Document ID: EPA-R08-OAR-2006-0098-0124
Agency: epa
Document Type: Rule
Title: Federal Implementation Plan for the Billings/Laurel, MT, Sulfur Dioxide Area
Posted Date: 2008-04-21T04:00Z

[Federal Register: April 21, 2008 (Volume 73, Number 77)]
[Rules and Regulations]               
[Page 21417-21465]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr21ap08-19]                         

[[Page 21417]]

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Part II

Environmental Protection Agency

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40 CFR Part 52

Federal Implementation Plan for the Billings/Laurel, Montana, Sulfur 
Dioxide Area; Final Rule

[[Page 21418]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R08-OAR-2006-0098; FRL-8551-2]
RIN 2008-AA01

 
Federal Implementation Plan for the Billings/Laurel, MT, Sulfur 
Dioxide Area

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: The Environmental Protection Agency (EPA) is promulgating a 
Federal Implementation Plan (FIP) containing emission limits and 
compliance determining methods for several sources located in Billings 
and Laurel, Montana. EPA is promulgating a FIP because of our previous 
partial and limited disapprovals of the Billings/Laurel Sulfur Dioxide 
(SO2) State Implementation Plan (SIP). The intended effect of this 
action is to assure attainment of the SO2 National Ambient Air Quality 
Standards (NAAQS) in the Billings/Laurel, Montana area. EPA is taking 
this action under sections 110, 301, and 307 of the Clean Air Act 
(Act).

DATES: Effective Date: This final rule is effective May 21, 2008. The 
incorporation by reference of certain publications listed in this 
regulation is approved by the Director of the Federal Register as of 
May 21, 2008.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-R08-OAR-2006-0098. All documents in the docket are listed on 
the http://www.regulations.gov Web site. Although listed in the index, 
some information is not publicly available, e.g., Confidential Business 
Information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the Internet and will be publicly available only in hard 
copy form. Publicly available docket materials are available either 
electronically through http://www.regulations.gov or in hard copy at 
the Air and Radiation Program, Environmental Protection Agency (EPA), 
Region 8, 1595 Wynkoop Street, Denver, Colorado 80202-1129. EPA 
requests that if at all possible, you contact the individual listed in 
the FOR FURTHER INFORMATION CONTACT section to view the hard copy of 
the docket. You may view the hard copy of the docket Monday through 
Friday, 8 a.m. to 4 p.m., excluding Federal holidays.

FOR FURTHER INFORMATION CONTACT: Laurie Ostrand, Air and Radiation 
Program, Environmental Protection Agency (EPA), Region 8, 1595 Wynkoop 
Street, Denver, Colorado 80202-1129, (303) 312-6437, 
ostrand.laurie@epa.gov.

SUPPLEMENTARY INFORMATION: 

Table of Contents

Definitions

I. Background of the Final Rules
II. Issues Raised by Commenters and EPA's Response
    A. FIP Not Necessary
    B. EPA Exceeded Its Authority in Proposing a FIP
    C. Flare Monitoring
    D. Flare Limits
    E. Concerns With Dispersion Modeling
    F. Miscellaneous Comments
    G. MSCC Specific Issues
    H. ConocoPhillips Specific Issues
    I. ExxonMobil Specific Issues
    J. CHS Inc. Specific Issues
III. Summary of the Final Rules and Changes From the July 12, 2006, 
Proposal
    A. Flare Requirements Applicable to All Sources
    B. CHS Inc.
    C. ConocoPhillips
    D. ExxonMobil
    E. Montana Sulphur & Chemical Company (MSCC)
    F. Modeling to Support Emission Limits
IV. Statutory and Executive Order Reviews
    A. Executive Order 12866, Regulatory Planning Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132, Federalism
    F. Executive Order 13175, Coordination With Indian Tribal 
Governments
    G. Executive Order 13045, Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211, Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act
    L. Petitions for Judicial Review

Definitions

    For the purpose of this document, we are giving meaning to certain 
words or initials as follows:
    (i) The words or initials Act or CAA mean or refer to the Clean Air 
Act, unless the context indicates otherwise.
    (ii) The initials API mean or refer to the American Petroleum 
Institute.
    (iii) The initials BAAQMD mean or refer to the Bay Area Air Quality 
Management District.
    (iv) The initials CEMS mean or refer to continuous emission 
monitoring system.
    (v) The initials CO mean or refer to carbon monoxide.
    (vi) The initials COPC mean or refer to ConocoPhillips.
    (vii) The words EPA, we, us or our mean or refer to the United 
States Environmental Protection Agency.
    (viii) The initials FIP mean or refer to Federal Implementation 
Plan.
    (ix) The initials H2S mean or refer to hydrogen sulfide.
    (x) The initials MBER mean or refer to the Montana Board of 
Environmental Review.
    (xi) The initials MDEQ mean or refer to the Montana Department of 
Environmental Quality.
    (xii) The initials MPA mean or refer to the Montana Petroleum 
Association.
    (xiii) The initials MSCC mean or refer to the Montana Sulphur & 
Chemical Company.
    (xiv) The initials NAAQS mean or refer to National Ambient Air 
Quality Standards
    (xv) The initials NEDA/CAP mean or refer to the National 
Environmental Development Association's Clean Air Project.
    (xvi) The initials NPRA mean or refer to the National Petrochemical 
& Refiners Association.
    (xvii) The initials SCAQMD mean or refer to the South Coast Air 
Quality Management District.
    (xviii) The initials SIP mean or refer to State Implementation 
Plan.
    (xix) The initials SO2 mean or refer to sulfur dioxide.
    (xx) The words State or Montana mean the State of Montana, unless 
the context indicates otherwise.
    (xxi) The initials SRU mean or refer to sulfur recovery unit.
    (xxii) The initials SWS mean or refer to sour water stripper.
    (xxiii) The initials WETA mean or refer to the Western 
Environmental Trade Association.
    (xxiv) The initials WSPA mean or refer to the Western States 
Petroleum Association.
    (xxv) The initials YCC mean or refer to the Yellowstone County 
Commissioners.
    (xxvi) The initials YVAS mean or refer to the Yellowstone Valley 
Audubon Society.

I. Background of the Final Rules

    The Clean Air Act (Act) requires EPA to establish national ambient 
air quality standards (NAAQS) that protect public health and welfare. 
NAAQS have been established for SO2 as follows: 0.030 parts 
per million (ppm) annual standard, not to be exceeded in a calendar 
year; 0.14 ppm 24-hour standard, not to be exceeded more than once per 
calendar year; and 0.5 ppm 3-hour standard, not to be exceeded more

[[Page 21419]]

than once per calendar year. See 40 CFR 50.4 and 50.5. The Act also 
requires states to prepare and gain EPA approval of a plan, termed a 
State Implementation Plan (SIP), to assure that the NAAQS are attained 
and maintained.
    Dispersion modeling completed in 1991 and 1993 for the Billings/
Laurel area of Montana predicted that the SO2 NAAQS were not 
being attained. As a result, in March 1993 EPA (pursuant to sections 
110(a)(2)(H) and 110(k)(5) of the Act, 42 U.S.C. 7410(a)(2)(H) and 
7410(k)(5)) requested the State of Montana to revise its previously 
approved SO2 SIP for the Billings/Laurel area. See 58 FR 
41450, August 4, 1993. In response, the State submitted revisions to 
the SO2 SIP on September 6, 1995, August 27, 1996, April 2, 
1997, July 29, 1998, and May 4, 2000.
    On May 2, 2002 (67 FR 22168) and May 22, 2003 (68 FR 27908), we 
partially approved, partially disapproved, limitedly approved, and 
limitedly disapproved the Billings/Laurel SO2 SIP. In those 
actions we disapproved the following:
     The attainment demonstration due to issues with various 
emission limits, inappropriate stack height credit, and lack of 
emission limits on flares.
     The emission limits for Montana Sulphur & Chemical 
Company's (MSCC's) sulfur recovery unit (SRU) 100-meter stack and the 
stack height credit on which those limits were based.
     The emission limits for MSCC's auxiliary vent stacks due 
to lack of an adequate limit on fuel burned in the associated heaters 
and boilers and lack of a reliable compliance determining method.
     The emission limits for MSCC's 30-meter stack due to lack 
of an adequate limit on fuel burned in the associated heaters and 
boilers, and lack of a reliable compliance determining method.
     Provisions that allowed sour water stripper overheads to 
be burned in the flares at CHS Inc. and ExxonMobil.
     ExxonMobil's refinery fuel gas combustion device emission 
limits and associated compliance determining methods.
     ExxonMobil's Coker CO Boiler stack emission limits and 
associated compliance determining methods.
     CHS Inc.'s combustion source emission limits and certain 
associated compliance determining methods.
    On June 10, 2002, MSCC petitioned the United States Court of 
Appeals for the Ninth Circuit for review of EPA's May 2, 2002, final 
SIP action. Subsequently, MSCC and EPA agreed to a stay of the 
litigation pending EPA's final action on this FIP. The case is 
captioned Montana Sulphur & Chemical Company v. United States 
Environmental Protection Agency, No. 02-71657. No petitions for 
judicial review were filed regarding EPA's May 22, 2003, SIP action.
    On July 12, 2006 (71 FR 39259), EPA proposed Federal Implementation 
Plan (FIP) provisions for the Billings/Laurel, Montana area because of 
our disapproval of portions of Montana's Billings/Laurel SO2 
SIP. In our proposal, we indicated that our FIP would not replace the 
SIP entirely, but instead would only replace elements of, or fill gaps 
in, the SIP.
    In promulgating today's rules, EPA is fulfilling its mandatory duty 
under section 110(c) of the Act. Under section 110(c), whenever we 
disapprove a SIP, in whole or in part, we are required to promulgate a 
FIP. Specifically, section 110(c) provides:

    ``(1) The Administrator shall promulgate a Federal 
implementation plan at any time within 2 years after the 
Administrator--
    (A) Finds that a State has failed to make a required submission 
or finds that the plan or plan revision submitted by the State does 
not satisfy the minimum criteria established under [section 
110(k)(1)(A)],\1\ or
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    \1\ Section 110(k)(1) requires the Administrator to promulgate 
minimum criteria that any plan submission must meet before EPA is 
required to act on the submission. These completeness criteria are 
set forth at 40 CFR 51, Appendix V.
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    (B) Disapproves a State implementation plan submission in whole 
or in part, unless the State corrects the deficiency, and the 
Administrator approves the plan or plan revision, before the 
Administrator promulgates such Federal implementation plan.''
    Thus, because we disapproved portions of the Billings/Laurel 
SO2 SIP, and the attainment demonstration, we are required 
to promulgate a FIP.
    Section 302(y) defines the term ``Federal implementation plan'' in 
pertinent part, as:

    ``[A] plan (or portion thereof) promulgated by the Administrator 
to fill all or a portion of a gap or otherwise correct all or a 
portion of an inadequacy in a State implementation plan, and which 
includes enforceable emission limitations or other control measures, 
means or techniques (including economic incentives, such as 
marketable permits or auctions or emissions allowances) * * *.''

