interest in a GHG 
reporting rule, and provided additional funding, in the 2009 and 
2010 Appropriations Acts (Consolidated Appropriations Act, 2009, 
Pub. L. 110-329, 122 Stat. 3574-3716 and Consolidated Appropriations 
Act, 2010, Pub. L. 111-117, 123 Stat. 3034-3408).
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    EPA proposed 40 CFR part 98 on April 10, 2009 (74 FR 16448) and 
held two public hearings in April 2009. The public comment period ended 
on June 9, 2009. The final 40 CFR part 98 was signed by EPA's 
Administrator on September 22, 2009 and published in the Federal 
Register on October 30, 2009 (74 FR 56260). The October 2009 Final 
Rule, which became effective on December 29, 2009, included reporting 
requirements for facilities and suppliers in 31 subparts. The April 
2009 proposal, however, included monitoring and reporting requirements 
for a further eleven source categories that were not finalized in the 
October 30, 2009 action. This action includes monitoring and reporting 
requirements for four of the eleven source categories (subpart T--
Magnesium Production, subpart FF--Underground Coal Mines, subpart II--
Industrial Wastewater Treatment, and subpart TT--Industrial Waste 
Landfills) that were proposed but not finalized in the October 30, 2009 
action, and amends the general provisions for 40 CFR part 98, subpart 
A. This action also provides EPA's final decision not to include 
ethanol production and food processing as distinct subparts in 40 CFR 
part 98, as well as the final decision not to include suppliers of coal 
in 40 CFR part 98 at this time.\3\
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    \3\ The remaining four source categories included in the April 
2009 proposal but not included here are being reproposed in Proposed 
Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas 
Systems (75 FR 18608, April 12, 2010) and Proposed Mandatory 
Reporting of Greenhouse Gases: Additional Sources of Fluorinate GHGs 
(75 FR 18652, April 12, 2010).
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    During the comment period, EPA received a number of detailed 
comments on the proposal, including comments specific to the proposed 
subparts for ethanol production, food processing, underground coal 
mines, industrial waste landfills, industrial wastewater treatment, and 
suppliers of coal. EPA decided to delay finalizing the reporting 
requirements for these source categories to allow for additional time 
to review public comments, perform additional analysis, and consider 
modifications and alternatives to the proposed methodologies. Changes 
made to the proposed requirements and significant comments received 
during the public comment period for 40 CFR part 98, subparts FF, II, 
and TT are described in more detail in the discussions of the 
individual source categories included in Section II of this preamble.
    Upon further consideration, EPA decided not to include distinct 
subparts for ethanol production and food processing in 40 CFR part 98 
because these facilities will already be covered under the rule due to 
their aggregate emissions from all applicable source categories in the 
rule, such as stationary combustion, industrial wastewater, industrial 
waste landfills, miscellaneous use of carbonates, and any others that 
may apply. Moreover, EPA has also decided to not include coal suppliers 
in 40 CFR part 98 because the vast majority of emissions from 
combustion of coal in the United States is already covered by the rule 
through reporting by direct emitters. Further explanation of these 
decisions is provided in more detail in the discussions of the proposed 
individual source categories in Section III of this preamble.
    Summaries of comments on other aspects of the reporting rule, such 
as the verification approach and selection of source categories, are 
included and were

[[Page 39739]]

responded to in the preamble to the October 2009 Final Rule (74 FR 
56260, October 30, 2009) and in volumes 1 through 14 of ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments.''

C. Legal Authority

    EPA is finalizing 40 CFR part 98, subparts T, FF, II, and TT under 
the existing CAA authorities provided in CAA section 114. As discussed 
in detail in Sections I.C and II.Q of the preamble to the 2009 final 
rule (74 FR 56260, October 30, 2009), CAA section 114(a)(1) provides 
EPA with broad authority to require emissions sources, persons subject 
to the CAA, manufacturers of process or control equipment, or persons 
whom the Administrator believes may have necessary information to 
monitor and report emissions and provide such other information the 
Administrator requests for the purposes of carrying out any provision 
of the CAA. EPA may gather information for a variety of purposes, 
including for the purpose of assisting in the development of emissions 
standards under CAA section 111, determining compliance with 
implementation plans or such standards, or more broadly for ``carrying 
out any provision'' of the CAA. Section 103 of the CAA authorizes EPA 
to establish a national research and development program, including 
nonregulatory approaches and technologies, for the prevention and 
control of air pollution, including GHGs. As discussed in the proposal 
(74 FR 16448, April 10, 2009), among other things, data from magnesium 
production, underground coal mines, industrial wastewater treatment, 
and industrial waste landfills will inform decisions about whether and 
how to use CAA section 111 to establish new source performance 
standards (NSPS) for these four source categories, including whether 
there are any additional categories of sources that should be listed 
under CAA section 111(b). The data collected will also inform EPA's 
implementation of CAA section 103(g) regarding improvements in sector 
based nonregulatory strategies and technologies for preventing or 
reducing air pollutants.

II. Reporting Requirements for Magnesium Production, Underground Coal 
Mines, Industrial Wastewater Treatment, and Industrial Waste Landfills

A. Overview

    40 CFR part 98 requires reporting of GHG emissions and supply from 
all sectors of the economy, including fossil fuel suppliers, industrial 
gas suppliers, and direct emitters of GHGs. It covers various GHGs, 
including carbon dioxide (CO2), methane (CH4), 
nitrous oxide (N2O), hydrofluorocarbons (HFCs), 
perfluorocarbons (PFCs), sulfur hexafluoride (SF6), and 
other fluorinated compounds (e.g., hydrofluoroethers (HFEs)). The rule 
requires that source categories subject to the rule monitor and report 
GHGs in accordance with the methods specified in the individual 
subparts. For a list of the specific GHGs to be reported and the GHG 
calculation procedures, monitoring, missing data procedures, 
recordkeeping, and reporting required by facilities subject to each of 
the four subparts included in today's action, see Section II.C through 
II.F of this preamble.
    In order to meet the quality assurance and verification 
requirements of the rule, EPA is establishing an electronic reporting 
system to facilitate collection of data under this rule. All facilities 
that are covered under 40 CFR part 98, including those subject to the 
reporting requirements in 40 CFR part 98, subparts T, FF, II, and TT 
will use this data system to submit required data.

B. Summary of Changes to the General Provisions of 40 CFR Part 98

    Today's action amends certain requirements in 40 CFR part 98, 
subpart A (General Provisions). These amendments are summarized in this 
section of the preamble and apply only to those subparts included in 
this action. Other than the changes to format discussed immediately 
below, none of the amendments change the general provisions applicable 
to those subparts already incorporated into 40 CFR part 98.
    Changes to Format. On March 16, 2010, EPA published both a direct 
final rule and concurrent proposal (75 FR 12451 and 75 FR 12489) that 
made minor changes to the format of several sections of the general 
provisions to accommodate the addition of new subparts in the future in 
a simple and clear manner. The changes included converting into a 
tabular format the lists of source categories and supply categories 
that are affected by the October 2009 final rule. The lists, which were 
originally embedded in three paragraphs of 40 CFR part 98, subpart A 
(40 CFR 98.2(a)), were moved to three new tables in 40 CFR part 98, 
subpart A. Each table also indicated the applicable first reporting 
year for each source and supply category. For source and supply 
categories included in the 2009 final rule, the first reporting year 
remains 2010. As a concurrent harmonizing change, all references to 
applicable subparts (e.g., ``40 CFR part 98 subparts C through JJ'') 
were replaced by references to the appropriate source or supply 
category table. Other changes included updating the language for the 
schedule for submitting reports and calibrating equipment to recognize 
that subparts that may be added in the future would have later 
deadlines. These revisions did not change the requirements for subparts 
included in the 2009 final rule.
    The direct final rule notice also stated the direct final rule 
would become effective May 17, 2010, unless any adverse comments were 
received by April 15, 2010. If such comments were received, EPA would 
withdraw the direct final rule and finalize the proposal at a later 
date. The Agency received two comments that could be construed as 
adverse and subsequently withdrew the direct final rule on April 30, 
2010 (75 FR 22699).
    EPA received two sets of ostensibly adverse comments, however 
neither addressed any of the specific formatting changes EPA made to 
the General Provisions in the direct final rule. Rather, the commenters 
focused on portions of the regulatory text that remained unchanged from 
the original final rule that was published on October 30, 2009 (74 FR 
56260). Both raised concerns with sentences that remained the same as 
they were in the October 2009 final rule and were not related to the 
formatting changes proposed on March 16, 2010. Specifically, both 
commenters objected to the reporting of biogenic emissions required 
under 40 CFR part 98, section 98.3(C)(4)(i) and (ii). EPA did not 
actually change that requirement from the October 2009 rule but rather 
revised the reference in the paragraph from ``source categories in 
subparts C through JJ'' to ``source categories listed in Table A-3 and 
Table A-4 of this subpart'' to reflect the proposed reformatting from 
lists of subparts to tables.
    One of the commenters also objected to the schedule for reporting 
described in 98.33(b)(2). Again, EPA did not change that requirement at 
all. Instead, the Agency inserted the phrase ``and becomes subject to 
the rule in the year that it becomes operational'' to the sentence that 
reads ``for a new facility or supplier that begins operation on or 
after January 1, 2010 and becomes subject to the rule in the year it 
becomes operational, reporting emissions beginning with the first 
operating month and ending on December 31 of that year.'' That 
additional phrase makes it clear that reporters must meet the 
applicability requirements for each

[[Page 39740]]

source category before they are subject to any reporting requirements 
but does not actually amend the schedule for reporting itself.
    Finally, one commenter objected to regulatory text in 98.3(i)(1) 
that requires calibration of flow meters and other devices. This 
specific requirement also remains unchanged from the 2009 final rule. 
Similar to the above amendment, EPA revised this paragraph not to 
change the requirements for sources covered by the October 2009 final 
rule, but rather to allow facilities that must report under any 
additional subparts to conduct any initial calibrations that are 
required by the newly published subparts during the first year that the 
subpart applies rather than in the year 2010. To do that, EPA changed 
the following sentence, ``for facilities and suppliers that become 
subject to this part about April 1, 2010, the initial calibration shall 
be conducted on the date that data collection is required to begin'' to 
``for facilities and suppliers that are subject to this part on January 
1, 2010, the initial calibration shall be conducted by April 1, 2010. 
For facilities and suppliers that become subject to this part after 
April 1, 2010, the initial calibration shall be conducted by the date 
that data collection is required to begin.''
    In both cases, the comments received did not address any of the 
changes EPA proposed to make to the General Provisions. As a result, 
EPA is finalizing those proposed minor amendments to accommodate the 
addition of new subparts in this rulemaking. The additional changes to 
40 CFR part 98, subpart A discussed below reflect these changes (i.e., 
revising Tables A-3 and A-4 instead of 40 CFR 98.2(a)(1), (2) or (4)). 
As explained above, the comments that could be construed as adverse 
related to parts of the regulatory text that remained unchanged from 
the 2009 final rule. If and when EPA decides to make any changes to any 
regulatory requirements set forth in the October 2009 final rule, 
including those highlighted in the comments above, the Agency will 
initiate a separate notice and comment process.
    Changes to Applicability. Facilities containing magnesium 
production, industrial waste landfills, and/or industrial wastewater 
treatment, are subject to 40 CFR part 98 if they emit 25,000 metric 
tons CO2-equivalent (CO2e) or more per year in 
combined emissions from combustion units, miscellaneous uses of 
carbonate, ferroalloy production, glass production, hydrogen 
production, iron and steel production, lead production, pulp and paper 
manufacturing, zinc production, magnesium production, industrial 
wastewater treatment, and industrial waste landfills, or if they are 
required to report under 98.2(a)(1). In today's action, EPA is making 
revisions to Table A-4 in 40 CFR part 98, subpart A from that included 
in the direct final rule and accompanying proposal to include the 
source categories: Magnesium production, industrial wastewater 
treatment, and industrial waste landfills.
    Underground coal mines that are subject to quarterly (or more 
frequent) sampling of ventilation systems by the Mine Safety and Health 
Administration (MSHA) are subject to 40 CFR part 98 regardless of the 
actual facility emissions. In today's action, we are making revisions 
to Table A-3 from that included in the direct final rule and 
accompanying proposal to include the underground coal mine source 
category.
    Changes to the Reporting Schedule. Facilities with existing 
magnesium production, underground coal mines, industrial wastewater 
treatment, and industrial waste landfills must begin monitoring GHG 
emissions on January 1, 2011 in accordance with the methods specified 
in 40 CFR part 98, subparts T, FF, II, and TT. Facilities must report 
the GHG emissions and associated verification data required under each 
of these subparts by March 31, 2012. Facilities with existing reporting 
requirements for the year 2010 are not required to collect the data 
required under 40 CFR part 98, subparts T, FF, II, and TT for the 
reporting year 2010 or report it in 2011.
    EPA decided to require reporting of calendar year 2011 emissions 
for the four source categories finalized in today's action because the 
data are crucial to the timely development of future GHG policy and 
regulatory programs. In the fiscal year 2008 Appropriations Act, 
Congress requested that EPA develop this reporting program on an 
expedited schedule, and Congressional inquiries along with public 
comments reinforce that data collection for calendar year 2011 is a 
priority. Delaying data collection until calendar year 2012 would mean 
the data would not be received until 2013, which would likely be too 
late for many ongoing GHG policy and program development needs.
    EPA received a number of comments on the April 2009 proposal from 
stakeholders expressing concerns that there would be insufficient time 
between the publication of a final rule and the date on which 
monitoring must begin. EPA concluded that the time period between the 
publication of this final action and the January 1, 2011 deadline for 
beginning monitoring for 40 CFR part 98, subparts T, FF, II, and TT is 
sufficient to allow facilities to implement the required monitoring 
methods, including calibrating and installing monitoring equipment. The 
monitoring requirements for each subpart included in today's action 
have not changed significantly from those requirements proposed in 
April 2009. Although facilities in some source categories will have to 
make emissions assessments to determine whether their facility exceeds 
the 25,000 metric tons CO2e applicability threshold, EPA has 
concluded that there is ample time to complete this assessment. Many 
facilities affected by today's action will not need additional time to 
make emissions assessments because they will already be subject to 
monitoring and reporting emissions under other applicable subparts in 
40 CFR part 98. For example, pulp and paper mills which may be required 
to report under 40 CFR part 98, subparts TT and II, are already 
required to report under 40 CFR part 98, subpart AA and any other 
applicable source categories if their emissions are more than 25,000 
metric tons CO2e per year. Furthermore, many of those 
facilities that are not subject to monitoring in 2010 will have already 
completed some assessments of their emissions from source categories 
included in the Octber 2009 Final Rule. For example, many industrial 
facilities will have already assessed their GHG emissions from 
combustion units for the 2010 reporting year. For these reasons, EPA 
concluded that the January 1, 2011 deadline should provide sufficient 
time for facilities to comply with the rule.
    Best Available Monitoring Methods. In the October 2009 Final Rule, 
facilities had the option to use Best Available Monitoring Methods 
(BAMM) for the first quarter of the first reporting year. While 
facilities in the source categories included in today's action will not 
automatically be allowed to use BAMM for the first quarter of 
monitoring (January 1, 2011 to March 31, 2011), facilities will have 
the option to request the use of BAMM. The request must be submitted by 
October 12, 2010 and must contain the information specified in 40 CFR 
98.3(d)(2)(ii). Specific information regarding the use of BAMM is 
included in the Monitoring and QA/QC Requirements section of each 
subpart for the source categories included in today's action. The use 
of BAMM for these source categories will not be approved beyond 
December 31, 2011. The only change to the general provisions, by virtue 
of inclusion of BAMM in each subpart, is to make it

[[Page 39741]]

clear that the automatic three month provision of 98.3 does not apply 
to these subparts.
    For most facilities covered by the source categories in today's 
action, there are monitoring requirements that may not be typical 
operating procedure and therefore, monitoring equipment will need to be 
purchased and installed. In addition, per EPA's experience with the 
source categories finalized in 2009 final rule, there will likely be 
facilities with unique circumstances that will require some additional 
time to comply with the rule requirements. Therefore, EPA decided to 
allow facilities to request the use of BAMM for the first reporting 
year so that those that are not able to acquire, install, and calibrate 
the required monitoring equipment due to their unique circumstances may 
still comply with the rule.
    Other Changes to 40 CFR part 98, subpart A. In today's action, we 
are also amending 40 CFR 98.6 (definitions) to add definitions for 
several terms used in 40 CFR part 98, subparts T, FF, II, and TT and to 
clarify the meaning of certain existing terms for purposes of 40 CFR 
part 98, subpart II.
    We are also amending 40 CFR 98.7 (incorporation by reference) to 
include standard methods references in 40 CFR part 98, subparts FF, II, 
and TT.

C. Magnesium Production (40 CFR Part 98, Subpart T)

1. Summary of the Final Rule
    Source Category Definition. Magnesium production and processing 
facilities are defined as any facility where magnesium metal is 
produced through smelting (including electrolytic smelting), refining, 
or remelting operations, or any site where molten magnesium is used in 
alloying, casting, drawing, extruding, forming, or rolling operations.
    Facilities that meet the applicability criteria in the General 
Provisions (40 CFR 98.2(a)) summarized in Section II.B of this preamble 
must report GHG emissions.
    GHGs to Report. Each magnesium production facility must report 
total emissions at the facility level for each of the following gases 
in metric tons of gas per year resulting from their use as cover gases 
or carrier gases in magnesium production or processing:
     SF6.
     HFC-134a.
     FK 5-1-12.
     CO2.
     Any other GHG as defined in 40 CFR part 98, subpart A 
(General Provisions) of the rule.
    In addition, each facility must report GHG emissions for other 
source categories for which calculation methods are provided in the 
rule. For example, facilities must report CO2, 
N2O, and CH4 emissions from each stationary 
combustion unit on site by following the requirements of 40 CFR part 
98, subpart C (General Stationary Fuel Combustion Sources).
    GHG Emissions Calculation and Monitoring. Owners or operators of 
magnesium production facilities must calculate emissions of each gas by 
monitoring the annual consumption of cover gases and carrier gases 
using one of three methods:
     Use a mass-balance approach that takes into account the 
following:
    - Decrease in Inventory: The decrease in inventory of cover or 
carrier gases stored in containers from the beginning to the end of the 
year.
    - Acquisitions: The amount of cover or carrier gas acquired through 
purchases or other transactions.
    - 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 mass of individual containers 
as the gases are used.
     Monitor the mass flow of pure cover gas and carrier gas 
into the cover gas distribution system.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)), reporters must 
submit additional data that are used to calculate GHG emissions. A list 
of the specific data to be reported for this source category is 
contained in 40 CFR part 98, subpart T.
    Recordkeeping. In addition to the information required by the 
General Provisions (40 CFR 98.3(g)), reporters must keep records of 
additional data used to calculate GHG emissions. A list of specific 
records that must be retained for this source category is included in 
40 CFR part 98, subpart T.
2. Summary of Major Changes Since Proposal
    No major changes since proposal have been made to the magnesium 
production sector.
3. Summary of Comments and Responses
    No comments specific to regulation of the magnesium production 
sector were received.

D. Underground Coal Mines (40 CFR Part 98, Subpart FF)

1. Summary of the Final Rule
    Source Category Definition. This source category consists of active 
underground coal mines and any underground mines under development that 
have operational pre-mining degasification systems. An underground coal 
mine is a mine at which coal is produced by tunneling into the earth to 
a subsurface coal seam, where the coal is then mined with equipment 
such as cutting machines, and transported to the surface. Active 
underground coal mines are underground mines categorized by the MSHA as 
active and where coal is currently being produced or has been produced 
within the previous 90 days. This source category includes each 
ventilation well or shaft, and each degasification system well or 
shaft, and includes degasification systems deployed before, during, or 
after mining operations are conducted in a mine area.
    This source category does not include abandoned (closed) mines, 
surface coal mines, post-coal mining activities (e.g., storage or 
transportation of coal), or coalbed methane recovery from coal seams 
not associated with active underground coal mines.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 
98.2(a)(1)) summarized in Section II.B of this preamble.
    GHGs to Report. For underground coal mines, report the following:
     Quarterly CH4 liberation from ventilation and 
degasification systems.
     Quarterly CH4 destruction for ventilation and 
degasification systems and resultant CO2 emissions, if 
destruction takes place on-site.
    In addition, each facility must report GHG emissions for other 
source categories for which calculation methods are provided in the 
rule. For example, facilities must report CO2, 
N2O, and CH4 emissions from each stationary 
combustion unit on site by following the requirements of 40 CFR part 
98, subpart C (General Stationary Fuel Combustion Sources).
    GHG Emissions Calculation and Monitoring. For CH4 
liberated from mine ventilation air, facilities are to monitor 
CH4 using either quarterly or more frequent sampling of 
CH4 content and gas flow, or continuous emissions monitoring 
systems (CEMS).
    For the quarterly sampling option, coal mine operators are required 
to either: (a) To obtain the results of the quarterly, or more 
frequent, testing that MSHA conducts, and use the results to calculate 
quarterly emissions, or (b) independently collect quarterly, or more 
frequent, samples of CH4 released from the ventilation 
system(s), using MSHA procedures, have these samples analyzed for 
CH4 composition, and use

[[Page 39742]]

the results to calculate quarterly emissions.
    If operators use CEMS as the basis for emissions reporting, they 
must provide documentation on the process for using data obtained from 
their CEMS to estimate emissions from their mine ventilation systems.
    For CH4 liberated from degasification systems, 
facilities are to monitor CH4 using either weekly sampling, 
or CEMS.
    The option of collecting weekly samples includes both measurement 
of the total gas volume liberated (including that which is emitted or 
sold, used onsite, or otherwise destroyed (including by flaring)), 
along with measurements of CH4 concentrations in gas volumes 
recovered or emitted. Under this option, facilities must determine 
weekly gas flow rates and CH4 composition from these 
degasification wells and shafts, either on an individual well or shaft 
basis, or in aggregate at one or more centralized collection points. 
Methane composition could be determined either by submitting samples to 
a lab for analysis, or from the use of methanometers at the 
degasification well site(s) and/or one or more centralized collection 
point(s).
    For the CEMS option, facilities must monitor either individual 
wellbores, or can monitor gas at points of aggregation, as long as 
emissions from all wells are addressed, and the methodology for 
calculating total emissions from all wells is documented.
    For all systems with CH4 destruction, CH4 
destruction is monitored through direct measurement of CH4 
flow to combustion devices with continuous monitoring systems. The 
resulting CO2 emissions for onsite combustion devices 
without energy recovery (i.e., flaring) are to be calculated from these 
monitored values.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)), reporters must 
submit additional data that are used to calculate GHG emissions. A list 
of specific data to be reported for this source category is contained 
in 40 CFR part 98, subpart FF.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)), reporters must keep records of additional 
data that are used to calculate GHG emissions. A list of specific 
records that must be retained for this source category is contained in 
40 CFR part 98, subpart FF.

