40 CFR part 60, Appendix F, within eight hours of when the Coker unit
flue gases begin exhausting through the Coker CO Boiler stack and that
ExxonMobil shall perform an annual RATA on the flow and SO2
CEMS.
    We proposed that compliance with ExxonMobil's Coker CO Boiler
emission limits \18\ be determined using the data from the CEMS
mentioned above and in accordance with the appropriate calculations
described in ExxonMobil's 1998 exhibit.\19\ We also proposed reporting
requirements similar to the requirements adopted in the Billings/Laurel
SO2 SIP and those contained in 40 CFR 60.7(c). Our final FIP
is the same as proposed, except as noted above.
---------------------------------------------------------------------------

    \18\ See section 3(B)(1) of ExxonMobil's 2000. (See reference
document HH for a copy of the exhibit.)
    \19\ See sections 2(A)(1), (8), (11)(a), and (16) of
ExxonMobil's 1998 exhibit. (See reference document GG for a copy of
the exhibit.)
---------------------------------------------------------------------------

E. Montana Sulphur & Chemical Company (MSCC)

1. Flare Requirements
    We proposed that MSCC's 80-foot west flare, 125-foot east flare,
and 100-meter flare be limited to 150 pounds of SO2 per 3-
hour period combined total and that compliance with the limit be
determined as discussed above. Our final FIP is the same as proposed
except for the flare monitoring changes applicable to all sources
mentioned above.
2. SRU 100-Meter Stack
    We proposed the following emission limits for the SRU 100-meter
stack: Emissions of SO2 not to exceed (a) 3,003.1 pounds per
3-hour period, (b) 24,025.0 pounds per calendar day, and (c)
9,088,000.0 pounds per calendar year. Our final FIP is the same as
proposed except that the 3-hour and calendar day emission limits have
been slightly reduced due to minor corrections in the modeling. The
final FIP emission limits for the SRU 100-meter stack are as follows:
Emissions of SO2 shall not exceed (a) 2981.7 pounds per 3-
hour period, (b) 23,853.6 pounds per calendar day, and (c) 9,088,000.0
pounds per calendar year
    We proposed that compliance with the above emission limits be
determined according to the methods established in MSCC's 1998 exhibit.
Finally, we proposed quarterly reporting requirements similar to the
reporting requirements contained in the Billings/Laurel SO2
SIP and those contained in 40 CFR 60.7(c). Our final FIP is the same as
proposed, except as noted above.
3. SRU 30-Meter Stack
    We proposed the following mass emission limits for the 30-meter
stack: Emissions of SO2 not to exceed: (a) 12.0 pounds per
3-hour period, (b) 96.0

pounds per calendar day, and (c) 35,040 pounds per calendar year. The
mass emission limits remain the same as proposed.
    We proposed that H2S concentrations in the fuel burned
in the boilers and heaters, while any boiler or heater was exhausting
through the SRU 30-meter stack, be limited to 100 ppm of H2S
or less, averaged over a 3-hour period. While we proposed the foregoing
approach for determining compliance with the SRU 30-meter stack
emission limits, we also solicited input on whether we should
promulgate a different compliance determining method.
    In our final FIP, we are keeping the simplified method to determine
compliance with mass emission limits. However, we are increasing the
H2S concentration limit to 160 ppm/3-hour period and adding
a calendar day H2S concentration limit of 100 ppm.
    We proposed that the H2S concentration in the fuel be
measured using a portable H2S monitor. In our final FIP, we
have revised the method by which MSCC shall determine the
H2S content of the fuel burned. Specifically, our final FIP
indicates that MSCC shall determine the H2S content of the
fuel burned using length-of-stain detector tubes with the appropriate
sample tube range. The final FIP indicates that if the results exceed
the tube's range, another tube of a higher range must be used until
results are in the tube's range.
    Finally, we proposed quarterly reporting requirements. The
quarterly reporting requirements are similar to the reporting
requirements contained in the Billings/Laurel SO2 SIP and
those contained in 40 CFR 60.7(c). Our final FIP is the same as
proposed, except as needed to address the changes noted above.
4. Combined SO2 Emission Limit From the Auxiliary Vent
Stacks
    We proposed the following mass emission limits for the auxiliary
vent stacks: emissions of SO2 not to exceed: (a) 12.0 pounds
per 3-hour period, (b) 96.0 pounds per calendar day, and (c) 35,040
pounds per calendar year. The mass emission limits remain the same as
proposed. In our proposal, we indicated that the issues associated with
monitoring compliance with these limits were essentially the same as
those associated with monitoring compliance with the SRU 30-meter stack
emission limits. Thus, we proposed the same approach for monitoring
compliance with these emission limits as we describe in section
III.E.3, above. Similarly, we solicited input on whether we should
promulgate a different compliance determining method.
    In our final FIP, we are keeping the simplified method to determine
compliance with mass emission limits. However, we are increasing the
H2S concentration limit to 160 ppm/3-hour period and adding
a calendar day H2S concentration limit of 100 ppm.
    We proposed that the H2S concentration in the fuel be
measured using a portable H2S monitor. In our final FIP we
have revised the method by which MSCC shall determine the
H2S content of the fuel burned. Specifically, our final FIP
indicates that MSCC shall determine the H2S content of the
fuel burned using length-of-stain detector tubes with the appropriate
sample tube range. The final FIP indicates that if the results exceed
the tube's range, another tube of a higher range must be used until
results are in the tube's range.
    Finally, we proposed quarterly reporting requirements similar to
reporting requirements contained in the Billings/Laurel SO2
SIP and those contained in 40 CFR 60.7(c). Our final FIP is the same as
proposed, except as noted above.

F. Modeling To Support Emission Limits

    Our proposal discussed the modeling conducted to support the
emission limits proposed for MSCC's SRU 100-meter stack. EPA received
comments regarding our modeling files that identified the need for
minor technical corrections to those files. In response to several of
these comments, EPA has revised its modeling files, as necessary, to
omit extraneous information, add information that was inadvertently
omitted, make minor corrections, or otherwise clarify the files. EPA
does not consider any of the revisions to be significant. The only
change with any substantive impact--the correction to the coordinates
for MSCC described below--results in a very slight decrease in our
proposed emission limit for MSCC's 100-meter stack from 126.13 g/second
to125.23 g/second, less than a 1 percent change. The specific changes
EPA has made are as follows:
    (1) A commenter recommended that the modeling files contain a more
complete description of the naming convention and purpose behind each
modeling effort.
    EPA changes: To improve documentation, some extraneous modeling
files have been removed and a text file added to explain the naming
conventions. The naming conventions, typically used by modelers, help
define the purpose behind each modeling effort.
    (2) One commenter indicated that only proper geographical
coordinates should be used as inputs to the dispersion modeling.
Commenters indicated that the location of the small boiler stacks at
MSCC that were modeled as volume sources was incorrect.
    EPA changes: We have corrected the incorrect source coordinate for
MSCC's boiler stacks in the modeling files.
    (3) One commenter indicated that three source input files were not
included in reference document EEE.
    EPA change: We have added the three source input files to the
compact disk containing the modeling files.
    (4) One commenter indicated that a source input file (ref-5t.sri)
was included in reference document EEE but did not appear to be used in
any input and output files.
    EPA change: This was a test file that we inadvertently included and
have now deleted.
    On July 13, 2007, the revised modeling files were indexed in the
electronic docket contained on http://www.regulations.gov and a compact
disk containing the modeling files was placed in the docket for this
action. See reference document FFFFF.
    Also, as noted above, with respect to the 30-meter stack and
auxiliary vent stacks, we are keeping the simplified method to
determine compliance with the mass emission limits. However, we are
increasing the H2S concentration limit to 160 ppm/3-hour
period and adding a calendar day H2S concentration limit of
100 ppm. The mass emission limits remain the same as proposed.
    We remodeled the area assuming the emissions were 1.01 g/s from the
30-meter stack and auxiliary vent stacks. We derived the higher
emission value from the same assumptions and calculations expressed in
our proposal, except we assumed a maximum H2S concentration
of 160 ppm (see 71 FR 39259, 39268, July 12, 2006). At the higher 3-
hour emissions, the area would still show attainment of the 3-hour
SO2 NAAQS. However, the area would not show attainment of
the 24-hour SO2 NAAQS if all 8 3-hour periods in a calendar
day were at the 160 ppm level. Therefore, we are revising the FIP to
indicate that the H2S concentration in the fuel burned in
the heaters and boilers, while any of the heaters and boilers are
exhausting to the SRU 30-meter stack or auxiliary vents stacks, shall
not exceed 160 ppm per 3-hour period and 100 ppm per calendar day. The
revised modeling files are indexed in the electronic docket contained
on http://www.regulations.gov, and a

compact disk containing the modeling files was placed in the docket for
this action. See reference document KKKKKK.

IV. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review

    Under Executive Order 12866, 58 FR 51735 (October 4, 1993), all
``regulatory actions'' that are ``significant'' are subject to Office
of Management and Budget (OMB) review and the requirements of the
Executive Order. A ``regulatory action'' is defined as ``any
substantive action by an agency (normally published in the Federal
Register) that promulgates or is expected to result in the promulgation
of a final rule or regulation, including * * * notices of proposed
rulemaking.'' A ``regulation or rule'' is defined as ``an agency
statement of general applicability and future effect, * * * ''
    The FIP is not subject to OMB review under E.O. 12866 because it
applies to only four specifically named facilities, with requirements
unique to each facility, and is, therefore, not a rule of general
applicability. Thus, it is not a ``regulatory action'' under E.O. 12866
and was not submitted to OMB for review.

B. Paperwork Reduction Act

    This action does not impose an information collection burden under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
Burden is defined at 5 CFR 1320.3(b). Under the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq., OMB must approve all ``collections of
information'' by EPA. The Act defines ``collection of information'' as
a requirement for ``answers to * * * identical reporting or
recordkeeping requirements imposed on ten or more persons * * * '' 4
U.S.C. 3502(3)(A). Because the FIP only applies to four companies, the
Paperwork Reduction Act does not apply.

C. Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (RFA), 5 U.S.C. section 601 et
seq., EPA generally must prepare a regulatory flexibility analysis of
any rule subject to notice and comment rulemaking requirements unless
EPA certifies that the rule will not have a significant economic impact
on a substantial number of small entities. Small entities include small
businesses, small not-for-profit enterprises, and small governmental
jurisdictions. 5 U.S.C. 603, 604, and 605(b).
    This FIP will not have a significant economic impact on a
substantial number of small entities because this FIP applies to only
four sources (CHS Inc., ConocoPhillips, ExxonMobil and MSCC) in the
Billings/Laurel, Montana area. Therefore, I certify that this action
will not have a significant economic impact on a substantial number of
small entities.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995, Public Law 04
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 UMRA, EPA generally must
prepare a written statement, including a cost benefit analysis, for
proposed rules and for final rules with ``Federal mandates'' that may
result in the expenditure by State, local, and tribal governments, in
the aggregate, or by the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost effective, or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that might significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
    EPA has determined that this rule does not contain a Federal
mandate that may result in the expenditure of $100 million for State,
local and tribal governments, in the aggregate, or the private sector
in any one year. The FIP does not impose any enforceable duties on
state, local, or tribal governments. Although the FIP would impose
enforceable duties on entities in the private sector, the costs are
expected to be less than $100 million in any one year. Thus, today's
rule is not subject to the requirements of 202 and 205 of the UMRA.
    EPA has determined that this rule contains no regulatory
requirements that might significantly or uniquely affect small
governments, because it imposes no requirements on small governments.
Nor will the rule impact small governments in any significant or unique
way. Thus, today's rule is not subject to the requirements of section
203 of the UMRA.

E. Executive Order 13132, Federalism

    Executive Order, 13132, entitled ``Federalism'' (64 FR 43255,
August 10, 1999), requires EPA to develop an accountable process to
ensure ``meaningful and timely input by State and local officials in
the development of regulatory policies that have federalism
implications.'' ``Policies that have federalism implications'' include
regulations that 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.''
    The final rule does not have federalism implications. It will not
have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. This rule establishes standards
appropriate for four companies in the Billings/Laurel, Montana area,
and, thus, does not directly affect any State or local government. It
does not alter the relationship or the distribution of power and
responsibilities established by the Clean Air Act. Thus, Executive
Order 13132 does not apply to this rule.

F. Executive Order 13175, Coordination With Indian Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This final rule does not have
tribal implications, as specified in Executive Order 13175. It will not
have substantial, direct effects on tribal governments, on the
relationship between the Federal government and Indian tribes, or on
the distribution of power and responsibilities between the

Federal government and Indian tribes as specified in Executive Order
13175. This Action does not involve or impose any requirements that
affect Indian Tribes. Thus, Executive Order 13175 does not apply to
this rule.

G. Executive Order 13045, Protection of Children From Environmental
Health Risks and Safety Risks

    Executive Order 13045: ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997), applies
to any rule that: (1) Is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
    This FIP is not subject to the Executive Order because it is not
economically significant as defined in Executive Order 12866. Further,
EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Order has the
potential to influence the regulation. This FIP is not subject to
Executive Order 13045 because it implements a previously promulgated
health and safety-based Federal standard.

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

    This rule is not subject to Executive Order 13211, ``Actions
Concerning Regulations That Significantly Affect Energy Supply,
Distribution, or Use'' (66 FR 28355, May 22, 2001) because it is not a
significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    As noted in the proposed rule, Section 12(d) of the National
Technology Transfer and Advancement Act (NTTAA) of 1995, Public Law No.
104-113 (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 (VCS) are technical standards (e.g., materials
specifications, test methods, sampling procedures, business practices)
that are developed or adopted by voluntary consensus standards bodies.
The NTTAA directs EPA to provide Congress, through OMB, explanations
when the Agency decides not to use available and applicable voluntary
standards.
    This rulemaking involves technical standards. We have identified
three VCS that can be used in lieu of EPA methods. The American Society
for Testing and Materials (ASTM) Methods D4468-85 (Reapproved 2000) and
D5504-01 (Reapproved 2006) are acceptable methods for determining total
sulfur concentrations in the gas streams going to facility flares in
lieu of using a continuous total sulfur analyzer in accordance with 40
CFR part 60, Appendix B, Performance Specification 5. ASTM Method
D4810-06 is an acceptable method for determining the hydrogen sulfide
concentration in ExxonMobil's refinery fuel gas in lieu of using the
Tutwiler method described in 40 CFR 60.648. We are incorporating these
methods by reference in 40 CFR 52.1392(j).

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

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it increases the
level of environmental protection for all affected populations without
having any disproportionately high and adverse human health or
environmental effects on any population, including any minority or low-
income population. This final rule establishes emission limits and
compliance determining methods at four sources in the Billings/Laurel,
Montana area to assure that the SO2 NAAQS are met.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. section 801 et seq., as
added by the Small Business Regulatory Enforcement Fairness Act of
1996, 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. Section 804 exempts from section 801 the
following types of rules: (1) Rules of particular applicability; (2)
rules relating to agency management or personnel; and (3) rules of
agency organization, procedure, or practice that do not substantially
affect the rights or obligations of non-agency parties. 5 U.S.C.
804(3). EPA is not required to submit a rule report regarding today's
action under section 801 because this is a rule of particular
applicability; it only applies to four specifically named sources, with
requirements unique to each facility.

L. Petitions for Judicial Review

    Under section 307(b)(1) of the Clean Air Act, petitions for
judicial review of this action must be filed in the United States Court
of Appeals for the appropriate circuit by June 20, 2008. Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this rule for the purposes of judicial
review nor does it extend the time within which a petition for judicial
review may be filed, and shall not postpone the effectiveness of such
rule or action. This action may not be challenged later in proceedings
to enforce its requirements. (See CAA section 307(b)(2).)

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements, Sulfur oxides.

    Dated: March 28, 2008.
Stephen L. Johnson,
Administrator.

0
For reasons stated in the preamble, 40 CFR part 52 is amended as
follows:

PART 52--[AMENDED]

0
1. The authority citation for part 52 continues to read as follows:

    Authority: 42 U.S.C. 7401 et seq.

Subpart BB--Montana

0
2. Subpart BB is amended by adding Sec.  52.1392 to read as follows:

Sec.  52.1392  Federal Implementation Plan for the Billings/Laurel
Area.

    (a) Applicability. This section applies to the owner(s) or
operator(s), including any new owner(s) or operator(s) in the

event of a change in ownership or operation, of the following
facilities in the Billings/Laurel, Montana area: CHS Inc. Petroleum
Refinery, Laurel Refinery, 803 Highway 212 South, Laurel, MT;
ConocoPhillips Petroleum Refinery, Billings Refinery, 401 South 23rd
St., Billings, MT; ExxonMobil Petroleum Refinery, 700 Exxon Road,
Billings, MT; and Montana Sulphur & Chemical Company, 627 Exxon Road,
Billings, MT.
    (b) Scope. The facilities listed in paragraph (a) of this section
are also subject to the Billings/Laurel SO2 SIP, as approved
at 40 CFR 52.1370(c)(46) and (52). In cases where the provisions of
this FIP address emissions activities differently or establish a
different requirement than the provisions of the approved SIP, the
provisions of this FIP take precedence.
    (c) Definitions. For the purpose of this section, we are defining
certain words or initials as described in this paragraph. Terms not
defined below that are defined in the Clean Air Act or regulations
implementing the Clean Air Act, shall have the meaning set forth in the
Clean Air Act or such regulations.
    (1) Aliquot means a fractional part of a sample that is an exact
divisor of the whole sample.
    (2) Annual Emissions means the amount of SO2 emitted in
a calendar year, expressed in pounds per year rounded to the nearest
pound, where:

Annual emissions = [Sigma] Daily emissions within the calendar year.

    (3) Calendar Day means a 24-hour period starting at 12 midnight and
ending at 12 midnight, 24 hours later.
    (4) Clock Hour means a twenty-fourth (\1/24\) of a calendar day;
specifically any of the standard 60-minute periods in a day that are
identified and separated on a clock by the whole numbers one (1)
through 12.
    (5) Continuous Emission Monitoring System or CEMS means all
continuous concentration and volumetric flow rate monitors, associated
data acquisition equipment, and all other equipment necessary to meet
the requirements of this section for continuous monitoring.
    (6) Daily Emissions means the amount of SO2 emitted in a
calendar day, expressed in pounds per day rounded to the nearest tenth
(\1/10\) of a pound, where:

Daily emissions = [Sigma] 3-hour emissions within a calendar day.

    (7) EPA means the United States Environmental Protection Agency.
    (8) Exhibit means for a given facility named in paragraph (a) of
this section, exhibit A to the stipulation of the Montana Department of
Environmental Quality and that facility, adopted by the Montana Board
of Environmental Review on either June 12, 1998, or March 17, 2000.
    (9) 1998 Exhibit means for a given facility named in paragraph (a)
of this section, the exhibit adopted by the Montana Board of
Environmental Review on June 12, 1998.
    (10) 2000 Exhibit means for a given facility named in paragraph (a)
of this section, the exhibit adopted by the Montana Board of
Environmental Review on March 17, 2000.
    (11) Flare means a combustion device that uses an open flame to
burn combustible gases with combustion air provided by uncontrolled
ambient air around the flame. This term includes both ground and
elevated flares.
    (12) The initials Hg mean mercury.
    (13) Hourly means or refers to each clock hour in a calendar day.
    (14) Hourly Average means an arithmetic average of all valid and
complete 15-minute data blocks in a clock hour. Four (4) valid and
complete 15-minute data blocks are required to determine an hourly
average for each CEMS per clock hour.
    Exclusive of the above definition, an hourly CEMS average may be
determined with two (2) valid and complete 15-minute data blocks, for
two (2) of the 24 hours in any calendar day. A complete 15-minute data
block for each CEMS shall have a minimum of one (1) data point value;
however, each CEMS shall be operated such that all valid data points
acquired in any 15-minute block shall be used to determine the 15-
minute block's reported concentration and flow rate.
    (15) Hourly Emissions means the pounds per clock hour of
SO2 emissions from a source (including, but not limited to,
a flare, stack, fuel oil system, sour water system, or fuel gas system)
determined using hourly averages and rounded to the nearest tenth (\1/
10\) of a pound.
    (16) The initials H2S mean hydrogen sulfide.
    (17) Integrated sampling means an automated method of obtaining a
sample from the gas stream to the flare that produces a composite
sample of individual aliquots taken over time.
    (18) The initials MBER mean the Montana Board of Environmental
Review.
    (19) The initials MDEQ mean the Montana Department of Environmental
Quality.
    (20) The initials mm mean millimeters.
    (21) The initials MSCC mean the Montana Sulphur & Chemical Company.
    (22) Pilot gas means the gas used to maintain the presence of a
flame for ignition of gases routed to a flare.
    (23) Purge gas means a continuous gas stream introduced into a
flare header, flare stack, and/or flare tip for the purpose of
maintaining a positive flow that prevents the formation of an explosive
mixture due to ambient air ingress.
    (24) The initials ppm mean parts per million.
    (25) The initials SCFH mean standard cubic feet per hour.
    (26) The initials SCFM mean standard cubic feet per minute.
    (27) Standard Conditions means (a) 20 [deg]C (293.2 [deg]K, 527.7
[deg]R, or 68.0 [deg]F) and one (1) atmosphere pressure (29.92 inches
Hg or 760 mm Hg) for stack and flare gas emission calculations, and (b)
15.6 [deg]C (288.7 [deg]K, 520.0 [deg]R, or 60.3 [deg]F) and one (1)
atmosphere pressure (29.92 inches Hg or 760 mm Hg) for refinery fuel
gas emission calculations.
    (28) The initials SO2 mean sulfur dioxide.
    (29) The initials SWS mean sour water stripper.
    (30) The term 3-hour emissions means the amount of SO2
emitted in each of the eight (8) non-overlapping 3-hour periods in a
calendar day, expressed in pounds and rounded to the nearest tenth (\1/
10\) of a pound, where:

3 hour emissions = [Sigma] Hourly emissions within the 3-hour period.