    More simply, a FIP is ``a set of enforceable federal regulations 
that stand in the place of deficient portions of a SIP.'' McCarthy v. 
Thomas, 27 F.3d 1363, 1365 (9th Cir. 1994). As the Court of Appeals for 
the D.C. Circuit noted in a 1995 case, FIPs are powerful tools to 
remedy deficient state action:

    The FIP provides an additional incentive for state compliance 
because it rescinds state authority to make the many sensitive 
technical and political choices that a pollution control regime 
demands. The FIP provision also ensures that progress toward NAAQS 
attainment will proceed notwithstanding inadequate action at the 
state level.

    Natural Resources Defense Council, Inc. v. Browner, 57 F.3d 1122, 
1124 (D.C. Cir. 1995).
    When EPA promulgates a FIP, courts have not required EPA to 
demonstrate explicit authority for specific measures: ``We are inclined 
to construe Congress' broad grant of power to the EPA as including all 
enforcement devices reasonably necessary to the achievement and 
maintenance of the goals established by the legislation.'' South 
Terminal Corp. v. EPA, 504 F.2d 646, 669 (1st Cir. 1974). As the Ninth 
Circuit stated in a case involving a FIP with far-reaching consequences 
in Los Angeles: ``The authority to regulate pollution carries with it 
the power to do so in a manner reasonably calculated to reach that 
end.'' City of Santa Rosa v. EPA, 534 F.2d 150, 155 (9th Cir. 1976), 
vacated and remanded on other grounds sub nom. Pacific Legal Foundation 
v. EPA, 429 U.S. 990 (1976).
    In addition to giving EPA remedial authority, section 110(c) 
enables EPA to assume the powers that the state would have to protect 
air quality, when the state fails to adequately discharge its planning 
responsibility. As the Ninth Circuit held, when EPA acts to fill in the 
gaps in an inadequate state plan under section 110(c), EPA `` `stands 
in the shoes of the defaulting State, and all of the rights and duties 
that would otherwise fall to the State accrue instead to EPA.' '' 
Central Arizona Water Conservation District v. EPA, 990 F.2d 1531, 1541 
(9th Cir. 1993). As the First Circuit held in an early case:

    ``[T]he Administrator must promulgate promptly regulations 
setting forth `an implementation plan for a State' should the state 
itself fail to propose a satisfactory one * * * The statutory scheme 
would be unworkable were it read as giving to EPA, when promulgating 
an implementation plan for a state, less than those necessary 
measures allowed by Congress to a state to accomplish federal clean 
air goals. We do not adopt any such crippling interpretation.''

    South Terminal Corp. v. EPA, supra, at 668 (citing previous version 
of section 110(c)).
    The Billings/Laurel SO2 FIP establishes emission limits 
and compliance determining methods for four sources located in 
Billings/Laurel, Montana, to replace/fill gaps in portions of the SIP 
we disapproved, and to

[[Page 21420]]

support our attainment demonstration. Three of the sources are 
petroleum refineries: CHS Inc., ConocoPhillips (including the Jupiter 
Sulfur facility), and ExxonMobil. The fourth source is Montana Sulphur 
& Chemical Company, which provides sulfur recovery for the ExxonMobil 
refinery.
    The following is a summary of the major components of our FIP rule:
    (1) The FIP establishes flare emission limits at all four sources 
(150 lbs SO2/3-hour period at all but the Jupiter Sulfur 
flare, 75 lbs SO2/3-hour period shared limit for the Jupiter 
Sulfur flare and the Jupiter Sulfur SRU/ATS stack) and monitoring 
methods to determine compliance with those limits. The FIP includes an 
affirmative defense to penalties for violations of the flare limits 
that occur during malfunction, startup, and shutdown periods. To 
determine flare emissions, the FIP requires concentration monitoring 
(which can consist of continuous monitoring, grab sampling, or 
integrated sampling) and continuous flow monitoring.
    (2) The FIP prohibits the burning of sour water stripper overheads 
in CHS Inc.'s main crude heater and requires CHS Inc. to keep the valve 
between the old sour water stripper and the main crude heater closed, 
chained, and locked.
    (3) The FIP provides that emission limits for identified ExxonMobil 
refinery fuel gas combustion units are contained in the SIP, and 
establishes compliance determining methods for instances in which the 
H2S concentration in the refinery fuel gas stream exceeds 
1200 ppmv. These methods involve the use of length-of-stain detector 
tubes on a once-per-hour frequency.
    (4) The FIP provides that emission limits for ExxonMobil's Coker CO 
Boiler stack, when ExxonMobil's Coker unit is operating and Coker unit 
flue gases are burned in the Coker CO Boiler, are contained in the SIP. 
The FIP establishes compliance determining methods for these emission 
limits that require measurement of the SO2 concentration and 
flow rate in the Coker CO Boiler stack using CEMS.
    (5) The FIP establishes emission limits on MSCC's SRU 100-meter 
stack, based on good engineering practice (GEP) stack height credit of 
65 meters, with compliance with these limits to be determined using 
methods already approved in the SIP. The FIP does not provide variable 
emission limits for this stack.
    (6) The FIP establishes emission limits and compliance determining 
methods for MSCC's auxiliary vent stacks and SRU 30-meter stack. In 
addition to mass limits, the FIP establishes concentration limits on 
fuel burned in the units that vent to the auxiliary vent stacks and SRU 
30-meter stack. These concentration limits are 160 ppm H2S 
per 3-hour period and 100 ppm H2S per calendar day. When 
trigger events specified in the rule occur, MSCC must measure the 
H2S concentration in the fuel using length-of-stain detector 
tubes on a once-per-3-hour period.
    (7) The FIP establishes various recordkeeping and reporting 
requirements.
    It is important to note that, in cases where the provisions of the 
FIP address emissions activities differently or establish different 
requirements than provisions of the SIP, the provisions of the FIP take 
precedence. We also caution that if any of the four sources are subject 
to requirements under other provisions of the Act (e.g., section 111 or 
112, part C of title I, or SIP-approved permit programs under part A of 
title I), our promulgation of the FIP does not excuse any of the 
sources from meeting such requirements. Finally, our promulgation of 
the FIP does not imply any sort of applicability determination under 
other provisions of the Act (e.g., section 111 or 112, part C of title 
I, or SIP-approved permit programs under part A of title I).

II. Issues Raised by Commenters and EPA's Response

A. FIP Not Necessary

1. Ambient Data and Historical Modeling Show Attainment
    (a) Comment (CHS Inc., COPC, ExxonMobil, NPRA, MPA, MDEQ, MSCC, 
WETA): The FIP is not necessary for attainment of the NAAQS because 
ambient data show that the Billings/Laurel area has been for many years 
and continues to be in attainment with both the Federal and State 
SO2 ambient air quality standards for all averaging periods.
    Response: EPA does not agree that a FIP is not necessary because 
ambient data show attainment of the SO2 NAAQS. Ambient 
monitoring is limited in time and in space. Ambient monitoring can 
measure pollutant concentrations only as they occur; it cannot predict 
future concentrations when emission levels and meteorological 
conditions may differ from present conditions.
    EPA has long held that ambient monitoring data alone generally are 
not adequate for SO2 attainment demonstrations. 
Additionally, a small number of ambient SO2 monitors usually 
are not representative of the air quality for an area. (See reference 
document GGGGG, April 21, 1983, memorandum from Sheldon Meyers, 
Director, Office of Air Quality Planning and Standards (OAQPS), to 
Regional Air and Waste Division Directors, titled ``Section 107 
Designation Policy Summary,'' and reference document HHHHH, September 
4, 1992, memorandum from John Calcagni, Director, Air Quality 
Management Division, OAQPS, to Regional Air Division Directors, titled 
``Procedures for Processing Requests to Redesignate Areas to 
Attainment.'')
    Typically, modeling estimates of maximum ambient concentrations are 
based on a fairly infrequent combination of meteorological and source 
operating conditions. To capture such results on an ambient monitor 
would normally require a prohibitively large and expensive network. 
Therefore, dispersion modeling is generally necessary to 
comprehensively evaluate sources' impacts and to determine the areas of 
expected high concentrations. (Id.) Air quality modeling results would 
be especially important if sources were not emitting at their maximum 
level during the monitoring period or if the monitoring period did not 
coincide with potentially worst-case meteorological conditions. 
Further, ambient monitoring data are not adequate if sources are using 
stacks with actual heights greater than good engineering practice stack 
height (which indeed is the case with MSCC and ConocoPhillips) or other 
dispersion techniques for which SIP/FIP modeling credit is not allowed. 
(See also our discussion of related issues in our final action on the 
Billings/Laurel SO2 SIP (67 FR 22168, 22185-22187, May 2, 
2002.))
    Ambient monitoring data and air quality modeling data for a 
particular area can sometimes appear to conflict. This is primarily due 
to the fact that modeling results may predict maximum SO2 
concentration at receptors where no monitors are located.
    Moreover, our SIP Call for the Billings/Laurel area was based on 
modeled violations of the SO2 NAAQS, not monitored 
violations. (See reference documents Y and Z.) We took final action on 
the SIP Call in our May 2, 2002, action on the Billings/Laurel SIP (67 
FR 22168, 22173), and we are not revisiting it in this FIP action. It 
would be inconsistent and inappropriate to now rely solely on 
monitoring to determine necessary measures and demonstrate attainment.
    It is especially important to recognize that, as a result of our 
partial and limited disapproval of the Billings/