2. Summary of Major Changes Since Proposal

    The major changes in this rule since the original proposal are 
identified in the following list. The rationale for these and any other 
significant changes to 40 CFR part 98, subpart FF can be found below or 
in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Subpart FF: Underground Coal Mines.''
     An option of using one or more CEMS to obtain data on mine 
ventilation systems was added.
     For CH4 liberated from degasification systems, 
the requirement to monitor each well was removed. CEMS may be used to 
monitor aggregate CH4 from more than one well, as long as 
CH4 from all wells is monitored, and the methodology for 
estimating total emissions from all wells is documented.
     The requirement for continuous monitoring for total 
CH4 liberation at degasification systems was removed. 
Degasification wells may be monitored with CEMS or through weekly 
sampling of all degasification wells, including gob gas vent holes and 
other degasification wells.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. EPA received many comments on this subpart covering numerous 
topics. EPA's responses to these significant comments can be found in 
the comment response document for underground coal mines in ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subpart FF: Underground Coal Mines.''
Definition of Source Category
    Comment: Several commenters stated that many operators currently 
recover liberated CH4 for various purposes, including 
destruction, and therefore CH4 that has been recovered is no 
longer an emission as it is not vented into the atmosphere. The 
commenters recommended that EPA not include recovered CH4 in 
the reporting requirements.
    Response: EPA agrees that CH4 that has been recovered 
and combusted is not emitted. However, EPA does not agree with the 
commenter that recovered CH4 should be excluded from the 
reporting requirements. Recovery projects at mines greatly reduce 
CH4 emissions from this source. It is vital that EPA obtain 
the best information available about these practices for future policy 
analysis. In addition, since mines with CH4 collection 
systems generally monitor the amount of CH4 collected in 
these systems, this can provide an effective internal validation method 
for assessment of CH4 generation within the mine. As such, 
data for mines with gas collection systems are also vitally important 
to better understand and improve estimates of CH4 emissions 
from mines in general. EPA has taken the same approach for the 
reporting of recovered CH4 from landfills under 40 CFR part 
98, subpart HH.
    Comment: Commenters suggested that EPA include abandoned mines in 
the source category definition. For existing abandoned mines whose 
operators can be identified from State or Federal records, they 
recommended that EPA require the installation of appropriate monitoring 
equipment. They also recommended that EPA make clear that the abandoned 
mine exception does not apply prospectively.
    Response: For currently abandoned mines, EPA considered this 
emission source and determined that measuring and/or monitoring 
emissions from abandoned mines would be difficult at this time, since 
there are currently no robust facility-level monitoring methods 
available to measure fugitive emissions from abandoned mines. Further, 
in many cases, EPA concluded that it would be difficult to identify 
owners of abandoned mine sites, i.e., it would be difficult to identify 
the responsible parties to monitor and report. Finally, even where the 
site owner is known, these sites are often unmanned, remote, and lack a 
source of nearby power, making it burdensome to monitor emissions. EPA 
may reconsider including abandoned mines in this rule should additional 
information become available demonstrating that monitoring is feasible.
    With regard to the ``once in, always in'' provision of the proposed 
reporting rule, a mine covered by the rule that later ceases coal 
production would need to continue reporting until its emissions fell 
below the levels specified in the provisions to cease reporting in 40 
CFR part 98, subpart A. Mines continue to emit CH4 after 
mining activities have ceased and therefore it is prudent to continuing 
monitoring emissions until they are below the threshold.
    Comment: For surface mines, while commenters recognized that 
existing monitoring methods presently may not be robust, some 
commenters consider the use of existing methods to be preferable to 
excluding this source of emissions. They suggested that EPA consider 
requiring these methods for surface mines, adjusting emissions figures 
appropriately to account for uncertainty.
    Response: EPA determined that monitoring emissions from surface 
mines would be challenging, since there are currently no robust 
facility-level monitoring methods to measure fugitive

[[Page 39743]]

CH4 emissions from surface mines at this time. Measuring 
fugitive emissions at specific locations would not adequately capture 
the emissions from the entire mine, would be expensive and resource-
intensive, and difficult for mine operators to implement on a periodic 
basis. EPA may reconsider including surface mines in this rule should 
additional information become available demonstrating that monitoring 
is feasible.
    Comment: One commenter expressed concern that even the most 
accurate instrumentation will have accuracy difficulties based upon 
varying conditions, calling into question the accuracy of the 
measurements. Because of this, they recommended that degasification 
wells be exempt from the rule.
    Response: EPA does not agree with the commenter that CH4 
degasification wells should be exempt. While the factors mentioned in 
the comment may indeed influence the accuracy of measurement of 
CH4 from degasification wells, EPA considered this issue 
when including this source category, and determined that the collection 
of facility-level data at these mines is still of value to EPA because 
it provides valuable information for characterizing CH4 
emissions from underground coal mining options. This information is 
also of value to mine owners, because those facilities reporting under 
the rule will have stringent monitoring systems in place that will 
allow them to quantify the mitigation value of destroying 
CH4 from their degasification systems.
Reporting Threshold
    Comment: One commenter recommended that establishing the reporting 
threshold at a level of 100,000 metric tons CO2e/yr instead 
of the proposed threshold of MSHA quarterly reporting would ensure 
accurate reporting while sparing small mines and manufacturers from the 
burdens of compliance.
    Response: In developing the threshold for active underground coal 
mines, EPA considered various emissions-based thresholds, and 
determined that reporting should be required for those coal mines for 
which CH4 emissions from the ventilation system are sampled 
quarterly by MSHA. MSHA conducts quarterly testing of CH4 
concentration and flow at mines emitting more than 100,000 cubic feet 
of CH4 per day. This threshold was selected because 
subjecting underground mine operators to a new emissions-based 
threshold would be unnecessarily burdensome and perhaps confusing, 
since these mines are already subject to MSHA regulations and therefore 
would be able to comply with this rule without having to separately 
determine applicability.
Selection of Proposed GHG Emissions Calculation and Monitoring Methods
    Comment: Several commenters recommended that CEMS should be allowed 
as a monitoring method, but not required, for both ventilation and 
degasification systems. In particular, they claim that continuous 
monitoring of CH4 emissions and air flow rates for all 
degasification wells and degasification vent holes is not feasible for 
several reasons. The remote location, unavailability of power, 
inaccessibility, susceptibility to vandalism, and the relatively short 
longevity of many degasification and vent holes renders continuous 
monitoring impractical in many cases.
    One commenter generally agreed with EPA's approach to underground 
coal mine CH4 monitoring, but urged EPA to require the use 
of CEMS for ventilation systems in addition to degasification systems.
    Most commenters stated that the procedures and quarterly sampling 
are sufficient as an option for GHG emissions reporting from 
ventilation of underground coal mines if such data can be received from 
MSHA. However, some expressed concern that MSHA does not normally 
report such data back to mines unless requested.
    Response: For monitoring CH4 liberation from underground 
coal mines, EPA considered several approaches: Engineering approaches 
whereby default emission factors would be applied to total annual coal 
production; periodic sampling of CH4; daily sampling of 
CH4; and the use of CEMS. EPA selected periodic sampling as 
its minimum requirement because the cost burden of purchasing, 
installing and maintaining CEMS, and the cost of maintaining a more 
frequent sampling program were not justifiable under present 
circumstances relative to the greater measurement accuracy achieved.
    We agree that CEMS should be allowed, but not required, to monitor 
CH4 liberation from ventilation and degasification systems, 
and have changed the rule accordingly. For systems where recovered 
CH4 is sold, destroyed, or used on site, EPA determined that 
such systems are already installed on most wells, and CEMS are 
required.
    For monitoring at ventilation systems, EPA has concluded that 
quarterly sampling is sufficient as an option for GHG monitoring from 
ventilation systems. Quarterly sampling was chosen for ventilation 
systems because that is the frequency of sampling conducted by MSHA. 
Greater frequency would provide more accurate data; however, the 
increased burden would outweigh the benefits of improved accuracy for 
the purposes of this reporting rule at this time. The quarterly option 
represents a balance between burden on reporters and accuracy of data.
    EPA is aware that MSHA does not normally report sampling data back 
to mines unless requested. However, since MSHA is conducting sampling 
that provides data useful to this rule, EPA determined that it should 
include use of the data collected by MSHA, by facilities that do obtain 
this data from MSHA, as an option under this rule. Under this option, 
facilities would input MSHA data into the emissions calculations 
required under this rule. Mines that do not obtain this data from MSHA 
must conduct sampling as specified in the rule.
    EPA added the use of CEMS at ventilation systems as an option for 
monitoring. CEMS are not currently widely implemented at ventilation 
systems, but mines evaluating the feasibility of mitigation, abatement, 
or use of ventilation air methane might install CEMS to monitor 
methane, and this monitoring would be allowed under this rule.
    For monitoring at degasification systems, it was determined that 
weekly sampling is sufficient. Most degasification systems conduct 
continuous monitoring and where this type of monitoring is already in 
place, it should be used for purposes of this rule. Based on interviews 
with a number of mine operators, for many of those sites where 
continuous monitoring is not being conducted (primarily for gob gas 
vent holes) degasification wells are monitored at least weekly. 
Moreover, EPA determined that emissions do not generally vary much from 
week to week for mine degasification systems, so the weekly 
measurements would provide sufficient accuracy.
Cost Data
    Comment: Many commenters noted that EPA did not appropriately take 
into consideration the full costs of compliance associated with the 
proposed rule, particularly those associated with the installation of 
CEMS on all degasification wells and vent holes. They noted that both 
the number of impacted wells and vent holes, as well as the costs 
associated with implementing such systems, was probably underestimated.
    Response: Based on these comments and further analysis, EPA 
reevaluated its cost assessment, revised its costs,

[[Page 39744]]

and on the basis of those revised costs, modified the monitoring 
requirements.
    EPA reassessed the number of degasification wells and vent holes 
that would likely be associated with mines required to report under the 
rule. This resulted in a substantially larger estimate of the number of 
degasification wells that would be required to install CEMS systems in 
compliance with the originally proposed requirements, with an 
associated greater incremental cost burden.
    EPA determined that implementing CEMS on some degasification wells 
could be quite costly, and in many cases, would be difficult and/or 
impractical due to remote location, unavailability of power, 
inaccessibility, susceptibility to vandalism, and the relatively short 
longevity of many degasification and vent holes. As a result, EPA 
included consideration of the costs associated with weekly or more 
frequent sampling, as an alternative to the installation of CEMS, to 
address this potential burden. For more detailed information on costs, 
please see Section 4 of the Economic Impact Analysis (EIA) found in 
docket EPA-OAR-2008-0508.

E. Industrial Wastewater Treatment (40 CFR Part 98, Subpart II)

1. Summary of the Final Rule
    Source Category Definition. This source category applies to 
anaerobic processes used to treat industrial wastewater and wastewater 
treatment sludge only at pulp and paper mills, food processing 
facilities, ethanol production facilities, and petroleum refineries. It 
does not include anaerobic processes used to treat wastewater and 
wastewater treatment sludge at other industrial facilities. It does not 
include municipal wastewater treatment plants or separate treatment of 
sanitary wastewater at industrial facilities. It does not include oil/
water separators. This source category consists of the following: 
Anaerobic reactors, anaerobic lagoons, anaerobic sludge digesters, and 
biogas destruction devices.
    Facilities that meet the applicability criteria in the General 
Provisions (40 CFR 98.2(a)) summarized in Section II.B of this preamble 
must report GHG emissions.
    GHGs To Report. Operators of anaerobic processes used to treat 
industrial wastewater and industrial wastewater treatment sludge at the 
above noted facilities must report the following:
     The amount of CH4 generated, recovered, and 
emitted from treatment of industrial wastewater using anaerobic lagoons 
or anaerobic reactors.
     The amount of CH4 recovered and emitted from 
anaerobic sludge digesters.
     The amount of CH4 destroyed by and emitted from 
biogas collection systems and destruction devices.
    Operators of anaerobic wastewater treatment sludge digesters are 
not required to report the amount of CH4 generated. It is 
EPA's understanding that all anaerobic sludge digesters are designed 
for CH4 recovery and are therefore not expected to emit 
CH4 directly from the digester apparatus. Further, this rule 
requires operators of anaerobic sludge digesters to report the amount 
of CH4 recovered and emitted from the recovery system. 
Therefore, all CH4 that is generated in the anaerobic sludge 
digester is already accounted for in the amount of CH4 
recovered and emitted from the recovery system. For this reason, a 
separate calculation and report of the amount of CH4 
generated is not necessary.
    GHG Emissions Calculation and Monitoring. For each anaerobic 
wastewater treatment process, facilities must calculate the mass of 
CH4 generated using the following inputs and data:
     Volume of wastewater sent to an anaerobic treatment 
process.
     Average concentration of chemical oxygen demand (COD) or 
5-day biochemical oxygen demand (BOD5) of wastewater 
entering an anaerobic treatment process.
     Maximum CH4 producing potential of wastewater 
(0.25 for COD, 0.6 for BOD5).
     CH4 conversion factor for the type of 
wastewater treatment process used.
    For each anaerobic process (such as a reactor, lagoon, or sludge 
digester) from which biogas is recovered, covered facilities must 
calculate the mass of CH4 recovered using the following 
inputs and data:
     Cumulative volumetric flow of biogas for the monitoring 
period.
     Average CH4 content of the biogas.
     Temperature, pressure, and moisture content at which flow 
is measured, as needed to accurately calculate biogas flow and 
CH4 content.
    For each anaerobic process (such as reactor, lagoon, or sludge 
digester) from which biogas is recovered, covered facilities must 
calculate the mass of CH4 emitted using the following inputs 
and data:
     Mass of CH4 recovered.
     Collection efficiency for the anaerobic process, based on 
the type of anaerobic process.
     Destruction efficiency of the biogas collection and 
combustion system.
     Fraction of hours the destruction device was operating in 
the reporting year.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)), facilities must 
submit additional data that are used to calculate or verify GHG 
emissions. A list of the specific data to be reported for this source 
category is contained in 40 CFR part 98, subpart II.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) facilities must keep records of additional 
data used to calculate GHG emissions. A list of specific records that 
must be retained for this source category is included in 40 CFR part 
98, subpart II.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified below. The 
rationale for these and any other significant changes can be found 
below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response 
to Public Comments, Subpart II: Industrial Wastewater Treatment,'' and 
``Technical Support Document for Industrial Wastewater Treatment.''
     The source category has been renamed Industrial Wastewater 
Treatment and the applicability of this subpart has been clarified. 
Only petroleum refineries, and ethanol production, food processing, and 
pulp and paper facilities that meet the requirements of 98.2(a)(2) are 
required to report CH4 emissions from anaerobic processes 
used to treat industrial wastewater and industrial wastewater treatment 
sludge and biogas destruction devices. Separate treatment of sanitary 
wastewater at industrial facilities is not included in the 
applicability, nor are facilities that do not employ the wastewater 
treatment processes listed in the source definition (i.e., those that 
employ only aerobic or anoxic processes are not required to report).
     The requirement to report emissions from oil/water 
separators at petroleum refineries has been removed. EPA expects no 
direct emissions of CO2 or other GHG from these oil/water 
separators.
     Because petrochemical facilities are not known to employ 
anaerobic wastewater treatment, this sector has been removed from the 
final version of the rule.
     For ease of reporting, EPA revised the regulation to allow 
for either continuous or weekly monitoring of biogas CH4 
concentration. Facilities may use either installed or portable monitors 
to measure the CH4 concentration. Further, EPA added 
BOD5 as an

[[Page 39745]]

alternative to measuring COD to determine the organic load of influent 
to anaerobic wastewater treatment systems.
3. Summary of Comments and Response
    This section contains a brief summary of major comments and 
responses. EPA received many comments on this subpart covering numerous 
topics. EPA's responses to these comments can be found in the comment 
response document for industrial wastewater treatment in ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subpart II: Industrial Wastewater Treatment.''
    Comment: Many commenters expressed confusion about which facilities 
were required to report emissions from wastewater treatment systems. 
Some commenters requested EPA clarify the definitions of aerobic and 
anaerobic wastewater treatment, while others were uncertain whether 
only the industries explicitly mentioned in the rule were required to 
report. Many commenters also requested that EPA clarify whether the 
rule applied to centralized municipal wastewater treatment plants and 
treatment of sanitary wastewater at industrial facilities.
    Response: EPA revised 40 CFR 98.351 to clarify that only ethanol 
production, food processing, petroleum refining, and pulp and paper 
manufacturing facilities must report wastewater treatment system 
emissions if they both meet the requirements of 40 CFR 98.2 (a)(1) or 
(2) and operate an anaerobic process to treat industrial wastewater or 
industrial wastewater treatment sludge.
    With regard to anaerobic processes covered by the rule, EPA revised 
40 CFR 98.350 to state explicitly that facilities are only required to 
report emissions for the following: anaerobic reactors, anaerobic 
lagoons, anaerobic sludge digesters, and biogas destruction devices. To 
further clarify the scope of 40 CFR part 98, subpart II, EPA has 
removed emission factors for aerobic processes used to treat industrial 
wastewater from Table II-1 of 40 CFR part 98, subpart II because these 
processes are not covered by the reporting rule.
    EPA agrees with commenters that it is appropriate to exclude 
centralized domestic or municipal wastewater treatment plants from 40 
CFR part 98, as was the case in the proposed rule. EPA continues to 
exclude municipal wastewater treatment plants from the final rule, and 
has retitled 40 CFR part 98, subpart II as Industrial Wastewater 
Treatment to clarify the applicability of this subpart.
    EPA also agrees with commenters that it is appropriate to exclude 
separate treatment of sanitary wastewater at industrial facilities from 
40 CFR part 98. Most such sanitary treatment plants are much smaller 
than municipal wastewater treatment plants and few use anaerobic 
treatment. As a result, EPA explicitly excluded these systems from 40 
CFR part 98; however, anaerobic processes used to treat combined 
industrial and sanitary wastewater are covered by the rule.
    Comment: Multiple commenters objected to the inclusion of emissions 
from petroleum refinery oil/water separators in the rule. Some argued 
that the GHG emissions from these devices would be insignificant. 
Others asserted that the GHG emissions calculations were unsupported 
and that this subpart was the only one to consider the atmospheric 
conversion of volatile organic compounds (VOCs) to CO2 in 
the calculation of GHG emissions.
    Response: In the proposed rule, EPA included a method to calculate 
CO2 emissions that indirectly come from VOCs from petroleum 
refinery oil/water separators. EPA agrees with commenters that this 
requirement should be removed because this is the only source category 
to consider and require reporting of the conversion of VOCs to 
CO2 in the atmosphere. The purpose of this rule is to 
collect direct GHG emissions data from downstream sources including 
industrial wastewater treatment. Therefore we are not collecting data 
from downstream sources on indirect emissions such as VOCs that can 
convert to CO2 once in the atmosphere. Please see 
``Technical Support Document for Industrial Wastewater Treatment'' for 
more detailed information on this issue. While EPA is not requiring the 
reporting of CO2 resulting from VOC emissions at this time, 
we understand that these emissions may be important and we may revisit 
this reporting requirement in the future.
    Comment: EPA received many comments recommending that wastewater 
treatment be considered a de minimis source. Some argued that 
wastewater treatment contributes an extremely small percentage of 
emissions compared to certain sectors' process emissions. Others 
contended that the burden of determining the small amount of wastewater 
treatment emissions was not warranted.
    Response: EPA disagrees that reporting of wastewater treatment 
emissions should be excluded from the rule. Despite the comparatively 
small amount of GHG emissions from wastewater treatment nationally, 
emissions at individual facilities could be significant. We note that 
the source categories required to report are industries that both have 
the potential to exceed the reporting threshold, and have high levels 
of BOD or COD in their wastewater and frequently employ anaerobic 
treatment operations. See the Wastewater Treatment Technical Support 
Document (EPA-HQ-OAR-2008-0508-035). These two conditions result in the 
opportunity for increased GHG emissions. EPA has minimized the overall 
reporting burden by focusing the rule requirements on those treatment 
systems with the highest likelihood of generating GHG emissions 
exceeding the reporting threshold. In light of the potential 
significance of the emissions, lack of facility specific data, and 
revisions made to the reporting requirements in response to comments, 
we find that the burden on facilities is justified.
    Given this reporting rule is aimed at collecting data to inform a 
range of future policies and programs it is important to understand the 
entirety of a facility's emissions. Therefore, requiring facilities in 
the included industry sectors to report wastewater treatment emissions, 
even though they may result in only a small portion of a facility's 
overall emissions, will allow each reporting facility to estimate their 
total emissions more accurately.
    Comment: Many commenters requested additional flexibility in the 
rule requirements. Some requested the ability to use BOD instead of COD 
to calculate the organic content of the wastewater they treat in 
anaerobic processes. Others requested changes in sampling frequency for 
both biogas and wastewater.
    Response: To reduce the reporting burden, EPA has revised the rule 
to allow for the use of either COD in conjunction with Equation II-1 of 
the rule or BOD5 in conjunction with Equation II-2 of the 
rule for the calculation of CH4 generation. EPA does not 
expect that this will effect the accuracy of the estimate of the annual 
mass of CH4 generated at the facility.
    EPA also revised the language regarding sampling of wastewater to 
require facilities to collect a flow-proportional composite sample 
(either constant time interval between samples with sample volume 
proportional to stream flow, or constant sample volume with time 
interval between samples proportional to stream flow). Facilities are 
required to collect a minimum of four sample aliquots per 24-hour 
period and to composite the aliquots for analysis. This requirement 
provides for greater certainty that the collected

[[Page 39746]]

sample represents the wastewater influent to the anaerobic wastewater 
treatment process, without imposing unnecessary burden on reporters.
    In response to comments, EPA considered revising the proposed 
language of 40 CFR 98.354 to clarify how facilities might meet the 
stated requirement for the collection of grab samples or time-weighted 
composite samples. EPA considered allowing facilities to collect grab 
samples if the wastewater influent to the anaerobic wastewater 
treatment process represents the discharge from a well-mixed wastewater 
storage unit (tank or pond), such that the COD or BOD5 
concentration of the waste stream does not vary in a 24-hour period. 
Similarly, EPA considered allowing facilities to collect time-weighted 
composite samples if the flow rate of the wastewater influent to the 
anaerobic wastewater treatment process does not vary more than 50 percent of the mean flow rate for a 24-hour sampling period. 
However, establishing that these conditions are met would require the 
facility to collect more samples than the proposed requirement to 
collect flow-weighted composite samples. Thus we did not include these 
sampling approaches in the final rule.
    The final rule establishes differing requirements for the frequency 
of monitoring biogas flow and biogas CH4 concentration. EPA 
expects that facilities that recover biogas will have existing gas flow 
meters, and is therefore requiring continuous monitoring of biogas flow 
from these facilities. EPA has revised the rule to allow either 
continuous or weekly monitoring of biogas CH4 concentration. 
If a facility has equipment that continuously monitors CH4 
concentration, the facility must use this equipment to determine the 
CH4 concentration in the recovered biogas. If a facility 
does not currently monitor biogas CH4 concentration, they 
must use either installed or portable equipment to monitor the 
CH4 concentration at least once a week. Once a week means 
once each calendar week, with at least three days between measurements. 
Weekly monitoring provides an adequate number of samples to evaluate 
the variability and uncertainly associated with CH4 
generation. Less frequent monitoring would result in greater 
uncertainty and would not significantly reduce the costs compared to 
weekly monitoring.
    Some gas flow meters and gas composition meters automatically 
compensate for temperature, pressure, and moisture content. EPA revised 
the equations in 40 CFR part 98, subpart II so that facilities that use 
automatically compensated meters are not required to measure 
temperature, pressure and moisture content. Facilities that operate 
meters that are not automatically compensated must measure these 
parameters as specified in 40 CFR 98.354.
    Some facilities, particularly food processing facilities, may not 
operate their wastewater treatment plants all year round. EPA clarified 
that wastewater monitoring requirements apply when the anaerobic 
wastewater treatment process is operating. Further, biogas methane 
concentration monitoring is only required in weeks when the cumulative 
biogas flow measured as specified in 40 CFR 98.354(g) is greater than 
zero.
    Comment: Many commenters argued that it would be unduly burdensome 
and costly to require facilities to monitor influent to wastewater 
treatment systems. Some stated that their influent often consists of 
multiple phases, making measurement of wastewater organic content 
(BOD5 or COD) difficult. Others contended that since 
effluent concentrations and flow are already measured for the purposes 
of National Pollutant Discharge Elimination System (NPDES) compliance, 
EPA should allow facilities to use engineering calculations and 
effluent measurements to calculate GHG emissions.
    Response: The rule requires that flow and BOD5 or COD be 
monitored at the location of influent to the anaerobic treatment 
process. EPA disagrees that facilities should be allowed to use the 
flow and organic loading of treated effluent to estimate CH4 
generation. CH4 generation is a function of the organic load 
into the treatment system. If facilities used measured treated effluent 
organic load, they would need to back-calculate the influent 
(untreated) load. This approach would require EPA to describe all 
possible treatment scenarios, which would make the rule cumbersome and 
overly complex. Facilities would be required to use complex and 
burdensome methodologies to back-calculate the influent load.
    Further, influent monitoring gives the most accurate determination 
of GHG emissions because it captures the inherent variability of the 
wastewater. In contrast, treated effluent characteristics typically 
have lower variability because high and/or variable influent 
concentrations have been reduced by treatment.
    EPA also disagrees that monitoring the influent to the anaerobic 
process would be difficult because it consists of multiple phases. EPA 
has revised 49 CFR 98.354(b) of the rule to clarify that flow and 
BOD5 or COD concentration must be monitored following all 
preliminary and primary treatment steps (e.g., after grit removal, 
primary clarification, oil-water separation, dissolved air flotation, 
or similar solids and oil separation processes). Such preliminary and 
primary treatment sufficiently removes the non-aqueous phases (oil, 
foam, suspended solids) that the wastewater stream that can be analyzed 
for BOD5 and COD without undue burden.
    EPA disagrees that the cost of monitoring would be an undue burden 
on facilities. The final rule continues to require facilities to 
collect and analyze samples of anaerobic treatment process influent no 
less than once per week. Weekly monitoring provides an adequate number 
of samples to evaluate the variability and uncertainty associated with 
CH4 generation. Less frequent monitoring would result in 
greater uncertainty and would not significantly reduce the costs 
compared to weekly monitoring.
    EPA has determined that the sampling methods contained in the rule 
are not unduly burdensome and still result in an accurate estimate of 
GHG emissions from industrial wastewater treatment processes for the 
purpose of this rulemaking.

