[Federal Register Volume 75, Number 132 (Monday, July 12, 2010)]
[Rules and Regulations]
[Pages 39736-39777]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-16488]
[[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
Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules
and Regulations
[[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:
[email protected]. 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
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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.
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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
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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
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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
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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