[[Page 21421]]

Laurel SO2 SIP, we are legally obligated to promulgate a FIP 
for the area. See section 110(c)(1) of the CAA, 42 U.S.C. 7410(c)(1). 
However, the SIP deficiencies that triggered our partial and limited 
disapproval were varied and were not necessarily associated with 
problems that could be measured at an ambient monitor. For example, one 
basis for disapproval of the SIP was the State's use of improper (too 
tall) stack height credit for MSCC in modeling attainment of the NAAQS. 
In the real world, emissions at the actual (100 meter) height of the 
stack create less impact on monitored ambient concentrations in the 
Billings/Laurel area than if the emissions were emitted from a lower 
stack. Nonetheless, we had to partially disapprove the SIP due to the 
State's inappropriate grant of stack height credit, and section 110(c) 
of the CAA requires that we correct the deficiency. Since the State did 
not model attainment at the proper stack height credit for MSCC's 
stack, it was necessary that we do so and set emission limits for the 
stack consistent with our attainment demonstration. We believe MSCC has 
consistently been meeting the emission limits we are adopting, so there 
may be no reduction in actual emissions from the stack, but that does 
not mean the CAA allows us to forego this aspect of the FIP.
    Likewise, CAA sections 110(a)(2)(A) and (C) require that SIP 
control measures be enforceable. We disapproved several source 
monitoring methods because they were not adequate to determine 
compliance under all operating conditions. It may be impossible to 
measure the impact these SIP deficiencies may have on ambient 
SO2 concentrations in the area, but the CAA still requires 
that we correct the deficiencies. Regarding the emission limits and 
compliance determining methods for the flares, the State-only flare 
limits, which the State relied on to demonstrate attainment, may have 
positively impacted flare emissions in the past few years. However, the 
State did not include the State-only flare limits or adequate 
compliance determining methods in the SIP. Thus, the SIP remains 
deficient. We now have the responsibility to ensure that emission 
limits relied on to demonstrate attainment are included in the SIP and 
are practically enforceable, consistent with the requirements of 
section 110 of the Act.
    (b) Comment (MSCC, MDEQ): The State's SIP modeling, along with 
appropriate emission limits, show attainment of the NAAQS.
    Response: EPA addressed this issue in its actions on Montana's SIP 
submissions. As explained in those actions, EPA does not agree that the 
State's SIP modeling, along with appropriate emission limits, show 
attainment of the NAAQS. EPA's formal determinations regarding the 
attainment demonstration and emission limits were made in final actions 
on May 2, 2002 (67 FR 22168) and May 22, 2003 (68 FR 27908). The FIP 
fills the gaps for the provisions we disapproved.
    We note that we have not reopened our SIP actions as part of this 
action. Thus, to the extent the commenters are expressing their 
disagreement with EPA's actions on the SIP, their comments are not 
relevant to this action, and EPA is not re-considering them here.
    (c) Comment (ExxonMobil): EPA's proposed FIP ignores the 
substantial improvement in air quality in the Billings/Laurel area and 
instead predicts exceedances of NAAQS based upon modeling performed as 
long as 15 years ago. EPA's FIP proposal must be further examined in 
light of subsequent developments, including correct modeling and 
consideration of currently available information indicating compliance.
    Response: See response to comment II.A.1.(a), above, regarding 
ambient data and response to comments in section II.E., below, 
regarding modeling.
2. Existing Controls Sufficient
    (a) Comment (MDEQ, MSCC, COPC, ExxonMobil, MPA, NPRA, WETA): The 
FIP offers questionable improvements because the existing control plan 
provisions submitted by the state are adequate and contain sufficient 
SO2 emission controls and strategies and provide for the 
implementation, maintenance, and enforcement of the SO2 
NAAQS.
    Response: EPA addressed the adequacy of Montana's SIP submissions 
in its final actions on the SIP. As explained in those actions, EPA 
does not agree that the State's SIP control plan provisions are 
adequate and contain sufficient SO2 emission controls to 
show attainment of the NAAQS. EPA's formal determinations regarding the 
attainment demonstration and emission control plan were made in final 
actions on May 2, 2002 (67 FR 22168) and May 22, 2003 (68 FR 27908). In 
our May 2002 and May 2003 actions we disapproved various control plan 
provisions. The FIP fills the gaps for the provisions we disapproved. 
The FIP offers necessary improvements to the SIP by imposing new 
emission limits and reliable compliance determining methods to ensure 
attainment of the SO2 NAAQS.
    We note that we have not reopened our SIP actions as part of this 
action. Thus, to the extent the commenters are expressing their 
disagreement with EPA's actions on the SIP, their comments are not 
relevant to this action, and EPA is not re-considering them here.
    (b) Comment (CHS Inc., WETA, COPC, MDEQ, ExxonMobil, NPRA): In 
addition to the SIP, SO2 emissions in the Billings/Laurel 
area have decreased as a result of Consent Decrees and Montana Air 
Quality Permit changes. These limits are all federally enforceable 
because there are Title V operating permit conditions (CHS Inc.). EPA 
did not consider these emission reductions in making its determination 
that the FIP was necessary. The FIP proposal does not otherwise 
acknowledge the practical effects of the recent consent decrees between 
the primary refinery parties subject to regulation as well as other 
permitting actions that have occurred over the past eight years (MSCC, 
COPC).
    Response: EPA did not consider the emission reductions that 
resulted, or will result, from the consent decrees and/or State permit 
revisions to determine that the FIP was necessary or include the 
emission reductions in our modeling for several reasons.
    First, the FIP is required because we disapproved the SIP, and the 
State has not made revisions to the SIP to address the SIP's flaws. As 
noted in other responses, because we disapproved the SIP, we have a 
legal obligation to promulgate a FIP. See CAA section 110(c), 42 U.S.C. 
7410(c).
    Second, even though permits and consent decrees are federally 
enforceable, some permits can be revised without EPA approval and 
consent decrees have a limited lifespan.\2\ To protect the integrity of 
the attainment demonstration, and our statutory role in assessing SIP/
FIP adequacy, we believe that stationary source emission limits 
necessary to demonstrate attainment must be included in the FIP (or 
approved SIP). See, e.g., CAA sections 110(a)(2)(A), 110(i), 110(k)(3)-
(6), and 110(l), 42 U.S.C. 7410(a)(2)(A), (i), (k)(3)-(6), and (l). 
This ensures that changes to those limits will only be made with EPA's 
approval as a SIP or FIP revision,

[[Page 21422]]

following notice and comment rulemaking.
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    \2\ The State can revise construction permits without EPA 
approval, and, while EPA has authority to object to Title V permits, 
that authority is only available to ensure that underlying 
applicable requirements are included in the Title V permits. Thus, 
if those underlying requirements change, EPA may have no recourse at 
the Title V stage.
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    Third, the consent decrees and permitting actions, for some 
emission points, do not contain SO2 emission limits that are 
consistent with the averaging times of the SO2 NAAQS, 
specifically, the 3-hour and calendar day averaging periods. For 
example, the SIP establishes 3-hour, calendar day, and calendar year 
emission limits for CHS Inc.'s FCC regenerator/CO boiler stack. The 
January 17, 2007, final State construction permit (reference document 
IIIII) and the consent decree (reference document JJJJJ) indicate that 
the FCC regenerator stack SO2 emissions shall not exceed 50 
ppm by volume (corrected to 0% O2) for a 7-day rolling 
average [or a fresh feed of 0.3 percent by weight] and 25 ppm by volume 
(corrected to 0% O2) for a 365-day rolling average. None of 
the commenters has suggested these limits be converted to FIP mass 
limits that would apply over a 3-hour averaging period, and the State 
has not submitted a SIP revision with such limits.
    It should be noted that EPA did solicit comment on whether we 
should limit the main flares to 500 pounds of SO2 per 
calendar day. This value is consistent with the trigger point for 
certain analyses contained in settlements (i.e., consent decrees) 
between the United States and CHS Inc., ConocoPhillips, and ExxonMobil. 
We received limited comments on this proposal and have decided to keep 
the limit at 150 pounds of SO2 per 3-hour period to maintain 
consistency with the State's State-only limit.