F. Industrial Waste Landfills (40 CFR Part 98, Subpart TT)

1. Summary of the Final Rule
    Source Category Definition. This source category consists of 
industrial waste landfills whose total landfill design capacity is 
greater than or equal to 300,000 metric tons and that accepted waste on 
or after January 1, 1980.
    This source category does not include Resource Conservation and 
Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA) 
hazardous waste landfills, construction and demolition landfills, or 
landfills that only receive inert waste materials, such as coal 
combustion residue (e.g., fly ash), cement kiln dust, rocks and/or 
soil, glass, non-chemically bound sand (e.g., green foundry sand), 
clay, gypsum, pottery cull, bricks, mortar, cement, furnace slag, 
refractory material, or plastics.
    Facilities that meet the applicability criteria in the General 
Provisions (40 CFR 98.2(a)) summarized in Section II.B of this preamble 
must report GHG emissions.
    GHGs to Report. For industrial waste landfills, facilities must 
report:

[[Page 39747]]

     Annual CH4 generation and CH4 
emissions from the industrial waste landfill.
     Annual CH4 recovered (for landfills with gas 
collection and destruction systems).
    GHG Emissions Calculation and Monitoring. All facilities must 
ascertain annual modeled CH4 generation based on:
     Measured or estimated values of historic annual waste 
disposal quantities; and
     Appropriate values for model inputs (i.e., degradable 
organic carbon (DOC) fraction in the waste, CH4 generation 
rate constant). Default parameter values are specified for certain 
industries and for industrial waste generically.
    Facilities that do not collect and destroy landfill gas must adjust 
the annual modeled CH4 generation to account soil oxidation 
(CH4 that is converted to CO2 as it passes 
through the landfill cover before being emitted) using a default soil 
oxidation factor. The resulting value must be reported and represents 
both CH4 generation (corrected for oxidation) and 
CH4 emissions.
    Facilities that collect and destroy landfill gas must calculate the 
annual quantity of CH4 recovered and destroyed based on 
continuous monitoring of landfill gas flow rate, and continuous or 
weekly monitoring of CH4 concentration, temperature, 
pressure, and moisture of the collected gas prior to the destruction 
device.
    Those facilities that collect and destroy landfill gas must then 
calculate CH4 emissions in two ways and report both results. 
Emissions must be calculated by:
    1. Subtracting the measured amount of CH4 recovered from 
the modeled annual CH4 generation (with adjustments for soil 
oxidation and destruction efficiency of the destruction device) using 
the equations provided; and
    2. Applying a gas collection efficiency to the measured amount of 
CH4 recovered to ``back-calculate'' CH4 
generation, then subtracting the measured amount of CH4 
recovered (with adjustments for soil oxidation and destruction 
efficiency of the destruction device) from the back-calculated 
CH4 generation using the equations provided. A default 
collection efficiency of 75 percent is specified, but landfills should 
use a collection efficiency that takes into account collection system 
coverage, operation, and landfill cover materials.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)), reporters must 
submit additional data that are used to calculate GHG emissions. A list 
of the specific data to be reported for this source category is 
contained in 40 CFR part 98, subpart TT.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)), reporters must keep records of additional 
data used to calculate GHG emissions. A list of specific records that 
must be retained for this source category is included in 40 CFR part 
98, subpart TT.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart TT: Industrial Waste Landfills.''
     A number of provisions were added to focus on industrial 
waste landfills that have a potential to generate significant 
quantities of methane rather than all landfills. These provisions 
include an exemption for landfills that did not accept any waste after 
January 1, 1980, an exemption of landfills with a total landfill design 
capacity of less than 300,000 metric tons, and an exemption for 
landfills that only receive inert waste materials.
     In addition to direct mass measurements for determining 
waste quantities for current reporting years, we also allow volume 
measurements, mass balance procedures, or number of truck loads.
     Additional model defaults for industrial waste are 
included in the final rule and additional methods are provided to 
estimate DOC content of industrial solid waste streams.
     For landfills with landfill gas recovery, all of the 
changes that were incorporated in the final 40 CFR part 98, subpart HH 
rule (allowing weekly sampling and direct flame ionization methods) are 
also included in this final rule for industrial waste landfills (by 
cross-referencing the final requirements in 40 CFR part 98, subpart 
HH). For additional details regarding the changes in the landfill gas 
recovery monitoring requirements, see the final preamble for the 40 CFR 
part 98, subpart HH [Municipal Solid Waste Landfills] rule at 74 FR 
56336.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. EPA received many comments on this subpart covering numerous 
topics. EPA's responses to these significant comments can be found in 
the comment response document for industrial waste landfills in 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Subpart TT: Industrial Waste Landfills.''
Definition of Source Category
    Comment: Many commenters stated that landfills containing inert 
industrial wastes should not be subject to this proposed rule because 
inert wastes do not generate methane via anaerobic processes. Inert 
wastes, according to various commenters, include: construction and 
demolition waste, coal combustion residue monofills, geothermal filter 
cake waste landfills, waste rock landfills at coal mines, plastics, 
soils from construction and other site activities, hazardous waste 
landfills, solid waste management units (SWMUs) and non-hazardous 
landfills located at refineries, agricultural waste landfills 
associated with sugar mills, pottery cull, gypsum, clays, green sand, 
resin sand, refractory, slag, carbon and graphite manufacturing 
byproducts.
    Several commenters stated that the rule would be very burdensome 
for industrial waste landfills with inert waste streams and that EPA 
has not sufficiently justified its decision to make all industrial 
waste landfills, regardless of typical byproduct waste characteristics, 
meet the provisions proposed.
    Rather than listing specific exclusions, several commenters stated 
that EPA should do as suggested by the proposed rule and limit the 
requirements of the rule to landfills located at food processing, pulp 
and paper and ethanol production facilities which are known for methane 
gas generation; several commenters also included petroleum refineries 
in this list. One commenter suggested that ethanol production 
facilities should not be required to report landfill emissions because 
emissions from landfills at these facilities are so small.
    A number of other exemptions were suggested by different 
commenters, including:
     Exempt inactive landfills, from which emissions are small.
     Exempt facilities that are not required to monitor methane 
or install and operate any methane control facilities under State 
permitting in order to keep the requirements simple and not overly 
burdensome.
     Exempt on-site industrial waste landfills that have been 
closed under RCRA because they have little or no

[[Page 39748]]

potential for air emissions and would create an unnecessary compliance 
burden.
    Response: We agree that there will be negligible methane emissions 
from landfills that contain only inert waste materials because they do 
not have organic materials that would emit methane after being placed 
in an industrial landfill. Therefore, we investigated alternative 
applicability requirements for industrial waste landfills to target the 
reporting requirements to landfills that are expected to produce 
significant amounts of methane. Based on an analysis of various options 
(see the ``Technical Support Document for Industrial Waste Landfills'' 
in Docket No. EPA-HQ-OAR-2008-0508), we decided to exclude from the 
industrial waste landfill reporting requirements landfills that are 
used exclusively to dispose of inert materials or ``inorganic'' wastes. 
Specific types of wastes that are expected to be inert in the landfill 
(e.g., bricks, glass, plastics, rocks, and fly ash) are listed. This 
list of inert waste types also includes wastes that contain 0.5 weight 
percent (dry basis) or less of volatile solids as a means for 
industrial waste landfill owners and operators to characterize a waste 
stream as ``inorganic'' if the waste stream is not already on the list 
of inert materials. We did not provide exemptions for specific 
industries nor limit coverage to specific industries (e.g., ethanol 
production, food processing, or pulp and paper facilities) because the 
waste material generated and managed in a landfill at any given 
facility can be widely different, even within a given industry sector. 
As such, we determined that the waste material exclusions provided a 
better mechanism to exclude inert materials without omitting waste 
materials that have high organic content. Additional rationale 
regarding waste materials that were not specifically excluded is 
provided in the following paragraph.
     Geothermal filter cake. We anticipate that geothermal 
filter cake would be included in the exemption for rocks and soil from 
excavation activities. If this filter cake includes other materials, 
the landfills managing this waste may still be exempted if the waste 
can be shown to contain 0.5 weight percent (dry basis) or less of 
volatile solids. We note that this exclusion applies to any waste 
material at any industrial waste landfill (i.e., any of the following 
bullets).
     Landfills at petroleum refineries. We did not exclude 
landfills at petroleum refineries because we anticipate that refinery 
waste materials will contain significant amounts of DOC.
     Agricultural wastes at sugar mills. Again, we did not 
exclude these wastes because we anticipate that the waste may contain 
significant amounts of DOC (scraps of sugar canes).
     Resin sand. While we excluded green sand (i.e., ``non-
chemically'' bound sand, we did not exclude resin sand because resin 
sand generally contains organic chemical binders that can degrade in 
landfills and generate methane emissions.
     Carbon and graphite wastes. These wastes are expected to 
contain significant amounts of carbon. It is unclear if the carbon 
material can be degraded. However, with the information currently 
available regarding this waste stream, we could not conclude that these 
wastes are inert. If the graphite does not contain volatile impurities, 
it may be possible to exempt these wastes by demonstrating that the 
waste material contains 0.5 weight percent (dry basis) or less of 
volatile solids.
    We also limited the reporting requirements for industrial waste 
landfills to facilities whose total landfill design capacity is greater 
than or equal to 300,000 metric tons. Our analysis indicated that there 
are a large number of very small industrial waste landfills. 
Approximately two-thirds of the total number of potentially affected 
industrial waste landfills have a total landfill design capacity of 
less than 300,000 metric tons, and these landfills are projected to 
contribute only 7 percent of the total GHG emissions from industrial 
waste landfills. Landfills with a design capacity of less than 300,000 
metric tons are expected to have emissions well below 25,000 metric 
tons CO2e. Landfills of this size would not be required to 
report emissions if they were not co-located at an industrial facility 
that has other emission sources exceeding the reporting threshold. The 
incremental costs for requiring these small co-located industrial waste 
landfills to report their landfill emissions was approximately $1.25 
per additional metric tons CO2e reported (1st year costs), 
compared to approximately $0.05 per metric tons CO2e 
reported (1st year costs) for facilities with landfills whose total 
landfill design capacity is greater than or equal to 300,000 metric 
tons.
    We also agree that certain inactive landfills can be excluded from 
the GHG reporting requirements. As described in the preamble to the 
final rule for municipal solid waste (MSW) landfills (74 FR 56335), 
landfills that have been closed over 30 years represent a small 
fraction of GHG emissions from landfills and are not relevant for 
purposes of policy analysis. Therefore, we also limit the reporting 
requirements for industrial waste landfills to facilities that received 
waste on or after January 1, 1980.
    We disagree that only industrial waste landfills that are required 
to monitor for methane or that are required to capture and destroy 
methane emissions should be included in the rule. Methane has not 
traditionally been a pollutant for which monitoring or destruction 
requirements have been established. We do not know of any such 
requirements, and available information indicates that few, if any, 
industrial waste landfills have methane capture and destruction 
equipment. Although few industrial landfills capture and destroy 
methane, that does not mean that these landfills do not generate 
methane in significant quantities.
    As proposed, the industrial waste landfill source category did not 
include hazardous waste landfills or dedicated construction and 
demolition landfills. The final rule also excludes these landfills, 
however, we have clarified that hazardous waste landfills refers to 
those subject to RCRA Subtitle C or TSCA requirements. These landfills 
are excluded due to the landfill design requirements, such as ``dry 
tomb'' methods, which are expected to minimize methane production.
    We have not exempted Comprehensive Environmental Response, 
Compensation, and Liability Act (CERCLA) (Superfund) landfills. 
Generally, landfills become listed as CERCLA sites because the 
landfills were not designed for hazardous wastes but some hazardous 
materials were disposed of in the landfill and subsequently these 
materials contaminated the groundwater. Thus, these landfills were not 
designed and operated in a manner similar to RCRA Subtitle C or TSCA 
landfills. Furthermore, the remediation requirements for CERCLA 
landfills are determined on a site-specific basis, and these methods 
generally do not necessarily require significant changes to the 
landfill. For example, clean-up efforts focused on groundwater 
remediation may pump and treat the contaminated groundwater and 
recirculate the treated groundwater to the landfill. This technique can 
be used to clean-up the groundwater and leach any other remaining 
contaminants from the landfill, but this technique will enhance rather 
than limit methane generation from the landfill. Consequently, 
landfills that are subsequently listed by States as ``hazardous'' for 
the purposes of

[[Page 39749]]

CERCLA (Superfund) or similar State programs are not excluded from the 
industrial waste landfill source category.
    In summary, the final industrial waste landfill rule does not apply 
to: (1) Industrial waste landfills that have not accepted waste on or 
after January 1, 1980; (2) industrial waste landfills that have a total 
design capacity of less than 300,000 metric tons; (3) RCRA Subtitle C 
or TSCA hazardous waste landfills; (4) dedicated construction and 
demolition landfills; and (5) industrial waste landfills that receive 
only one or more of the following types of waste materials: coal 
combustion residue (e.g., fly ash); cement kiln dust; rocks and/or soil 
from excavation and construction and similar activities; glass; non-
chemically bound sand (e.g., green foundry sand); clay, gypsum, or 
pottery cull; bricks, mortar, or cement; furnace slag; materials used 
as refractory (e.g., alumina, silicon, fire clay, fire brick); 
plastics; or other waste material that has a volatile solids 
concentration of 0.5 weight percent (on a dry basis) or less.
Method for Calculating GHG Emissions
    Comment: Several commenters suggested that EPA not require direct 
measurement of the waste entering the landfill. One commenter noted 
that there are materials that are conveyed and sluiced to solid waste 
disposal areas that could not be monitored across truck scales. The 
commenters suggested a number of alternatives to direct mass 
measurements, which include:
     Allow the use of company records.
     Allow the use of any measurement method specified in an 
applicable permit or any reasonable estimation method that is 
adequately documented.
     Allow the use of typical waste disposal records and other 
testing on parameters such as density and chemical analysis.
     Allow periodic calibration of the trucks hauling landfill 
waste to determine the weight to volume ratio of various waste streams 
provides a practical measurement for industrial waste landfills.
     Allow estimation methods outlined in the proposal to 
calculate previous years' data be applied in future years (i.e., 
require direct waste measurements for only one year).
    Response: Unlike MSW landfills, many industrial waste landfills do 
not directly weigh waste loads as they enter the landfill. We 
reevaluated the cost of requiring direct mass measurements for 
industrial waste landfills. According to one of the commenters, the 
capital cost of installing scales could be as much as $50,000 each, 
with operating and driver time resulting in an estimated annualized 
cost of over $23,000. We also considered the uncertainty associated 
with different measuring methods and their resulting uncertainty in the 
overall modeled methane generation. Given the significant additional 
costs for requiring direct mass measurements at industrial waste 
landfills and the limited improvement in the uncertainty of the 
reported methane emissions, we revised the rule so that direct mass 
measurements are not required for industrial waste landfills.
    In 40 CFR 98.463 of the final rule, industrial waste landfills that 
are subject to the rule are given several options for determining the 
current waste quantities and historical values for waste quantities and 
DOC. The types of processes that generate the waste, the types of waste 
generated, and the means by which the wastes are transported or 
conveyed to the landfill are very diverse. As such, different methods 
of determining these waste quantities are needed. Consequently waste 
quantities determined for years for which emissions reports are 
required may be determined by any of the following methods: direct mass 
measurements; volume measurements and waste stream density determined 
from measurement data or process knowledge; mass balance procedures, 
determining the mass of waste as the difference between the mass of the 
process inputs and the mass of the process outputs; and the number of 
loads (e.g., trucks) and the mass of waste per load based on the 
working capacity of the container or vehicle.
    We determined these methods accommodate the approaches requested by 
the commenters except for the last bulleted item. We do not agree with 
the commenter's request to allow projections of waste quantities 
disposed of after the first reporting year based on processing rate 
correlations used to project historical waste quantities. This method 
would not account for processing changes that may reduce (or increase) 
the waste generation rate. Given the flexibility in determining waste 
disposal quantities in a given reporting year, we determined that the 
costs of determining these waste quantities as provided in the final 
rule are reasonable and that the provided methods would produce more 
accurate values for the purposes of reporting than the ``future'' 
projection of waste quantities based on a single year of measurement 
data.
    We also provide a number of methods by which historical waste 
quantities must be determined subject to the hierachy of available 
data. Historical waste quantities must be determined using the methods 
specified for current waste quantities when that information is 
available. For years when waste quantity data are not available, 
historical waste quantities must be estimated using production or 
processing rates when these data are available. For years when neither 
waste quantity data nor production/processing rate data are available, 
historical waste quantities must be estimated based on the capacity of 
the landfill used and the number of years the landfill has accepted 
waste.
    Comment: Several commenters requested that more information be 
provided in the rule to calculate GHG emissions from industrial waste 
landfills, including an expansion of the type of information in Table 
HH-1 of the rule, especially if reporting of GHG emissions from 
industrial waste landfills is not limited to the food processing, pulp 
and paper, and ethanol production facilities. One commenter suggested 
that, if there are no DOC or k parameters in Table HH-1 for a given 
waste category, such as boiler ashes, reporters should assume they are 
zero and that no CH4 is generated from that waste. According 
to the commenter, this assumption would more accurately calculate 
CH4 emissions from a landfill by excluding quantities of 
inert wastes rather than assuming all wastes generate CH4.
    Response: We have specifically included a default DOC value of zero 
for inert materials in Table TT-1. Inert material is described as any 
waste material (such as glass, cement, and fly ash) that is 
specifically listed in Sec.  98.460(b)(3) paragraphs (i) through (xii). 
As discussed previously, industrial waste landfills that receive only 
inert materials are not required to report, but landfills that receive 
both degradable organic and inert waste streams may use the default DOC 
for the quantity of inert material disposed of in the industrial waste 
landfill. For all other (non-inert) waste materials, the final rule 
allows either the use of Table TT-1 to determine the default values for 
DOC or the use of measured, waste stream-specific DOC values following 
the methods provided in the final rule. In addition to default DOC and 
k values for selected industries, we have also included in Table TT-1 
of 40 CFR part 98, subpart TT default DOC and k value for ``other solid 
industrial waste (not otherwise specified).'' As such, there should no 
longer be an ``unlisted'' waste stream.

[[Page 39750]]

Costs
    Comment: One commenter stated that EPA presents its summary cost 
analysis data in the preamble with further details in the accompanying 
regulatory impact analysis (RIA) report. The commenter stated that EPA 
presented cost data for each of the subparts separately but fails to 
consider the overall burden per facility of complying with multiple 
subparts, including landfills, as is the case with most industrial 
facilities.
    Response: EPA agrees that the costs facing facilities in some 
sectors include not only process costs but additional costs associated 
with other subparts in the rule. While these costs are presented 
individually in the costs tables, where these conditions apply the 
costs are summed across applicable subparts and compared to revenues in 
the economic and small entity impact analyses. In response to comments 
on this issue, we revised the RIA of the 2009 final rule to more 
clearly describe the approach taken. The same approach has been taken 
for this rule.

III. Other Source Categories Proposed in 2009

A. Overview

    With this action EPA has made the final decision not to include 
Ethanol Production or Food Processing as distinct subparts in 40 CFR 
part 98. This decision does not change the applicability requirements 
under other subparts of this rule that may affect these industries. 
Further explanation of this decision is included in Section III.B and 
III.C of this preamble. EPA has also made the final decision to not 
include Suppliers of Coal in 40 CFR part 98 at this time. Further 
explanation of this decision is included in Section III.D of this 
preamble.

B. Ethanol Production

    EPA has made the final decision not to include Ethanol Production 
(proposed as 40 CFR part 98, subpart J) as a distinct subpart in 40 CFR 
part 98. EPA has determined that it is not necessary to include 40 CFR 
part 98, subpart J in order to cover ethanol facilities in the final 
rule. Thus, although there is no distinct subpart applicable to ethanol 
production, these facilities will still be subject to the final rule 
(if emissions exceed the applicable threshold) and the overall coverage 
of the final rule regarding these facilities is the same as that of the 
proposed rule.
    The proposal for this subpart (74 FR 16448, April 10, 2009) did not 
include any unique requirements for monitoring or reporting of process 
emissions from ethanol production facilities. Instead, the proposed 
subpart simply referred to reporting that those facilities might be 
required to do under other subparts, namely, 40 CFR part 98, subpart 
C--Stationary Combustion, subpart HH-Landfills, and subpart II--
Wastewater Treatment.
    EPA received many comments on this subpart covering various topics. 
EPA's response to these comments can be found in the comment response 
document for ethanol production in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Subpart J: Ethanol 
Production.''
    40 CFR part 98, subpart J was originally included as a distinct 
subpart to clearly indicate that these facilities must aggregate 
emissions from all source categories when determining whether emissions 
exceeded the applicable threshold. As structured, the proposed subpart 
specifically required that emissions from stationary combustion, on-
site landfills, and on-site wastewater treatment were to be aggregated 
in determining the reporting threshold and reporting emissions from 
these facilities.
    Upon closer examination of 40 CFR 98.2(a), it is clear that ethanol 
production facilities are already required to report if they meet the 
threshold of 25,000 tons CO2e by aggregating emissions from 
all applicable source categories in the rule including stationary 
combustion, industrial wastewater treatment, industrial waste 
landfills, miscellaneous use of carbonates, and any others that may 
apply. In fact, any type of facility not specifically identified in a 
subpart must report their GHG emissions if that facility contains 
source categories itemized by the rule and their aggregate emissions 
meet the applicable threshold.
    Note that in this final rule, ethanol production facilities are 
among those specifically identified in 40 CFR part 98, subpart II--
Industrial Wastewater Treatment and are required to report if they meet 
the applicability provisions in 40 CFR 98.2(a)(2). Thus for clarity, 
the definition of ethanol production facility is included in 40 CFR 
98.358.
    Again, in sum, EPA has determined that it is not necessary to 
include 40 CFR part 98, subpart J in order to cover ethanol facilities 
in the final rule. Moreover, highlighting the ethanol production (and 
food processing) categories as being covered by the rule due to 
emissions covered by other source categories may give the false 
impression that there are not any other types of sources that may be 
covered by the rule due to their aggregate emissions from stationary 
combustion, industrial waste landfills and/or industrial wastewater 
treatment.

C. Food Processing

    EPA has made the final decision not to include Food Processing 
(proposed as 40 CFR part 98, subpart M) as a distinct subpart in 40 CFR 
part 98. EPA had determined that it is not necessary to include 40 CFR 
part 98, subpart M in order to cover food processing facilities in 40 
CFR part 98. Thus, although there is no distinct subpart applicable to 
food processing, these facilities will still be subject to the final 
rule (if emissions exceed the applicable threshold) and the overall 
coverage of the final rule regarding these facilities is the same as 
that of the proposed rule.
    The proposal for this subpart (74 FR 16448, April 10, 2009) did not 
include any unique requirements for monitoring or reporting of process 
emissions from food processing facilities. Instead, the proposed 
subpart simply referred to reporting that those facilities might be 
required to do under other subparts, namely, 40 CFR part 98, subpart 
C--Stationary Combustion, subpart HH--Landfills, and subpart II--
Wastewater Treatment.
    EPA received many comments on this subpart covering various topics. 
EPA's response to these comments can be found in the comment response 
document for food processing in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Subpart M: Food Processing.''
    40 CFR part 98, subpart M was originally included as a distinct 
subpart to clearly indicate that these facilities must aggregate 
emissions from all source categories when determining whether emissions 
exceeded the applicable threshold. As structured, the proposed subpart 
specifically required that emissions from stationary combustion, on-
site landfills, and on-site wastewater treatment were to be aggregated 
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 are already required to report if they meet the 
threshold of 25,000 tons CO2e by aggregating emissions from 
all applicable source categories in the rule including stationary 
combustion, industrial wastewater treatment, industrial waste 
landfills, miscellaneous use of carbonates, and any others that may 
apply. In fact, any type of facilities not specifically identified in a 
subpart must report their GHG emissions if that facility contains 
source categories

[[Page 39751]]

itemized by the rule and their aggregate emissions meet the applicable 
threshold.
    Note that in this final rule, food processing facilities are among 
those specifically identified in 40 CFR part 98, subpart II--Industrial 
Wastewater Treatment and are required to report if they meet the 
applicability provisions in 40 CFR 98.2(a)(2). Thus, for clarity, a 
definition of food processing facility is included in 40 CFR 98.358.
    Again, in sum, EPA has determined that it is not necessary to 
include 40 CFR part 98, subpart M in order to cover food processing 
facilities in the final rule. Moreover, highlighting the food 
processing (and ethanol production) categories as being covered by the 
rule due to emissions covered by other source categories may give the 
false impression that there are not any other types of sources that may 
be covered by the rule due to their aggregate emissions from stationary 
combustion, industrial waste landfills and/or industrial wastewater 
treatment.

D. Suppliers of Coal

    As proposed (74 FR 16448, April 10, 2009) 40 CFR part 98, subpart 
KK would have required that all coal mines, coal importers and 
exporters, and coal waste reclaimers report the amount of coal produced 
or supplied to the economy annually, as well as the CO2 
emissions that would result from complete oxidation or combustion of 
this quantity of coal. After reviewing the comments received on the 
proposal as well as other available information, EPA has made a final 
decision not to include Suppliers of Coal (proposed as 40 CFR part 98, 
subpart KK) in 40 CFR part 98 at this time.
    EPA's rationale for not requiring reporting from coal suppliers at 
this time is that (i) the overlap in reporting from upstream coal 
suppliers and downstream emitters is almost 100 percent indicating that 
double-reporting does not provide more complete information to EPA, 
unlike with other upstream supplier subparts (e.g., 40 CFR part 98, 
subpart MM and NN), and (ii) the high accuracy of the downstream 
reporting provisions in 40 CFR part 98 provide more than adequate 
emissions data for anticipated near-term uses.
    The overall purpose of 40 CFR part 98 is to collect information to 
inform the development of future climate policy and programs under the 
CAA. In the context of GHG emissions from coal consumption, EPA seeks 
information on the magnitude and location of facility-level emissions 
across the economy as well as overall emissions at the national level. 
These near-term needs can be met with high accuracy and at principally 
the same coverage through existing reporting requirements for direct 
emitters under 40 CFR part 98, primarily through reporting under 40 CFR 
part 98, subparts C, D, and Q. For example, the existing 40 CFR part 
98, subpart D, which accounts for approximately 94 percent of emissions 
from the use of coal, builds on rigorous monitoring requirements of 40 
CFR part 75. Coal-fired electricity generating units subject to 40 CFR 
part 75 typically use continuous emissions monitoring equipment that 
measures actual carbon dioxide emissions hourly. Furthermore, 40 CFR 
part 98 requires rigorous Tier 3 and Tier 4 reporting at industrial 
facilities with large units combusting coal and other solid fuels. 
Reporting requirements under 40 CFR part 98, subpart C (general 
stationary combustion) and 40 CFR part 98, subpart D (electricity 
generation) will allow EPA to obtain data on more than 99 percent of 
total CO2 emissions from coal combustion through existing 
reporting provisions of 40 CFR part 98. The proposed 40 CFR part 98, 
subpart KK procedures would have covered approximately 100 percent of 
coal supplied to the economy and resulting downstream CO2 
combustion emissions. The difference in combustion coverage of less 
than 1 percent is estimated to come from the smallest consumers of 
coal, such as home owners for use in heating.
    Furthermore, EPA's near-term needs regarding the data can be met 
with higher accuracy through existing reporting requirements for direct 
emitters. Under the proposed 40 CFR part 98, subpart KK, approximately 
50 percent of coal suppliers would have used engineering calculations 
to correlate HHV from daily coal samples with carbon content from 
either daily or monthly coal samples, assuming those are representative 
of the entire coal stream. For the remaining coal mines, the proposed 
40 CFR part 98, subpart KK procedures would have relied on default 
CO2 emissions values, which are less accurate than direct 
measurement and would not have supplied mine specific data. 
Furthermore, existing reporting procedures for direct emitters account 
for the combustion efficiency of the facility rather than assume 100 
percent combustion or oxidation as was proposed in 40 CFR part 98, 
subpart KK.
    While EPA believes that the proposal had a pragmatic approach to 
balancing accuracy and cost, it is clear that the upstream data under 
proposed 40 CFR part 98, subpart KK would not have been as accurate as 
the more rigorously monitored data reported by direct emitters. In sum, 
including proposed 40 CFR part 98, subpart KK would have provided EPA 
with a near negligible amount of additional information on emissions, 
while not achieving the same level of accuracy as the existing 
reporting downstream.
    Though cost and burden are not reasons for EPA's decision to 
exclude 40 CFR part 98, subpart KK, EPA notes that changing the 40 CFR 
part 98, subpart KK proposal to require more rigorous reporting on par 
with downstream requirements would have raised the costs and burden of 
proposed 40 CFR part 98, subpart KK significantly. In the proposed 
Regulatory Impacts Analysis Cost Appendix Section 29, EPA assumed that 
52 percent of coal mines (706) mines would meet 40 CFR part 98, subpart 
KK requirements by sampling and testing for coal content monthly and 
that 48 percent (659 mines) would meet requirements by using default 
factors. To raise the reporting rigor, EPA would have had to require 
100 percent of coal mines (1,365 mines) to sample and test coal content 
daily.
    In addition, there is other information available to EPA such as 
the Inventory of U.S. Greenhouse Gas Emissions and Sinks,\4\ other data 
reported by coal-fired electricity generating units to EPA's Acid Rain 
Program, and the Energy Information Administration's (EIA) detailed 
coal production, consumption, imports and exports data.\5\ The national 
GHG inventory tracks CO2 emissions from the combustion of 
coal across the entire economy for each year since 1990 and breaks down 
emissions according to economic sector. From this data set EPA 
determined that in 2007, electricity generation accounted for 
approximately 94 percent of all CO2 emissions from coal 
combustion. The remaining emissions from coal consumption come 
primarily from the industrial sector. EIA collects and publishes annual 
data on coal production, consumption, imports and exports, thus 
providing an additional source of information to serve as a check on 
estimates of emissions from this sector and to inform potential 
policies and programs related to coal supply. As EPA has stated in this 
preamble and in the original 40 CFR part 98, subpart KK proposal, 
rigorous, direct CO2 emissions measurements of coal 
combustion are preferred by EPA over the use of default CO2 
values for informing policies and programs that relate to stationary 
source emissions. However, policies and programs of another nature for 
which default

[[Page 39752]]

emissions values are more appropriate and have been previously used by 
EPA, such as life cycle emissions considerations for National 
Environmental Policy Act (NEPA) analyses and Federal government climate 
change contribution analyses, can be adequately informed at this time 
by existing EIA data on coal production and default CO2 
emissions values.
---------------------------------------------------------------------------