    (31) The term 3-hour period means any of the eight (8) non-
overlapping 3-hour periods in a calendar day: Midnight to 3 a.m., 3
a.m. to 6 a.m., 6 a.m. to 9 a.m., 9 a.m. to noon, noon to 3 p.m., 3
p.m. to 6 p.m., 6 p.m. to 9 p.m., 9 p.m. to midnight.
    (32) Turnaround means a planned activity involving shutdown and
startup of one or several process units for the purpose of performing
periodic maintenance, repair, replacement of equipment, or installation
of new equipment.
    (33) Valid means data that are obtained from a monitor or meter
serving as a component of a CEMS which meets the applicable
specifications, operating requirements, and quality assurance and
control requirements of section 6 of ConocoPhillips', CHS Inc.'s,
ExxonMobil's, and MSCC's 1998 exhibits, respectively, and this section.
    (d) CHS Inc. emission limits and compliance determining methods.
    (1) Introduction. The provisions for CHS Inc. cover the following
units:
    (i) The flare.
    (ii) Combustion sources, which consist of those sources identified
in the

combustion sources emission limit in section 3(A)(1)(d) of CHS Inc.'s
1998 exhibit.
    (2) Flare requirements.
    (i) Emission limit. The total emissions of SO2 from the
flare shall not exceed 150.0 pounds per 3-hour period.
    (ii) Compliance determining method. Compliance with the emission
limit in paragraph (d)(2)(i) of this section shall be determined in
accordance with paragraph (h) of this section.
    (3) Combustion sources.
    (i) Restrictions. Sour water stripper overheads (ammonia
(NH3) and H2S gases removed from the sour water
in the sour water stripper) shall not be burned in the main crude
heater. At all times, CHS Inc. shall keep a chain and lock on the valve
that supplies sour water stripper overheads from the old sour water
stripper to the main crude heater and shall keep such valve closed.
    (ii) Compliance determining method. CHS Inc. shall log and report
any noncompliance with the requirements of paragraph (d)(3)(i) of this
section.
    (4) Data reporting requirements.
    (i) CHS Inc. shall submit quarterly reports beginning with the
first calendar quarter following May 21, 2008. The quarterly reports
shall be submitted within 30 days of the end of each calendar quarter.
The quarterly reports shall be submitted to EPA at the following
address: Air Program Contact, EPA Montana Operations Office, Federal
Building, 10 West 15th Street, Suite 3200, Helena, MT 59626.
    The quarterly report shall be certified for accuracy in writing by
a responsible CHS Inc. official. The quarterly report shall consist of
both a comprehensive electronic-magnetic report and a written hard copy
data summary report.
    (ii) The electronic report shall be on magnetic or optical media,
and such submittal shall follow the reporting format of electronic data
being submitted to the MDEQ. EPA may modify the reporting format
delineated in this section, and, thereafter, CHS Inc. shall follow the
revised format. In addition to submitting the electronic quarterly
reports to EPA, CHS Inc. shall also record, organize, and archive for
at least five (5) years the same data, and upon request by EPA, CHS
Inc. shall provide EPA with any data archived in accordance with this
provision. The electronic report shall contain the following:
    (A) Hourly average total sulfur concentrations as H2S or
SO2 in ppm in the gas stream to the flare;
    (B) Hourly average H2S concentrations of the flare pilot
and purge gases in ppm;
    (C) Hourly average volumetric flow rates in SCFH of the gas stream
to the flare;
    (D) Hourly average volumetric flow rates in SCFH of the flare pilot
and purge gases;
    (E) Hourly average temperature (in [deg]F) and pressure (in mm or
inches of Hg) of the gas stream to the flare;
    (F) Hourly emissions from the flare in pounds per clock hour; and
    (G) Daily calibration data for all flare, pilot gas, and purge gas
CEMS.
    (iii) The quarterly written report shall contain the following
information:
    (A) The 3-hour emissions in pounds per 3-hour period from each
flare;
    (B) Periods in which only natural gas or an inert gas was used as
flare pilot gas or purge gas or both;
    (C) The results of all quarterly Cylinder Gas Audits (CGA),
Relative Accuracy Audits (RAA), and annual Relative Accuracy Test
Audits (RATA) for all total sulfur analyzer(s) and H2S
analyzer(s), and the results of all annual calibrations and
verifications for the volumetric flow, temperature, and pressure
monitors;
    (D) For all periods of flare volumetric flow rate monitoring system
or total sulfur analyzer system downtime, flare pilot gas or purge gas
volumetric flow or H2S analyzer system downtime, or failure
to obtain or analyze a grab or integrated sample, the written report
shall identify:
    (1) Dates and times of downtime or failure;
    (2) Reasons for downtime or failure;
    (3) Corrective actions taken to mitigate downtime or failure; and
    (4) The other methods, approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section, used to determine flare
emissions;
    (E) For all periods that the range of the flare or any pilot or
purge gas volumetric flow rate monitor(s), any flare total sulfur
analyzer(s), or any pilot or purge gas H2S analyzer(s) is
exceeded, the written report shall identify:
    (1) Date and time when the range of the volumetric flow monitor(s),
total sulfur analyzer(s), or H2S analyzer(s) was exceeded;
and
    (2) The other methods, approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section, used to determine flare
emissions;
    (F) For all periods that the flare volumetric flow monitor or
monitors are recording flow, yet any Flare Water Seal Monitoring Device
indicates there is no flow, the written report shall identify:
    (1) Date, time, and duration when the flare volumetric flow
monitor(s) recorded flow, yet any Flare Water Seal Monitoring Device
indicated there was no flow;
    (G) For each 3-hour period in which the flare emission limit is
exceeded, the written report shall identify:
    (1) The date, start time, and end time of the excess emissions;
    (2) Total hours of operation with excess emissions, the hourly
emissions, and the 3-hour emissions;
    (3) All information regarding reasons for operating with excess
emissions; and
    (4) Corrective actions taken to mitigate excess emissions;
    (H) The date and time of any noncompliance with the requirements of
paragraph (d)(3)(i) of this section; and
    (I) When no excess emissions have occurred or the continuous
monitoring system(s) or manual system(s) have not been inoperative,
repaired, or adjusted, such information shall be stated in the report.
    (e) ConocoPhillips emission limits and compliance determining
methods.
    (1) Introduction. The provisions for ConocoPhillips cover the
following units:
    (i) The main flare, which consists of two flares--the north flare
and the south flare--that are operated on alternating schedules. These
flares are referred to herein as the north main flare and south main
flare, or generically as the main flare.
    (ii) The Jupiter Sulfur SRU flare, which is the flare at Jupiter
Sulfur, ConocoPhillips' sulfur recovery unit.
    (2) Flare requirements.
    (i) Emission limits.
    (A) Combined emissions of SO2 from the main flare (which
can be emitted from either the north or south main flare, but not both
at the same time) shall not exceed 150.0 pounds per 3-hour period.
    (B) Emissions of SO2 from the Jupiter Sulfur SRU flare
and the Jupiter Sulfur SRU/ATS stack (also referred to as the Jupiter
Sulfur SRU stack) shall not exceed 75.0 pounds per 3-hour period, 600.0
pounds per calendar day, and 219,000 pounds per calendar year.
    (ii) Compliance determining method.
    (A) Compliance with the emission limit in paragraph (e)(2)(i)(A) of
this section shall be determined in accordance with paragraph (h) of
this section. In the event that a single monitoring location cannot be
used for both the north and south main flare, ConocoPhillips shall
monitor the flow and measure the total sulfur concentration at more
than one location in order to determine compliance with the main flare
emission limit. ConocoPhillips shall log and report any instances when
emissions are vented