B. EPA Exceeded Its Authority in Proposing a FIP

1. State's Responsibility
    (a) Comment (WETA, MPA, ExxonMobil): EPA's role is limited to 
determining whether or not a SIP is attaining and maintaining the 
NAAQS. Selecting the source mix and various control measures to achieve 
these ends has been determined by courts to be the sole responsibility 
of the state. EPA's proposed action intrudes on the primary 
responsibility of the state and local governments to implement the 
Clean Air Act (MSCC).
    Response: The commenters' characterization of EPA's role regarding 
SIPs is not accurate. We lack authority to question a state's choices 
of emissions limitations if they are part of a plan that satisfies the 
standards of the Clean Air Act. Train v. Natural Resources Defense 
Council, 95 S.Ct. 1470, 1481-1482 (1975). In our 2002 and 2003 actions, 
we found that Montana's SO2 SIP for Billings/Laurel did not 
fully satisfy CAA requirements. See 67 FR 22168, May 2, 2002 and 68 FR 
27908, May 22, 2003. Thus, pursuant to section 110(c) of the CAA, 42 
U.S.C. 7410(c), we are required to promulgate a FIP. In doing so, we 
stand in the state's shoes and have authority to determine emissions 
limitations and other measures for specific sources to fill gaps in the 
SIP. Central Arizona Water Conservation District v. EPA, 990 F.2d 1531, 
1541 (9th Cir. 1993); South Terminal Corp. v. EPA, 504 F.2d 646, 668 
(1st Cir. 1974) (citing previous version of CAA section 110(c)).
    We note that we have not reopened our SIP actions as part of this 
action. Thus, to the extent the commenters are expressing their 
disagreement with EPA's actions on the SIP, their comments are not 
relevant to this action, and EPA is not re-considering them here.
    (b) Comment (WETA): Since the State of Montana has already taken 
appropriate actions to reduce sulfur dioxide emissions, EPA does not 
have the authority under the CAA to adopt the proposed FIP.
    Response: See response to comment II.B.1.(a), above. The adequacy 
of the State of Montana's actions has already been considered by EPA in 
other rulemaking actions that addressed the State's SIP submission. 
Those actions are not the subject of EPA's present rulemaking, which 
promulgates the necessary measures to remedy the deficiencies EPA 
identified in its prior SIP reviews.
    (c) Comment (MSCC): States have primacy, and because EPA did not 
choose to exercise its rights in the comprehensive and competent state 
decision process, EPA may not default and then act.
    Response: Under section 110(c) of the Act, EPA is not required to 
participate in a state's administrative process before promulgating a 
FIP.
    (d) Comment (MSCC, MDEQ, ExxonMobil): EPA has no authority to 
question the wisdom of a state's choices of emission limitations if 
they are part of a plan that satisfies the standards of Sec.  110(a)(2) 
of the Act. As long as the ultimate effect of a state's choice of 
emission limitations is compliance with the NAAQS, the state is at 
liberty to adopt whatever mix of emission limitations it deems best 
suited to its particular situation. There is no evidence provided by 
EPA that Montana reached its material conclusions or choices in the SIP 
unreasonably. Additionally, EPA has not shown that additional controls 
beyond the SIP measures adopted by Montana are necessary to meet or 
assure SO2 NAAQS compliance.
    Response: See our responses to comments II.A.1.(a) and II.B.1.(a), 
above. Much of this comment pertains to our actions on Montana's SIP. 
We are not revisiting or reopening comment on those actions here. Our 
basis for finding that the SIP was not adequate to ensure attainment 
and meet other CAA requirements is described in our actions on the SIP. 
Once we disapprove part or all of a required SIP, section 110(c) of the 
Act requires that we issue a FIP. Our obligation in this action is to 
correct the SIP deficiencies we previously identified. Thus, the 
findings that triggered our responsibility to promulgate a FIP were 
established in the prior rulemaking actions reviewing Montana's SIP. 
EPA is not required to repeat those findings in the FIP rulemaking 
itself.
    (e) Comment (ExxonMobil): EPA cannot propose a FIP to replace a 
SIP, unless the SIP is substantially inadequate to ensure compliance 
with the CAA.
    Response: The commenter misstates the standard for promulgation of 
a FIP. Section 110(c) of the CAA is straightforward--a FIP is required 
if (1) EPA finds that a state has failed to make a required submission; 
(2) EPA finds that a plan submission does not satisfy the completeness 
criteria established under section 110(k)(1)(A) of the CAA; or (3) EPA 
disapproves a SIP in whole or in part. EPA partially disapproved the 
Billings/Laurel SO2 SIP; thus, a FIP is required. Contrary 
to the commenter's assertion, the obligation to promulgate a FIP is not 
contingent on an EPA finding of substantial inadequacy. As explained 
above, the findings triggering our responsibility to promulgate a FIP 
were made in the prior actions reviewing Montana's SIP.
    (f) Comment (MSCC): The commenter claims EPA's action violates the 
Tenth Amendment to the Constitution. The commenter also claims EPA's 
FIP is dictating the required controls in contravention of the holdings 
in Commonwealth of Virginia v. EPA, 108 F.3d 1397 (D.C. Cir. 1997) and 
Bethlehem Steel v. Gorsuch, 742 F.2d 1028 (7th Cir. 1984).
    Response: Our FIP compels no action on the part of the State and is 
not coercive vis-[agrave]-vis the State. Our FIP contains requirements 
applicable to four private companies. The Tenth Amendment is not 
implicated. Nor do our actions contravene Commonwealth of Virginia or 
Bethlehem Steel. The former case held that EPA cannot, in a SIP Call, 
dictate that a state adopt a particular control measure to

[[Page 21423]]

demonstrate attainment of the NAAQS. EPA had issued a SIP Call finding 
that the SIPs of 12 states were inadequate to meet the ozone NAAQS and 
in its SIP Call rule, specified that the states needed to submit SIPs 
that included the California Low Emission Vehicle Program. In this 
matter, we are promulgating a FIP, not issuing a SIP Call. We are not 
directing any action by the State. Thus, the Commonwealth of Virginia 
case is not relevant to our FIP. Bethlehem Steel is also not relevant 
to our FIP action. In that case, the 7th Circuit held that it was 
improper for EPA to partially approve an Indiana SIP revision so as to 
render it more stringent than the State intended. We are promulgating a 
FIP in this action, not acting on a SIP; thus, Bethlehem Steel does not 
apply. As we note elsewhere, once we disapprove a SIP, we are required 
to promulgate a FIP, and in promulgating the FIP, we stand in the 
state's shoes. See section 110(c) of the CAA, 42 U.S.C. 7410(c); 
Central Arizona Water Conservation District v. EPA, 990 F.2d 1531, 1541 
(9th Cir. 1993).
    (g) Comment (MSCC): The commenter argues that the cases EPA cited 
in the preamble to the proposed Billings/Laurel FIP, regarding its FIP 
authority, do not speak to the central question--``When and on what 
authority may the EPA undertake the draconian act of displacing a 
state's implementation plan?'' The commenter argues that the question 
is particularly sensitive in this case because the State and the 
sources spent years negotiating the SIP.
    Response: As noted in response to comment II.B.1.(e), the CAA 
requires that we promulgate a FIP whenever we disapprove a SIP, in 
whole or in part. While we are sensitive to the fact that the State and 
sources spent years negotiating the SIP, that does not change our 
obligation under the CAA.
2. No Adequate Basis for FIP
    (a) Comment (MSCC, ExxonMobil): Because EPA must find substantive 
noncompliance with some provision of the Clean Air Act, specifically, 
failure to attain NAAQS, and because that finding of substantial 
inadequacy must be clearly stated, the present FIP decision must fall. 
It is inadequate on both counts. EPA has not provided any evidence that 
the State plan is not working.
    Response: See our response to comment II.B.1.(e), above. The 
evidence supporting EPA's determinations regarding the adequacy of 
Montana's SIP is contained in the record for those rulemaking actions, 
and need not be repeated here. EPA's disapproval of the SIP triggered 
the obligation for a FIP. No separate showing that the State plan is 
not working or does not meet CAA requirements is needed as part of this 
action. Commenters' comments regarding EPA's SIP actions are not 
relevant for this rulemaking.
    (b) Comment (ExxonMobil): Even when the EPA has statutory authority 
for a particular rule, its technical decisions about the level of 
pollutant reduction needed to comply with the CAA and the control 
strategies necessary to meet the level of pollutant reduction must be 
rational. Courts ``confronted with important and seemingly plausible 
objections going to the heart of a key technical determination * * * '' 
will not presume that EPA would never behave irrationally. South 
Terminal Corporation v. Environmental Protection Agency, 504 F.2d 646, 
665 (1st Cir. 1974). In South Terminal Corporation, various interested 
parties challenged EPA's FIP on technical grounds. Id. at 662-66. The 
court held that EPA failed to adequately support its decision to 
promulgate the rules contained in the FIP and remanded the case to EPA 
to develop the record. Id. at 666. The court questioned EPA's position 
in light of contradictory modeling and data, concluding that ``it is 
not clear whether or not the ambient air at Logan meets, or will 
without controls by mid-1975 will meet, the national primary 
standard.'' Id. 664. Similarly, in the present FIP proposal, EPA has 
neither determined appropriate current modeling nor used currently 
available information.
    Response: The standards for judicial review of this rulemaking 
action are contained in section 307(d)(9) of the CAA, 42 U.S.C. 
7607(d)(9). We believe the emission limitations and other requirements 
in this FIP are reasonable and that the situation in the cited case is 
not analogous.\3\ The commenter has not identified any modeling that 
contradicts our attainment demonstration, which forms the basis for the 
FIP's emission limitations; nor has the commenter shown that a 
different model would result in substantially different emission 
limitations. Our responses pertaining to model selection and input data 
are contained in section II.E., below. Further, we note that it does 
not appear the commenter is suggesting that the entire SIP should be 
re-done based on more current modeling and more up-to-date information. 
On the contrary, the commenter seems satisfied with the EPA-approved 
emission limitations in the SIP,\4\ which were based on the very 
modeling that the commenter now claims is unreliable.
---------------------------------------------------------------------------

    \3\ In South Terminal Corporation, EPA had determined emissions 
reductions needed to achieve the ozone and carbon dioxide NAAQS 
based on monitored values that the Court found highly questionable 
(petitioners claimed the ozone monitor was defective). South 
Terminal Corporation, 504 F.2d 646, 662 (1974). The commenter seems 
to suggest that the Court rejected EPA's modeling approach, but in 
fact, the Court was satisfied with the rollback modeling that EPA 
used. Id.
    \4\ Among other things, the commenter asserts that the state SIP 
requirements are adequate to protect the NAAQS. See reference 
document YYYY, page 27.
---------------------------------------------------------------------------