    \4\ http://www.epa.gov/climatechange/emissions/
usinventoryreport.html.
    \5\ http://www.eia.doe.gov/fuelcoal.html.
---------------------------------------------------------------------------

    EPA views potential double-reporting for emissions from other 
fossil fuels as appropriate where downstream reporting of all or the 
large majority of emissions is impractical and where the upstream and 
downstream reporting combine to provide the complete picture. Near 
complete downstream coverage, as is achieved with coal, is not possible 
for downstream users of petroleum, natural gas, or industrial gases. In 
many cases, the fossil fuels and industrial GHGs supplied by producers 
and importers are used and ultimately emitted by a large number of 
small sources, particularly in the commercial and residential sectors 
(e.g., HFCs emitted from home air conditioning units or CO2 
emissions from individual motor vehicles). EPA would have had to 
require reporting by hundreds or thousands of small facilities to cover 
all direct emissions. EPA determined it was more appropriate to require 
reporting by the suppliers of petroleum products, natural gas and 
natural gas liquids, and industrial gases and CO2. As 
exhibited by Table 5-18 of the RIA of the October 2009 Final Rule, the 
downstream emitters requirements of the October 2009 Final Rule account 
for only 20 percent of petroleum supply, approximately 23 percent of 
natural gas supply and 28 percent of industrial gas supply. 
Comparatively, requiring reporting by suppliers of these fuels, 
accounts for a much larger percentage of emissions (100 percent for 
petroleum and industrial gas suppliers and approximately 68 percent for 
natural gas suppliers).
    Some commenters suggested that 40 CFR part 98, subpart KK data on 
the carbon content of all coal supplied would have informed the 
downstream effects of emissions changes resulting from the changing 
carbon intensity of the fuel (which in turn assists in analyses such as 
Best Available Control Technology (BACT)). EPA notes that it did not 
propose that facilities affected by 40 CFR part 98, subpart KK would 
report information on their customers because coal from multiple 
suppliers can be blended together and sent to multiple customers. 
Therefore information on downstream effect would not have been 
available for use from the proposed 40 CFR part 98, subpart KK. For 
other upstream categories, EPA also did not propose and does not 
require detailed information about specific customers. If EPA 
determines that such type of carbon content data are necessary for a 
specific analysis or determination, the Agency can request it at that 
time. The robust data being collected now on downstream CO2 
emissions are adequate for general policy analysis and will assist the 
Agency in targeting additional information requests in the future.
    EPA's final decision is entirely consistent with the language of 
the various appropriations acts authorizing the expenditure of money 
for the reporting rule. The language in the FY2008 Appropriations Act 
instructed EPA to spend the money on a rule requiring reporting ``in 
all sectors of the economy.'' The Joint Explanatory Statement provided 
that EPA should include upstream production ``to the extent that the 
Administrator deems appropriate.'' The appropriations language grants 
EPA much discretion to determine the appropriate source categories to 
include in the reporting rule.
    The phrase ``all sectors of the economy'' is not further elaborated 
in the FY2008 or later appropriations language. The term is ambiguous, 
and EPA may interpret it in any reasonable manner. See Chevron, U.S.A. 
v. NRDC, 467 U.S. 837 (1984). Notably, the phrase is not ``all 
industrial sectors'' but rather ``all sectors of the economy.'' There 
is a difference between an industrial sector and a sector of the 
economy. The former typically refers to a specific type of industry, 
while the latter refers to categories of industries or businesses. For 
example, the North American Industrial Classification System (NAICS) is 
a two- through six-digit hierarchical classification system, offering 
five levels of detail, ranging from the broad economic sector to the 
narrower national industry. See http://www.census.gov/eos/www/naics/
faqs/faqs.html#q5 (last visited May 10, 2010) (``Each digit in the code 
is part of a series of progressively narrower categories, and the more 
digits in the code signify greater classification detail. The first two 
digits designate the economic sector, the third digit designates the 
subsector, the fourth digit designates the industry group, the fifth 
digit designates the NAICS industry, and the sixth digit designates the 
national industry.'').\6\
---------------------------------------------------------------------------

    \6\ Although we cite to the NAICS system as an example 
illustrating that sectors of the economy are considered to be 
broader than industrial groupings, we are not indicating that we 
think the appropriations language requires EPA to cover sources from 
the 20 sectors covered by the NAICS.
---------------------------------------------------------------------------

    In the proposed rule, EPA used the term ``sector'' to refer both to 
different types of sectors of the economy and specific industrial 
sectors or source categories. Compare 74 FR 16467/1 (referring to 
source categories in the ``agricultural and land use sectors'') to 74 
FR 16488/1 (referring to ``adipic acid production sector''). 
Unfortunately, that usage may have caused some confusion, and lead some 
stakeholders to believe that the two types of sectors are 
interchangeable and equivalent. But as noted above, there are 
differences between sectors of the economy, industrial sectors and 
source categories in the reporting rule. EPA can cover a sector of the 
economy in the reporting rule without covering every type of source in 
that sector of the economy.
    40 CFR part 98 already covers a broad and diverse selection of 
sources and emissions in the various sectors of the economy (e.g., fuel 
and industrial gas suppliers, motor vehicle manufacturers, underground 
coal mines, manufacturing facilities, universities and other facilities 
with stationary combustion). While EPA considers it reasonable to 
include more than one source category in any given sector of the 
economy, it is not required to include every possible source category.
    In any event, the appropriations language at most denotes a 
Congressional intent to ensure that emissions from various economic 
sectors are covered by the rule. As noted above, 40 CFR part 98 already 
adequately covers emissions from coal combustion even without getting 
additional information from coal suppliers.
    Finally, the Joint Explanatory Statement already contemplated that 
the Administrator may not ``deem[] it appropriate'' to include all 
possible upstream production and downstream sources. As explained 
above, the October 2009 Final Rule already thoroughly covers the 
emissions that result from coal combustion. That information, combined 
with other sources of information regarding the coal supply available 
to EPA, makes EPA's decision that it is not ``appropriate'' at this 
time to include coal suppliers in the rule entirely reasonable.
    EPA will continue to assess the need for reporting from coal 
suppliers in the future in light of new information or identification 
of policy or program needs. If EPA were to decide in the future to add 
coal suppliers to 40 CFR

[[Page 39753]]

part 98 it would initiate a new rulemaking process.

IV. Economic Impacts on the Rule

    This section of the preamble examines the costs and economic 
impacts of the proposed rulemaking and the estimated economic impacts 
of the rule on affected entities, including estimated impacts on small 
entities. Complete detail of the economic impacts of the final rule can 
be found in the text of the EIA in the docket for this rulemaking (EPA-
HQ-OAR-2008-0508).
    A large number of comments on economic impacts of the rule were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Cost and Economic Impacts of the 
Rule.'' Additional subpart specific comments and responses can be found 
in EPA's Response to Public Comments subpart specific documents.

A. How were compliance costs estimated?

1. Summary of Method Used To Estimate Compliance Costs
    EPA used available industry and EPA data to characterize conditions 
at affected sources. Incremental monitoring, recordkeeping, and 
reporting activities were then identified for each type of facility and 
the associated costs were estimated. The annual costs reported in 
2006$. EPA's estimated costs of compliance are discussed below and in 
greater detail in Section 4 of the EIA (EPA-HQ-OAR-2008-0508):
    Labor Costs. The vast majority of the reporting costs include the 
time of managers, technical, and administrative staff in both the 
private sector and the public sector. Staff hours are estimated for 
activities, including:
     Monitoring (private): staff hours to operate and maintain 
emissions monitoring systems.
     Recordkeeping and Reporting (private): staff hours to 
gather and process available data and reporting it to EPA through 
electronic systems.
     Assuring and releasing data (public): staff hours to 
quality assure, analyze, and release reports.
    Staff activities and associated labor costs will potentially vary 
over time. Thus, cost estimates are developed for start-up and first-
time reporting, and subsequent reporting. Wage rates to monetize staff 
time are obtained from the Bureau of Labor Statistics (BLS).
    Equipment Costs. Equipment costs include both the initial purchase 
price and any facility modification that may be required. Based on 
expert judgment, the engineering costs analyses annualized capital 
equipment costs with appropriate lifetime and interest rate 
assumptions. One-time capital costs are amortized over a 10-year cost 
recovery period at a rate of 7 percent.

B. What are the costs of the rule?

1. Summary of Costs
    The total annualized costs incurred under the reporting rule would 
be approximately $7.0 million in the first year and $5.5 million in 
subsequent years ($2006). This includes a public sector burden estimate 
of $0.3 million for program implementation and verification activities. 
Table 3 of this preamble shows the first year and subsequent year costs 
by subpart. In addition, it presents the relative share of the total 
cost represented by each subpart.

      Table 3--National Annualized Mandatory Reporting Costs Estimates (2008$): Subparts T, KK, II, and TT
----------------------------------------------------------------------------------------------------------------
                                                                     First year             Subsequent years
                                                             ---------------------------------------------------
             Subpart                       2007 NAICS           Millions                  Millions
                                                                 2006$        Share        2006$        Share
----------------------------------------------------------------------------------------------------------------
Subpart T--Magnesium Production..  331419 and 331492........         $0.1           2%         $0.1           2%
Subpart FF--Underground Coal       212112...................          4.0          57%          2.8          51%
 Mines.
Subpart II--Industrial Wastewater  322110, 322121, 322122,            1.5           21          1.5           26
 Treatment.                         322130, 311611, 311411,
                                    311421, 325193, and
                                    324110.
Subpart TT--Industrial Waste       322110, 322121, 322122,            1.1          16%          0.8          15%
 Landfills.                         322130, 311611, 311411,
                                    and 311421.
                                                             ---------------------------------------------------
    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%
----------------------------------------------------------------------------------------------------------------

C. What are the economic impacts of the rule?

1. Summary of Economic Impacts
    EPA prepared an economic analysis to evaluate the impacts of this 
rule on affected industries. To estimate the economic impacts, EPA 
first conducted a screening assessment, comparing the estimated total 
annualized compliance costs by industry, where industry is defined in 
terms of North American Industry Classification System (NAICS) code, 
with industry average revenues. Average cost-to-sales ratios for 
establishments in affected NAICS codes are typically less than 1 
percent.
    These low average cost-to-sales ratios indicate that the rule is 
unlikely to result in significant changes in firms' production 
decisions or other behavioral changes, and thus unlikely to result in 
significant changes in prices or quantities in affected markets. Thus, 
EPA followed its Guidelines for Preparing Economic Analyses (EPA, 2002, 
p. 124-125) and used the engineering cost estimates to measure the 
social cost of the rule, rather than modeling market responses and 
using the resulting measures of social cost. Table 4 of this preamble 
summarizes cost-to-sales ratios for affected industries.

[[Page 39754]]

                          Table 4--Estimated Cost-to-Sales Ratios for Affected Entities
                                               [First year, 2006$]
----------------------------------------------------------------------------------------------------------------
                                                                                   Average cost         All
           2007 NAICS                 NAICS description            Subpart        per entity  ($/   enterprises
                                                                                      entity)           (%)
----------------------------------------------------------------------------------------------------------------
331419..........................  Primary Smelting and      T                            $10,520             0.1
                                   Refining of Nonferrous
                                   Metal (except Copper
                                   and Aluminum).
331492..........................  Secondary Smelting,       T                             10,520             0.1
                                   Refining, and Alloying
                                   of Nonferrous Metal
                                   (except Copper and
                                   Aluminum).
212112..........................  Bituminous Coal           FF                            34,717             0.2
                                   Underground Mining.
322110..........................  Pulp Mills..............  TT                             5,583           < 0.1
322121..........................  Paper (except Newsprint)  TT                             5,583           < 0.1
                                   Mills.
322122..........................  Newsprint Mills.........  TT                             5,583           < 0.1
322130..........................  Paperboard Mills........  TT                             5,583           < 0.1
311611..........................  Animal (except Poultry)   TT                             5,583           < 0.1
                                   Slaughtering.
311411..........................  Frozen Fruit, Juice, and  TT                             5,583           < 0.1
                                   Vegetable Manufacturing.
311421..........................  Fruit and Vegetable       TT                             5,583           < 0.1
                                   Canning.
322110..........................  Pulp Mills..............  II                             4,235           < 0.1
322121..........................  Paper (except Newsprint)  II                             4,235           < 0.1
                                   Mills.
322122..........................  Newsprint Mills.........  II                             4,235           < 0.1
322130..........................  Paperboard Mills........  II                             4,235           < 0.1
311611..........................  Animal (except Poultry)   II                             3,963           < 0.1
                                   Slaughtering.
311411..........................  Frozen Fruit, Juice, and  II                             3,963           < 0.1
                                   Vegetable Manufacturing.
311421..........................  Fruit and Vegetable       II                             3,963           < 0.1
                                   Canning.
325193..........................  Ethyl Alcohol             II                             5,140           < 0.1
                                   Manufacturing.
324110..........................  Petroleum Refineries....  II                             3,963           < 0.1
----------------------------------------------------------------------------------------------------------------

D. What are the impacts of the rule on small businesses?

1. Summary of Impacts on Small Businesses
    As required by the RFA and SBREFA, EPA assessed the potential 
impacts of the rule on small entities (small businesses, governments, 
and non-profit organizations). (See Section V.C of this preamble for 
definitions of small entities).
    EPA conducted a screening assessment comparing compliance costs for 
affected industry sectors to industry-specific receipts data for 
establishments owned by small businesses. This ratio constitutes a 
``sales'' test that computes the annualized compliance costs of this 
rule as a percentage of sales and determines whether the ratio exceeds 
some level (e.g., 1 percent or 3 percent).
    The cost-to-sales ratios were constructed at the establishment 
level (average reporting program costs per establishment/average 
establishment receipts) for several business size ranges. This allowed 
EPA to account for receipt differences between establishments owned by 
large and small businesses and differences in small business 
definitions across affected industries. The results of the screening 
assessment are shown in Table 5 of this preamble.
    As shown, the cost-to-sales ratios are typically less than 1 
percent for establishments owned by small businesses that EPA considers 
most likely to be covered by the reporting program (e.g., 
establishments owned by businesses with 100 or more employees).

                                                 Table 5--Estimated Cost-To-Sales Ratios by Industry and Enterprise Size (First Year, 2006$) \a\
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                         Average                                      Owned by enterprises with:
                                                                 SBA size standard       cost per              -----------------------------------------------------------------------
      2007 NAICS           NAICS description       Subpart     (effective  August 22,     entity       All        1 to 20                                                    1,000 to
                                                                       2008)               ($/     enterprises   employees   20 to 99   100 to 499  500 to 749  750 to 999     1,499
                                                                                         entity)                    \b\      employees   employees   employees   employees   employees
--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
331419...............  Primary Smelting and              T   750 employees............    $10,520         0.1%        0.9%        0.2%        0.1%           D           D           D
                        Refining of Nonferrous
                        Metal (except Copper and
                        Aluminum).
331492...............  Secondary Smelting,               T   750 employees............    $10,520         0.1%        0.7%        0.1%        0.2%           D           D           D
                        Refining, and Alloying
                        of Nonferrous Metal
                        (except Copper and
                        Aluminum).
212112...............  Bituminous Coal                  FF   500 employees............    $34,717         0.2%        3.0%        3.4%        0.2%           D           D           D
                        Underground Mining.
322110...............  Pulp Mills...............        TT   750 employees............     $5,583        <0.1%        0.4%           D           D           D           D           D
322121...............  Paper (except Newsprint)         TT   750 employees............     $5,583        <0.1%           D        0.1%           D           D           D           D
                        Mills.

[[Page 39755]]

322122...............  Newsprint Mills..........        TT   750 employees............     $5,583        <0.1%           D           D           D          NA           D           D
322130...............  Paperboard Mills.........        TT   750 employees............     $5,583        <0.1%        1.1%        0.1%       <0.1%          NA           D           D
311611...............  Animal (except Poultry)          TT   500 employees............     $5,583        <0.1%        0.5%        0.1%       <0.1%           D           D       <0.1%
                        Slaughtering.
311411...............  Frozen Fruit, Juice, and         TT   500 employees............     $5,583        <0.1%        0.3%        0.1%       <0.1%       <0.1%           D       <0.1%
                        Vegetable Manufacturing.
311421...............  Fruit and Vegetable              TT   500 employees............     $5,583        <0.1%        0.4%        0.1%       <0.1%       <0.1%       <0.1%       <0.1%
                        Canning.
322110...............  Pulp Mills...............        II   750 employees............     $4,235        <0.1%        0.3%           D           D           D           D           D
322121...............  Paper (except Newsprint)         II   750 employees............     $4,235        <0.1%           D       <0.1%           D           D           D           D
                        Mills.
322122...............  Newsprint Mills..........        II   750 employees............     $4,235        <0.1%           D           D           D          NA           D           D
322130...............  Paperboard Mills.........        II   750 employees............     $4,235        <0.1%        0.8%       <0.1%       <0.1%          NA           D           D
311611...............  Animal (except Poultry)          II   500 employees............     $3,963        <0.1%        0.4%       <0.1%       <0.1%           D           D       <0.1%
                        Slaughtering.
311411...............  Frozen Fruit, Juice, and         II   500 employees............     $3,963        <0.1%        0.2%       <0.1%       <0.1%       <0.1%           D       <0.1%
                        Vegetable Manufacturing.
311421...............  Fruit and Vegetable              II   500 employees............     $3,963        <0.1%        0.3%       <0.1%       <0.1%       <0.1%       <0.1%       <0.1%
                        Canning.
325193...............  Ethyl Alcohol                    II   1,000 employees..........     $5,140        <0.1%           D           D           D           D          NA           D
                        Manufacturing.
324110...............  Petroleum Refineries.....        II   1,500 employees \c\......     $3,963        <0.1%        0.1%       <0.1%       <0.1%       <0.1%           D           D
331419...............  Primary Smelting and              T   750 employees............    $10,520         0.1%        0.9%        0.2%        0.1%           D           D           D
                        Refining of Nonferrous
                        Metal (except Copper and
                        Aluminum).
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Note: D denotes that receipt data was not disclosed. NA denotes that the enterprise category is not applicable (i.e., no enterprises were reported within this category). Receipt data in Table
  5-7 has been adjusted to 2006$ using the latest GDP implicit price deflator reported by the U.S. Bureau of Economic Analysis (103.257/92.118 = 1.121) http://www.bea.gov/national/nipaweb/
  Index.asp (accessed December 21, 2009).
\a\ The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise
  and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise--the enterprise employment and annual payroll are summed from the
  associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition above is
  consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
\b\ Excludes Statistics of U.S. Businesses (SUSB) employment category for zero employees. These entities only operated for a fraction of the year.
\c\ NAICS code 324110--in addition, the petroleum refiner must not have more than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes
  owned or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or a throughput. The total product to be delivered under the
  contract must be at least 90 percent refined by the successful bidder from either crude oil or bona fide feedstocks.

E. What are the benefits of the rule for society?

    EPA examined the potential benefits of 40 CFR part 98. EPA's 
previous analysis of 40 CFR part 98 discussed the benefits of a 
reporting system with respect to policy making relevance, transparency 
issues, and market efficiency. Instead of a quantitative analysis of 
the benefits, EPA conducted a systematic literature review of existing 
studies including government, consulting, and scholarly reports.
    A mandatory reporting system will benefit the public by increased 
transparency of facility emissions data. Transparent, public data on 
emissions allows for accountability of polluters to the public 
stakeholders who bear the cost of the pollution. Citizens, community 
groups, and labor unions have made use of data from Pollutant Release 
and Transfer Registers to negotiate directly with polluters to lower 
emissions, circumventing greater government regulation. Publicly 
available emissions data also will allow individuals to alter their 
consumption habits based on the GHG emissions of producers.
    The greatest benefit of mandatory reporting of industry GHG 
emissions to government will be realized in developing future GHG 
policies. For example, in the EU's Emissions Trading System, a lack of 
accurate monitoring at the facility level before establishing 
CO2 allowance permits resulted in allocation of permits for 
emissions levels an average of 15 percent above actual levels in every 
country except the United Kingdom.
    Benefits to industry of GHG emissions monitoring include the value 
of having independent, verifiable data to present

[[Page 39756]]

to the public to demonstrate appropriate environmental stewardship, and 
a better understanding of their emission levels and sources to identify 
opportunities to reduce emissions. Such monitoring allows for inclusion 
of standardized GHG data into environmental management systems, 
providing the necessary information to achieve and disseminate their 
environmental achievements.
    Standardization will also be a benefit to industry, once facilities 
invest in the institutional knowledge and systems to report emissions, 
the cost of monitoring should fall and the accuracy of the accounting 
should improve. A standardized reporting program will also allow for 
facilities to benchmark themselves against similar facilities to 
understand better their relative standing within their industry.

V. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) 
this action is a ``significant action'' because it raises novel legal 
or policy issues arising out of legal mandates, the President's 
priorities, or the principles set forth in the EO. Accordingly, EPA 
submitted this action to the Office of Management and Budget (OMB) for 
review under EO 12866 and any changes made in response to OMB 
recommendations have been documented in the docket for this action. In 
addition, EPA prepared an analysis of the potential costs and benefits 
associated with this action. This analysis is contained in the EIA, 
``Economic Impact Analysis for the Mandatory Reporting of Greenhouse 
Gas Emissions: Subparts: T, FF, II, and TT''. A copy of the analysis is 
available in the docket for this action (Docket Item EPA-HQ-OAR-2008-
0508-2313) and the analysis is briefly summarized here. EPA's cost 
analysis, presented in Section 4 of the EIA, estimates the total 
annualized cost of the rule will be approximately $7.0 million (in 
2006$) during the first year of the program and $5.5 million in 
subsequent years (including $0.3 million of programmatic costs to the 
Agency).

B. Paperwork Reduction Act

    The information collection requirements in this rule have been 
submitted for approval to the Office of Management and Budget (OMB) 
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
information collection requirements are not enforceable until OMB 
approves them.
    EPA plans to collect complete and accurate economy-wide data on 
facility-level GHG emissions. Accurate and timely information on GHG 
emissions is essential for informing future climate change policy 
decisions. Through data collected under this rule, EPA will gain a 
better understanding of the relative emissions of specific industries, 
and the distribution of emissions from individual facilities within 
those industries. The facility-specific data will also improve our 
understanding of the factors that influence GHG emission rates and 
actions that facilities are already taking to reduce emissions. 
Additionally, EPA will be able to track the trend of emissions from 
industries and facilities within industries over time, particularly in 
response to policies and potential regulations. The data collected by 
this rule will improve EPA's ability to formulate climate change policy 
options and to assess which industries would be affected, and how these 
industries would be affected by the options.
    This information collection is mandatory and will be carried out 
under CAA section 114. Information identified and marked as CBI will 
not be disclosed except in accordance with procedures set forth in 40 
CFR part 2. However, emissions data collected under CAA section 114 
cannot generally be claimed as CBI and will be made public.
    For these final subparts, the projected cost and hour burden for 
non-Federal respondents is $5.13 million and 66.0 million hours per 
year. The estimated average burden per response is 29.1 hours; the 
frequency of response is annual for all respondents that must comply 
with the rule's reporting requirements and the estimated average number 
of likely respondents per year is 683. The cost burden to respondents 
resulting from the collection of information includes the total capital 
cost annualized over the equipment's expected useful life (averaging 
$0.5 million), a total operation and maintenance component (averaging 
$1.6 million per year), and a labor cost component (averaging $3.6 
million per year).
    Burden is defined at 5 CFR 1320.3(b). These cost numbers differ 
from those shown elsewhere in the EIA for these subparts because the 
information collection request (ICR) costs represent the average cost 
over the first three years of the rule, but costs are reported 
elsewhere in the EIA for the subparts for the first year of the rule 
and for subsequent years of the rule. In addition, the ICR focuses on 
respondent burden, while the RIA for the final rule includes EPA Agency 
costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is 
approved by OMB, the Agency will publish a technical amendment to 40 
CFR part 9 in the Federal Register to display the OMB control number 
for the approved information collection requirements contained in this 
final rule.

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, a small entity is defined as a small business as defined by 
the Small Business Administration's regulations at 13 CFR 121.201; 
according to these size standards, criteria for determining if ultimate 
parent companies owning affected facilities are categorized as small 
vary by NAICS. Small entity criteria range from total number of 
employees at the firm fewer than 500 to number of employees fewer than 
1,500; one affected NAICS, 324110, the petroleum refiner must have no 
more than 1,500 employees nor more than 125,000 barrels per calendar 
day total Operable Atmospheric Crude Oil Distillation capacity. 
Capacity includes owned or leased facilities as well as facilities 
under a processing agreement or an arrangement such as an exchange 
agreement or a throughput. The total product to be delivered under the 
contract must be at least 90 percent refined by the successful bidder 
from either crude oil or bona fide feedstocks. EIA tables 5-10 and 5-11 
present small business criteria and enterprise size distribution data 
for affected NAICS.
    EPA assessed the potential impacts of the final rule on small 
entities using a sales test, defined as the ratio of total annualized 
compliance costs to firm sales. Details are provided in Section 5.3 of 
the EIA. These sales tests examine the average establishment's total 
annualized mandatory reporting costs to the average establishment 
receipts for enterprises

[[Page 39757]]

within several employment categories. The average entity costs used to 
compute the sales test are the same across all of these enterprise size 
categories. As a result, the sales-test will overstate the cost-to-
receipt ratio for establishments owned by small businesses, because the 
reporting costs are likely lower than average entity estimates provided 
by the engineering cost analysis.
    The results of the screening analysis show that for most NAICS, the 
costs are estimated to be less than 1 percent of sales in all firm size 
categories. For one NAICS (322130 Paperboard Mills), the costs exceed 1 
percent of sales for the 1-20 employee size category; for another NAICS 
(212112 Bituminous Coal Underground Mining), the costs exceed 1 percent 
of sales for the 1-20 and 20-100 employee size category. Previous 
``Regulatory Impact Analysis for the Mandatory Reporting of Greenhouse 
Gas Emissions'' (EPA-HQ-OAR-2008-0508) illustrated that pulp and paper 
industry enterprises with less than 20 employees were unlikely to be 
covered by the rule. For mining facilities, EPA's initial review of 
facility data suggests that mines owned by enterprises with less than 
100 employees would also be unlikely to be covered by the rule.
    After considering the economic impacts of today's final rule on 
small entities, I therefore certify that this final rule will not have 
a significant economic impact on a substantial number of small 
entities.
    Although this rule would not have a significant economic impact on 
a substantial number of small entities, the Agency nonetheless tried to 
reduce the impact of this rule on small entities, including seeking 
input from a wide range of private- and public-sector stakeholders. 
When developing the rule, the Agency took special steps to ensure that 
the burdens imposed on small entities were minimal. The Agency 
conducted several meetings with industry trade associations to discuss 
regulatory options and the corresponding burden on industry, such as 
recordkeeping and reporting. The Agency investigated alternative 
thresholds and analyzed the marginal costs associated with requiring 
smaller entities with lower emissions to report. The Agency also 
selected a hybrid method for reporting, which provides flexibility to 
entities and helps minimize reporting costs.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and Tribal 
governments and the private sector. Under Section 202 of the UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for final rules with ``Federal mandates'' that may result in 
expenditures to State, local, and Tribal governments, in the aggregate, 
or to the private sector, of $100 million or more in any one year.
    This final rule does not contain a Federal mandate that may result 
in expenditures of $100 million or more for State, local, and Tribal 
governments, in the aggregate, or the private sector in any one year. 
Overall, EPA estimates that the total annualized costs of this final 
rule are approximately $6.7 million in the first year, and $5.3 million 
per year in subsequent years. Thus, this final rule is not subject to 
the requirements of UMRA sections 202 or 205.
    This final rule is also not subject to the requirements of UMRA 
section 203 because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. None of the 
facilities currently known to undertake these activities are owned by 
small governments.