from the north main flare and south main flare simultaneously.
    (B) Compliance with the emission limits and requirements in
paragraph (e)(2)(i)(B) of this section shall be determined by summing
the emissions from the Jupiter Sulfur SRU flare and SRU/ATS stack.
Emissions from the Jupiter Sulfur SRU flare shall be determined in
accordance with paragraph (h) of this section and the emissions from
the Jupiter Sulfur SRU/ATS stack shall be determined pursuant to
ConocoPhillips' 1998 exhibit (see section 4(A) of the exhibit).
    (3) Data reporting requirements.
    (i) ConocoPhillips shall submit quarterly reports on a calendar
year basis, beginning with the first calendar quarter following May 21,
2008. The quarterly reports shall be submitted within 30 days of the
end of each calendar quarter. The quarterly reports shall be submitted
to EPA at the following address: Air Program Contact, EPA Montana
Operations Office, Federal Building, 10 West 15th Street, Suite 3200,
Helena, MT 59626.
    The quarterly report shall be certified for accuracy in writing by
a responsible ConocoPhillips official. The quarterly report shall
consist of both a comprehensive electronic-magnetic report and a
written hard copy data summary report.
    (ii) The electronic report shall be on magnetic or optical media,
and such submittal shall follow the reporting format of electronic data
being submitted to the MDEQ. EPA may modify the reporting format
delineated in this section, and, thereafter, ConocoPhillips shall
follow the revised format. In addition to submitting the electronic
quarterly reports to EPA, ConocoPhillips shall also record, organize,
and archive for at least five (5) years the same data, and upon request
by EPA, ConocoPhillips shall provide EPA with any data archived in
accordance with this provision. The electronic report shall contain the
following:
    (A) Hourly average total sulfur concentrations as H2S or
SO2 in ppm in the gas stream to the ConocoPhillips main
flare and Jupiter Sulfur SRU flare;
    (B) Hourly average H2S concentrations of the
ConocoPhillips main flare and Jupiter Sulfur SRU flare pilot and purge
gases in ppm;
    (C) Hourly average volumetric flow rates in SCFH of the gas streams
to the ConocoPhillips main flare and Jupiter Sulfur SRU flare;
    (D) Hourly average volumetric flow rates in SCFH of the
ConocoPhillips main flare and Jupiter Sulfur SRU flare pilot and purge
gases;
    (E) Hourly average temperature (in [deg]F) and pressure (in mm or
inches of Hg) of the gas streams to the ConocoPhillips main flare and
Jupiter Sulfur SRU flare;
    (F) Hourly emissions in pounds per clock hour from the
ConocoPhillips main flare and Jupiter Sulfur SRU flare; and
    (G) Daily calibration data for all flare, pilot gas, and purge gas
CEMS.
    (iii) The quarterly written report shall contain the following
information:
    (A) The 3-hour emissions in pounds per 3-hour period from the
ConocoPhillips main flare and the sum of the combined 3-hour emissions
from the Jupiter Sulfur SRU/ATS stack and Jupiter Sulfur SRU flare in
pounds per 3-hour period;
    (B) Periods in which only natural gas or an inert gas was used as
flare pilot gas or purge gas or both;
    (C) The results of all quarterly Cylinder Gas Audits (CGA),
Relative Accuracy Audits (RAA), and annual Relative Accuracy Test
Audits (RATA) for all total sulfur analyzer(s) and H2S
analyzer(s), and the results of all annual calibrations and
verifications for the volumetric flow, temperature, and pressure
monitors;
    (D) For all periods of flare volumetric flow rate monitoring system
or total sulfur analyzer system downtime, flare pilot gas or purge gas
volumetric flow or H2S analyzer system downtime, or failure
to obtain or analyze a grab or integrated sample, the written report
shall identify:
    (1) Dates and times of downtime or failure;
    (2) Reasons for downtime or failure;
    (3) Corrective actions taken to mitigate downtime or failure; and
    (4) The other methods, approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section, used to determine flare
emissions;
    (E) For all periods that the range of the flare or any pilot or
purge gas volumetric flow rate monitor(s), any flare total sulfur
analyzer(s), or any pilot or purge gas H2S analyzer(s) is
exceeded, the written report shall identify:
    (1) Date and time when the range of the volumetric flow monitor(s),
total sulfur analyzer(s), or H2S analyzer(s) was exceeded,
and
    (2) The other methods, approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section, used to determine flare
emissions;
    (F) For all periods that the flare volumetric flow monitor or
monitors are recording flow, yet any Flare Water Seal Monitoring Device
indicates there is no flow, the written report shall identify:
    (1) Date, time, and duration when the flare volumetric flow
monitor(s) recorded flow, yet any Flare Water Seal Monitoring Device
indicated there was no flow;
    (G) Identification of dates, times, and duration of any instances
when emissions were vented from the north and south main flares
simultaneously;
    (H) For each 3-hour period in which a flare emission limit is
exceeded, the written report shall identify:
    (1) The date, start time, and end time of the excess emissions;
    (2) Total hours of operation with excess emissions, the hourly
emissions, and the 3-hour emissions;
    (3) All information regarding reasons for operating with excess
emissions; and
    (4) Corrective actions taken to mitigate excess emissions; and
    (I) When no excess emissions have occurred or the continuous
monitoring system(s) or manual system(s) have not been inoperative,
repaired, or adjusted, such information shall be stated in the report.
    (f) ExxonMobil emission limits and compliance determining methods.
    (1) Introduction. The provisions for ExxonMobil cover the following
units:
    (i) The Primary process flare and the Turnaround flare. The Primary
process flare is the flare normally used by ExxonMobil. The Turnaround
flare is the flare ExxonMobil uses for about 30 to 40 days every 5 to 6
years when the facility's major SO2 source, the fluid
catalytic cracking unit, is not normally operating.
    (ii) The following refinery fuel gas combustion units: The FCC CO
Boiler, F-2 crude/vacuum heater, F-3 unit, F-3X unit, F-5 unit, F-700
unit, F-201 unit, F-202 unit, F-402 unit, F-551 unit, F-651 unit,
standby boiler house (B-8 boiler), and Coker CO Boiler (only when the
Yellowstone Energy Limited Partnership (YELP) facility is receiving
ExxonMobil Coker unit flue gas or whenever the ExxonMobil Coker is not
operating).
    (iii) Coker CO Boiler stack.
    (2) Flare requirements.
    (i) Emission limit. The total combined emissions of SO2
from the Primary process and Turnaround refinery flares shall not
exceed 150.0 pounds per 3-hour period.
    (ii) Compliance determining method. Compliance with the emission
limit in paragraph (f)(2)(i) of this section shall be determined in
accordance with paragraph (h) of this section. If volumetric flow
monitoring device(s) installed and concentration monitoring methods
used to measure the gas stream

to the Primary Process flare cannot measure the gas stream to the
Turnaround flare, ExxonMobil may apply to EPA for alternative measures
to determine the volumetric flow rate and total sulfur concentration of
the gas stream to the Turnaround flare. Before EPA will approve such
alternative measures, ExxonMobil must agree that the Turnaround flare
will be used only during refinery turnarounds of limited duration and
frequency--no more than 60 days once every five (5) years--which
restriction shall be considered an enforceable part of this FIP. Such
alternative measures may consist of reliable flow estimation parameters
to estimate volumetric flow rate and manual sampling of the gas stream
to the flare to determine total sulfur concentrations, or such other
measures that EPA finds will provide accurate estimations of
SO2 emissions from the Turnaround flare.
    (3) Refinery fuel gas combustion requirements.
    (i) Emission limits. The applicable emission limits are contained
in section 3(A)(1) of ExxonMobil's 2000 exhibit and section 3(B)(2) of
ExxonMobil's 1998 exhibit.
    (ii) Compliance determining method. For the limits referenced in
paragraph (f)(3)(i) of this section, the compliance determining methods
specified in section 4(B) of ExxonMobil's 1998 exhibit shall be
followed except when the H2S concentration in the refinery
fuel gas stream exceeds 1200 ppmv as measured by the H2S
CEMS required by section 6(B)(3) of ExxonMobil's 1998 exhibit (the
H2S CEMS.) When such value is exceeded, the following
compliance monitoring method shall be employed:
    (A) ExxonMobil shall measure the H2S concentration in
the refinery fuel gas according to the procedures in paragraph
(f)(3)(ii)(B) of this section and calculate the emissions according to
the equations in paragraph (f)(3)(ii)(C) of this section.
    (B) Within four (4) hours after the H2S CEMS measures an
H2S concentration in the refinery fuel gas stream greater
than 1200 ppmv, ExxonMobil shall initiate sampling of the refinery fuel
gas stream at the fuel header on a once-per-hour frequency using
length-of-stain detector tubes pursuant to ASTM Method D4810-06,
``Standard Test Method for Hydrogen Sulfide in Natural Gas Using
Length-of-Stain Detector Tubes'' (incorporated by reference, see
paragraph (j) of this section) with the appropriate sample tube range.
If the results exceed the tube's range, another tube of a higher range
must be used until results are in the tube's range. ExxonMobil shall
continue to use the length-of-stain detector tube method at this
frequency until the H2S CEMS measures an H2S
concentration in the refinery fuel gas stream equal to or less than
1200 ppmv continuously over a 3-hour period.
    (C) When the length-of-stain detector tube method is required,
SO2 emissions from refinery fuel gas combustion shall be
calculated as follows: the Hourly emissions shall be calculated using
equation 1, 3-hour emissions shall be calculated using equation 2, and
the Daily emissions shall be calculated using equation 3.

Equation 1: EH = K * CH * QH

Where:

EH = Refinery fuel gas combustion hourly emissions in
pounds per hour, rounded to the nearest tenth of a pound;
K= 1.688 x 10-\7\ in (pounds/standard cubic feet (SCF))/
parts per million (ppm);
CH = Hourly refinery fuel gas H2S
concentration in ppm determined by the length-of-stain detector tube
method as required by paragraph (f)(3)(ii)(B) of this section; and
QH = actual fuel gas firing rate in standard cubic feet
per hour (SCFH), as measured by the monitor required by section
6(B)(8) of ExxonMobil's 1998 exhibit.

Equation 2: (Refinery fuel gas combustion 3-hour emissions) = [Sigma]
(Hourly emissions within the 3-hour period as determined by equation
1).
Equation 3: (Refinery fuel gas combustion daily emissions) = [Sigma]
(3-hour emissions within the day as determined by equation 2).

    (4) Coker CO Boiler stack requirements.
    (i) Emission limits. When ExxonMobil's Coker unit is operating and
Coker unit flue gases are burned in the Coker CO Boiler, the applicable
emission limits are contained in section 3(B)(1) of ExxonMobil's 2000
exhibit.
    (ii) Compliance determining method.
    (A) Compliance with the emission limits referenced in paragraph
(f)(4)(i) of this section shall be determined by measuring the
SO2 concentration and flow rate in the Coker CO Boiler stack
according to the procedures in paragraphs (f)(4)(ii)(B) and (C) of this
section and calculating emissions according to the equations in
paragraph (f)(4)(ii)(D) of this section.
    (B) Beginning on May 21, 2008, ExxonMobil shall operate and
maintain a CEMS to measure sulfur dioxide concentrations in the Coker
CO Boiler stack. Whenever ExxonMobil's Coker unit is operating and
Coker unit flue gases are exhausted through the Coker CO Boiler stack,
the CEMS shall be operational and shall achieve a temporal sampling
resolution of at least one (1) concentration measurement per minute,
meet the requirements expressed in the definition of ``hourly average''
in paragraph (c)(14) of this section, and meet the CEMS Performance
Specifications contained in section 6(C) of ExxonMobil's 1998 exhibit,
except that ExxonMobil shall perform a Cylinder Gas Audit (CGA) or
Relative Accuracy Audit (RAA) which meets the requirements of 40 CFR
part 60, Appendix F, within eight (8) hours of when the Coker unit flue
gases begin exhausting through the Coker CO Boiler stack. ExxonMobil
shall perform an annual Relative Accuracy Test Audit (RATA) on the CEMS
and notify EPA in writing of each annual RATA a minimum of 25 working
days prior to actual testing.
    (C) Beginning on May 21, 2008, ExxonMobil shall operate and
maintain a continuous stack flow rate monitor to measure the stack gas
flow rates in the Coker CO Boiler stack. Whenever ExxonMobil's Coker
unit is operating and Coker unit flue gases are exhausted through the
Coker CO Boiler stack, this CEMS shall be operational and shall achieve
a temporal sampling resolution of at least one (1) flow rate
measurement per minute, meet the requirements expressed in the
definition of ``hourly average'' in paragraph (c)(14) of this section,
and meet the Stack Gas Flow Rate Monitor Performance Specifications of
section 6(D) of ExxonMobil's 1998 exhibit, except that ExxonMobil shall
perform an annual Relative Accuracy Test Audit (RATA) on the CEMS and
notify EPA in writing of each annual RATA a minimum of 25 working days
prior to actual testing.
    (D) SO2 emissions from the Coker CO Boiler stack shall
be determined in accordance with the equations in sections 2(A)(1),
(8), (11)(a), and (16) of ExxonMobil's 1998 exhibit.
    (5) Data reporting requirements.
    (i) ExxonMobil shall submit quarterly reports beginning with the
first calendar quarter following May 21, 2008. The quarterly reports
shall be submitted within 30 days of the end of each calendar quarter.
The quarterly reports shall be submitted to EPA at the following
address: Air Program Contact, EPA Montana Operations Office, Federal
Building, 10 West 15th Street, Suite 3200, Helena, MT 59626.
    The quarterly report shall be certified for accuracy in writing by
a responsible ExxonMobil official. The quarterly report shall consist
of both a comprehensive electronic-magnetic report and a written hard
copy data summary report.