    (c) Comment (ExxonMobil): Citing Hall v. United States 
Environmental Protection Agency, 273 F.3d 1146, 1159 (9th Cir. 2001), 
the commenter states that in acting on a SIP, the test EPA applies is 
to ``measure the existing level of pollution, compare it with the 
national standards, and determine the effect on this comparison of 
specified emission modifications.'' The commenter argues that in the 
FIP proposal, EPA did not correctly identify the existing level of 
pollution and ignored the substantial evidence of permanently reduced 
SO2 emissions and levels in the Billings/Laurel area. The 
commenter also argues that EPA's authority is limited by its mandate 
under the CAA to ensure attainment and maintenance of the NAAQS as well 
as the CAA's other general requirements.
    Response: See responses to comments II.A.1.(a), II.A.2(b), and 
II.E.1.(e) and (g). Also, the Hall case involved a challenge to EPA's 
approval of a SIP revision for Clark County, Nevada, and EPA's 
interpretation of section 110(l) of the CAA, which provides that EPA 
may not approve a SIP revision if it would interfere with attainment or 
other applicable requirements of the CAA. EPA asserted that its 
approval of the Clark County SIP revision was consistent with section 
110(l) because the revision did not relax the existing SIP. The Court 
disagreed, holding that 110(l) requires more--a determination that the 
specific revision, when considered in the context of the SIP elements 
already in place, can meet the Act's attainment requirements. Hall at 
1152, 1159. It was in these circumstances that the Court expected EPA 
to determine the extent of pollution reductions required and evaluate 
whether the reductions resulting from the revision would be sufficient 
to attain the NAAQS.
    In its reference to Hall, the commenter appears to be conflating 
two disparate concepts. The Hall Court was addressing EPA's action on a 
SIP revision and indicating that EPA was not adequately evaluating 
whether Clark County's rule change would interfere

[[Page 21424]]

with attainment and other CAA requirements. The Court was not 
establishing a standard for a FIP or indicating that EPA was requiring 
more than necessary for the area, which seems to be what the commenter 
is suggesting in the case of the Billings/Laurel FIP. As we explain in 
greater depth elsewhere in this notice, we are not starting from 
scratch with our FIP. Instead, we are working within the framework of 
the existing Billings/Laurel SIP to fill the gaps resulting from our 
partial and limited disapproval of discrete SIP elements. In this 
unique circumstance, where only discrete elements of the SIP were 
deficient, the CAA does not require us to reevaluate or replace the 
entire SIP or the basic modeling approach upon which it was based. 
Nothing in the CAA requires EPA to reject an entire SIP when only 
certain elements within it are not approvable, and doing so, where that 
is not necessary to address a discrete deficiency, would be 
inconsistent with the basic scheme of cooperative federalism embodied 
in the CAA.
    Nor are we required as part of this FIP to revisit our SIP Call or 
the bases for our SIP disapproval. Our task is to fix the portions of 
the SIP that were deficient. It is reasonable to continue to treat as 
valid the factors we found adequate to support the portions of the SIP 
we approved, and augment and/or replace those factors that we found 
inadequate. In fact, based on the holding in Train v. NRDC, 421 U.S. 57 
(1975), recited by this commenter and others, it would be inappropriate 
for EPA to now reject or replace the portions of the SIP that we 
approved as meeting the CAA's requirements, because to do so would be 
to intrude on the State's authority under the CAA to establish the mix 
of controls for the area.\5\ The State, of course, remains free to 
submit a SIP revision that reflects a different mix of controls across 
all the sources. This would be the mechanism, for example, whereby the 
State could adopt SIP limits that correlate to refinery consent decree 
limits.\6\ If the State were to submit such a revision, we would 
evaluate the revision according to the Act, our regulations, and the 
relevant cases.
---------------------------------------------------------------------------

    \5\ To the extent the commenter is arguing that we may do no 
more in this FIP than appears minimally necessary to attain the 
NAAQS, we reject that notion as well. See, e.g., Central Arizona 
Water Conservation District v. EPA, 990 F.2d 1531, 1541 (9th Cir. 
1993) (EPA ``stands in the shoes of the defaulting State, and all of 
the rights and duties that would otherwise fall to the State accrue 
instead to EPA.'') Under the CAA, states are not restricted to 
barely meeting the NAAQS. In fact, the opposite is true--states may 
exceed minimum requirements. See CAA section 116, 42 U.S.C. 7416. In 
any event, our modeled attainment demonstration resulted in 
projected values just at the 24-hour SO2 NAAQS (365 
[mu]g/m\3\) and just below the 3-hour SO2 NAAQS (1291.5 
[mu]g/m\3\). However, we think we had discretion to adopt limits (to 
replace those we disapproved) consistent with modeled ambient 
concentrations further below the NAAQS, if we had felt a larger 
margin of safety was justified to ensure attainment and maintenance.
    \6\ As we allude to in sections II.A.2.(b), II.D.4., and 
II.E.1.(e), the consent decree limits would need to be translated 
into limits that support an attainment demonstration for the 
SO2 NAAQS. In sections II.A.2.(b) and II.D.4., we 
identify some of our concerns with the consent decree limits.
---------------------------------------------------------------------------

    (d) Comment (ExxonMobil): EPA's proposal imposes costly technology 
requirements not rationally designed to achieving their stated 
objectives. While EPA has authority to impose an emission limitation, 
the emission limitation must be necessary to attain NAAQS. City of 
Santa Rosa v. EPA, 534 F.2d 150, 155 (9th Cir. 1976), vacated on other 
grounds, 429 U.S. 990 (1976). The EPA derived its authority in City of 
Santa Rosa from its statutory mandate to ensure compliance with NAAQS 
and the fact that no alternative to its proposal was adequate to ensure 
compliance with NAAQS. It is clear that Montana's existing SIP, 
supplemented as it is by further state and federally enforceable 
consent decrees are a more than adequate alternative.
    Response: The cited case actually stands for the proposition that 
EPA's authority to adopt measures to meet the NAAQS is expansive. EPA 
adopted a FIP provision that would have required a substantial 
reduction (up to 100%) in the supply of gasoline to major metropolitan 
areas in California, including Los Angeles. Even the EPA acknowledged 
that the rule would cause severe social and economic disruption, and 
the EPA Administrator at the time publicly advocated amendments to the 
CAA to provide relief from EPA's own FIP rule. Nonetheless, the Court 
held that economic and social disruption are not cognizable if (1) a 
measure is necessary to attain the NAAQS; (2) there is no statutory 
limitation on EPA's authority to adopt the measure; and (3) there are 
no equally effective, less burdensome alternatives. City of Santa Rosa 
at 151-154.
    The measures EPA is promulgating in this FIP are in no way 
comparable to the reduction in gasoline supply at issue in the City of 
Santa Rosa case. Our FIP is narrowly tailored to fill the gaps in the 
Billings/Laurel SIP. Section 110(c) requires us to promulgate the FIP. 
There is no statutory limitation on our authority to adopt the measures 
we are adopting. On the contrary, section 110(a)(2)(A) of the Act 
requires enforceable emission limitations as necessary or appropriate 
to meet the applicable requirements of the Act, which include 
attainment and maintenance of the SO2 NAAQS. Using ISC, the 
same model the State used to set the commenter's emission limits in the 
SIP, we have determined emission levels consistent with attainment and 
established corresponding emission limits on the flares, MSCC's main 
stack, and other emission units, whose emission limits we disapproved 
in our SIP action. While the authority to require monitoring, 
recordkeeping, and reporting requirements can be inferred from CAA 
sections 110(a)(2)(A) and (C), section 110(a)(2)(F) of the Act 
specifically indicates that the EPA Administrator may prescribe the 
installation, maintenance, and replacement of monitoring equipment by 
stationary sources, as well as reporting requirements. Our requirement 
for the refineries and MSCC to install monitoring equipment to measure 
flare gas flow and concentrations is consistent with this authority and 
is rationally related to the goals of the FIP, i.e., to ensure 
attainment and maintenance of the SO2 NAAQS. We do not 
believe estimating flare emissions or emissions from other units is a 
sufficient substitute for real-time monitoring for purposes of this 
FIP; estimation is not an equally effective technique.
    The commenter argues that the existing SIP and the State and 
federally enforceable consent decrees are a more than adequate 
alternative to our FIP requirements. This comment ignores the fact that 
we disapproved portions of the SIP as not meeting the CAA's 
requirements. Elsewhere we explain that the consent decree provisions 
are not sufficient to meet the CAA's requirements under section 110 
related to attainment and maintenance of the NAAQS. See, e.g., sections 
II.A.2.(b), II.D.4., and II.E.1.(e).
    (e) Comment (MSCC): EPA's failure to issue the FIP within the CAA's 
two-year deadline is important in this case. As a result of EPA's 
delay, EPA should have to consider the cleanup of emissions that has 
occurred and significant changes in modeling technology.
    Response: We regret that it has taken this long to issue the FIP. 
We disagree that missing the two-year deadline obviates our duty or the 
need for the FIP. The State has not submitted a SIP revision correcting 
the portions of the SIP that we disapproved, despite the passage of 
time. Regarding the argument that we should have considered the 
reduction in emissions since we disapproved the SIP, see our responses 
to comments in section II.A. In section II.E, we respond to comments 
arguing

[[Page 21425]]

that we should have used newer modeling technology.