E. Executive Order 13132: Federalism

    These final subparts do not have federalism implications. They will 
not have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in EO 13132.
    Entities affected by these final subparts are facilities that 
directly emit GHGs. These final subparts do not apply to governmental 
entities unless the government entity owns a facility that directly 
emits GHGs above threshold levels such as a landfill or large 
stationary combustion source, so relatively few government facilities 
would be affected. This regulation also does not limit the power of 
States or localities to collect GHG data and/or regulate GHG emissions. 
Thus, EO 13132 does not apply to this rule.
    In the spirit of EO 13132, and consistent with EPA policy to 
promote communications between EPA and State and local governments, EPA 
specifically solicited comments on these subparts from State and local 
officials. For a discussion of outreach activities to State, local, or 
Tribal organizations, see Section IX of the preamble to the proposed 
rule (74 FR 16602).

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have Tribal implications, as specified in EO 
13175 (65 FR 67249, November 9, 2000). This regulation applies directly 
to facilities that directly emit GHGs. Facilities expected to be 
affected by these final subparts are not expected to be owned by Tribal 
governments. Thus, EO 13175 does not apply to this action.
    Although EO 13175 does not apply to these final subparts, EPA 
sought opportunities to provide information to Tribal governments and 
representatives during development of the proposed rule, which included 
these subparts being finalized today. See Section IX of the preamble to 
the proposed rule (74 FR 16602).

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

    EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying 
only to those regulatory actions that concern health or safety risks, 
such that the analysis required under section 5-501 of the EO has the 
potential to influence the regulation. This action is not subject to EO 
13045 because it does not establish an environmental standard intended 
to mitigate health or safety risks.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This action is not a ``significant energy action'' as defined in EO 
13211 (66 FR 28355 (May 22, 2001)), because it is not likely to have a 
significant adverse effect on the supply, distribution, or use of 
energy. Further, we have concluded that this rule is not likely to have 
any adverse energy effects. This rule relates to monitoring, reporting 
and recordkeeping at facilities that directly emit GHGs and does not 
impact energy supply, distribution or use. Therefore, we conclude that 
this rule is not likely to have any adverse effects on energy supply, 
distribution, or use.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business

[[Page 39758]]

practices) that are developed or adopted by voluntary consensus 
standards bodies. NTTAA directs EPA to provide Congress, through OMB, 
explanations when the Agency decides not to use available and 
applicable voluntary consensus standards.
    This rulemaking involves technical standards. For these final 
subparts, EPA has decided to use more than a dozen voluntary consensus 
standards from four different voluntary consensus standards bodies, 
including American Society for Testing and Materials (ASTM) and 
American Society for Mechanical Engineers (ASME).
    These voluntary consensus standards will help facilities monitor, 
report, and keep records of GHG emissions. No new test methods were 
developed for this rule. Instead, from existing rules for source 
categories and voluntary GHG programs, EPA identified existing means of 
monitoring, reporting, and keeping records of GHG emissions. The 
existing methods (voluntary consensus standards) include a broad range 
of measurement techniques, including methods to measure gas or liquid 
flow and methods to analyze gases by gas chromatography. All except 
three of these methods have already been incorporated by reference in 
the October 2009 Final Rule. Thus, we are adding entries to 40 CFR 98.7 
for new voluntary consensus standards and modifying the entries for 
other voluntary consensus standards to reflect their usage in these 
final subparts. Thus, the test methods are incorporated by reference 
into the final rule and are available as specified in 40 CFR 98.7.
    By incorporating voluntary consensus standards into the subparts, 
EPA is both meeting the requirements of the NTTAA and presenting 
multiple options and flexibility for measuring GHG emissions.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    EO 12898 (59 FR 7629 (Feb. 16, 1994)) establishes Federal executive 
policy on environmental justice. Its main provision directs Federal 
agencies, to the greatest extent practicable and permitted by law, to 
make environmental justice part of their mission by identifying and 
addressing, as appropriate, disproportionately high and adverse human 
health or environmental effects of their programs, policies, and 
activities on minority populations and low-income populations in the 
United States.
    EPA has determined that these final subparts will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment. These final subparts do not affect the level of protection 
provided to human health or the environment because they address 
information collection and reporting procedures.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 
generally provides that before a rule may take effect, the agency 
promulgating the rule must submit a rule report, which includes a copy 
of the rule, to each House of the Congress and to the Comptroller 
General of the United States. EPA will submit a report containing this 
rule and other required information to the U.S. Senate, the U.S. House 
of Representatives, and the Comptroller General of the U.S. prior to 
publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective September 10, 2010.

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure, 
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and 
recordkeeping requirements.

    Dated: June 28, 2010.
Lisa P. Jackson,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is amended as follows:

PART 98--[AMENDED]

0
1. The authority citation for part 98 continues to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

Subpart A--[Amended]

0
2. Section 98.1 is amended by revising paragraph (b) to read as 
follows:

Sec.  98.1  Purpose and Scope.

* * * * *
    (b) Owners and operators of facilities and suppliers that are 
subject to this part must follow the requirements of this subpart and 
all applicable subparts of this part. If a conflict exists between a 
provision in subpart A and any other applicable subpart, the 
requirements of the applicable subpart shall take precedence.

0
3. Section 98.2 is amended by revising paragraphs (a)(1), (a)(2), and 
(a)(4); and revising the third sentence of paragraph (i)(3) to read as 
follows:

Sec.  98.2  Who must report?

    (a) * * *
    (1) A facility that contains any source category that is listed in 
Table A-3 of this subpart in any calendar year starting in 2010. For 
these facilities, the annual GHG report must cover stationary fuel 
combustion sources (subpart C of this part), miscellaneous use of 
carbonates (subpart U of this part), and all applicable source 
categories listed in Table A-3 and Table A-4 of this subpart.
    (2) A facility that contains any source category that is listed in 
Table A-4 of this subpart that emits 25,000 metric tons CO2e or more 
per year in combined emissions from stationary fuel combustion units, 
miscellaneous uses of carbonate, and all applicable source categories 
that are listed in Table A-3 and Table A-4 of this subpart. For these 
facilities, the annual GHG report must cover stationary fuel combustion 
sources (subpart C of this part), miscellaneous use of carbonates 
(subpart U of this part), and all applicable source categories listed 
in Table A-3 and Table A-4 of this subpart.
* * * * *
    (4) A supplier that is listed in Table A-5 of this subpart. For 
these suppliers, the annual GHG report must cover all applicable 
products for which calculation methodologies are provided in the 
subparts listed in Table A-5 of this subpart.
* * * * *
    (i) * * *
    (3) * * * This paragraph (i)(3) does not apply to facilities with 
municipal solid waste landfills or industrial waste landfills, or to 
underground coal mines. * * *
* * * * *

0
4. Section 98.3 is amended by:
    a. Revising paragraph (b) introductory text.
    b. Removing and reserving paragraph (b)(1).
    c. Revising paragraphs (b)(2), (c)(4)(i), (c)(4)(ii), (c)(4)(iii) 
introductory text, (c)(7), and (i)(1) to read as follows.

Sec.  98.3  What are the general monitoring, reporting, recordkeeping 
and verification requirements of this part?

* * * * *
    (b) Schedule. The annual GHG report must be submitted no later than 
March

[[Page 39759]]

31 of each calendar year for GHG emissions in the previous calendar 
year. As an example, for a facility that is subject to the rule in 
calendar year 2010, the first report must be submitted on March 31, 
2011.
    (1) [Reserved]
    (2) For a new facility or supplier that begins operation on or 
after January 1, 2010 and becomes subject to the rule in the year that 
it becomes operational, report emissions beginning with the first 
operating month and ending on December 31 of that year. Each subsequent 
annual report must cover emissions for the calendar year, beginning on 
January 1 and ending on December 31.
* * * * *
    (c) * * *
    (4) * * *
    (i) Annual emissions (excluding biogenic CO2) aggregated 
for all GHG from all applicable source categories listed in Tables A-3 
and Table A-4 of this subpart and expressed in metric tons of 
CO2e calculated using Equation A-1 of this subpart.
    (ii) Annual emissions of biogenic CO2 aggregated for all 
applicable source categories in listed in Tables A-3 and Table A-4 of 
this subpart.
    (iii) Annual emissions from each applicable source category listed 
in Tables A-3 and Table A-4 of this subpart, expressed in metric tons 
of each GHG listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) 
of this section.
* * * * *
    (7) A brief description of each ``best available monitoring 
method'' used according to paragraph (d) of this section, the parameter 
measured using the method, and the time period during which the ``best 
available monitoring method'' was used, if applicable.
* * * * *
    (i) * * *
    (1) Except as provided in paragraphs (i)(4) through (i)(6) of this 
section, flow meters and other devices (e.g., belt scales) that measure 
data used to calculate GHG emissions shall be calibrated using the 
procedures specified in this paragraph and each relevant subpart of 
this part. All measurement devices must be calibrated according to the 
manufacturer's recommended procedures, an appropriate industry 
consensus standard, or a method specified in a relevant subpart of this 
part. All measurement devices shall be calibrated to an accuracy of 5 
percent. For facilities and suppliers that are subject to this part on 
January 1, 2010, the initial calibration shall be conducted by April 1, 
2010. For facilities and suppliers that become subject to this part 
after April 1, 2010, the initial calibration shall be conducted by the 
date that data collection is required to begin. Subsequent calibrations 
shall be performed at the frequency specified in each applicable 
subpart.
* * * * *

0
5. Section 98.6 is amended by revising the definition of ``anaerobic 
lagoon'' and adding definitions for ``Cement kiln dust,'' 
``Degasification system,'' ``Destruction device,'' ``Furnace slag,'' 
``Liberated,'' ``Municipal wastewater treatment plant,'' ``Ventilation 
well or shaft,'' ``Ventilation system,'' and ``Working capacity.''

Sec.  98.6  Definitions.

* * * * *
    Anaerobic lagoon, with respect to subpart JJ of this part, means a 
type of liquid storage system component that is designed and operated 
to stabilize wastes using anaerobic microbial processes. Anaerobic 
lagoons may be designed for combined stabilization and storage with 
varying lengths of retention time (up to a year or greater), depending 
on the climate region, volatile solids loading rate, and other 
operational factors.
* * * * *
    Cement kiln dust means non-calcined to fully calcined dust produced 
in the kiln or pyroprocessing line. Cement kiln dust is a fine-grained, 
solid, highly alkaline material removed from the cement kiln exhaust 
gas by scrubbers (filtration baghouses and/or electrostatic 
precipitators).
* * * * *
    Degasification system means the entirety of the equipment that is 
used to drain gas from underground and collect it at a common point, 
such as a vacuum pumping station. This includes all degasification 
wells and gob gas vent holes at the underground coal mine. 
Degasification systems include surface pre-mining, horizontal pre-
mining, and post-mining systems.
* * * * *
    Destruction device, for the purposes of subparts II and TT of this 
part, means a flare, thermal oxidizer, boiler, turbine, internal 
combustion engine, or any other combustion unit used to destroy or 
oxidize methane contained in landfill gas or wastewater biogas.
* * * * *
    Furnace slag means a by-product formed in metal melting furnaces 
when slagging agents, reducing agents, and/or fluxes (e.g., coke ash, 
limestone, silicates) are added to remove impurities from the molten 
metal.
* * * * *
    Liberated means released from coal and surrounding rock strata 
during the mining process. This includes both methane emitted from the 
ventilation system and methane drained from degasification systems.
* * * * *
    Municipal wastewater treatment plant means a series of treatment 
processes used to remove contaminants and pollutants from domestic, 
business, and industrial wastewater collected in city sewers and 
transported to a centralized wastewater treatment system such as a 
publicly owned treatment works (POTW).
* * * * *
    Ventilation well or shaft means a well or shaft employed at an 
underground coal mine to serve as the outlet or conduit to move air 
from the ventilation system out of the mine.
    Ventilation system means a system that is used to control the 
concentration of methane and other gases within mine working areas 
through mine ventilation, rather than a mine degasification system. A 
ventilation system consists of fans that move air through the mine 
workings to dilute methane concentrations. This includes all 
ventilation shafts and wells at the underground coal mine.
* * * * *
    Working capacity, for the purposes of subpart TT of this part, 
means the maximum volume or mass of waste that is actually placed in 
the landfill from an individual or representative type of container 
(such as a tank, truck, or roll-off bin) used to convey wastes to the 
landfill, taking into account that the container may not be able to be 
100 percent filled and/or 100 percent emptied for each load.
* * * * *

0
6. Section 98.7 is amended by:
0
a. Revising paragraphs (d)(1) through (d)(5), and (d)(7) through 
(d)(10).
0
b. Revising paragraphs (e)(10), (e)(11), (e)(25), and (e)(42).
0
c. Adding paragraphs (e)(43) and (e)(44).
0
d. Revising paragraph (f)(2).
0
e. Adding paragraphs (k) through (m).

Sec.  98.7  What standardized methods are incorporated by reference 
into this part?

* * * * *
    (d) * * *
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved 
for Sec.  98.34(b), Sec.  98.244(b),

[[Page 39760]]

Sec.  98.254(c), Sec.  98.324(e), Sec.  98.344(c), Sec.  98.354(d), 
Sec.  98.354(h), and Sec.  98.364(e).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters, IBR approved for Sec.  98.34(b), Sec.  98.244(b), Sec.  
98.254(c), Sec.  98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  
98.364(e).
    (3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR 
approved for Sec.  98.34(b) and Sec.  98.244(b), and Sec.  98.354(d).
    (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters, IBR approved for Sec.  98.34(b), Sec.  98.244(b), 
Sec.  98.254(c), Sec.  98.324(e), Sec.  98.344(c), Sec.  98.354(h), and 
Sec.  98.364(e).
    (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles, IBR approved for Sec.  
98.34(b), Sec.  98.244(b), Sec.  98.254(c), Sec.  98.324(e), Sec.  
98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
* * * * *
    (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters, IBR approved for Sec.  98.244(b), Sec.  
98.254(c), Sec.  98.324(e), Sec.  98.344(c), and Sec.  98.354(h).
    (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters, IBR approved for Sec.  98.244(b), Sec.  
98.254(c), Sec.  98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  
98.364(e).
    (9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits 
with Electromagnetic Flowmeters, IBR approved for Sec.  98.244(b) and 
Sec.  98.354(d).
    (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable 
Area Meters, IBR approved for Sec.  98.244(b), Sec.  98.254(c), Sec.  
98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
* * * * *
    (e) * * *
    (10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography, IBR approved for Sec.  98.34(b), Sec.  98.74(c), 
Sec.  98.164(b), Sec.  98.324(d), Sec.  98.244(b), Sec.  98.254(d), 
Sec.  98.344(b), and Sec.  98.354(g).
    (11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography, IBR approved for Sec.  98.34(b), 
Sec.  98.74(c), Sec.  98.164(b), Sec.  98.254(d), Sec.  98.324(d), 
Sec.  98.344(b), Sec.  98.354(g), and Sec.  98.364(c).
* * * * *
    (25) ASTM D4891-89 (Reapproved 2006), Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion, IBR approved for Sec.  98.34(a), Sec.  98.254(e), and Sec.  
98.324(d).
* * * * *
    (42) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography, 
IBR approved for Sec.  98.164(b), Sec.  98.244(b), Sec.  98.254(d), 
Sec.  98.324(d), Sec.  98.344(b), and Sec.  98.354(g).
    (43) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open 
Channel Flow Measurement of Water with the Parshall Flume, approved 
June 15, 2007, IBR approved for Sec.  98.354(d).
    (44) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open 
Channel Flow Measurement of Water with Broad-Crested Weirs, approved 
October 1, 2008, IBR approved for Sec.  98.354(d).
    (f) * * *
    (2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography, IBR approved for Sec.  98.34(a), Sec.  
98.164(b), Sec.  98.254(d), Sec.  98.344(b), and Sec.  98.354(g).
* * * * *
    (k) The following material is available for purchase from Standard 
Methods, at http://www.standardmethods.org, (877) 574-1233; or, through 
a joint publication agreement from the American Public Health 
Association (APHA), P.O. Box 933019, Atlanta, GA 31193-3019, (888) 320-
APHA (2742), http://www.apha.org/publications/pubscontact/.
    (1) Method 2540G Total, Fixed, and Volatile Solids in Solid and 
Semisolid Samples, IBR approved for Sec.  98.464(b).
    (2) [Reserved]
    (l) The following material is available from the U.S. Department of 
Labor, Mine Safety and Health Administration, 1100 Wilson Boulevard, 
21st Floor, Arlington, VA 22209-3939, (202) 693-9400, http://
www.msha.gov.
    (1) General Coal Mine Inspection Procedures and Inspection Tracking 
System, Handbook Number: PH-08-V-1, January 1, 2008, IBR approved for 
Sec.  98.324(b).
    (2) [Reserved]
    (m) The following material is available from the U.S. Environmental 
Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, 
(202) 272-0167, http://www.epa.gov.
    (1) NPDES Compliance Inspection Manual, Chapter 5, Sampling, EPA 
305-X-04-001, July 2004, http://www.epa.gov/compliance/monitoring/
programs/cwa/npdes.html, IBR approved for Sec.  98.354(c).
    (2) U.S. EPA NPDES Permit Writers' Manual, Section 7.1.3, Sample 
Collection Methods, EPA 833-B-96-003, December 1996, http://
www.epa.gov/npdes/pubs/owm0243.pdf, IBR approved for Sec.  98.354(c).

0
7. Add Tables A-3, A-4, and A-5 to Subpart A to read as follows:

   Table A-3 to Subpart A--Source Category List for Sec.   98.2(a)(1)
------------------------------------------------------------------------

-------------------------------------------------------------------------
Source Categories\a\ Applicable in 2010 and Future Years
    Electricity generation units that report CO2 mass emissions year
     round through 40 CFR part 75 (subpart D).
    Adipic acid production (subpart E).
    Aluminum production (subpart F).
    Ammonia manufacturing (subpart G).
    Cement production (subpart H).
    HCFC-22 production (subpart O).
    HFC-23 destruction processes that are not collocated with a HCFC-22
     production facility and that destroy more than 2.14 metric tons of
     HFC-23 per year (subpart O).
    Lime manufacturing (subpart S).
    Nitric acid production (subpart V).
    Petrochemical production (subpart X).
    Petroleum refineries (subpart Y).
    Phosphoric acid production (subpart Z).
    Silicon carbide production (subpart BB).
    Soda ash production (subpart CC).
    Titanium dioxide production (subpart EE).
    Municipal solid waste landfills that generate CH4 in amounts
     equivalent to 25,000 metric tons CO2e or more per year, as
     determined according to subpart HH of this part.

[[Page 39761]]

    Manure management systems with combined CH4 and N2O emissions in
     amounts equivalent to 25,000 metric tons CO2e or more per year, as
     determined according to subpart JJ of this part.
Additional Source Categories \a\ Applicable in 2011 and Future Years
    Underground coal mines that are subject to quarterly or more
     frequent sampling by Mine Safety and Health Administration (MSHA)
     of ventilation systems (subpart FF).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.

   Table A-4 to Subpart A--Source Category List for Sec.   98.2(a)(2)
------------------------------------------------------------------------

-------------------------------------------------------------------------
Source Categories \a\ Applicable in 2010 and Future Years
    Ferroalloy production (subpart K).
    Glass production (subpart N).
    Hydrogen production (subpart P).
    Iron and steel production (subpart Q).
    Lead production (subpart R).
    Pulp and paper manufacturing (subpart AA).
    Zinc production (subpart GG).
Additional Source Categories \a\ Applicable in 2011 and Future Years
    Magnesium production (subpart T).
    Industrial wastewater treatment (subpart II).
    Industrial waste landfills (subpart TT).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.

  Table A-5 to Subpart A--Supplier Category List for Sec.   98.2(a)(4)
------------------------------------------------------------------------

-------------------------------------------------------------------------
Supplier Categories \a\ Applicable in 2010 and Future Years
    Coal-to-liquids suppliers (subpart LL):
        (A) All producers of coal-to-liquid products.
        (B) Importers of an annual quantity of coal-to-liquid products
         that is equivalent to 25,000 metric tons CO2e or more.
        (C) Exporters of an annual quantity of coal-to-liquid products
         that is equivalent to 25,000 metric tons CO2e or more.
    Petroleum product suppliers (subpart MM):
        (A) All petroleum refineries that distill crude oil.
        (B) Importers of an annual quantity of petroleum products that
         is equivalent to 25,000 metric tons CO2e or more.
        (C) Exporters of an annual quantity of petroleum products that
         is equivalent to 25,000 metric tons CO2e or more.
    Natural gas and natural gas liquids suppliers (subpart NN):
        (A) All fractionators.
        (B) All local natural gas distribution companies.
    Industrial greenhouse gas suppliers (subpart OO):
        (A) All producers of industrial greenhouse gases.
        (B) Importers of industrial greenhouse gases with annual bulk
         imports of N2O, fluorinated GHG, and CO2 that in combination
         are equivalent to 25,000 metric tons CO2e or more.
        (C) Exporters of industrial greenhouse gases with annual bulk
         exports of N2O, fluorinated GHG, and CO2 that in combination
         are equivalent to 25,000 metric tons CO2e or more.
    Carbon dioxide suppliers (subpart PP):
        (A) All producers of CO2.
        (B) Importers of CO2 with annual bulk imports of N2O,
         fluorinated GHG, and CO2 that in combination are equivalent to
         25,000 metric tons CO2e or more.
        (C) Exporters of CO2 with annual bulk exports of N2O,
         fluorinated GHG, and CO2 that in combination are equivalent to
         25,000 metric tons CO2e or more.
Additional Supplier Categories Applicable \a\ in 2011 and Future Years
    (Reserved)
------------------------------------------------------------------------
\a\ Suppliers are defined in each applicable subpart.

0
8. Add subpart T to read as follows:
Subpart T--Magnesium Production
Sec.
98.200 Definition of source category.
98.201 Reporting threshold.
98.202 GHGs to report.
98.203 Calculating GHG emissions.
98.204 Monitoring and QA/QC requirements.
98.205 Procedures for estimating missing data.
98.206 Data reporting requirements.
98.207 Records that must be retained.
98.208 Definitions.

Subpart T--Magnesium Production

Sec.  98.200  Definition of source category.

    The magnesium production and processing source category consists of 
the following processes:
    (a) Any process in which magnesium metal is produced through 
smelting (including electrolytic smelting), refining, or remelting 
operations.
    (b) Any process in which molten magnesium is used in alloying, 
casting, drawing, extruding, forming, or rolling operations.

Sec.  98.201  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a magnesium production process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (2).

Sec.  98.202  GHGs to report.

    (a) You must report emissions of the following gases in metric tons 
per year resulting from their use as cover gases or carrier gases in 
magnesium production or processing:
    (1) Sulfur hexafluoride (SF6).
    (2) HFC-134a.

[[Page 39762]]

    (3) The fluorinated ketone, FK 5-1-12.
    (4) Carbon dioxide (CO2).
    (5) Any other GHGs (as defined in Sec.  98.6).
    (b) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the CO2, N2O, 
and CH4 emissions from each combustion unit by following the 
requirements of subpart C.

Sec.  98.203  Calculating GHG emissions.

    (a) Calculate the mass of each GHG emitted from magnesium 
production or processing over the calendar year using either Equation 
T-1 or Equation T-2 of this section, as appropriate. Both of these 
equations equate emissions of cover gases or carrier gases to 
consumption of cover gases or carrier gases.
    (1) To estimate emissions of cover gases or carrier gases by 
monitoring changes in container masses and inventories, emissions of 
each cover gas or carrier gas shall be estimated using Equation T-1 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR12JY10.000

Where:

Ex = Emissions of each cover gas or carrier gas, X, in 
metric tons over the reporting year.
IB,x = Inventory of each cover gas or carrier gas stored 
in cylinders or other containers at the beginning of the year, 
including heels, in kg.
IE,x = Inventory of each cover gas or carrier gas stored 
in cylinders or other containers at the end of the year, including 
heels, in kg.
Ax = Acquisitions of each cover gas or carrier gas during 
the year through purchases or other transactions, including heels in 
cylinders or other containers returned to the magnesium production 
or processing facility, in kg.
Dx = Disbursements of each cover gas or carrier gas to 
sources and locations outside the facility through sales or other 
transactions during the year, including heels in cylinders or other 
containers returned by the magnesium production or processing 
facility to the gas supplier, in kg.
0.001 = Conversion factor from kg to metric tons
X = Each cover gas or carrier gas that is a GHG.

    (2) To estimate emissions of cover gases or carrier gases by 
monitoring changes in the masses of individual containers as their 
contents are used, emissions of each cover gas or carrier gas shall be 
estimated using Equation T-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR12JY10.001

Where:

EGHG = Emissions of each cover gas or carrier gas, X, 
over the reporting year (metric tons).
Qp = The mass of the cover or carrier gas consumed (kg) 
over the container-use period p, from Equation T-3 of this section.
n = The number of container-use periods in the year.
0.001 = Conversion factor from kg to metric tons.
X = Each cover gas or carrier gas that is a GHG.

    (b) For purposes of Equation T-2 of this section, the mass of the 
cover gas used over the period p for an individual container shall be 
estimated by using Equation T-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR12JY10.002

Where:

Qp = The mass of the cover or carrier gas consumed (kg) 
over the container-use period p (e.g., one month).
MB = The mass of the container's contents (kg) at the 
beginning of period p.
ME = The mass of the container's contents (kg) at the end 
of period p.
    (c) If a facility has mass flow controllers (MFC) and the capacity 
to track and record MFC measurements to estimate total gas usage, the 
mass of each cover or carrier gas monitored may be used as the mass of 
cover or carrier gas consumed (Qp), in kg for period p in 
Equation T-2 of this section.