    (ii) The electronic report shall be on magnetic or optical media,
and such submittal shall follow the reporting format of electronic data
being submitted to the MDEQ. EPA may modify the reporting format
delineated in this section, and, thereafter, ExxonMobil shall follow
the revised format. In addition to submitting the electronic quarterly
reports to EPA, ExxonMobil shall also record, organize, and archive for
at least five (5) years the same data, and upon request by EPA,
ExxonMobil shall provide EPA with any data archived in accordance with
this provision. The electronic report shall contain the following:
    (A) Hourly average total sulfur concentrations as H2S or
SO2 in ppm in the gas stream to the flare(s);
    (B) Hourly average H2S concentrations of the flare pilot
and purge gases in ppm;
    (C) Hourly average SO2 concentrations in ppm from the
Coker CO Boiler stack;
    (D) Hourly average volumetric flow rates in SCFH of the flare pilot
and purge gases;
    (E) Hourly average volumetric flow rates in SCFH in the gas stream
to the flare(s) and in the Coker CO Boiler stack;
    (F) Hourly average H2S concentrations in ppm from the
refinery fuel gas system;
    (G) Hourly average refinery fuel gas combustion units' actual fuel
firing rate in SCFH;
    (H) Hourly average temperature (in [deg]F) and pressure (in mm or
inches of Hg) of the gas stream to the flare(s);
    (I) Hourly emissions in pounds per clock hour from the flare(s),
Coker CO Boiler stack, and refinery fuel gas combustion system; and
    (J) Daily calibration data for the CEMS described in paragraphs
(f)(2)(ii), (f)(3)(ii) and (f)(4)(ii) of this section.
    (iii) The quarterly written report shall contain the following
information:
    (A) The 3-hour emissions in pounds per 3-hour period from the
flare(s), Coker CO Boiler stack, and refinery fuel gas combustion
system;
    (B) Periods in which only natural gas or an inert gas was used as
flare pilot gas or purge gas or both;
    (C) Daily emissions in pounds per calendar day from the Coker CO
Boiler stack and refinery fuel gas combustion system;
    (D) The results of all quarterly or other Cylinder Gas Audits
(CGA), Relative Accuracy Audits (RAA), and annual Relative Accuracy
Test Audits (RATA) for the CEMS described in paragraphs (f)(2)(ii)
(flare total sulfur analyzer(s); pilot gas or purge gas H2S
analyzer(s)), (f)(3)(ii), and (f)(4)(ii) of this section, and the
results of all annual calibrations and verifications for the volumetric
flow, temperature, and pressure monitors;
    (E) For all periods of flare volumetric flow rate monitoring system
or total sulfur analyzer system downtime, Coker CO Boiler stack CEMS
downtime, refinery fuel gas combustion system CEMS downtime, flare
pilot gas or purge gas volumetric flow or H2S analyzer
system downtime, or failure to obtain or analyze a grab or integrated
sample, the written report shall identify:
    (1) Dates and times of downtime or failure;
    (2) Reasons for downtime or failure;
    (3) Corrective actions taken to mitigate downtime or failure; and
    (4) The other methods, approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section, used to determine flare
emissions;
    (F) For all periods that the range of the flare or any pilot or
purge gas volumetric flow rate monitor(s), any flare total sulfur
analyzer(s), or any pilot or purge gas H2S analyzer(s) is
exceeded, the written report shall identify:
    (1) Date and time when the range of the volumetric flow monitor(s),
total sulfur analyzer(s), or H2S analyzer(s) was exceeded,
and
    (2) The other methods, approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section, used to determine flare
emissions;
    (G) For all periods that the range of the refinery fuel gas CEMS is
exceeded, the written report shall identify:
    (1) Date, time, and duration when the range of the refinery fuel
gas CEMS was exceeded;
    (H) For all periods that the flare volumetric flow monitor or
monitors are recording flow, yet any Flare Water Seal Monitoring Device
indicates there is no flow, the written report shall identify:
    (1) Date, time, and duration when the flare volumetric flow
monitor(s) recorded flow, yet any Flare Water Seal Monitoring Device
indicated there was no flow;
    (I) For each 3-hour period and calendar day in which the flare
emission limits, the Coker CO Boiler stack emission limits, or the fuel
gas combustion system emission limits are exceeded, the written report
shall identify:
    (1) The date, start time, and end time of the excess emissions;
    (2) Total hours of operation with excess emissions, the hourly
emissions, the 3-hour emissions, and the daily emissions;
    (3) All information regarding reasons for operating with excess
emissions; and
    (4) Corrective actions taken to mitigate excess emissions; and
    (J) When no excess emissions have occurred or the continuous
monitoring system(s) or manual system(s) have not been inoperative,
repaired, or adjusted, such information shall be stated in the report.
    (g) Montana Sulphur & Chemical Company (MSCC) emission limits and
compliance determining methods.
    (1) Introduction. The provisions for MSCC cover the following
units:
    (i) The flares, which consist of the 80-foot west flare, 125-foot
east flare, and 100-meter flare.
    (ii) The SRU 100-meter stack.
    (iii) The auxiliary vent stacks and the units that can exhaust
through the auxiliary vent stacks, which consist of the Railroad
Boiler, the H-1 Unit, the H1-A unit, the H1-1 unit and the H1-2 unit.
    (iv) The SRU 30-meter stack and the units that can exhaust through
the SRU 30-meter stack. The units that can exhaust through the SRU 30-
meter stack are identified in section 3(A)(2)(d) and (e) of MSCC's 1998
exhibit.
    (2) Flare requirements.
    (i) Emission limit. Total combined emissions of SO2 from
the 80-foot west flare, 125-foot east flare, and 100-meter flare shall
not exceed 150.0 pounds per 3-hour period.
    (ii) Compliance determining method. Compliance with the emission
limit in paragraph (g)(2)(i) of this section shall be determined in
accordance with paragraph (h) of this section. In the event MSCC cannot
monitor all three flares from a single location, MSCC shall establish
multiple monitoring locations.
    (3) SRU 100-meter stack requirements.
    (i) Emission limits. Emissions of SO2 from the SRU 100-
meter stack shall not exceed:
    (A) 2,981.7 pounds per 3-hour period;
    (B) 23,853.6 pounds per calendar day; and
    (C) 9,088,000 pounds per calendar year.
    (ii) Compliance determining method.
    (A) Compliance with the emission limits contained in paragraph
(g)(3)(i) of this section shall be determined by the CEMS and emission
testing methods required by sections 6(B)(1) and (2) and section 5,
respectively, of MSCC's 1998 exhibit.
    (B) MSCC shall notify EPA in writing of each annual source test a
minimum of 25 working days prior to actual testing.
    (C) The CEMS referenced in paragraph (g)(3)(ii)(A) of this section