C. Flare Monitoring

1. Flare Flow Monitoring
    (a) Comment (MSCC): The core flowmeter technology application for 
flare systems seems to be an established technology, with thousands of 
installations completed around the world on other types of gas and 
liquid streams. However, none was identified that is following the 
precise specifications of the FIP proposal. Installation and operation 
of a flow meter in flare gas service at MSCC are probably achievable 
today, but not at the flow range below 1 fps, and not with conventional 
QA/QC procedures. Flow monitors have a difficult time measuring or 
reliably detecting low flow velocities (under approximately 1.0 fps) 
without false positives or false negatives. EPA should revise the 
proposed rule that currently indicates:

``[t]he 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% over the range of 1 to 275 fps.
    The revised rule should read ``[t]he minimum resolution of the 
flow monitoring device(s) shall be 0.1 feet per second (fps) when 
measuring flow rates above 1.0 fps. The device(s) shall continuously 
measure the range of flow rates corresponding to velocities from 1.0 
to 275 fps and have a manufacturer's specified accuracy of 5% over the range of that range.''

    The rule should also clarify if ``accuracy'' is intended to be 5% 
of the full-scale range of the instrument (13.7 fps is 5% of 275 fps), 
or if this is intended to be 5% of the measured flow, which would be 
0.05 fps at a flow of 1 fps, and would clearly be non-achievable with a 
resolution of 0.1 fps.
    Response: EPA proposed the volumetric flow monitoring 
specifications based on what we saw was achievable in vendor literature 
(see reference documents NN and OO) and what was being required by 
regulation in the Bay Area Air Quality Management District (BAAQMD) 
(see reference document LL) and South Coast Air Quality Management 
District (SCAQMD) (see reference document CCC).
    The commenter asserts that installation and operation of a flow 
meter at the flow range below 1 fps are not achievable. However, 
various sources indicate that ultrasonic flow meters can measure in the 
range of 0.1 to 1 fps. For example, in ``Flare Gas Ultrasonic Flow 
Meter,'' J.W. Smalling, L.D. Brawsell, L.C. Lynnwoth and D. Russel 
Wallace, Proceedings Thirty-Ninth Annual Symposium on Instrumentation 
for the Process Industries, 1984, the authors reported ``initially, a 
modest objective was established to develop an ultrasonic flow switch 
capable of detecting leaks in flare lines corresponding to flow 
velocity on the orders of 0.3 ms/ (1 ft/s). As testing continued, 
however, it became apparent that the equipment could measure flows 
below 0.03 m/s (0.1ft/s) and up to at least 6 m/s (20 ft/s) in flare 
stacks * * *'' (see reference document KKKKK). See also reference 
document OO, ``the DigitalFlowGF868 meter achieves rangeability of 2750 
to 1. It measures velocities from 0.1 to 275 ft/s (0.03 to 85 m/s) in 
both directions, in steady or rapidly changing flow, in pipes from 3 
in. to 120 in. (76 mm to 3 m) in diameter.''
    Additionally, the BAAQMD (see reference document LL) and SCAQMD 
(see reference document CCC) require flow meters on flares. BAAQMD 
requires that the minimum detectable velocity shall be 0.1 fps and the 
SCAQMD requires monitors with a velocity range of 0.1 to 250 fps. Based 
on conversations with the BAAQMD, it appears that the refineries in the 
Bay Area have installed flow meters meeting the requirements of the 
rule (see reference document OOOOO).
    Based on the above, we conclude that flow meters are available that 
can measure in the velocity range below 1.0 fps, and other regulatory 
authorities are requiring such flow meters with success.
    The commenter also claims that installation and operation of a flow 
meter are probably not achievable with conventional QA/QC procedures. 
The QA/QC procedures are discussed below in response to comment 
II.C.1.(d).
    The commenter argues that flow monitors have a difficult time 
measuring or reliably detecting low flow velocities (under 
approximately 1.0 fps) without false positives or false negatives. As 
indicated in the response to comment II.C.1.(b) below, there are 
approaches available for improving measurement accuracy in the 0.1 to 
1.0 fps range. In addition, as the response to comment II.C.1.(b) 
indicates, in the final FIP we are specifying a separate accuracy range 
for the velocity range of 0.1 to 1 fps. Finally, we describe how we are 
addressing the false positive and false negative flows in response to 
comment II.C.1.(c).
    The commenter asked that the rule clarify if ``accuracy'' of the 
instrument is intended to be 5% of the full-scale range of the 
instrument or 5% of the measured flow. In the rule, we have clarified 
that ``accuracy'' of the instrument is the accuracy of the measured 
flow and not the ``full-scale range'' of the instrument.
    The commenter also suggests some changes to the rule. Apart from 
adding a separate accuracy range for the velocity range of 0.1 to 1 fps 
and clarifying that accuracy is based on the measured flow, we are not 
making any additional changes to this aspect of the rule. We explain 
our reasoning in the response to this comment II.C.1.(a) and in the 
responses to comments II.C.1.(b)-(d), below.
    (b) Comment (ExxonMobil, WSPA): Manufacturers of flow monitoring 
instrumentation publish impressive performance specifications regarding 
velocity measurement range and accuracy, but often manufacturers' 
claims are not actually achieved in practice over the long term. To 
achieve a high level of measurement performance in the field requires 
adequate lengths of straight flare header pipe upstream and downstream 
of the monitor, the absence of flow disturbances, etc. Where these 
criteria cannot be met, the advertised or predicted performance of the 
flow monitoring system may not be fully realized in practice. MSCC 
claimed that significant piping modifications and possible flare 
relocation would be required to provide such runs at accessible 
locations. CHS Inc. asserted that it is likely that the CHS refinery 
flare header will not have adequate distances of undisturbed piping for 
ideal installation. In this case, either major, costly piping 
modification will be required or the accuracy criteria will not be 
achievable.
    Response: The commenters are correct that piping modifications may 
be appropriate to optimize the measurements. Each flare system will 
have unique flow measurement location issues and will have to be 
addressed on a case-by-case basis. Sources may need to work with the 
flow monitor manufacturer and flow testers to assure that the monitors 
meet the FIP's specifications for accuracy and representativeness and 
manufacturer's requirements for assuring ongoing equipment performance.
    In addition to making piping modifications (e.g. flow 
straighteners), other approaches are available to improve the 
measurement accuracy in the 0.1 to 1.0 fps range. Among the approaches 
are the use of additional monitoring paths, monitoring paths of longer 
length, and unconventional monitor configurations and path locations. 
Another approach involves

[[Page 21426]]

the use of Computer Fluid Dynamics (CFD) for the existing piping. CFD 
analysis has been used to provide correction factors for a series of 
velocities across the range of flow velocities. For example, these 
factors have been used to correct flow measurement data for 
disturbances caused by upstream pipe irregularities. These approaches 
are discussed in ``A Total Approach to Flare Gas Flow Measurement for 
Environmental Compliance,'' Gordon Mackie, Jed Matson and Mike Scelzo, 
Institute of Measurement and Control--Environmental Conference 2006. 
(See reference document LLLLL.) (See also Note to Billings/Laurel 
SO2 FIP File regarding conversations with GE Sensing 
(reference document MMMMM)).
    Finally, to address concerns regarding the measurement accuracy in 
the 0.1 to 1.0 fps range, we are revising the rule to indicate that the 
flow monitor must have a manufacturer's specified accuracy of  20% over the range 0.1 to 1 fps. Based on conversations with a 
vendor, we believe this is achievable. The vendor indicated that they 
have provided methodologies for sources to meet the SCAQMD rule, which 
also requires 20% accuracy in the 0.1 to 1.0 fps range. Methodologies 
include a second interrogation path or straightening of pipe. (See 
reference document MMMMM.)
    (c) Comment (ExxonMobil, WSPA, NPRA, MSCC): Consistently achieving 
low flow detection limits can be very difficult. Spurious signal, 
resulting in ``eddy'' currents and back-and-forth flows in the flare 
header, can easily limit the detection and accuracy of low flow 
readings. Furthermore, sometimes a flow monitor will show an indication 
of flow even though water seals ahead of the flare stack remain intact 
(i.e., there is not flow to the flares). Other regulations in other 
jurisdictions allow the sources other means to positively determine 
when the flare is not operating (e.g., flare on/off monitoring device, 
pressure of water seal). ExxonMobil recommends that similar language be 
considered by the stakeholder process for inclusion in the EPA's 
proposed FIP, and thereby remove the uncertainty of low flow reading. 
MSCC claimed that the EPA proposed FIP language should be revised to 
allow flare operations to be monitored by other means, and to disregard 
low flow readings when the flare is not operating to eliminate falsely 
reported SO2 emissions, when in fact there are none.
    Response: We agree that it is appropriate to include in the 
regulation the ability to use other secondary means to determine 
whether flow is reaching the flare when the flow monitor indicates low 
flow. If the secondary device indicates that no flow is going to the 
flare, yet the continuous flow monitor is indicating flow, the 
presumption will be that no flow is going to the flare. We have revised 
the final rule to allow the use of flare water seal monitoring devices 
to determine whether there is flow going to the flare, in addition to 
the continuous flow monitoring device. See response to comment 
II.F.1.(a) regarding the comment seeking a stakeholder process.
    (d) Comment (ExxonMobil, WSPA): A limitation of flare gas 
monitoring systems is the inability to provide for an independent ``in 
situ'' verification of accuracy. For example, there is no practical way 
to vary the flare gas flow that the monitor sees, and no practical way 
to utilize a reference method. Consequently, the calibration of a 
monitor is performed electronically, and the demonstration of accuracy 
is based on that calibration method. MSCC asserted that the proposed 
FIP does not provide adequate guidance to allow development of an 
acceptable QA/QC system for routine calibration or daily checks of the 
system. Without clear guidance, it is not possible to specify a system 
for a systems integrator (DAS/reporting) or an end-user to design or 
build a system to accomplish these checks.
    Response: Since refinery flares contain highly variable flows and 
highly combustible material, in situ verification of flow measurement 
accuracy is difficult. For that reason, the performance specifications 
in the FIP rely in large part on procedures developed by the ultrasonic 
flow monitor manufacturers \7\ for commissioning monitors to assure the 
monitors will meet performance specifications on an ongoing basis. 
Manufacturers have established procedures for conducting annual or more 
frequent verifications of the performance of installed flow monitors as 
well as for the initial installation and performance verification (see 
reference document NNNNN). Based on manufacturer established procedures 
(Id.), we expect that the annual verification procedures will address 
elements such as:

    \7\ Ultrasonic flow monitors will most likely be the monitors 
installed to meet the FIP's flow monitoring performance 
specifications.