Sec.  98.204  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, the facility may submit a 
request to the Administrator to use one or more best available 
monitoring methods as listed in Sec.  98.3(d)(1)(i) through (iv). The 
request must be submitted no later than October 12, 2010 and must 
contain the information in Sec.  98.3(d)(2)(ii). To obtain approval, 
the request must demonstrate to the Administrator's satisfaction that 
it is not reasonably feasible to acquire, install, and operate a 
required piece of monitoring equipment by January 1, 2011. The use of 
best available monitoring methods will not be approved beyond December 
31, 2011.
    (b) Emissions (consumption) of cover gases and carrier gases may be 
estimated by monitoring the changes in container weights and 
inventories using Equation T-1 of this subpart, by monitoring the 
changes in individual container weights as the contents of each 
container are used using Equations T-2 and T-3 of this subpart, or by 
monitoring the mass flow of the pure cover gas or carrier gas into the 
gas distribution system. Emissions must be estimated at least annually.
    (c) When estimating emissions by monitoring the mass flow of the 
pure cover gas or carrier gas into the gas distribution system, you 
must use gas flow meters, or mass flow controllers, with an accuracy of 
1 percent of full scale or better.
    (d) When estimating emissions using Equation T-1 of this subpart, 
you must ensure that all the quantities required by Equation T-1 of 
this subpart have been measured using scales or load cells with an 
accuracy of 1 percent of full scale or better, accounting for the tare 
weights of the containers. You may accept gas masses or weights 
provided by the gas supplier e.g., for the contents of containers 
containing new gas or for the heels remaining in containers returned to 
the gas supplier) if the supplier provides documentation verifying that 
accuracy standards are met; however you remain responsible for the 
accuracy of these masses or weights under this subpart.
    (e) When estimating emissions using Equations T-2 and T-3 of this 
subpart, you must monitor and record container identities and masses as 
follows:
    (1) Track the identities and masses of containers leaving and 
entering storage with check-out and check-in sheets and procedures. The 
masses of cylinders returning to storage shall be measured immediately 
before the cylinders are put back into storage.
    (2) Ensure that all the quantities required by Equations T-2 and T-
3 of this subpart have been measured using scales or load cells with an 
accuracy of 1 percent of full scale or better, accounting for the tare 
weights of the containers. You may accept gas masses or weights 
provided by the gas supplier e.g., for the contents of cylinders 
containing new gas or for the heels remaining in cylinders returned to 
the gas supplier) if the supplier provides documentation verifying that 
accuracy standards are met; however, you remain responsible for the 
accuracy of these masses or weights under this subpart.

[[Page 39763]]

    (f) All flowmeters, scales, and load cells used to measure 
quantities that are to be reported under this subpart shall be 
calibrated using calibration procedures specified by the flowmeter, 
scale, or load cell manufacturer. Calibration shall be performed prior 
to the first reporting year. After the initial calibration, 
recalibration shall be performed at the minimum frequency specified by 
the manufacturer.

Sec.  98.205  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emission calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter will be used in the calculations as 
specified in paragraph (b) of this section.
    (b) Replace missing data on the emissions of cover or carrier gases 
by multiplying magnesium production during the missing data period by 
the average cover or carrier gas usage rate from the most recent period 
when operating conditions were similar to those for the period for 
which the data are missing. Calculate the usage rate for each cover or 
carrier gas using Equation T-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR12JY10.003

Where:

RGHG = The usage rate for a particular cover or carrier 
gas over the period of comparable operation (metric tons gas/metric 
ton Mg).
CGHG = The consumption of that cover or carrier gas over 
the period of comparable operation (kg).
Mg = The magnesium produced or fed into the process over the period 
of comparable operation (metric tons).
0.001 = Conversion factor from kg to metric tons.

    (c) If the precise before and after weights are not available, it 
should be assumed that the container was emptied in the process (i.e., 
quantity purchased should be used, less heel).

Sec.  98.206  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must include the following information at the facility 
level:
    (a) Emissions of each cover or carrier gas in metric tons.
    (b) Types of production processes at the facility (e.g., primary, 
secondary, die casting).
    (c) Amount of magnesium produced or processed in metric tons for 
each process type. This includes the output of primary and secondary 
magnesium production processes and the input to magnesium casting 
processes.
    (d) Cover and carrier gas flow rate (e.g., standard cubic feet per 
minute) for each production unit and composition in percent by volume.
    (e) For any missing data, you must report the length of time the 
data were missing for each cover gas or carrier gas, the method used to 
estimate emissions in their absence, and the quantity of emissions 
thereby estimated.
    (f) The annual cover gas usage rate for the facility for each cover 
gas, excluding the carrier gas (kg gas/metric ton Mg).
    (g) If applicable, an explanation of any change greater than 30 
percent in the facility's cover gas usage rate (e.g., installation of 
new melt protection technology or leak discovered in the cover gas 
delivery system that resulted in increased emissions).
    (h) A description of any new melt protection technologies adopted 
to account for reduced or increased GHG emissions in any given year.

Sec.  98.207  Records that must be retained.

    In addition to the records specified in Sec.  98.3(g), you must 
retain the following information at the facility level:
    (a) Check-out and weigh-in sheets and procedures for gas cylinders.
    (b) Accuracy certifications and calibration records for scales 
including the method or manufacturer's specification used for 
calibration.
    (c) Residual gas amounts (heel) in cylinders sent back to 
suppliers.
    (d) Records, including invoices, for gas purchases, sales, and 
disbursements for all GHGs.

Sec.  98.208  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part. Additionally, some sector-
specific definitions are provided below:
    Carrier gas means the gas with which cover gas is mixed to 
transport and dilute the cover gas thus maximizing its efficient use. 
Carrier gases typically include CO2, N2, and/or 
dry air.
    Cover gas means SF6, HFC-134a, fluorinated ketone (FK 5-
1-12) or other gas used to protect the surface of molten magnesium from 
rapid oxidation and burning in the presence of air. The molten 
magnesium may be the surface of a casting or ingot production operation 
or the surface of a crucible of molten magnesium that feeds a casting 
operation.

0
9. Add subpart FF to read as follows:

Subpart FF--Underground Coal Mines

Sec.
98.320 Definition of the source category.
98.321 Reporting threshold.
98.322 GHGs to report.
98.323 Calculating GHG emissions.
98.324 Monitoring and QA/QC requirements.
98.325 Procedures for estimating missing data.
98.326 Data reporting requirements.
98.327 Records that must be retained.
98.328 Definitions.

Sec.  98.320  Definition of the source category.

    (a) This source category consists of active underground coal mines, 
and any underground mines under development that have operational pre-
mining degasification systems. An underground coal mine is a mine at 
which coal is produced by tunneling into the earth to the coalbed, 
which is then mined with underground mining equipment such as cutting 
machines and continuous, longwall, and shortwall mining machines, and 
transported to the surface. Underground coal mines are categorized as 
active if any one of the following five conditions apply:
    (1) Mine development is underway.
    (2) Coal has been produced within the last 90 days.
    (3) Mine personnel are present in the mine workings.
    (4) Mine ventilation fans are operative.
    (5) The mine is designated as an ''intermittent'' mine by the Mine 
Safety and Health Administration (MSHA).
    (b) This source category includes the following:
    (1) Each ventilation well or shaft, including both those wells and 
shafts where gas is emitted and those where gas is sold, used onsite, 
or otherwise destroyed (including by flaring).
    (2) Each degasification system well or shaft, including 
degasification systems deployed before, during, or after mining 
operations are conducted in a mine area. This includes both those wells 
and shafts where gas is emitted, and those where gas is sold, used 
onsite, or otherwise destroyed (including by flaring).
    (c) This source category does not include abandoned or closed 
mines, surface coal mines, or post-coal mining activities (e.g., 
storage or transportation of coal).

Sec.  98.321  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an active underground coal mine and the facility meets the 
requirements of Sec.  98.2(a)(1).

Sec.  98.322  GHGs to report.

    (a) You must report CH4 liberated from ventilation and 
degasification systems.

[[Page 39764]]

    (b) You must report CH4 destruction from systems where 
gas is sold, used onsite, or otherwise destroyed (including by 
flaring).
    (c) You must report net CH4 emissions from ventilation 
and degasification systems.
    (d) You must report under this subpart the CO2 emissions 
from coal mine gas CH4 destruction occuring at the facility, 
where the gas is not a fuel input for energy generation or use (e.g., 
flaring).
    (e) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the CO2, CH4, 
and N2O emissions from each stationary fuel combustion unit 
by following the requirements of subpart C. Report emissions from both 
the combustion of collected coal mine CH4 and any other 
fuels.
    (f) An underground coal mine that is subject to this part because 
emissions from source categories described in subparts C through PP of 
this part is not required to report emissions under subpart FF of this 
part unless the coal mine is subject to quarterly or more frequent 
sampling of ventilation systems by MSHA.

Sec.  98.323  Calculating GHG emissions.

    (a) For each ventilation shaft, vent hole, or centralized point 
into which CH4 from multiple shafts and/or vent holes are 
collected, you must calculate the quarterly CH4 liberated 
from the ventilation system using Equation FF-1 of this section. You 
must measure CH4 content, flow rate, temperature, pressure, 
and moisture content of the gas using the procedures outlined in Sec.  
98.324.
[GRAPHIC] [TIFF OMITTED] TR12JY10.004

Where:

CH4V = Quarterly CH4 liberated from a 
ventilation monitoring point (metric tons CH4).
V = Daily volumetric flow rate for the quarter (scfm) based on 
sampling or a flow rate meter. If a flow rate meter is used and the 
meter automatically corrects for temperature and pressure, replace 
``520 [deg]R/T x P/1 atm'' with ``1''.
MCF = Moisture correction factor for the measurement period, 
volumetric basis.
    = 1 when V and C are measured on a dry basis or if both are 
measured on a wet basis.
    = 1-(fH2O)n when V is measured 
on a wet basis and C is measured on a dry basis.
    = 1/[1-(fH2O)] when V is measured on a dry 
basis and C is measured on a wet basis.
(fH2O) = Moisture content of the methane 
emitted during the measurement period, volumetric basis (cubic feet 
water per cubic feet emitted gas).
C = Daily CH4 concentration of ventilation gas for the 
quarter (%, wet basis).
n = The number of days in the quarter where active ventilation of 
mining operations is taking place at the monitoring point.
0.0423 = Density of CH4 at 520 [deg]R (60 [deg]F) and 1 
atm (lb/scf).
520 [deg]R = 520 degrees Rankine.
T = Temperature at which flow is measured ([deg]R) for the quarter.
P = Pressure at which flow is measured (atm) for the quarter.
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/lb).

    (1) Consistent with MSHA inspections, the quarterly periods are:
    (i) January 1-March 31.
    (ii) April 1-June 30.
    (iii) July 1-September 30.
    (iv) October 1-December 31.
    (2) Daily values of V, MCF, C, T, and P must be based on 
measurements taken at least once each quarter with no fewer than 6 
weeks between measurements. If measurements are taken more frequently 
than once per quarter, then use the average value for all measurements 
taken. If continous measurements are taken, then use the average value 
over the time period of continuous monitoring.
    (3) If a facility has more than one monitoring point, the facility 
must calculate total CH4 liberated from ventilation systems 
(CH4VTotal) as the sum of the CH4 from all 
ventilation monitoring points in the mine, as follows:
[GRAPHIC] [TIFF OMITTED] TR12JY10.005

Where:

CH4VTotal = Total quarterly CH4 liberated from 
ventilation systems (metric tons CH4).
CH4V = Quarterly CH4 liberated from each 
ventilation monitoring point (metric tons CH4).
m = Number of ventilation monitoring points.

    (b) For each monitoring point in the degasification system (this 
could be at each degasification well and/or vent hole, or at more 
centralized points into which CH4 from multiple wells and/or 
vent holes are collected), you must calculate the weekly CH4 
liberated from the mine using CH4 measured weekly or more 
frequently (including by CEMS) according to 98.234(c), CH4 
content, flow rate, temperature, pressure, and moisture content, and 
Equation FF-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.006

Where:
CH4D = Weekly CH4 liberated from at the 
monitoring point (metric tons CH4).
Vi = Daily measured total volumetric flow rate for the 
days in the week when the degasification system is in operation at 
that monitoring point, based on sampling or a flow rate meter 
(scfm). If a flow rate meter is used and the meter automatically 
corrects for temperature and pressure, replace ``520 [deg]R/
Ti x Pi/1 atm'' with ``1''.
MCFi = Moisture correction factor for the measurement 
period, volumetric basis.
    = 1 when Vi and Ci are measured on a dry 
basis or if both are measured on a wet basis.
    = 1-(fH2O)i when Vi is measured 
on a wet basis and Ci is measured on a dry basis.

    = 1/[1-(fH2O)i] when Vi is 
measured on a dry basis and Ci is measured on a wet 
basis.
(fH2O) = Moisture content of the CH4 emitted 
during the measurement period, volumetric basis (cubic feet water 
per cubic feet emitted gas)
Ci = Daily CH4 concentration of gas for the 
days in the week when the degasification system is in operation at 
that monitoring point (%, wet basis).
n = The number of days in the week that the system is operational at 
that measurement point.
0.0423 = Density of CH4 at 520 [deg]R (60 [deg]F) and 1 
atm (lb/scf).
520 [deg]R = 520 degrees Rankine.

[[Page 39765]]

Ti = Daily temperature at which flow is measured 
([deg]R).
Pi = Daily pressure at which flow is measured (atm).
1,440 = Conversion factor (minutes/day).
0.454/1,000 = Conversion factor (metric ton/lb).

    (1) Daily values for V, MCF, C, T, and P must be based on 
measurements taken at least once each calendar with at least 3 days 
between measurements. If measurements are taken more frequently than 
once per week, then use the average value for all measurements taken 
that week. If continuous measurements are taken, then use the average 
values over the time period of continuous monitoring when the 
continuous monitoring equipment is properly functioning.
    (2) Quarterly total CH4 liberated from degasification 
systems for the mine should be determined as the sum of CH4 
liberated determined at each of the monitoring points in the mine, 
summed over the number of weeks in the quarter, as follows:
[GRAPHIC] [TIFF OMITTED] TR12JY10.007

Where:
CH4DTotal = Quarterly CH4 liberated from all 
degasification monitoring points (metric tons CH4).
CH4D = Weekly CH4 liberated from a 
degasification monitoring point (metric tons CH4).
m = Number of monitoring points.
w = Number of weeks in the quarter during which the degasification 
system is operated.
    (c) If gas from degasification system wells or ventilation shafts 
is sold, used onsite, or otherwise destroyed (including by flaring), 
you must calculate the quarterly CH4 destroyed for each 
destruction device and each point of offsite transport to a destruction 
device, using Equation FF-5 of this section. You must measure 
CH4 content and flow rate according to the provisions in 
Sec.  98.324.
[GRAPHIC] [TIFF OMITTED] TR12JY10.008

Where:
CH4Destroyed = Quarterly CH4 destroyed (metric 
tons).
CH4 = Quarterly CH4 routed to the destruction 
device or offsite transfer point (metric tons).
DE = Destruction efficiency (lesser of manufacturer's specified 
destruction efficiency and 0.99). If the gas is transported off-site 
for destruction, use DE = 1.

    (1) Calculate total CH4 destroyed as the sum of the 
methane destroyed at all destruction devices (onsite and offsite), 
using Equation FF-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.009

Where:
CH4DestroyedTotal = Quarterly total CH4 
destroyed at the mine (metric tons CH4).
CH4Destroyed = Quarterly CH4 destroyed from 
each destruction device or offsite transfer point.
d = Number of onsite destruction devices and points of offsite 
transport.

    (2) [Reserved]
    (d) You must calculate the quarterly measured net CH4 
emissions to the atmosphere using Equation FF-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.010

Where:
CH4 emitted (net)= Quarterly CH4 emissions 
from the mine (metric tons).
CH4VTotal = Quarterly sum of the CH4 liberated 
from all mine ventilation monitoring points (CH4V), 
calculated using Equation FF-2 of this section (metric tons).
CH4DTotal = Quarterly sum of the CH4 liberated 
from all mine degasification monitoring points (CH4D), 
calculated using Equation FF-4 of this section (metric tons).
CH4DestroyedTotal = Quarterly sum of the measured 
CH4 destroyed from all mine ventilation and 
degasification systems, calculated using Equation FF-6 of this 
section (metric tons).

    (e) For the methane collected from degasification and/or 
ventilation systems that is destroyed on site and is not a fuel input 
for energy generation or use (those emissions are monitored and 
reported under Subpart C of this part), you must estimate the 
CO2 emissions using Equation FF-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.011

Where:
CO2 = Total quarterly CO2 emissions from 
CH4 destruction (metric tons).
CH4Destroyedonsite = Quarterly sum of the CH4 
destroyed, calculated as the sum of CH4 destroyed for 
each onsite, non-energy use, as calculated individually in Equation 
FF-5 of this section (metric tons).
44/16 = Ratio of molecular weights of CO2 to 
CH4.

Sec.  98.324  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, the facility may submit a 
request to the Administrator to use one or more best available 
monitoring methods as listed in Sec.  98.3(d)(1)(i) through (iv). The 
request must be submitted no later than October 12, 2010 and must 
contain the information in Sec.  98.3(d)(2)(ii). To obtain approval, 
the request must demonstrate to the Administrator's satisfaction that 
it is not reasonably feasible to acquire,

[[Page 39766]]

install, and operate a required piece of monitoring equipment by 
January 1, 2011. The use of best available monitoring methods will not 
be approved beyond December 31, 2011.
    (b) For CH4 liberated from ventilation systems, 
determine whether CH4 will be monitored from each 
ventilation well and shaft, from a centralized monitoring point, or 
from a combination of the two options. Operators are allowed 
flexibility for aggregating emissions from more than one ventilation 
well or shaft, as long as emissions from all are addressed, and the 
methodology for calculating total emissions documented. Monitor by one 
of the following options:
    (1) Collect quarterly or more frequent grab samples (with no fewer 
than 6 weeks between measurements) and make quarterly measurements of 
flow rate, temperature, and pressure. The sampling and measurements 
must be made at the same locations as MSHA inspection samples are 
taken, and should be taken when the mine is operating under normal 
conditions. You must follow MSHA sampling procedures as set forth in 
the MSHA Handbook entitled, General Coal Mine Inspection Procedures and 
Inspection Tracking System Handbook Number: PH-08-V-1, January 1, 2008 
(incorporated by reference, see Sec.  98.7). You must record the date 
of sampling, airflow, temperature, and pressure measured, the hand-held 
methane and oxygen readings (percent), the bottle number of samples 
collected, and the location of the measurement or collection.
    (2) Obtain results of the quarterly (or more frequent) testing 
performed by MSHA.
    (3) Monitor emissions through the use of one or more continuous 
emission monitoring systems (CEMS). If operators use CEMS as the basis 
for emissions reporting, they must provide documentation on the process 
for using data obtained from their CEMS to estimate emissions from 
their mine ventilation systems.
    (c) For CH4 liberated at degasification systems, 
determine whether CH4 will be monitored from each well and 
gob gas vent hole, from a centralized monitoring point, or from a 
combination of the two options. Operators are allowed flexibility for 
aggregating emissions from more than one well or gob gas vent hole, as 
long as emissions from all are addressed, and the methodology for 
calculating total emissions documented. Monitor both gas volume and 
methane concentration by one of the following two options:
    (1) Monitor emissions through the use of one or more continuous 
emissions monitoring systems (CEMS).
    (2) Collect weekly (once each calendar week, with at least three 
days between measurements) or more frequent samples, for all 
degasification wells and gob gas vent holes. Determine weekly or more 
frequent flow rates and methane composition from these degasification 
wells and gob gas vent holes. Methane composition should be determined 
either by submitting samples to a lab for analysis, or from the use of 
methanometers at the degasification well site. Follow the sampling 
protocols for sampling of methane emissions from ventilation shafts, as 
described in Sec.  98.324(b)(1).
    (d) Monitoring must adhere to ASTM D1945-03, Standard Test Method 
for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 
(Reapproved 2006), Standard Practice for Analysis of Reformed Gas by 
Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test 
Method for Heating Value of Gases in Natural Gas Range by 
Stoichiometric Combustion; or ASTM UOP539-97 Refinery Gas Analysis by 
Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (e) All fuel flow meters, gas composition monitors, and heating 
value monitors that are used to provide data for the GHG emissions 
calculations shall be calibrated prior to the first reporting year, 
using the applicable methods specified in paragraphs (e)(1) through (7) 
of this section. Alternatively, calibration procedures specified by the 
flow meter manufacturer may be used. Fuel flow meters, gas composition 
monitors, and heating value monitors shall be recalibrated either 
annually or at the minimum frequency specified by the manufacturer, 
whichever is more frequent. For fuel, flare, or sour gas flow meters, 
the operator shall operate, maintain, and calibrate the flow meter 
using any of the following test methods or follow the procedures 
specified by the flow meter manufacturer. Flow meters must meet the 
accuracy requirements in Sec.  98.3(i).
    (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.  
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec.  98.7).
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters (incorporated by reference, see Sec.  98.7).
    (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec.  98.7).
    (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area 
Meters (incorporated by reference, see Sec.  98.7).
    (f) For CH4 destruction, CH4 must be 
monitored at each onsite destruction device and each point of offsite 
transport for combustion using continuous monitors of gas routed to the 
device or point of offsite transport.
    (g) All temperature and pressure monitors must be calibrated using 
the procedures and frequencies specified by the manufacturer.
    (h) If applicable, the owner or operator shall document the 
procedures used to ensure the accuracy of gas flow rate, gas 
composition, temperature, and pressure measurements. These procedures 
include, but are not limited to, calibration of fuel flow meters, and 
other measurement devices. The estimated accuracy of measurements, and 
the technical basis for the estimated accuracy shall be recorded.

Sec.  98.325  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, in accordance with paragraph (b) of this section.
    (b) For each missing value of CH4 concentration, flow 
rate, temperature, and pressure for ventilation and degasification 
systems, the substitute data value shall be the arithmetic average of 
the quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident. If, for a particular 
parameter, no quality-assured data are available prior to the missing 
data incident, the substitute data value shall be the first quality-
assured value obtained after the missing data period.

Sec.  98.326  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report

[[Page 39767]]

must contain the following information for each mine:
    (a) Quarterly CH4 liberated from each ventilation 
monitoring point (CH4Vm), (metric tons CH4).
    (b) Weekly CH4 liberated from each degasification system 
monitoring point (metric tons CH4).
    (c) Quarterly CH4 destruction at each ventilation and 
degasification system destruction device or point of offsite transport 
(metric tons CH4).
    (d) Quarterly CH4 emissions (net) from all ventilation 
and degasification systems (metric tons CH4).
    (e) Quarterly CO2 emissions from on-site destruction of 
coal mine gas CH4, where the gas is not a fuel input for 
energy generation or use (e.g., flaring) (metric tons CO2).
    (f) Quarterly volumetric flow rate for each ventilation monitoring 
point (scfm), date and location of each measurement, and method of 
measurement (quarterly sampling or continuous monitoring).
    (g) Quarterly CH4 concentration for each ventilation 
monitoring point, dates and locations of each measurement and method of 
measurement (sampling or continuous monitoring).
    (h) Weekly volumetric flow used to calculate CH4 
liberated from degasification systems (scf) and method of measurement 
(sampling or continuous monitoring).
    (i) Quarterly CEMS CH4 concentration (%) used to 
calculate CH4 liberated from degasification systems (average 
from daily data), or quarterly CH4 concentration data based 
on results from weekly sampling data) (C).
    (j) Weekly volumetric flow used to calculate CH4 
destruction for each destruction device and each point of offsite 
transport (scf).
    (k) Weekly CH4 concentration (%) used to calculate 
CH4 destruction (C).
    (l) Dates in quarterly reporting period where active ventilation of 
mining operations is taking place.
    (m) Dates in quarterly reporting period where degasification of 
mining operations is taking place.
    (n) Dates in quarterly reporting period when continuous monitoring 
equipment is not properly functioning, if applicable.
    (o) Temperatures ([deg]R) and pressure (atm) at which each sample 
is collected.
    (p) For each destruction device, a description of the device, 
including an indication of whether destruction occurs at the coal mine 
or off-site. If destruction occurs at the mine, also report an 
indication of whether a back-up destruction device is present at the 
mine, the annual operating hours for the primary destruction device, 
the annual operating hours for the back-up destruction device (if 
present), and the destruction efficiencies assumed (percent).
    (q) A description of the gas collection system (manufacturer, 
capacity, and number of wells) the surface area of the gas collection 
system (square meters), and the annual operating hours of the gas 
collection system.
    (r) Identification information and description for each well and 
shaft, indication of whether the well or shaft is monitored 
individually, or as part of a centralized monitoring point. Note which 
method (sampling or continuous monitoring) was used.
    (s) For each centralized monitoring point, identification of the 
wells and shafts included in the point. Note which method (sampling or 
continuous monitoring) was used.

Sec.  98.327  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the following records:
    (a) Calibration records for all monitoring equipment, including the 
method or manufacturer's specification used for calibration.
    (b) Records of gas sales.
    (c) Logbooks of parameter measurements.
    (d) Laboratory analyses of samples.

Sec.  98.328  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

0
10. Add subpart II to read as follows.
Subpart II--Industrial Wastewater Treatment
Sec.
 98.350 Definition of source category.
 98.351 Reporting threshold.
 98.352 GHGs to report.
 98.353 Calculating GHG emissions.
 98.354 Monitoring and QA/QC requirements.
 98.355 Procedures for estimating missing data.
 98.356 Data reporting requirements.
 98.357 Records that must be retained.
 98.358 Definitions.
Table II-1 to Subpart II-Emission Factors
Table II-2 to Subpart II-Collection Efficiencies of Anaerobic 
Processes

Subpart II--Industrial Wastewater Treatment

Sec.  98.350  Definition of source category.

    (a) This source category consists of anaerobic processes used to 
treat industrial wastewater and industrial wastewater treatment sludge 
at facilities that perform the operations listed in this paragraph.
    (1) Pulp and paper manufacturing.
    (2) Food processing.
    (3) Ethanol production.
    (4) Petroleum refining.
    (b) An anaerobic process is a procedure in which organic matter in 
wastewater, wastewater treatment sludge, or other material is degraded 
by micro organisms in the absence of oxygen, resulting in the 
generation of CO2 and CH4. This source category 
consists of the following: anaerobic reactors, anaerobic lagoons, 
anaerobic sludge digesters, and biogas destruction devices (for 
example, burners, boilers, turbines, flares, or other devices).
    (1) An anaerobic reactor is an enclosed vessel used for anaerobic 
wastewater treatment (e.g., upflow anaerobic sludge blanket, fixed 
film).
    (2) An anaerobic sludge digester is an enclosed vessel in which 
wastewater treatment sludge is degraded anaerobically.
    (3) An anaerobic lagoon is a lined or unlined earthen basin used 
for wastewater treatment, in which oxygen is absent throughout the 
depth of the basin, except for a shallow surface zone. Anaerobic 
lagoons are not equipped with surface aerators. Anaerobic lagoons are 
classified as deep (depth more than 2 meters) or shallow (depth less 
than 2 meters).
    (c) This source category does not include municipal wastewater 
treatment plants or separate treatment of sanitary wastewater at 
industrial sites.