shall achieve a temporal sampling resolution of at least one (1)
concentration and flow rate measurement per minute, meet the
requirements expressed in the definition of ``hourly average'' in
paragraph (c)(14) of this section, and meet the ``CEM Performance
Specifications'' in sections 6(C) and (D) of MSCC's 1998 exhibit,
except that MSCC shall also notify EPA in writing of each annual
Relative Accuracy Test Audit at least 25 working days prior to actual
testing.
    (4) Auxiliary vent stacks.
    (i) Emission limits.
    (A) Total combined emissions of SO2 from the auxiliary
vent stacks shall not exceed 12.0 pounds per 3-hour period;
    (B) Total combined emissions of SO2 from the auxiliary
vent stacks shall not exceed 96.0 pounds per calendar day;
    (C) Total combined emissions of SO2 from the auxiliary
vent stacks shall not exceed 35,040 pounds per calendar year; and
    (D) The H2S concentration in the fuel burned in the
Railroad Boiler, the H-1 Unit, the H1-A unit, the H1-1 unit, and the
H1-2 unit, while any of these units is exhausting to the auxiliary vent
stacks, shall not exceed 160 ppm per 3-hour period and 100 ppm per
calendar day.
    (ii) Compliance determining method.
    (A) Compliance with the emission limits in paragraph (g)(4)(i) of
this section shall be determined by measuring the H2S
concentration of the fuel burned in the Railroad Boiler, the H-1 Unit,
the H1-A unit, the H1-1 unit, and the H1-2 unit (when fuel other than
natural gas is burned in one or more of these units) according to the
procedures in paragraph (g)(4)(ii)(C) of this section.
    (B) Beginning June 20, 2008, MSCC shall maintain logs of:
    (1) The dates and time periods that emissions are exhausted through
the auxiliary vent stacks,
    (2) The heaters and boilers that are exhausting to the auxiliary
vent stacks during such time periods, and
    (3) The type of fuel burned in the heaters and boilers during such
time periods.
    (C) Beginning June 20, 2008, MSCC shall measure the H2S
content of the fuel burned when fuel other than natural gas is burned
in a heater or boiler that is exhausting to an auxiliary vent stack.
MSCC shall begin measuring the H2S content of the fuel at
the fuel header within one (1) hour from when a heater or boiler begins
exhausting to an auxiliary vent stack and on a once-per-3-hour period
frequency until no heater or boiler is exhausting to an auxiliary vent
stack. To determine the H2S content of the fuel burned, MSCC
shall use length-of-stain detector tubes pursuant to ASTM Method D4810-
06, ``Standard Test Method for Hydrogen Sulfide in Natural Gas Using
Length-of-Stain Detector Tubes'' (incorporated by reference, see
paragraph (j) of this section) with the appropriate sample tube range.
If the results exceed the tube's range, another tube of a higher range
must be used until results are in the tube's range.
    (5) SRU 30-meter stack.
    (i) Emission limits.
    (A) Emissions of SO2 from the SRU 30-meter stack shall
not exceed 12.0 pounds per 3-hour period;
    (B) Emissions of SO2 from the SRU 30-meter stack shall
not exceed 96.0 pounds per calendar day;
    (C) Emissions of SO2 from the SRU 30-meter stack shall
not exceed 35,040 pounds per calendar year; and
    (D) The H2S concentration in the fuel burned in the
heaters and boilers described in paragraph (g)(1)(iv) of this section,
while any of these units is exhausting to the SRU 30-meter stack, shall
not exceed 160 ppm per 3-hour period and 100 ppm per calendar day.
    (ii) Compliance determining method.
    (A) Compliance with the emission limits in paragraph (g)(5)(i) of
this section shall be determined by measuring the H2S
concentration of the fuel burned in the heaters and boilers described
in paragraph (g)(1)(iv) of this section (when fuel other than natural
gas is burned in one or more of these heaters or boilers) according to
the procedures in paragraph (g)(5)(ii)(C) of this section.
    (B) Beginning June 20, 2008, MSCC shall maintain logs of:
    (1) The dates and time periods that emissions are exhausted through
the SRU 30-meter stack,
    (2) The heaters and boilers that are exhausting to the SRU 30-meter
stack during such time periods, and
    (3) The type of fuel burned in the heaters and boilers during such
time periods.
    (C) Beginning June 20, 2008, MSCC shall measure the H2S
content of the fuel burned when fuel other than natural gas is burned
in a heater or boiler that is exhausting to the SRU 30-meter stack.
MSCC shall begin measuring the H2S content of the fuel at
the fuel header within one (1) hour from when any heater or boiler
begins exhausting to the SRU 30-meter stack and on a once-per-3-hour
period frequency until no heater or boiler is exhausting to the SRU 30-
meter stack. To determine the H2S content of the fuel
burned, MSCC shall use length-of-stain detector tubes pursuant to ASTM
Method D4810-06, ``Standard Test Method for Hydrogen Sulfide in Natural
Gas Using Length-of-Stain Detector Tubes'' (incorporated by reference,
see paragraph (j) of this section) with the appropriate sample tube
range. If the results exceed the tube's range, another tube of a higher
range must be used until results are in the tube's range.
    (6) Data reporting requirements:
    (i) MSCC shall submit quarterly reports beginning with the first
calendar quarter following May 21, 2008. The quarterly reports shall be
submitted within 30 days of the end of each calendar quarter. The
quarterly reports shall be submitted to EPA at the following address:
Air Program Contact, EPA Montana Operations Office, Federal Building,
10 West 15th Street, Suite 3200, Helena, MT 59626.
    The quarterly report shall be certified for accuracy in writing by
a responsible MSCC official. The quarterly report shall consist of both
a comprehensive electronic-magnetic report and a written hard copy data
summary report.
    (ii) The electronic report shall be on magnetic or optical media,
and such submittal shall follow the reporting format of electronic data
being submitted to the MDEQ. EPA may modify the reporting format
delineated in this section, and, thereafter, MSCC shall follow the
revised format. In addition to submitting the electronic quarterly
reports to EPA, MSCC shall also record, organize, and archive for at
least five (5) years the same data, and upon request by EPA, MSCC shall
provide EPA with any data archived in accordance with this provision.
The electronic report shall contain the following:
    (A) Hourly average total sulfur concentrations as H2S or
SO2 in ppm, in the gas stream to the flare(s);
    (B) Hourly average H2S concentrations of the flare pilot
and purge gases in ppm;
    (C) Hourly average SO2 concentrations in ppm from the
SRU 100-meter stack;
    (D) Hourly average volumetric flow rates in SCFH in the gas stream
to the flare(s) and in the SRU 100-meter stack;
    (E) Hourly average volumetric flow rates in SCFH of the flare pilot
and purge gases;
    (F) Hourly average temperature (in (F) and pressure (in mm or
inches of Hg) in the gas stream to the flare(s);
    (G) Hourly emissions in pounds per clock hour from the flare(s) and
SRU 100-meter stack;
    (H) Daily calibration data for all flare CEMS, all pilot gas and
purge gas CEMS, and the SRU 100-meter stack CEMS;
    (iii) The quarterly written report shall contain the following
information:

    (A) The 3-hour emissions in pounds per 3-hour period from the
flare(s) and SRU 100-meter stack, and 3-hour H2S
concentrations in the fuel burned in the heaters and boilers described
in paragraphs (g)(1)(iii) and (iv) of this section while any of these
units is exhausting to the SRU 30-meter stack or auxiliary vent stacks
and burning fuel other than natural gas;
    (B) Periods in which only natural gas or an inert gas was used as
flare pilot gas or purge gas or both;
    (C) Daily emissions in pounds per calendar day from the SRU 100-
meter stack;
    (D) Annual emissions of SO2 in pounds per calendar year
from the SRU 100-meter stack;
    (E) The results of all quarterly Cylinder Gas Audits (CGA),
Relative Accuracy Audits (RAA) and annual Relative Accuracy Test Audits
(RATA) for all total sulfur analyzer(s), all H2S
analyzer(s), and the SRU 100-meter stack CEMS, and the results of all
annual calibrations and verifications for the volumetric flow,
temperature, and pressure monitors;
    (F) For all periods of flare volumetric flow rate monitoring system
or total sulfur analyzer system downtime, SRU 100-meter CEMS downtime,
flare pilot gas or purge gas volumetric flow or H2S analyzer
system downtime, failure to obtain or analyze a grab or integrated
sample, or failure to obtain an H2S concentration sample as
required by paragraphs (g)(4)(ii)(C) and (g)(5)(ii)(C) of this section,
the written report shall identify:
    (1) Dates and times of downtime or failure;
    (2) Reasons for downtime or failure;
    (3) Corrective actions taken to mitigate downtime or failure; and
    (4) The other methods, approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section, used to determine flare
emissions;
    (G) For all periods that the range of the flare or any pilot or
purge gas volumetric flow rate monitor(s), any flare total sulfur
analyzer(s), or any pilot or purge gas H2S analyzer(s), is
exceeded, the written report shall identify:
    (1) Date and time when the range of the volumetric flow monitor(s),
total sulfur analyzer(s), or H2S analyzer(s) was exceeded;
and
    (2) The other methods, approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section, used to determine flare
emissions;
    (H) For all periods that the flare volumetric flow monitor or
monitors are recording flow, yet any Flare Water Seal Monitoring Device
indicates there is no flow, the written report shall identify:
    (1) Date, time, and duration when the flare volumetric flow
monitor(s) recorded flow, yet any Flare Water Seal Monitoring Device
indicated there was no flow;
    (I) For each 3-hour period and calendar day in which the flare
emission limit, the SRU 100-meter stack emission limits, the SRU 30-
meter stack emission limits, or auxiliary vent stack emission limits
are exceeded, the written report shall identify:
    (1) The date, start time, and end time of the excess emissions;
    (2) Total hours of operation with excess emissions, the hourly
emissions, the 3-hour emissions, and the daily emissions;
    (3) All information regarding reasons for operating with excess
emissions; and
    (4) Corrective actions taken to mitigate excess emissions;
    (J) For instances in which emissions are exhausted through the
auxiliary vent stacks or 30-meter stack, the quarterly written report
shall identify:
    (1) The dates and time periods that emissions were exhausted
through the auxiliary vent stacks or the 30-meter stack;
    (2) The heaters and boilers that were exhausting to the auxiliary
vent stacks or 30-meter stack during such time periods; and
    (3) The type of fuel burned in the heaters and boilers during such
time periods; and
    (K) When no excess emissions have occurred or the continuous
monitoring system(s) or manual system(s) have not been inoperative,
repaired, or adjusted, such information shall be stated in the report.
    (h) Flare compliance determining method.
    (1) Compliance with the emission limits in paragraphs (d)(2)(i),
(e)(2)(i), (f)(2)(i) and (g)(2)(i) of this section shall be determined
by measuring the total sulfur concentration and volumetric flow rate of
the gas stream to the flare(s) (corrected to one (1) atmosphere
pressure and 68[deg] F) and using the methods contained in the flare
monitoring plan required by paragraph (h)(5) of this section. The
volumetric flow rate of the gas stream to the flare(s) shall be
determined in accordance with the requirements in paragraph (h)(2) of
this section and the total sulfur concentration of the gas stream to
the flare(s) shall be determined in accordance with paragraph (h)(3) of
this section.
    (2) Flare flow monitoring:
    (i) Within 365 days after receiving EPA approval of the flare
monitoring plan required by paragraph (h)(5) of this section, each
facility named in paragraph (a) of this section shall install and
calibrate, and, thereafter, calibrate, maintain and operate, a
continuous flow monitoring system capable of measuring the volumetric
flow of the gas stream to the flare(s) in accordance with the
specifications contained in paragraphs (h)(2)(iii) through (vi) of this
section. The flow monitoring system shall require more than one flow
monitoring device or flow measurements at more than one location if one
monitor cannot measure the total volumetric flow to each flare.
    (ii) Volumetric flow monitors meeting the proposed volumetric flow
monitoring specifications below should be able to measure the majority
of volumetric flow in the gas streams to the flare. However, in rare
events (e.g., upset conditions) the flow to the flare may exceed the
range of the monitor. In such cases, or when the volumetric flow
monitor or monitors are not working, other methods approved by EPA in
the flare monitoring plan required by paragraph (h)(5) of this section
shall be used to determine the volumetric flow rate to the flare, which
shall then be used to calculate SO2 emissions. In quarterly
reports, sources shall indicate when these other methods are used.
    (iii) The flare gas stream volumetric flow rate shall be measured
on an actual wet basis, converted to Standard Conditions, and reported
in SCFH. The minimum detectable velocity of the flow monitoring
device(s) shall be 0.1 feet per second (fps). The flow monitoring
device(s) shall continuously measure the range of flow rates
corresponding to velocities from 0.5 to 275 fps and have a
manufacturer's specified accuracy of 5% of the measured
flow over the range of 1.0 to 275 fps and 20% of the
measured flow over the range of 0.1 to 1.0 fps. The volumetric flow
monitor(s) shall feature automated daily calibrations at low and high
ranges. The volumetric flow monitor(s) shall be calibrated annually
according to manufacturer's specifications.
    (iv) For correcting flow rate to standard conditions (defined as
68[deg]F and 760 mm, or 29.92 inches, of Hg), temperature and pressure
shall be monitored continuously. Temperature and pressure shall be
monitored in the same location as volumetric flow, and the temperature
and pressure monitors shall be calibrated prior to installation
according to manufacturer's specifications and, thereafter, annually to
meet accuracy specifications as follows: The temperature monitor shall