    1. Verification of the Flowmeter with Reference Transducers--the 
purpose is to evaluate all flowmeter subsystems with factory-
certified ultrasonic transducers;
    2. Mechanical Inspection of Flowmeter Transducers--the purpose 
is to visually verify the integrity of the flare gas flowmeter 
transducers and to clean any accumulated debris from the transducer 
faces;
    3. Zero Flow Verification--the purpose is to evaluate the 
operation of the transducer pair in the flare gas process (the 
integrity of the original process transducers is tested in a 
controlled environment);
    4. Input/Output Verification--the purpose is to verify the 
calibration of the analog I/O of the flare gas flowmeter;
    5. Electronic Flow Simulation--the purpose is to demonstrate the 
operation of the flare gas flowmeter over the full measurement range 
of the instrument; and
    6. Flowmeter System Reinstallation and Test--the purpose is to 
verify that all mechanical systems were properly aligned.

    It should also be noted that since ultrasonic flow monitors do not 
contain any moving parts, their performance is not expected to 
deteriorate over time. One ultrasonic flow monitoring vendor provided 
information on the reliability and availability of the transducers 
(sensors in the flare that transmit and receive the ultrasound) they 
have installed. The information indicates that the 3,998 transducers 
installed between first quarter 2005 and first quarter 2007 had a 
reliability percentage of 94.32% and an availability percentage of 
99.96%. (See reference documents MMMMM and XXXXXX.) (See also reference 
document LLLLL, ``A Total Approach to Flare Gas Flow Measurement for 
Environmental Compliance,'' Gordon Mackie, Jed Matson and Mike Scelzo, 
GE Sensing, Institute of Measurement and Control, Environmental 
Conference 2006, and reference document NNNNN, April 5, 2007, email 
from Jed Matson, GE Sensing, to Laurie Ostrand, EPA, containing flare 
gas flow meter procedures.
    (e) Comment (COPC): ConocoPhillips asserts it would need to replace 
a GE Panametrics flare flow monitor that is well-suited to the variable 
flow conditions it experiences, but does not conform precisely to the 
proposed specifications. It is difficult to quantify what additional 
benefit this change would provide although the cost is significant and 
quantifiable. The benefit evaluation is further clouded because of the 
relatively recent installation of the Flare Gas Recovery Unit (FGRU). 
There is no flow to measure in the flare header when the FGRU is 
operating. The FGRU operates on a full-time basis, with the exception 
of nominal periods of malfunction or maintenance.
    Response: As indicated above, each source will have unique issues 
that will have to be addressed on a case-by-case basis.

[[Page 21427]]

    We understand that ConocoPhillips has a FGRU and ExxonMobil will be 
installing one. We do not agree that a source with a FGRU should be 
exempted from monitoring flow to the flare. We still believe it is 
reasonable to include this requirement to gain an accurate picture of 
occasions when flow is going to the flare. We note that other areas 
that have required refinery flare monitoring (SCAQMD and the BAAQMD) 
have not eliminated the flare monitoring requirements at sources with 
FGRUs. (See Note to Billings/Laurel SO2 FIP File regarding 
conversations with BAAQMD, reference document OOOOO.) However, as 
indicated below, we are providing sources other means to determine 
total sulfur concentrations in the gas stream to the flare.
    Additionally, we note that the ConocoPhillips refinery in Rodeo, 
California has installed flare flow meters and that the refinery also 
has a flare gas recovery system. The ConocoPhillips San Francisco 
Refinery's July 2007 Flare Minimization Plan (FMP), pages 3-7, 
indicates that flow meters have been installed on the Main and MP30 
flares per the BAAQMD Regulation 12-11-501. EPA's Billings/Laurel FIP 
contains flare flow monitoring specifications very similar to the 
specifications in BAAQMD Regulation 12-11-501. The July 2007 FMP 
indicates ``The installation of the flow meters provides for enhanced 
recognition of flaring events. The flow meters help reduce flaring by 
providing an accurate means to measure and provide indication as to 
when flaring is occurring. The flow meters are especially useful for 
small flaring events which may not be detectable from visual flare 
stack monitoring only. The meters help to track and record all 
instances of flaring as well as giving Unit Operators immediate 
indication that flaring is occurring so that they can take action to 
reduce flaring.'' (See reference document PPPPP.)
    (f) Comment (MSCC): The proposed 40 CFR 52.1392(h)(2)(iii) appears 
to be in error. The rule indicates that ``The flare gas stream 
volumetric flow rate shall be measured on an actual wet basis in 
SCFH.'' Actual wet basis would be abbreviated as ACFH. SCFH means 
standard cubic feet per hour, meaning that the data has been corrected 
to standard temperature and pressure. The SCFH could be replaced with 
ACFH. Alternately, the term ``actual'' could be removed from the 
section, leaving ``wet basis in SCFH.'' SCFH (corrected for temperature 
and pressure) can also be used to compute a mass emission rate of 
sulfur dioxide, provided that any concentration measurements of sulfur 
are also made on a ``wet'' basis.
    Response: The commenter is correct. We are revising the regulatory 
text to read: ``The flare gas stream volumetric flow rate shall be 
measured on an actual wet basis, converted to Standard Conditions, and 
reported in SCFH.''
    (g) Comment (several commenters): Several commenters express a 
general concern that the technology will not be able to meet the 
performance specifications.
    Response: See responses to comments II.C.1.(a)-(c), above.
    (h) Comment (YVAS): YVAS concurs with the proposed volumetric flow 
monitoring requirements.
    Response: We acknowledge receipt of the supportive comment.
2. Flare Total Sulfur Analyzers
    (a) Comment (ExxonMobil, WSPA, COPC): SCAQMD staff was not able to 
identify a single commercial sulfur analyzer in service on a refinery 
flare system. It is unreasonable for EPA to conclude that sulfur 
analyzer technology is either ``available'' or ``reliable.'' MSCC was 
not able to identify any installations where flare gas monitoring was, 
in fact, covering a range from 0-100% sulfur.
    Response: EPA has identified two sources where analyzers are on 
lines leading to the refinery flare. Specifically, the Tesoro refinery 
in the Bay Area, California, has two Thermo Electron Tracker XP 
continuous H2S analyzers. The Tesoro analyzers are dual 
range instruments, 0-1% and 0-5% (see reference document OOOOO). 
Additionally, the Shell refinery in Puget Sound, Washington, uses an 
analyzer that thermally oxidizes total sulfur to SO2 and 
then measures the SO2. The analyzer can measure up to 40,000 
ppm of SO2 (see reference document QQQQQ). Finally, as 
indicated in the response to comment II.C.2.(b) below, the SCAQMD 
recently reported on a pilot project study, testing a total sulfur 
analyzer at the BP Carson facility in southern California, and 
indicated that the ``preliminary results have demonstrated the 
feasibility of measuring total sulfur emissions from vent gases 
directed to flares.''
    The proposed FIP did not specifically require that an analyzer be 
capable of measuring in the range from 1-100% sulfur, although the 
preamble implied and the record reported conversations with vendors 
indicating that analyzers could measure in the range from 1-100% 
sulfur. We are clarifying the final FIP to indicate that the total 
sulfur analyzers should measure in the range of concentrations that are 
normally present in the gas stream to the flare. In cases when the 
total sulfur analyzer is not working or where the concentration of the 
total sulfur exceeds the range of the monitor, methods established in 
the flare monitoring plan required by the FIP 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.
    (b) Comment (ExxonMobil, WSPA): SCAQMD Rule 1118 had an important 
provision requiring an analyzer pilot project, and one Los Angeles area 
refiner is currently engaged with a sulfur analyzer demonstration 
project. It is conceivable that the pilot project could result in the 
conclusion that the analyzer being evaluated could not provide 
sufficient accuracy, that the system was not maintainable, or that 
there were other problems.
    Response: On June 1, 2007, the SCAQMD presented to its Governing 
Board an ``Implementation Status Report for 2006 for Rule 1118--Control 
of Emissions from Refinery Flares.'' Agenda No. 27 discusses the total 
sulfur (TS) analyzer pilot project at the BP refinery in Carson and 
indicates:

    The TS pilot project is in the final step prior to certification 
of the analyzer. Although several adjustments and redesign of 
sampling equipment were required; [sic] preliminary results have 
demonstrated the feasibility of measuring total sulfur emissions 
from vent gases directed to flares. Based on these results, two 
refineries have already placed purchase orders for their TS 
analyzers.

    In the May 15, 2007, ``Implementation Status Report for 2006 for 
Rule 1118--Control of Emissions From Refinery Flares,'' attached to 
Agenda No. 27, the SCAQMD concludes:

    Although they are behind schedule to comply with the July 1, 
2007 monitoring requirements, the pilot projects are moving ahead 
convincingly towards completion by the end of 2007. As the rule is 
forcing new technologies for flare emission reporting, analyzer 
vendors have responded to the challenge and several options are now 
available, such as calorimeters, gas chromatographs, mass 
spectrometers and Pulsed UV Fluorescence analyzers, for continuously 
measuring HHV [higher heating value] and TS. Therefore, staff 
expects full implementation of the continuous monitoring provisions 
of the rule once the pilot projects are complete. Since the 
refineries could not meet the monitoring requirements by July 1, 
2007, the refineries petitioned and were granted variances in late 
April 2007 by the AQMD Hearing Board to install and operate their 
flare monitoring systems over the next two years.