Sec.  98.351  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
meets all of the conditions under paragraphs (a) or (b) of this 
section:
    (a) Petroleum refineries and pulp and paper manufacturing.
    (1) The facility is subject to reporting under subpart Y of this 
part (Petroleum Refineries) or subpart AA of this part (Pulp and Paper 
Manufacturing).
    (2) The facility meets the requirements of either Sec.  98.2(a)(1) 
or (2).
    (3) The facility operates an anaerobic process to treat industrial 
wastewater and/or industrial wastewater treatment sludge.
    (b) Ethanol production and food processing facilities.
    (1) The facility performs an ethanol production or food processing 
operation, as defined in Sec.  98.358 of this subpart.
    (2) The facility meets the requirements of Sec.  98.2(a)(2).
    (3) The facility operates an anaerobic process to treat industrial 
wastewater and/or industrial wastewater treatment sludge.

[[Page 39768]]

Sec.  98.352  GHGs to report.

    (a) You must report CH4 generation, CH4 
emissions, and CH4 recovered from treatment of industrial 
wastewater at each anaerobic lagoon and anaerobic reactor.
    (b) You must report CH4 emissions and CH4 
recovered from each anaerobic sludge digester.
    (c) You must report CH4 emissions and CH4 
destruction resulting from each biogas collection and biogas 
destruction device.
    (d) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
associated with the landfill gas destruction device, if present, by 
following the requirements of subpart C of this part.

Sec.  98.353  Calculating GHG emissions.

    (a) For each anaerobic reactor and anaerobic lagoon, estimate the 
annual mass of CH4 generated according to the applicable 
requirements in paragraphs (a)(1) through (a)(2) of this section.
    (1) If you measure the concentration of organic material entering 
the anaerobic reactors or anaerobic lagoon using methods for the 
determination of chemical oxygen demand (COD), then estimate annual 
mass of CH4 generated using Equation II-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.012

Where:

CH4Gn = Annual mass CH4 generated 
from the nth anaerobic wastewater treatment process (metric tons).
n = Index for processes at the facility, used in Equation II-7.
w = Index for weekly measurement period.
Floww = Volume of wastewater sent to an anaerobic 
wastewater treatment process in week w (m\3\/week), measured as 
specified in Sec.  98.354(d).
CODw = Average weekly concentration of chemical oxygen 
demand of wastewater entering an anaerobic wastewater treatment 
process (for week w)(kg/m\3\), measured as specified in Sec.  
98.354(b) and (c).
B0 = Maximum CH4 producing potential of 
wastewater (kg CH4/kg COD), use the value 0.25.
MCF = CH4 conversion factor, based on relevant values in 
Table II-1 of this subpart.
0.001 = Conversion factor from kg to metric tons.

    (2) If you measure the concentration of organic material entering 
the anaerobic reactors or anaerobic lagoon using methods for the 
determination of 5-day biochemical oxygen demand (BOD5), 
then estimate annual mass of CH4 generated using Equation 
II-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.013

Where:

CH4Gn = Annual mass of CH4 
generated from the anaerobic wastewater treatment process (metric 
tons).
n = Index for processes at the facility, used in Equation II-7.
w = Index for weekly measurement period.
Floww = Volume of wastewater sent to an anaerobic 
wastewater treatment process in week w(m\3\/week), measured as 
specified in Sec.  98.354(d).
BOD5,w = Average weekly concentration of 5-day 
biochemical oxygen demand of wastewater entering an anaerobic 
wastewater treatment process for week w(kg/m\3\), measured as 
specified in Sec.  98.354(b) and (c).
B0 = Maximum CH4 producing potential of 
wastewater (kg CH4/kg BOD5), use the value 
0.6.
MCF = CH4 conversion factor, based on relevant values in 
Table II-1 of this subpart.
0.001 = Conversion factor from kg to metric tons.

    (b) For each anaerobic reactor and anaerobic lagoon from which 
biogas is not recovered, estimate annual CH4 emissions using 
Equation II-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.014

Where:

CH4En = Annual mass of CH4 
emissions from the wastewater treatment process n from which biogas 
is not recovered (metric tons).
CH4Gn = Annual mass of CH4 
generated from the wastewater treatment process n, as calculated in 
Equation II-1 or II-2 of this section (metric tons).

    (c) For each anaerobic digester, anaerobic reactor, or anaerobic 
lagoon from which some biogas is recovered, estimate the annual mass of 
CH4 recovered according to the requirements in paragraphs 
(c)(1) and (c)(2) of this section. To estimate the annual mass of 
CH4 recovered, you must continuously monitor gas flow rate 
as specified in Sec.  98.354(f) and (h).
    (1) If you continuously monitor CH4 concentration (and 
if necessary, temperature, pressure, and moisture content required as 
specified in Sec.  98.354(f)) of the biogas that is collected and 
routed to a destruction device using a monitoring meter specifically 
for CH4 gas, as specified in Sec.  98.354(g), you must use 
this monitoring system and calculate the quantity of CH4 
recovered for destruction using Equation II-4 of this section. A fully 
integrated system that directly reports CH4 content requires 
only the summing of results of all monitoring periods for a given year.
[GRAPHIC] [TIFF OMITTED] TR12JY10.015

[[Page 39769]]

Where:

Rn = Annual quantity of CH4 recovered from the 
nth anaerobic reactor, digester, or lagoon (metric tons 
CH4/yr)
n = Index for processes at the facility, used in Equation II-7.
M = Total number of measurement periods in a year. Use M = 365 (M = 
366 for leap years) for daily averaging of continuous monitoring, as 
provided in paragraph (c)(1)of this section. Use M = 52 for weekly 
sampling, as provided in paragraph (c)(2)of this section.
m = Index for measurement period.
Vm = Cumulative volumetric flow for the measurement 
period in actual cubic feet (acf). If no biogas was recovered during 
a monitoring period, use zero.
(KMC)m = Moisture correction term for the 
measurement period, volumetric basis.
    = 1 when (V)m and (CCH4)m are 
measured on a dry basis or if both are measured on a wet basis.
    = 1-(fH2O)m when (V)m is 
measured on a wet basis and (CCH4)m is 
measured on a dry basis.
    = 1/[1-(fH2O)m] when (V)m is 
measured on a dry basis and (CCH4)m is 
measured on a wet basis.
(fH2O)m = Average moisture content of biogas 
during the measurment period, volumetric basis, (cubic feet water 
per cubic feet biogas).
(CCH4)m = Average CH4 concentration 
of biogas during the measurement period, (volume %).
0.0423 = Density of CH4 lb/cf at 520 [deg]R or 60 [deg]F 
and 1 atm.
520 [deg]R = 520 degrees Rankine.
Tm = Temperature at which flow is measured for the 
measurement period ([deg]R). If the flow rate meter automatically 
corrects for temperature replace ``520 [deg]R/Tm'' with 
``1''.
Pm = Pressure at which flow is measured for the 
measurement period (atm). If the flow rate meter automatically 
corrects for pressure, replace ``Pm/1'' with ``1''.
0.454/1,000 = Conversion factor (metric ton/lb).

    (2) If you do not continuously monitor CH4 concentration 
according to paragraph (c)(1) of this section, you must determine the 
CH4 concentration, temperature, pressure, and, if necessary, 
moisture content of the biogas that is collected and routed to a 
destruction device according to the requirements in paragraphs 
(c)(2)(i) through (c)(2)(iii) of this section and calculate the 
quantity of CH4 recovered for destruction using Equation II-
4 of this section.
    (i) Continuously monitor gas flow rate and determine the volume of 
biogas each week and the cumulative volume of biogas each year that is 
collected and routed to a destruction device. If the gas flow meter is 
not equipped with automatic correction for temperature, pressure, or, 
if necessary, moisture content, you must determine these parameters as 
specified in paragraph (c)(2)(iii) of this section.
    (ii) Determine the CH4 concentration in the biogas that 
is collected and routed to a destruction device in a location near or 
representative of the location of the gas flow meter once each calendar 
week, with at least three days between measurements. For a given 
calendar week, you are not required to determine CH4 
concentration if the cumulative volume of biogas for that calendar 
week, determined as specified in paragraph (c)(2)(i) of this section, 
is zero.
    (iii) If the gas flow meter is not equipped with automatic 
correction for temperature, pressure, or, if necessary, moisture 
content:
    (A) Determine the temperature and pressure in the biogas that is 
collected and routed to a destruction device in a location near or 
representative of the location of the gas flow meter once each calendar 
week, with at least three days between measurements.
    (B) If the CH4 concentration is determined on a dry 
basis and biogas flow is determined on a wet basis, or CH4 
concentration is determined on a wet basis and biogas flow is 
determined on a dry basis, and the flow meter does not automatically 
correct for moisture content, determine the moisture content in the 
biogas that is collected and routed to a destruction device in a 
location near or representative of the location of the gas flow meter 
once each calendar week that the cumulative biogas flow measured as 
specified in Sec.  98.354(h) is greater than zero, with at least three 
days between measurements.
    (d) For each anaerobic digester, anaerobic reactor, or anaerobic 
lagoon from which some quantity of biogas is recovered, you must 
estimate both the annual mass of CH4 that is generated, but 
not recovered, according to paragraph (d)(1) of this section and the 
annual mass of CH4 emitted according to paragraph (d)(2) of 
this section.
    (1) Estimate the annual mass of CH4 that is generated, 
but not recovered, using Equation II-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.016

Where:

CH4Ln = Leakage at the anaerobic process n 
(metric tons CH4).
n = Index for processes at the facility, used in Equation II-7.
Rn = Annual quantity of CH4 recovered from the 
nth anaerobic reactor, anaerobic lagoon, or anaerobic digester, as 
calculated in Equation II-4 of this section (metric tons 
CH4).
CE = CH4 collection efficiency of anaerobic process n, as 
specified in Table II-2 of this subpart (decimal).

    (2) For each anaerobic digester, anaerobic reactor, or anaerobic 
lagoon from which some quantity of biogas is recovered, estimate the 
annual mass of CH4 emitted using Equation II-6 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.017

Where:

CH4En = Annual quantity of CH4 
emitted from the process n from which biogas is recovered (metric 
tons/yr).
n = Index for processes at the facility, used in Equation II-7.
CH4Ln = Leakage at the anaerobic process n, as 
calculated in Equation II-5 of this section (metric tons 
CH4).
Rn = Annual quantity of CH4 recovered from the 
nth anaerobic reactor or anaerobic digester, as calculated in 
Equation II-4 of this section (metric tons CH4).
DE1 = Primary destruction device CH4 
destruction efficiency (lesser of manufacturer's specified 
destruction efficiency and 0.99). If the gas is transported off-site 
for destruction, use DE = 1.
fDest--1 = Fraction of hours the primary destruction 
device was operating (device operating hours/hours in the year). If 
the gas is transported off-site for destruction, use 
fDest = 1.
DE2 = Back-up destruction device CH4 
destruction efficiency (lesser of manufacturer's specified 
destruction efficiency and 0.99).
fDest--2 = Fraction of hours the back-up destruction 
device was operating (device operating hours/hours in the year).

    (e) Estimate the total mass of CH4 emitted from all 
anaerobic processes from which biogas is not recovered (calculated in 
Eq. II-3) and all anaerobic processes from which some biogas is 
recovered (calculated in Equation II-6) using Equation II-7 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.018

Where:

CH4ET = Annual mass CH4 emitted 
from all anaerobic processes at the facility (metric tons).
n = Index for processes at the facility.
CH4En = Annual mass of CH4 
emissions from process n (metric tons).

[[Page 39770]]

j = Total number of processes from which methane is emitted.

Sec.  98.354  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, the facility may submit a 
request to the Administrator to use one or more best available 
monitoring methods as listed in Sec.  98.3(d)(1)(i) through (iv). The 
request must be submitted no later than October 12, 2010 and must 
contain the information in Sec.  98.3(d)(2)(ii). To obtain approval, 
the request must demonstrate to the Administrator's satisfaction that 
it is not reasonably feasible to acquire, install, and operate a 
required piece of monitoring equipment by January 1, 2011. The use of 
best available monitoring methods will not be approved beyond December 
31, 2011.
    (b) You must determine the concentration of organic material in 
wastewater treated anaerobically using analytical methods for COD or 
BOD5 specified in 40 CFR 136.3 Table 1B. For the purpose of 
determining concentrations of wastewater influent to the anaerobic 
wastewater treatment process, samples may be diluted to the 
concentration range of the approved method, but the calculated 
concentration of the undiluted wastewater must be used for calculations 
and reporting required by this subpart.
    (c) You must collect samples representing wastewater influent to 
the anaerobic wastewater treatment process, following all preliminary 
and primary treatment steps (e.g., after grit removal, primary 
clarification, oil-water separation, dissolved air flotation, or 
similar solids and oil separation processes). You must collect and 
analyze samples for COD or BOD5 concentration once each 
calendar week that the anaerobic wastewater treatment process is 
operating, with at least three days between measurements. You must 
collect a sample that represents the average COD or BOD5 
concentration of the waste stream over a 24-hour sampling period. You 
must collect a minimum of four sample aliquots per 24-hour period and 
composite the aliquots for analysis. Collect a flow-proportional 
composite sample (either constant time interval between samples with 
sample volume proportional to stream flow, or constant sample volume 
with time interval between samples proportional to stream flow). Follow 
sampling procedures and techniques presented in Chapter 5, Sampling, of 
the ``NPDES Compliance Inspection Manual,'' (incorporated by reference, 
see Sec.  98.7) or Section 7.1.3, Sample Collection Methods, of the 
``U.S. EPA NPDES Permit Writers' Manual,'' (incorporated by reference, 
see Sec.  98.7).
    (d) You must measure the flowrate of wastewater entering anaerobic 
wastewater treatment process once each calendar week that the process 
is operating, with at least three days between measurements. You must 
measure the flowrate for the 24-hour period for which you collect 
samples analyzed for COD or BOD5 concentration. The flow 
measurement location must correspond to the location used to collect 
samples analyzed for COD or BOD5 concentration. You must 
measure the flowrate using one of the methods specified in paragraphs 
(d)(1) through (d)(5) of this section or as specified by the 
manufacturer.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.  
98.7).
    (2) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters 
(incorporated by reference, see Sec.  98.7).
    (3) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits 
with Electromagnetic Flowmeters (incorporated by reference, see Sec.  
98.7).
    (4) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open 
Channel Flow Measurement of Water with the Parshall Flume, approved 
June 15, 2007, (incorporated by reference, see Sec.  98.7).
    (5) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open 
Channel Flow Measurement of Water with Broad-Crested Weirs, approved 
October 1, 2008, (incorporated by reference, see Sec.  98.7).
    (e) All wastewater flow measurement devices must be calibrated 
prior to the first year of reporting and recalibrated either biennially 
(every 2 years) or at the minimum frequency specified by the 
manufacturer. Wastewater flow measurement devices must be calibrated 
using the procedures specified by the device manufacturer.
    (f) For each anaerobic process (such as anaerobic reactor, 
digester, or lagoon) from which biogas is recovered, you must 
continuously measure the gas flow rate as specified in paragraph (h) of 
this section and determine the cumulative volume of gas recovered as 
specified in Equation II-4 of this subpart. You must also determine the 
CH4 concentration of the recovered biogas as specified in 
paragraph (g) of this section at a location near or representative of 
the location of the gas flow meter. You must determine CH4 
concentration either continuously or intermittently. If you determine 
the concentration intermittently, you must determine the concentration 
at least once each calendar week that the cumulative biogas flow 
measured as specified in paragraph (h) of this section is greater than 
zero, with at least three days between measurements. As specified in 
Sec.  98.353(c) and paragraph (h) of this section, you must also 
determine temperature, pressure, and moisture content as necessary to 
accurately determine the gas flow rate and CH4 
concentration. You must determine temperature and pressure if the gas 
flow meter or gas composition monitor do not automatically correct for 
temperature or pressure. You must measure moisture content of the 
recovered biogas if the gas flow rate is measured on a wet basis and 
the CH4 concentration is measured on a dry basis. You must 
also measure the moisture content of the recovered biogas if the gas 
flow rate is measured on a dry basis and the CH4 
concentration is measured on a wet basis.
    (g) For each anaerobic process (such as an anaerobic reactor, 
digester, or lagoon) from which biogas is recovered, operate, maintain, 
and calibrate a gas composition monitor capable of measuring the 
concentration of CH4 in the recovered biogas using one of 
the methods specified in paragraphs (g)(1) through (g)(6) of this 
section or as specified by the manufacturer.
    (1) Method 18 at 40 CFR part 60, appendix A-6.
    (2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec.  98.7).
    (4) GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography (incorporated by reference, see 
Sec.  98.7).
    (5) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec.  98.7).
    (6) As an alternative to the gas chromatography methods provided in 
paragraphs (g)(1) through (g)(5) of this section, you may use total 
gaseous organic concentration analyzers and calculate the 
CH4 concentration following the requirements in paragraphs 
(g)(6)(i) through (g)(6)(iii) of this section.
    (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to 
determine total gaseous organic concentration. You must calibrate the 
instrument with CH4 and determine the total gaseous organic 
concentration as carbon (or as CH4; K=1

[[Page 39771]]

in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
    (ii) Determine a non-methane organic carbon correction factor at 
the routine sampling location no less frequently than once a reporting 
year following the requirements in paragraphs (g)(6)(ii)(A) through 
(g)(6)(ii)(C) of this section.
    (A) Take a minimum of three grab samples of the biogas with a 
minimum of 20 minutes between samples and determine the methane 
composition of the biogas using one of the methods specified in 
paragraphs (g)(1) through (g)(5) of this section.
    (B) As soon as practical after each grab sample is collected and 
prior to the collection of a subsequent grab sample, determine the 
total gaseous organic concentration of the biogas using either Method 
25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph 
(g)(6)(i) of this section.
    (C) Determine the arithmetic average methane concentration and the 
arithmetic average total gaseous organic concentration of the samples 
analyzed according to paragraphs (g)(6)(ii)(A) and (g)(6)(ii)(B) of 
this section, respectively, and calculate the non-methane organic 
carbon correction factor as the ratio of the average methane 
concentration to the average total gaseous organic concentration. If 
the ratio exceeds 1, use 1 for the non-methane organic carbon 
correction factor.
    (iii) Calculate the CH4 concentration as specified in 
Equation II-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.019

Where:

CCH4 = Methane (CH4) concentration in the 
biogas (volume %) for use in Equation II-4 of this subpart.
fNMOC = Non-methane organic carbon correction factor from 
the most recent determination of the non-methane organic carbon 
correction factor as specified in paragraph (g)(6)(ii) of this 
section (unitless).
CTGOC = Total gaseous organic carbon concentration 
measured using Method 25A or 25B at 40 CFR part 60, appendix A-7 
during routine monitoring of the biogas (volume %).

    (h) For each anaerobic process (such as an anaerobic reactor, 
digester, or lagoon) from which biogas is recovered, install, operate, 
maintain, and calibrate a gas flow meter capable of continuously 
measuring the volumetric flow rate of the recovered biogas using one of 
the methods specified in paragraphs (h)(1) through (h)(8) of this 
section or as specified by the manufacturer. Recalibrate each gas flow 
meter either biennially (every 2 years) or at the minimum frequency 
specified by the manufacturer. Except as provided in Sec.  
98.353(c)(2)(iii), each gas flow meter must be capable of correcting 
for the temperature and pressure and, if necessary, moisture content.
    (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.  
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec.  98.7).
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters (incorporated by reference, see Sec.  98.7). 
The mass flow must be corrected to volumetric flow based on the 
measured temperature, pressure, and gas composition.
    (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec.  98.7).
    (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area 
Meters (incorporated by reference, see Sec.  98.7).
    (8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
    (i) All temperature, pressure, and, moisture content monitors 
required as specified in paragraph (f) of this section must be 
calibrated using the procedures and frequencies where specified by the 
device manufacturer, if not specified use an industry accepted or 
industry standard practice.
    (j) All equipment (temperature, pressure, and moisture content 
monitors and gas flow meters and gas composition monitors) must be 
maintained as specified by the manufacturer.
    (k) If applicable, the owner or operator must document the 
procedures used to ensure the accuracy of measurements of COD or 
BOD5 concentration, wastewater flow rate, gas flow rate, gas 
composition, temperature, pressure, and moisture content. These 
procedures include, but are not limited to, calibration of gas flow 
meters, and other measurement devices. The estimated accuracy of 
measurements made with these devices must also be recorded, and the 
technical basis for these estimates must be documented.

Sec.  98.355  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required sample is not 
taken), a substitute data value for the missing parameter must be used 
in the calculations, according to the following requirements in 
paragraphs (a) through (c) of this section:
    (a) For each missing weekly value of COD or BOD5 or 
wastewater flow entering an anaerobic wastewater treatment process, the 
substitute data value must be the arithmetic average of the quality-
assured values of those parameters for the week immediately preceding 
and the week immediately following the missing data incident.
    (b) For each missing value of the CH4 content or gas 
flow rates, the substitute data value must be the arithmetic average of 
the quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident.
    (c) If, for a particular parameter, no quality-assured data are 
available prior to the missing data incident, the substitute data value 
must be the first quality-assured value obtained after the missing data 
period. If, for a particular parameter, the ``after'' value is not 
obtained by the end of the reporting year, you may use the last 
quality-assured value obtained ``before'' the missing data period for 
the missing data substitution. You must document and keep records of 
the procedures you use for all such estimates.

Sec.  98.356  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for each 
wastewater treatment system.
    (a) A description or diagram of the industrial wastewater treatment 
system, identifying the processes used to treat industrial wastewater 
and industrial wastewater treatment sludge. Explain how the processes 
are related to each other and identify the anaerobic processes. Provide 
a unique identifier for each anaerobic process, indicate the average 
depth in meters of all anaerobic lagoons, and indicate whether biogas 
generated by each anaerobic process is recovered. The anaerobic 
processes must be identified as:
    (1) Anaerobic reactor.
    (2) Anaerobic deep lagoon (depth more than 2 meters).
    (3) Anaerobic shallow lagoon (depth less than 2 meters).

[[Page 39772]]

    (4) Anaerobic sludge digester.
    (b) For each anaerobic wastewater treatment process (reactor, deep 
lagoon, or shallow lagoon) you must report:
    (1) Weekly average COD or BOD5 concentration of 
wastewater entering each anaerobic wastewater treatment process, for 
each week the anaerobic process was operated.
    (2) Volume of wastewater entering each anaerobic wastewater 
treatment process for each week the anaerobic process was operated.
    (3) Maximum CH4 production potential (B0) 
used as an input to Equation II-1 or II-2 of this subpart.
    (4) Methane conversion factor (MCF) used as an input to Equation 
II-1 or II-2 of this subpart.
    (5) Annual mass of CH4 generated by each anaerobic 
wastewater treatment process, calculated using Equation II-1 or II-2 of 
this subpart.
    (c) For each anaerobic wastewater treatment process from which 
biogas is not recovered, you must report the annual CH4 
emissions, calculated using Equation II-3 of this subpart.
    (d) For each anaerobic wastewater treatment process and anaerobic 
digester from which some biogas is recovered, you must report:
    (1) Annual quantity of CH4 recovered from the anaerobic 
process calculated using Equation II-4 of this subpart.
    (2) Cumulative volumetric biogas flow for each week that biogas is 
collected for destruction.
    (3) Weekly average CH4 concentration for each week that 
biogas is collected for destruction.
    (4) Weekly average temperature for each week at which flow is 
measured for biogas collected for destruction, or statement that 
temperature is incorporated into monitoring equipment internal 
calculations.
    (5) Whether flow was measured on a wet or dry basis, whether 
CH4 concentration was measured on a wet or dry basis, and if 
required for Equation II-4 of this subpart, weekly average moisture 
content for each week at which flow is measured for biogas collected 
for destruction, or statement that moisture content is incorporated 
into monitoring equipment internal calculations.
    (6) Weekly average pressure for each week at which flow is measured 
for biogas collected for destruction, or statement that pressure is 
incorporated into monitoring equipment internal calculations.
    (7) CH4 collection efficiency (CE) used in Equation II-5 
of this subpart.
    (8) Whether destruction occurs at the facility or off-site. If 
destruction occurs at the facility, also report whether a back-up 
destruction device is present at the facility, the annual operating 
hours for the primary destruction device, the annual operating hours 
for the back-up destruction device (if present), the destruction 
efficiency for the primary destruction device, and the destruction 
efficiency for the backup destruction device (if present).
    (9) For each anaerobic process from which some biogas is recovered, 
you must report the annual CH4 emissions, as calculated by 
Equation II-6 of this subpart.
    (e) The total mass of CH4 emitted from all anaerobic 
processes from which biogas is not recovered (calculated in Equation 
II-3 of this supbart) and from all anaerobic processes from which some 
biogas is recovered (calculated in Equation II-6 of this subpart) using 
Equation II-7 of this subpart.

Sec.  98.357  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration.

Sec.  98.358  Definitions.

    Except as provided below, all terms used in this subpart have the 
same meaning given in the CAA and subpart A of this part.
    Biogas means the combination of CO2, CH4, and 
other gases produced by the biological breakdown of organic matter in 
the absence of oxygen.
    Ethanol production means an operation that produces ethanol from 
the fermentation of sugar, starch, grain, or cellulosic biomass 
feedstocks, or the production of ethanol synthetically from 
petrochemical feedstocks, such as ethylene or other chemicals.
    Food processing means an operation used to manufacture or process 
meat, poultry, fruits, and/or vegetables as defined under NAICS 3116 
(Meat Product Manufacturing) or NAICS 3114 (Fruit and Vegetable 
Preserving and Specialty Food Manufacturing). For information on NAICS 
codes, see http://www.census.gov/eos/www/naics/.
    Industrial wastewater means water containing wastes from an 
industrial process. Industrial wastewater includes water which comes 
into direct contact with or results from the storage, production, or 
use of any raw material, intermediate product, finished product, by-
product, or waste product. Examples of industrial wastewater include, 
but are not limited to, paper mill white water, wastewater from 
equipment cleaning, wastewater from air pollution control devices, 
rinse water, contaminated stormwater, and contaminated cooling water.
    Industrial wastewater treatment sludge means solid or semi-solid 
material resulting from the treatment of industrial wastewater, 
including but not limited to biosolids, screenings, grit, scum, and 
settled solids.
    Wastewater treatment system means the collection of all processes 
that treat or remove pollutants and contaminants, such as soluble 
organic matter, suspended solids, pathogenic organisms, and chemicals 
from wastewater prior to its reuse or discharge from the facility.

