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.

                          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.

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

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

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

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

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),

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,<PHONE_NUMBER>; 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,<PHONE_NUMBER>, 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.

    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.

    (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.

    (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.

    (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.

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,

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

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.

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

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).

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

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).

    (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