be calibrated to within  2.0% at absolute temperature and
the pressure monitor shall be calibrated to within  5.0
mmHg;
    (v) The flow monitoring device(s) shall be calibrated prior to
installation to demonstrate accuracy of the measured flow to within
5.0% at flow rates equivalent to 30%, 60%, and 90% of monitor full
scale.
    (vi) Each volumetric flow device shall achieve a temporal sampling
resolution of at least one (1) flow rate measurement per minute, meet
the requirements expressed in the definition of ``hourly average'' in
paragraph (c)(14) of this section, and be installed in a manner and at
a location that will allow for accurate measurements of the total
volume of the gas stream going to each flare. Each temperature and
pressure monitoring device shall achieve a temporal sampling resolution
of at least one (1) measurement per minute, meet the requirements
expressed in the definition of ``hourly average'' in paragraph (c)(14)
of this section, and be installed in a manner that will allow for
accurate measurements.
    (vii) In addition to the continuous flow monitors, facilities may
use flare water seal monitoring devices to determine whether there is
flow going to the flare. If used, owners or operators shall install,
calibrate, operate, and maintain these devices according to
manufacturer's specifications. The devices shall include a continuous
monitoring system that:
    (A) Monitors the status of the water seal to indicate when flow is
going to the flare;
    (B) Automatically records the time and duration when flow is going
to the flare; and
    (C) Verifies that the physical seal has been restored after flow
has been sent to the flare.
    If the water seal monitoring devices indicate that there is no flow
going to the flare, yet the continuous flow monitor is indicating flow,
the presumption will be that no flow is going to the flare.
    (viii) Each facility named in paragraph (a) of this section, that
does not certify that only natural gas or an inert gas is used for both
the pilot gas and purge gas, shall determine the volumetric flow of
each pilot gas and purge gas stream for which natural gas or inert gas
is not used by one of the following methods:
    (A) Measure the volumetric flow of the gas using continuous flow
monitoring devices on an actual wet basis, converted to Standard
Conditions, and reported in SCFH. Each flow monitoring device shall
achieve a temporal sampling resolution of at least one (1) flow rate
measurement per minute, meet the requirements expressed in the
definition of ``hourly average'' in paragraph (c)(14) of this section,
and be installed in a manner and at a location that will allow for
accurate measurements of the total volume of the gas. Gas flow rate
monitor accuracy determinations shall be required at least once every
48 months or more frequently at routine refinery turn-around. In cases
when the flow monitoring device or devices are not working or the range
of the monitoring device(s) is exceeded, other methods approved by EPA
in the flare monitoring plan required by paragraph (h)(5) of this
section shall be used to determine volumetric flow of the gas which
shall then be used to calculate SO2 emissions. In quarterly
reports, sources shall indicate when other methods are used; or
    (B) Use parameters and methods approved by EPA in the flare
monitoring plan required by paragraph (h)(5) of this section to
calculate the volumetric flows of the gas, in SCFH.
    (3) Flare concentration monitoring:
    (i) Within 365 days after receiving EPA approval of the flare
monitoring plan required by paragraph (h)(5) of this section, each
facility named in paragraph (a) of this section shall determine the
total sulfur concentration of the gas stream to the flare(s) using
either continuous total sulfur analyzers or grab or integrated sampling
with lab analysis, as described in the following paragraphs:
    (A) Continuous total sulfur concentration monitoring. If a facility
chooses to use continuous total sulfur concentration monitoring, the
following requirements apply:
    (1 ) The facility shall install and calibrate, and, thereafter,
calibrate, maintain and operate, a continuous total sulfur
concentration monitoring system capable of measuring the total sulfur
concentration of the gas stream to each flare. Continuous monitoring
shall occur at a location or locations that are representative of the
gas combusted in the flare and be capable of measuring the normally
expected range of total sulfur in the gas stream to the flare. The
concentration monitoring system shall require more than one
concentration monitoring device or concentration measurements at more
than one location if one monitor cannot measure the total sulfur
concentration to each flare. Total sulfur concentration shall be
reported as H2S or SO2 in ppm. In cases when the
total sulfur analyzer or analyzers are not working or the concentration
of the total sulfur exceeds the range of the analyzer(s), other
methods, approved by EPA in the flare monitoring plan required by
paragraph (h)(5) of this section, shall be used to determine total
sulfur concentrations, which shall then be used to calculate
SO2 emissions. In quarterly reports, sources shall indicate
when these other methods are used.
    (2 ) The total sulfur analyzer(s) shall achieve a temporal sampling
resolution of at least one (1) concentration measurement per 15
minutes, meet the requirements expressed in the definition of ``hourly
average'' in paragraph (c)(14) of this section, be installed, certified
(on a concentration basis), and operated in accordance with 40 CFR part
60, Appendix B, Performance Specification 5, and be subject to and meet
the quality assurance and quality control requirements (on a
concentration basis) of 40 CFR part 60, Appendix F.
    (3) Each affected facility named in paragraph (a) of this section
shall notify the Air Program Contact at EPA's Montana Operations
Office, Federal Building, 10 West 15th Street, Suite 3200, Helena, MT
59626, in writing of each Relative Accuracy Test Audit a minimum of 25
working days prior to the actual testing.
    (B) Grab or integrated total sulfur concentration monitoring: If a
facility chooses grab or integrated sampling instead of continuous
total sulfur concentration monitoring, the facility shall comply with
the methods specified in either paragraph (h)(3)(i)(B)(1) (``Grab
Sampling'') or (h)(3)(B)(i)(B)(2 ) (``Integrated Sampling''), and the
requirements of paragraphs (h)(3)(i)(B)(3) (``Sample Analysis''),
(h)(3)(i)(B)(4) (``Exemptions''), and (h)(3)(i)(B)(5) (``Missing or
Unanalyzed Sample'') of this section, as follows:
    (1) Grab Sampling. Each facility that chooses to use grab sampling
shall meet the following requirements: if the flow rate of the gas
stream to the flare in any consecutive 15-minute period continuously
exceeds 0.5 feet per second (fps) and the water seal monitoring device,
if any, indicates that flow is going to the flare, a grab sample shall
be collected within 15 minutes. The grab sample shall be collected at a
location that is representative of the gas combusted in the flare.
Thereafter, the sampling frequency shall be one (1) grab sample every
three (3) hours, which shall continue until the velocity of the gas
stream going to the flare in any consecutive 15-minute period is
continuously 0.5 fps or less. Samples shall be analyzed according to
paragraph (h)(3)(i)(B)(3) of this section. The requirements of this
paragraph (h)(3)(i)(B)(1) shall apply to each flare at

a facility for which the sampling threshold is exceeded.
    (2) Integrated Sampling. Each facility that chooses to use
integrated sampling shall meet the following requirements: if the flow
rate of the gas stream to the flare in any consecutive 15-minute period
continuously exceeds 0.5 feet per second (fps) and the water seal
monitoring device, if any, indicates that flow is going to the flare, a
sample shall be collected within 15 minutes. The sample shall be
collected at a location that is representative of the gas combusted in
the flare. The sampling frequency, thereafter, shall be a minimum of
one (1) aliquot for each 15-minute period until the sample container is
full, or until the end of a 3-hour period is reached, whichever comes
sooner. Within 30 minutes thereafter, a new sample container shall be
placed in service, and sampling on this frequency, and in this manner,
shall continue until the velocity of the gas stream going to the flare
in any consecutive 15-minute period is continuously 0.5 fps or less.
Samples shall be analyzed according to paragraph (h)(3)(i)(B)(3) of
this section. The requirements of this paragraph (h)(3)(i)(B)(2) shall
apply to each flare at a facility for which the sampling threshold is
exceeded.
    (3) Samples shall be analyzed using ASTM Method D4468-85
(Reapproved 2000) ``Standard Test Method for Total Sulfur in Gaseous
Fuels by Hydrogenolysis and Rateometric Colorimetry,'' (incorporated by
reference, see paragraph (j) of this section) ASTM Method D5504-01
(Reapproved 2006) ``Standard Test Method for Determination of Sulfur
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and
Chemiluminescence,'' (incorporated by reference, see paragraph (j) of
this section) or 40 CFR part 60, Appendix A-5, Method 15A
``Determination of Total Reduced Sulfur Emissions From the Sulfur
Recovery Plants in Petroleum Refineries.'' Total sulfur concentration
shall be reported as H2S or SO2 in ppm.
    (4) Exemptions. For facilities using a sampling method specified in
either paragraph (h)(3)(i)(B)(1) (``Grab Sampling'') or (h)(3)(i)(B)(2)
(``Integrated Sampling'') of this section, obtaining a sample is not
required if flaring is a result of a catastrophic or other unusual
event, including a major fire or an explosion at the facility, such
that collecting a sample at the EPA-approved location during the
relevant period is infeasible or constitutes a safety hazard, provided
that the owner or operator shall collect a sample at an alternative
location if feasible, safe, and representative of the flaring event.
The owner or operator shall demonstrate to EPA that it was infeasible
or unsafe to collect a sample or to collect a sample at the sampling
location approved by EPA in the flare monitoring plan required by
paragraph (h)(5) of this section. The owner or operator shall also
demonstrate to EPA that any sample collected at an alternative location
is representative of the flaring incident. If a facility experiences
ongoing difficulties collecting grab or integrated samples in
accordance with its flare monitoring plan approved by EPA pursuant to
paragraph (h)(5) of this section, EPA may require the facility to
revise its flare monitoring plan and use continuous total sulfur
concentration monitoring as described in paragraph (h)(3)(i)(A) of this
section or other reliable method to determine total sulfur
concentrations of the gas stream to the flare.
    (5) Missing or Unanalyzed Samples. For facilities using a sampling
method specified in either paragraph (h)(3)(i)(B)(1) (``Grab
Sampling'') or (h)(3)(i)(B)(2) (``Integrated Sampling'') of this
section, if a required sample is not obtained or analyzed for any
reason, other methods approved by EPA in the flare monitoring plan
required by paragraph (h)(5) of this section shall be used to determine
total sulfur concentrations, which shall then be used to calculate
SO2 emissions. In quarterly reports, sources shall indicate
when these other methods are used.
    (6) Reporting. For facilities using a sampling method specified in
either paragraph (h)(3)(i)(B)(1 ) (``Grab Sampling'') or (h)(3)(i)(B)(2
) (``Integrated Sampling'') of this section, since normally only one
(1) sample per flare will be analyzed for a 3-hour period, the total
sulfur concentration of a sample obtained during a given 3-hour period
shall be substituted for each hour of such 3-hour period. If integrated
sampling for a flare produces more than one (1) sample container during
a 3-hour period, and the gas in each container is analyzed separately,
the concentrations for the containers shall be averaged. For that
flare, the resulting average shall be substituted for each hour of the
3-hour period during which the sampling occurred. The substituted
hourly total sulfur concentrations determined per this paragraph shall
be used to determine hourly emissions from the flare.
    (ii) Each facility named in paragraph (a) of this section that does
not certify that only natural gas or an inert gas is used for both the
pilot gas and purge gas shall determine the H2S
concentration of each pilot gas and purge gas stream for which natural
gas or inert gas is not used by one of the following methods:
    (A) Measure the H2S concentration of the gas by
continuous H2S analyzer. The H2S concentration
analyzer(s) shall achieve a temporal sampling resolution of at least
one (1) concentration measurement per three (3) minutes, meet the
requirements expressed in the definition of ``hourly average'' in
paragraph (c)(14) of this section, be installed, certified (on a
concentration basis), and operated in accordance with 40 CFR part 60,
Appendix B, Performance Specification 2, and be subject to and meet the
quality assurance and quality control requirements (on a concentration
basis) of 40 CFR part 60, Appendix F. In cases where the H2S
analyzer or analyzers are not working or the H2S
concentration exceeds the range of the analyzer(s), other methods
approved by EPA in the flare monitoring plan required by paragraph
(h)(5) of this section shall be used to determine the H2S
concentration of the gas, which shall then be used to calculate
SO2 emissions. In quarterly reports, sources shall indicate
when other methods are used; or
    (B) Use methods approved by EPA as part of the facility's flare
monitoring plan required by paragraph (h)(5) of this section to
estimate the H2S concentration of the gas.
    (4) Calculation of SO2 emissions from flares. Methods
for calculating hourly and 3-hour SO2 emissions from flares
shall be submitted to EPA as part of the flare monitoring plan required
by paragraph (h)(5) of this section. Following approval by EPA, such
methods shall be followed for calculating hourly and 3-hour
SO2 emissions from a facility's flare(s).
    (5) By October 20, 2008, each facility named in paragraph (a) of
this section shall submit a flare monitoring plan. Each flare
monitoring plan shall include, at a minimum, the following:
    (i) A facility plot plan showing the location of each flare in
relation to the general plant layout;
    (ii) Drawing(s) with dimensions, preferably to scale, and an as-
built process flow diagram of the flare(s) identifying major
components, such as flare header, flare stack, flare tip(s) or
burner(s), purge gas system, pilot gas system, water seal, knockout
drum, and molecular seal;
    (iii) A representative flow diagram showing the interconnections of
the flare system(s) with vapor recovery system(s), process units, and
other equipment as applicable;
    (iv) A complete description of the gas flaring process for an
integrated gas