               Table II-1 to Subpart II--Emission Factors
------------------------------------------------------------------------
            Factors                Default value           Units
------------------------------------------------------------------------
B0--for facilities monitoring                0.25  Kg CH4/kg COD
 COD.
B0--for facilities monitoring                0.60  Kg CH4/kg BOD5
 BOD5.
MCF--anaerobic reactor.........               0.8  Fraction.
MCF--anaerobic deep lagoon                    0.8  Fraction.
 (depth more than 2 m).
MCF--anaerobic shallow lagoon                 0.2  Fraction.
 (depth less than 2 m).
------------------------------------------------------------------------

[[Page 39773]]

Table II-2 to Subpart II--Collection Efficiencies of Anaerobic Processes
------------------------------------------------------------------------
                                                              Methane
      Anaerobic process type             Cover type         collection
                                                            efficiency
------------------------------------------------------------------------
Covered anaerobic lagoon (biogas    Bank to bank,                  0.975
 capture).                           impermeable.
                                    Modular, impermeable            0.70
Anaerobic sludge digester;          Enclosed Vessel.....            0.99
 anaerobic reactor.
------------------------------------------------------------------------

0
11. Add and reserve subparts QQ, RR, and SS.

0
12. Add subpart TT to read as follows:
Subpart TT--Industrial Waste Landfills
Sec.
 98.460 Definition of the source category.
 98.461 Reporting threshold.
 98.462 GHGs to report.
 98.463 Calculating GHG emissions.
 98.464 Monitoring and QA/QC requirements.
 98.465 Procedures for estimating missing data.
 98.466 Data reporting requirements.
 98.467 Records that must be retained.
 98.468 Definitions.
Table TT-1 to Subpart TT-Default DOC and Decay Rate Values for 
Industrial Waste Landfills

Subpart TT--Industrial Waste Landfills

Sec.  98.460  Definition of the source category.

    (a) This source category applies to industrial waste landfills that 
accepted waste on or after January 1, 1980, and that are located at a 
facility whose total landfill design capacity is greater than or equal 
to 300,000 metric tons.
    (b) An industrial waste landfill is a landfill other than a 
municipal solid waste landfill, a RCRA Subtitle C hazardous waste 
landfill, or a TSCA hazardous waste landfill, in which industrial solid 
waste, such as RCRA Subtitle D wastes (non-hazardous industrial solid 
waste, defined in 40 CFR 257.2), commercial solid wastes, or 
conditionally exempt small quantity generator wastes, is placed. An 
industrial waste landfill includes all disposal areas at the facility.
    (c) This source category does not include:
    (1) Dedicated construction and demolition waste landfills. A 
dedicated construction and demolition waste landfill receives materials 
generated from the construction or destruction of structures such as 
buildings, roads, and bridges.
    (2) Industrial waste landfills that only receive one or more of the 
following inert waste materials:
    (i) Coal combustion residue (e.g., fly ash).
    (ii) Cement kiln dust.
    (iii) Rocks and/or soil from excavation and construction and 
similar activities.
    (iv) Glass.
    (v) Non-chemically bound sand (e.g., green foundry sand).
    (vii) Clay, gypsum, or pottery cull.
    (viii) Bricks, mortar, or cement.
    (ix) Furnace slag.
    (x) Materials used as refractory (e.g., alumina, silicon, fire 
clay, fire brick).
    (xi) Plastics (e.g., polyethylene, polypropylene, polyethylene 
terephthalate, polystyrene, polyvinyl chloride).
    (xii) Other waste material that has a volatile solids concentration 
of 0.5 weight percent (on a dry basis) or less.
    (d) This source category consists of the following sources at 
industrial waste landfills: Landfills, gas collection systems at 
landfills, and destruction devices for landfill gases (including 
flares).

Sec.  98.461  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an industrial waste landfill meeting the criteria in Sec.  
98.460 and the facility meets the requirements of Sec.  98.2(a)(2). For 
the purposes of Sec.  98.2(a)(2), the emissions from the industrial 
waste landfill are to be determined using the methane generation 
corrected for oxidation as determined using Equation TT-6 of this 
subpart times the global warming potential for methane in Table A-1 of 
subpart A of this part.

Sec.  98.462  GHGs to report.

    (a) You must report CH4 generation and CH4 
emissions from industrial waste landfills.
    (b) You must report CH4 destruction resulting from 
landfill gas collection and destruction devices, if present.
    (c) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
associated with the landfill gas destruction device, if present, by 
following the requirements of subpart C of this part.

Sec.  98.463  Calculating GHG emissions.

    (a) For each industrial waste landfill subject to the reporting 
requirements of this subpart, calculate annual modeled CH4 
generation according to the applicable requirements in paragraphs 
(a)(1) through (a)(3) of this section. Apply Equation TT-1 of this 
section for each waste stream disposed of in the landfill and sum the 
CH4 generation rates for all waste streams disposed of in 
the landfill to calculate the total annual modeled CH4 
generation rate for the landfill.
    (1) Calculate annual modeled CH4 generation using 
Equation TT-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.020

Where:

GCH4 = Modeled methane generation rate in reporting year 
T (metric tons CH4).
X = Year in which waste was disposed.
S = Start year of calculation. Use the year 1960 or the opening year 
of the landfill, whichever is more recent.
T = Reporting year for which emissions are calculated.
Wx = Quantity of waste disposed in the industrial waste 
landfill in year X from measurement data and/or other company 
records (metric tons, as received (wet weight)).
DOCx = Degradable organic carbon for year X from Table 
TT-1 of this subpart or from measurement data [as specified in 
paragraph (a)(3) of this section], if available [fraction (metric 
tons C/metric ton waste)].
DOCF = Fraction of DOC dissimilated (fraction); use the 
default value of 0.5.
MCF = Methane correction factor (fraction); use the default value of 
1.
Fx = Fraction by volume of CH4 in landfill gas 
(fraction, dry basis). If you have a gas collection system, use the 
annual average

[[Page 39774]]

CH4 concentration from measurement data for the given 
year; otherwise, use the default value of 0.5.
k = Decay rate constant from Table TT-1 of this subpart 
(yr-1). Select the most applicable k value for the 
majority of the past 10 years (or operating life, whichever is 
shorter).

    (2) Waste stream quantities. Determine annual waste quantities as 
specified in paragraphs (a)(2)(i) through (ii) of this section for each 
year starting with January 1, 1980 or the year the landfills first 
accepted waste if after January 1, 1980, up until the most recent 
reporting year. The choice of method for determining waste quantities 
will vary according to the availability of historical data. Beginning 
in the first emissions monitoring year (2011 or later) and for each 
year thereafter, use the procedures in paragraph (a)(2)(i) of this 
section to determine waste stream quantities. These procedures should 
also be used for any year prior to the first emissions monitoring year 
for which the data are available. For other historical years, use 
paragraph (a)(2)(i) of this section, where waste disposal records are 
available, and use the procedures outlined in paragraph (a)(2)(ii) of 
this section when waste disposal records are unavailable, to determine 
waste stream quantities. Historical disposal quantities deposited (i.e, 
prior to the first year in which monitoring begins) should only be 
determined once, as part of the first annual report, and the same 
values should be used for all subsequent annual reports, supplemented 
by the next year's data on new waste disposal.
    (i) Determine the quantity of waste (in metric tons as received, 
i.e., wet weight) disposed of in the landfill separately for each waste 
stream by any one or a combination of the following methods.
    (A) Direct mass measurements.
    (B) Direct volume measurements multiplied by waste stream density 
determined from periodic density measurement data or process knowledge.
    (C) Mass balance procedures, determining the mass of waste as the 
difference between the mass of the process inputs and the mass of the 
process outputs.
    (D) The number of loads (e.g., trucks) multiplied by the mass of 
waste per load based on the working capacity of the container or 
vehicle.
    (ii) Determine the historical disposal quantities for landfills 
using the Waste Disposal Factor approach in paragraphs (a)(2)(ii)(A) 
and (B) of this section when historical production or processing data 
are available. If production or processing data are available for a 
given year, you must use Equation TT-3 of this section for that year. 
Determine historical disposal quantities using the method specified in 
paragraph (a)(2)(ii)(C) of this section when historical production or 
processing data are not available, and for waste streams received from 
an off-site facility when historical disposal quantities cannot be 
determined using the methods specified in paragraph (a)(2)(i) of this 
section.
    (A) Determining Waste Disposal Factor: For each waste stream 
disposed of in the landfill, calculate the average waste disposal rate 
per unit of production or unit throughput using all available waste 
quantity data and corresponding production or processing rates for the 
process generating that waste or, if appropriate, the facility, using 
Equation TT-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.021

Where:

WDF = Average waste disposal factor as determined for the first 
annual report required for this industrial waste landfill (metric 
tons per production unit).
X = Year in which waste was disposed. Include only those years for 
which disposal and production data are both available; the years do 
not need to be sequential.
Y1 = First year in which disposal and production/
throughput data are both available.
Y2 = First year for which GHG emissions from this 
industrial waste landfill must be reported.
N = Number of years for which disposal and production/throughput 
data are both available.
Wx = Quantity of waste placed in the industrial waste 
landfill in year X from measurement data and/or other company 
records (metric tons, as received (wet weight)).
Px = Quantity of product produced or feedstock entering 
the process or facility in year X from measurement data and/or other 
company records (production units). You must use the same basis for 
all years in the calculation. That is, Px must be 
determined based on production (quantity of product produced) for 
all ``N'' years or Px must be determined based on 
throughput (quantity of feedstock) for all ``N'' years.

    (B) Calculate waste: For each waste stream disposed of in the 
landfill, calculate the waste disposal quantities for historic years in 
which direct waste disposal measurements are not available using 
historical production data and Equation TT-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.022

Where:

X = Historic year in which waste was disposed.
Wx = Calculated quantity of waste placed in the landfill 
in year X (metric tons).
WDF = Average waste disposal factor from Equation TT-2 of this 
section (metric tons per production unit).
Px = Quantity of product produced or feedstock entering 
the process or facility in year X from measurement data and/or other 
company records (production units). You must use the same basis for 
Px (either production only or throughput only) as used to 
determine WDF in Equation TT-2 of this section.

    (C) For any year in which historic production or processing data 
are not available such that historic waste quantities cannot be 
estimated using Equation TT-3 of this section, calculate an average 
annual bulk waste disposal quantity using fixed average annual bulk 
waste disposal quantity for each year for which historic disposal 
quantity and Equation TT-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.023

Where:

Wx = Quantity of waste placed in the landfill in year X 
(metric tons, wet basis).
LFC = Landfill capacity or, for operating landfills, capacity of the 
landfill used (or the total quantity of waste-in-place) at the end 
of the ``YrData'' from design drawings or engineering estimates 
(metric tons).
YrData = Year in which the landfill last received waste or, for 
operating landfills, the year prior to the year when waste disposal 
data is first available from company records or from Equation TT-3 
of this section.
YrOpen = Year 1960 or the year in which the landfill first received 
waste from company records, whichever is more recent. If no data are 
available for estimating YrOpen for a closed landfill, use 1960 as 
the default ``YrOpen'' for the landfill.

[[Page 39775]]

    (3) Degradable organic content (DOC). For any year, X, in Equation 
TT-1 of this section, use either the applicable default DOC values 
provided in Table TT-1 of this subpart or determine values for 
DOCx as specified in paragraphs (a)(3)(i) through (iv) of 
this section. When developing historical waste quantity data, you may 
use default DOC values from Table TT-1 of this subpart for certain 
years and determined values for DOCx for other years. The 
historical values for DOC or DOCx must be developed only for 
the first annual report required for the industrial waste landfill; and 
used for all subsequent annual reports (e.g., if DOC for year x=1990 
was determined to be 0.15 in the first reporting year, you must use 
0.15 for the 1990 DOC value for all subsequent annual reports).
    (i) For the first year in which GHG emissions from this industrial 
waste landfill must be reported, determine the DOCx value of 
each waste stream disposed of in the landfill no less frequently than 
once per quarter using the methods specified in Sec.  98.464(b). 
Calculate annual DOCx for each waste stream as the 
arithmetic average of all DOCx values for that waste stream 
that were measured during the year.
    (ii) For subsequent years (after the first year in which GHG 
emissions from this industrial waste landfill must be reported), either 
use the DOCx of each waste stream calculated for the most 
recent reporting year for which DOC values were determined according to 
paragraph (a)(3)(i) of this section, or determine new DOC values for 
that year following the requirements in paragraph (a)(3)(i) of this 
section. You must determine new DOC values following the requirements 
in paragraph (a)(3)(i) of this section if changes in the process 
operations occurred during the previous reporting year that can 
reasonably be expected to alter the characteristics of the waste 
stream, such as the water content or volatile solids concentration. 
Should changes to the waste stream occur, you must revise the GHG 
Monitoring Plan as required in Sec.  98.3(g)(5)(iii) and report the new 
DOCx value according to the requirements of Sec.  98.466.
    (iii) If DOCx measurement data for each waste stream are 
available according to the methods specified in Sec.  98.464(b) for 
years prior to the first year in which GHG emissions from this 
industrial waste landfill must be reported, determine DOCx 
for each waste stream as the arithmetic average of all DOCx 
values for that waste stream that were measured in Year X. A single 
measurement value is acceptable for determining DOCx for 
years prior to the first reporting year.
    (iv) For historical years for which DOCx measurement 
data, determined according to the methods specified in Sec.  98.464(b), 
are not available, determine the historical values for DOCx 
using the applicable methods specified in paragraphs (a)(3)(iv)(A) and 
(B) of this section. Determine these historical values for 
DOCx only for the first annual report required for this 
industrial waste landfill; historical values for DOCx 
calculated for this first annual report should be used for all 
subsequent annual reports.
    (A) For years in which waste stream-specific disposal quantities 
are determined (as required in paragraphs (a)(2) (ii)(A) and (B) of 
this section), calculate the average DOC value for a given waste stream 
as the arithmetic average of all DOC measurements of that waste stream 
that follow the methods provided in Sec.  98.464(b), including any 
measurement values for years prior to the first reporting year and the 
four measurement values required in the first reporting year. Use the 
resulting waste-specific average DOC value for all applicable years 
(i.e., years in which waste stream-specific disposal quantities are 
determined) for which direct DOC measurement data are not available.
    (B) For years for which bulk waste disposal quantities are 
determined according to paragraphs (a)(2)(ii)(C) of this section, 
calculate the weighted average bulk DOC value according to the 
following: Calculate the average DOC value for each waste stream as the 
arithmetic average of all DOC measurements of that waste stream that 
follows the methods provided in Sec.  98.464(b) (generally, this will 
include only the DOC values determined in the first year in which GHG 
emissions from this industrial waste landfill must be reported); 
calculate the average annual disposal quantity for each waste stream as 
the arithmetic average of the annual disposal quantities for each year 
in which waste stream-specific disposal quantities have been 
determined; and calculate the bulk waste DOC value using Equation TT-5 
of this section. Use the bulk waste DOC value as DOCx for 
all years for which bulk waste disposal quantities are determined 
according to paragraphs (a)(2)(ii)(C) of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.024

Where:

DOCbulk = Degradable organic content value for bulk 
historical waste placed in the landfill (mass fraction).
N = Number of different waste streams placed in the landfill.
n = Index for waste stream.
DOCave,n = Average degradable organic content value for 
waste stream ``n'' based on available measurement data (mass 
fraction).
Wave,n = Average annual quantity of waste stream ``n'' 
placed in the landfill for years in which waste stream-specific 
disposal quantities have been determined (metric tons per year, wet 
basis).

    (b) For each landfill, calculate CH4 generation 
(adjusted for oxidation in cover materials) and CH4 
emissions (taking into account any CH4 recovery, if 
applicable, and oxidation in cover materials) according to the 
applicable methods in paragraphs (b)(1) through (b)(3) of this section.
    (1) For each landfill, calculate CH4 generation, 
adjusted for oxidation, from the modeled CH4 
(GCH4 from Equation TT-1 of this section) using Equation TT-
6 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.025

Where:

MG = Methane generation, adjusted for oxidation, from the landfill 
in the reporting year (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year 
from Equation TT-1 of this section (metric tons CH4).
OX = Oxidation fraction. Use the default value of 0.1 (10 percent).

    (2) For landfills that do not have landfill gas collection systems 
operating during the reporting year, the CH4 emissions are 
equal to the CH4 generation (MG) calculated in Equation TT-6 
of this section.

[[Page 39776]]

    (3) For landfills with landfill gas collection systems in operation 
during any portion of the reporting year, perform all of the 
calculations specified in paragraphs (b)(3)(i) through (iv) of this 
section.
    (i) Calculate the quantity of CH4 recovered according to 
the requirements at Sec.  98.343(b).
    (ii) Calculate CH4 emissions using the Equation HH-6 of 
Sec.  98.343(c)(3)(i), except use GCH4 determined using 
Equation TT-1 of this section in Equation HH-6 of Sec.  
98.343(c)(3)(i).
    (iii) Calculate CH4 generation (MG) from the quantity of 
CH4 recovered using Equation HH-7 of Sec.  98.343(c)(3)(ii).
    (iv) Calculate CH4 emissions from the quantity of 
CH4 recovered using Equation HH-8 of Sec.  98.343(c)(3)(ii).

Sec.  98.464  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, the facility may submit a 
request to the Administrator to use one or more best available 
monitoring methods as listed in Sec.  98.3(d)(1)(i) through (iv). The 
request must be submitted no later than October 12, 2010 and must 
contain the information in Sec.  98.3(d)(2)(ii). To obtain approval, 
the request must demonstrate to the Administrator's satisfaction that 
it is not reasonably feasible to acquire, install, and operate a 
required piece of monitoring equipment by January 1, 2011. The use of 
best available monitoring methods will not be approved beyond December 
31, 2011.
    (b) For each waste stream for which you choose to determine 
volatile solids concentration for the purposes of paragraph Sec.  
98.460(c)(2)(xii) or choose to determine a landfill-specific 
DOCx for use in Equation TT-1 of this subpart, you must 
collect and test a representative sample of that waste stream using the 
methods specified in paragraphs (b)(1) through (b)(4) of this section.
    (1) Develop and follow a sampling plan to collect a representative 
sample of each waste stream for which testing is elected.
    (2) Determine the percent total solids and the percent volatile 
solids of each sample following Standard Method 2540G ``Total, Fixed, 
and Volatile Solids in Solid and Semisolid Samples'' (incorporated by 
reference; see Sec.  98.7).
    (3) Calculate the volatile solids concentration (weight percent on 
a dry basis) using Equation TT-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.026

Where:

CVS = Volatile solids concentration in the waste stream 
(weight percent, dry basis).
% Volatile Solids = Percent volatile solids determined using 
Standard Method 2540G ``Total, Fixed, and Volatile Solids in Solid 
and Semisolid Samples'' (incorporated by reference; see Sec.  98.7).
% Total Solids = Percent total solids determined using Standard 
Method 2540G ``Total, Fixed, and Volatile Solids in Solid and 
Semisolid Samples'' (incorporated by reference; see Sec.  98.7).

    (4) Calculate the waste stream-specific DOCx value using 
Equation TT-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.027

Where:

DOCx = Degradable organic content of waste stream in Year 
X (weight fraction, wet basis)
FDOC = Fraction of the volatile residue that is 
degradable organic carbon (weight fraction). Use a default value of 
0.6.
% Volatile Solidsx = Percent volatile solids determined 
using Standard Method 2540G Total, ``Fixed, and Volatile Solids in 
Solid and Semisolid Samples'' (incorporated by reference; see Sec.  
98.7) for Year X.

    (c) For landfills with gas collection systems, operate, maintain, 
and calibrate a gas composition monitor capable of measuring the 
concentration of CH4 according to the requirements specified 
at Sec.  98.344(b).
    (d) For landfills with gas collection systems, install, operate, 
maintain, and calibrate a gas flow meter capable of measuring the 
volumetric flow rate of the recovered landfill gas according to the 
requirements specified at Sec.  98.344(c).
    (e) For landfills with gas collection systems, all temperature, 
pressure, and if applicable, moisture content monitors must be 
calibrated using the procedures and frequencies specified by the 
manufacturer.
    (f) The facility shall document the procedures used to ensure the 
accuracy of the estimates of disposal quantities and, if the industrial 
waste landfill has a gas collection system, gas flow rate, gas 
composition, temperature, pressure, and moisture content measurements. 
These procedures include, but are not limited to, calibration of 
weighing equipment, fuel flow meters, and other measurement devices. 
The estimated accuracy of measurements made with these devices shall 
also be recorded, and the technical basis for these estimates shall be 
provided.

Sec.  98.465  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, in accordance with paragraph (b) of this section.
    (b) For industrial waste landfills with gas collection systems, 
follow the procedures for estimating missing data specified in Sec.  
98.345(a) and (b).

Sec.  98.466  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for each landfill.
    (a) Report the following general landfill information:
    (1) A classification of the landfill as ``open'' (actively received 
waste in the reporting year) or ``closed'' (no longer receiving waste).
    (2) The year in which the landfill first started accepting waste 
for disposal.
    (3) The last year the landfill accepted waste (for open landfills, 
enter the estimated year of landfill closure).
    (4) The capacity (in metric tons) of the landfill.
    (5) An indication of whether leachate recirculation is used during 
the reporting year and its typical frequency of use over the past 10 
years (e.g., used several times a year for the past 10

[[Page 39777]]

years, used at least once a year for the past 10 years, used 
occasionally but not every year over the past 10 years, not used).
    (b) Report the following waste characterization information:
    (1) The number of waste steams (including ``Other Industrial Solid 
Waste (not otherwise listed)'') for which Equation TT-1 of this subpart 
is used to calculate modeled CH4 generation.
    (2) A description of each waste stream (including the types of 
materials in each waste stream).
    (c) For each waste stream identified in paragraph (b) of this 
section, report the following information:
    (1) The decay rate (k) value used in the calculations.
    (2) The method(s) for estimating historical waste disposal 
quantities and the range of years for which each method applies.
    (3) If Equation TT-2 of this subpart is used, provide:
    (i) The total number of years (N) for which disposal and production 
data are both available.
    (ii) The year, the waste disposal quantity and production quantity 
for each year Equation TT-2 of this subpart applies.
    (iii) The average waste disposal factor (WDF) calculated for the 
waste stream.
    (4) If Equation TT-4 of this subpart is used, provide:
    (i) The value of landfill capacity (LFC).
    (ii) YrData.
    (iii) YrOpen.
    (d) For each year of landfilling starting with the ``Start Year'' 
(S) to the current reporting year, report the following information:
    (1) The quantity of waste (Wx) disposed of in the 
landfill (metric tons, wet weight) for each waste stream identified in 
paragraph (b) of this section.
    (2) The degradable organic carbon (DOCx) value (mass 
fraction) and an indication as to whether this was the default value 
from Table TT-1 of this subpart or a value determined through sampling 
and calculation for each waste stream identified in paragraph (b) of 
this section.
    (3) The fraction of CH4 in the landfill gas (volume 
fraction, dry basis) and an indication as to whether this was the 
default value or a value determined through measurement data.
    (e) Report the following information describing the landfill cover 
material:
    (1) The type of cover material used (as either organic cover, clay 
cover, sand cover, or other soil mixtures).
    (2) For each type of cover material used, the surface area (in 
square meters) at the start of the reporting year for the landfill 
sections that contain waste and that are associated with the selected 
cover type.
    (f) The modeled annual methane generation rate for the reporting 
year (metric tons CH4) calculated using Equation TT-1 of 
this subpart.
    (g) For landfills without gas collection systems, provide:
    (1) The annual methane emissions (i.e., the methane generation, 
adjusted for oxidation, calculated using Equation TT-5 of this 
subpart), reported in metric tons CH4.
    (2) An indication of whether passive vents and/or passive flares 
(vents or flares that are not considered part of the gas collection 
system as defined in Sec.  98.6) are present at this landfill.
    (h) For landfills with gas collection systems, in addition to the 
reporting requirements in paragraphs (a) through (f) of this section, 
you must report according to Sec.  98.346(i).

Sec.  98.467  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration.

Sec.  98.468  Definitions.

    Except as provided below, all terms used in this subpart have the 
same meaning given in the CAA and subpart A of this part.
    Solid waste has the meaning established by the Administrator 
pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq.).
    Waste stream means industrial solid waste material that is 
generated by a specific manufacturing process or client. For wastes 
generated at the facility that includes the industrial waste landfill, 
a waste stream is the industrial solid waste material generated by a 
specific processing unit at that facility. For industrial solid wastes 
that are received from off-site facilities, a waste stream can be 
defined as each waste shipment or group of waste shipments received 
from a single client or group of clients that produce industrial solid 
wastes with similar waste properties.

           Table TT-1 to Subpart TT--Default DOC and Decay Rate Values for Industrial Waste Landfills
----------------------------------------------------------------------------------------------------------------
                                       DOC  (weight
        Industry/Waste Type           fraction, wet     k [dry climatea]      k [moderate       k [wet climatea]
                                          basis)             (yr-1)        climatea]  (yr-1)         (yr-1)
----------------------------------------------------------------------------------------------------------------
Food Processing...................               0.22               0.06                 0.12               0.18
Pulp and Paper....................               0.20               0.02                 0.03               0.04
Wood and Wood Product.............               0.43               0.02                 0.03               0.04
Construction and Demolition.......               0.04               0.02                 0.03               0.04
Inert Waste [i.e., wastes listed                    0                  0                    0                  0
 in Sec.   98.460(b)(3)]..........
Other Industrial Solid Waste (not                0.20               0.02                 0.04               0.06
 otherwise listed)................
----------------------------------------------------------------------------------------------------------------
a The applicable climate classification is determined based on the annual rainfall plus the recirculated
  leachate application rate. Recirculated leachate application rate (in inches/year) is the total volume of
  leachate recirculated and applied to the landfill divided by the area of the portion of the landfill
  containing waste [with appropriate unit conversions].
(1) Dry climate = precipitation plus recirculated leachate less than 20 inches/year.
(2) Moderate climate = precipitation plus recirculated leachate from 20 to 40 inches/year (inclusive).
(3) Wet climate = precipitation plus recirculated leachate greater than 40 inches/year.

[FR Doc. 2010-16488 Filed 7-9-10; 8:45 am]
BILLING CODE 6560-50-P