flaring system that describes the method of operation of the flares;
    (v) A complete description of the vapor recovery system(s) which
have interconnection to a flare, such as compressor description(s);
design capacities of each compressor and the vapor recovery system; and
the method currently used to determine and record the amount of vapors
recovered;
    (vi) A complete description of the proposed method to monitor,
determine, and record the total volume and total sulfur concentration
of gases combusted in the flare, including drawing(s) with dimensions,
preferably to scale, showing the following information for the proposed
flare gas stream monitoring systems:
    (A) The locations to be used for all monitoring and sampling,
including, but not limited to: Flare flow monitors, total sulfur
analyzers, concentration integrated sampling, concentration grab
sampling, water seal monitoring devices, pilot and purge gas flow
monitors, and pilot and purge gas concentration monitors;
    (vii) A description of the method(s) used to determine, and
reasoning behind, all monitoring and sampling locations;
    (viii) The following information regarding pilot gas and purge gas
for each flare:
    (A) Type(s) of gas used;
    (B) A complete description of the monitor(s) to be used, or the
other parameters that will be used and monitored, to determine
volumetric flows of the pilot gas and purge gas streams for which
natural gas or inert gas is not used; and
    (C) A complete description of the analyzer(s) to be used to
determine, or other methods that will be used to estimate, the
H2S concentrations in the pilot gas and purge gas streams
for which natural gas or inert gas is not used;
    (ix) A detailed description of manufacturer's specifications,
including, but not limited to, make, model, type, range, precision,
accuracy, calibration, maintenance, quality assurance procedure, and
any other relevant specifications and information referenced in
paragraphs (h)(2) and (3) of this section for all existing and proposed
flow monitoring devices and total sulfur analyzers;
    (x) The following information if grab or integrated sampling is
used:
    (A) A complete description of proposed analytical and sampling
methods if grab or integrated sampling methods will be used for
determining the total sulfur concentration of the gas stream going to
the flare;
    (B) A detailed description of manufacturer's specifications,
including, but not limited to, make, model, type, maintenance, and
quality assurance procedures for the integrated sampling device, if
used; and
    (C) A complete description of the proposed method to alert
personnel designated to collect samples that the trigger for collecting
a sample has occurred;
    (xi) A complete description of the methods to be used to estimate
flare emissions when any flare, pilot gas, or purge gas volumetric flow
monitoring devices, total sulfur analyzers, or grab or integrated
sampling methods, or pilot gas or purge gas H2S analyzers
are not working or available, or the operating range of the monitors or
analyzers is exceeded;
    (xii) A complete description of the proposed data recording,
collection, and management system and any other relevant specifications
and information referenced in paragraphs (h)(2) and (3) of this section
for each flare monitoring system;
    (xiii) The following information for each flare using a water seal
monitoring device:
    (A) A detailed description of manufacturer's specifications,
including, but not limited to, make, model, type, maintenance, and
quality assurance procedures;
    (B) A complete description of the proposed methods to determine
that the water seal is no longer intact and flow is going to the flare,
and the data used to establish, and reasoning behind, these methods;
    (xiv) A schedule for the installation and operation of each flare
monitoring system consistent with the deadline in paragraphs (h)(2) and
(h)(3) of this section; and
    (xv) A complete description of the methods to be used for
calculating hourly and 3-hour SO2 emissions from flares.
    (6) Thirty (30) days prior to installing any continuous monitor or
integrated sampler pursuant to paragraphs (h)(2) and (3) of this
section, each facility named in paragraph (a) of this section shall
submit for EPA review a quality assurance/quality control (QA/QC) plan
for each monitor or sampler being installed.
    (i) Affirmative defense provisions for exceedances of flare
emission limits during malfunctions, startups, and shutdowns.
    (1) In response to an action to enforce the emission limits in
paragraphs (d)(2)(i), (e)(2)(i), (f)(2)(i), and (g)(2)(i) of this
section, owners and/or operators of the facilities named in paragraph
(a) of this section may assert an affirmative defense to a claim for
civil penalties for exceedances of such limits during periods of
malfunction, startup, or shutdown. To establish the affirmative defense
and to be relieved of a civil penalty in any action to enforce such a
limit, the owner or operator of the facility must meet the notification
requirements of paragraph (i)(2) of this section in a timely manner and
prove by a preponderance of evidence that:
    (i) For claims of malfunction:
    (A) The excess emissions were caused by a sudden, unavoidable
breakdown of equipment, or a sudden, unavoidable failure of a process
to operate in the normal or usual manner, beyond the control of the
owner or operator;
    (B) The excess emissions:
    (1) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
    (2) Could not have been avoided by better operation and maintenance
practices;
    (C) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable;
    (D) The amount and duration of the excess emissions (including any
bypass) were minimized to the maximum extent practicable during periods
of such emissions;
    (ii) For claims of startup or shutdown:
    (A) All or a portion of the facility was in startup or shutdown
mode, resulting in the need to route gases to the flare;
    (B) The periods of excess emissions that occurred during startup
and shutdown were short and infrequent and could not have been
prevented through careful planning and design or better operation and
maintenance practices; and
    (C) The frequency and duration of operation in startup or shutdown
mode were minimized to the maximum extent practicable;
    (iii) For claims of malfunction, startup, or shutdown:
    (A) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage;
    (B) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality;
    (C) All emissions monitoring systems were kept in operation if at
all possible;
    (D) The owner or operator's actions in response to the excess
emissions were documented by properly signed, contemporaneous operating
logs;

    (E) The excess emissions were not part of a recurring pattern
indicative of inadequate design, operation, or maintenance;
    (F) At all times, the facility was operated in a manner consistent
with good practices for minimizing emissions; and
    (G) During the period of excess emissions, there were no
exceedances of the SO2 NAAQS that could be attributed to the
emitting source.
    (2) Notification. The owner or operator of the facility
experiencing an exceedance of its flare emission limit(s) during
startup, shutdown, or malfunction shall notify EPA verbally as soon as
possible, but no later than noon of EPA's next working day, and shall
submit written notification to EPA within 30 days of the initial
occurrence of the exceedance. The written notification shall explain
whether and how the elements set forth in paragraph (i)(1) of this
section were met, and include all supporting documentation.
    (3) Injunctive relief. The Affirmative Defense Provisions contained
in paragraph (i)(1) of this section shall not be available to claims
for injunctive relief.
    (j) Incorporation by reference. (1) The materials listed in this
paragraph are incorporated by reference in the corresponding paragraphs
noted. These incorporations by reference are approved by the Director
of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR
part 51. These materials are incorporated as they exist on the date of
the approval, and notice of any change in these materials will be
published in the Federal Register. The materials are available for
purchase at the corresponding address noted below, and all are
available for inspection at the National Archives and Records
Administration (NARA) and at the Air Program, EPA, Region 8, 1595
Wynkoop Street, Denver, CO. For information on the availability of this
material at NARA, call<PHONE_NUMBER>, or go to: http://www.archives.gov/
federal_register/code_of_federal_regulations/ibr_locations.html.
    (2) The following materials are available for purchase from the
following address: American Society for Testing and Materials (ASTM),
100 Barr Harbor Drive, Post Office Box C700, West Conshohocken, PA
19428-2959, www.astm.org, or by calling<PHONE_NUMBER>.
    (i) ASTM Method D4468-85 (Reapproved 2000), Standard Test Method
for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for paragraph (h)(3)(i)(B)(3) of this
section.
    (ii) ASTM Method D4810-06, Standard Test Method for Hydrogen
Sulfide in Natural Gas Using Length-of-Stain Detector Tubes, IBR
approved for paragraphs (f)(3)(ii)(B), (g)(4)(ii)(C), and (g)(5)(ii)(C)
of this section.
    (ii) ASTM Method D5504-01 (Reapproved 2006), Standard Test Method
for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels
by Gas Chromatography IBR approved for paragraph (h)(3)(i)(B)(3) of
this section.

[FR Doc. E8-7868 Filed 4-18-08; 8:45 am]

BILLING CODE 6560-50-P