    See reference document RRRRR.
    Based on the above information, the total sulfur pilot project did 
not

[[Page 21428]]

conclude that the analyzer being evaluated could not provide sufficient 
accuracy, that the system was not maintainable, or that there were 
other insurmountable problems.
    (c) Comment (ExxonMobil): EPA and industry need more time to review 
the SCAQMD pilot project test results and conclusions as they become 
available over the next few months and to determine if the technology 
that was tested is technically viable and whether or not a more cost 
effective alternative technology may be available. MSCC recommends that 
the implementation of total sulfur monitoring on the flares be delayed 
at least until the full results from the long-term program in 
California are available, and the capability of the market to supply 
and support such systems in severe weather locations such as Montana is 
demonstrated. At that point EPA should revise and then issue the final 
rule, after full stakeholder involvement in the process and full 
consideration of realistically available options.
    Response: See responses to comments II.C.2.(a) and (b), above. 
Also, as noted in response to comment II.C.3.(a), below, EPA is 
revising the proposed FIP to allow other methods to determine total 
sulfur concentration in the gas stream to the flare. See response to 
comment II.F.1.(a) regarding the request for a stakeholder process.
    (d) Comment (ExxonMobil): Recognizing that these total sulfur 
analyzer systems do not, by themselves, provide any air quality 
benefit, and considering that there are alternatives to continuous 
analyzers (e.g., individual grab samples, etc.), ExxonMobil submits 
that the proposed requirement to install continuous analyzers requires 
further evaluation in the stakeholder process.
    Response: As discussed under response to comment II.C.1.(a), below, 
our final FIP allows other methods to determine total sulfur 
concentration in the gas stream going to the flare, including grab or 
integrated sampling methods. This should address the commenter's 
concerns. However, we note that whether or not total sulfur analyzer 
systems provide any air quality benefit by themselves is immaterial; 
the FIP establishes emission limits to assure that the SO2 
NAAQS are attained and maintained and it is essential that the FIP 
include reliable mechanisms to determine compliance with the limits. 
See, e.g., CAA section 110(a)(2)(F), 42 U.S.C. 7410(a)(2)(F). Finally, 
as we noted in our May 14, 2007, proposal to revise subpart J of the 
new source performance standards (NSPS), and to adopt new subpart Ja, 
the requirement to monitor flare emissions in the SCAQMD in fact 
resulted in reduced flaring (72 FR 27178, at 27195) (see reference 
document SSSSS).
    (e) Comment (ExxonMobil, WSPA): Cost of installing total sulfur 
analyzers should be further evaluated given that the analyzers 
themselves do not provide an air quality benefit. Costs of total sulfur 
analyzer pilot project in the South Coast area expected to be in the 
range of 3 to 5 million dollars.
    Response: See response to comment II.C.2.(d), above. Additionally, 
the cost of the South Coast pilot project was higher than expected 
because it was a pilot study and because some difficulties were 
encountered during the study. (See also note to Billings/Laurel 
SO2 FIP File regarding conversations with SCAQMD, reference 
document TTTTT.)
    Also, in its ``Implementation Status Report for 2006 for Rule 
1118--Control of Emissions From Refinery Flares,'' May 15, 2007, the 
SCAQMD reported that refineries involved in the pilot projects reported 
that monitoring costs were estimated to be about 2 to 4.7 million 
dollars per flare. After looking at the breakdown of the costs, SCAQMD 
staff concluded that the total sulfur and higher heating value analyzer 
costs were comparable to staff's original estimates. However, the costs 
to design and build the monitoring system were significantly different. 
Research and development (R&D), engineering, labor/oversight, piping/
electrical, analyzer shelters, and contingencies stated by the 
refineries represented approximately 75 to 85 percent of the flare 
monitoring system cost. (See reference document RRRRR.)
    SCAQMD also indicated that in a related development, ExxonMobil 
informed staff in January 2007 that ExxonMobil was taking a different 
approach and was going to use a different technology, namely, gas 
chromatography (GC) for both the TS and the HHV analyzer; the estimated 
cost given to SCAQMD staff was 1 to 2 million dollars. ExxonMobil 
advised SCAQMD staff that similar instruments had been used at 
ExxonMobil's flares in Baytown, TX, and Chalmette, LA, for monitoring 
H2S and the BTU content of vent gases for compliance with 
EPA and Texas Commission on Environmental Quality (TCEQ) regulations. 
(Id.)
    (f) Comment (CHS Inc.): Analysis of total sulfur in a flare system 
is challenging because of the wide range of sulfur concentrations 
possible as well as the number of individual sulfur compounds 
potentially present. It is the understanding of CHS that there is not 
one commercial total sulfur analyzer in service on a refinery flare.
    Response: See response to comment II.C.2.(a), above.
    (g) Comment (MSCC): Since H2S is believed to be the 
principal (overwhelming) sulfur component of candidate flares, further 
consideration is warranted as to whether the ``total'' sulfur component 
is the appropriate methodology, given the clear lack of existing 
equipment for the full potential range of concentrations of flare 
gases, and the complexity involved in continuously converting a 
variable mixture into a single component such as SO2 or 
H2S. EPA should evaluate whether there is a real, necessary, 
and significant need to require total sulfur analysis instead of 
allowing a somewhat simpler H2S analysis of flare gases.
    Response: The commenter has not provided any technical analyses 
supporting the notion that H2S is the overwhelming component 
of the total sulfur in the gas stream to its flares or other flares in 
the area. EPA reported in the May 14, 2007, proposed new source 
performance standards (NSPS) for Subpart Ja (72 FR 27178, at 27194) 
(see reference document SSSSS) that ``based on available data, we 
understand that a significant portion of the sulfur in fuel gas from 
coking units is in the form of methyl mercaptan and other reduced 
sulfur compounds. These compounds will also be converted to 
SO2 in the fuel gas combustion unit, which means the 
SO2 emissions will be higher than the amount predicted when 
H2S is the only sulfur-containing compound in the fuel 
gas.'' See also the response to comment II.C.2.(a), above. Therefore, 
in the FIP we are still requiring that the gas stream to the flare be 
analyzed for total sulfur.
    (h) Comment (ConocoPhillips, MSCC): In a typical CEMS installation, 
the analyzers are subjected to frequent testing with gases intended to 
represent a ``zero'' condition and a ``span'' condition which is 
specified as a significant percent of full scale of the analyzer. 
``Total Sulfur'' analyzers, operating over a wide range of 
concentrations, present some special concerns for span gases. If the 
proposed FIP requires high concentration analyzers, it also needs to 
incorporate protocols to establish calibration standards for these 
analyzers. ConocoPhillips indicates that flare gas sulfur 
concentrations can be highly variable, which makes the comparison 
required by the Relative Accuracy Test Audit (RATA) difficult. The 
sulfur analyzer captures samples in a series of periodic discrete 
``grab'' samples, to be averaged over the period of total sample time. 
Comparison sample techniques vary, but in general involve getting a 
continuous sample over a period of

[[Page 21429]]

time, with the concentration averaged over that time period. Depending 
on the variability of the concentration over this time period, the 
average of the discrete ``grab'' samples has the potential to be 
different than the average of the continuous RATA sample. When the 
concentrations are numerically low, this difference is compounded and 
skews the accuracy calculations. This poses a significant risk of 
failing the RATA specifications, thereby voiding the monitor data and 
imposing a compliance issue (even if the difference is a few parts per 
million). ConocoPhillips believes that this requirement is not 
technically valid for the operations for which it is being proposed.
    Response: As indicated in response to II.C.2.(b), above, the BP 
Pilot Project is nearing completion and expected to be a success. Also, 
see note to Billings/Laurel SO2 FIP File regarding 
conversations with SCAQMD (reference document TTTTT). With respect to 
the calibration of the analyzer, SCAQMD indicated that there are 
several issues that need to be addressed. Specifically, one needs to 
assure that (1) the correct calibration gas is in the bottle, (2) the 
sample lines do not absorb or desorb sulfur, (3) the probe is 
positioned appropriately, and (4) all flow testing or other sample 
collection is correlated temporally with the analyzer measurements to 
ensure representative comparisons.
    (i) Comment (ExxonMobil): EPA recognized the impracticality of 
concentration monitoring for flares during the recent Consent Decree 
negotiations. CEMS were deemed unnecessary and impractical for flares, 
unless the flare was in continuous use.
    Response: The basis for the FIP is different than the consent 
decrees. The FIP assures attainment of the SO2 NAAQS, a 
health-based standard, and the consent decrees assure that the new 
source performance standards (NSPS), technology-based standards, are 
met. Because of these differences, we believe it is appropriate to take 
a different approach.
    We disagree with the commenter's statement that ``EPA recognized 
the impracticality of concentration monitoring for flares during the 
recent Consent Decree negotiations. CEMS were deemed unnecessary and 
impractical for flares.'' The CDs required that compliance with 40 CFR 
60.104(a) be determined by several options, one of which was to install 
and operate a CEMS per 40 CFR supbart J (e.g. see paragraph 77 of CHS 
Inc.'s CD, reference document JJJJJ):

    77. All continuous or intermittent, routinely-generated refinery 
fuel gas streams that are routed to the flare header at Cenex shall 
be equipped with a CEMS as required by 40 CFR Sec.  60.105(a)(4) or 
with a parametric monitoring system approved by EPA as an 
alternative monitoring plan (``AMP'') under 40 CFR Sec.  60.13(i), 
at the combined juncture prior to the flare. Cenex shall comply with 
the reporting requirements of 40 CFR Part 60, Subpart J, for the 
Refinery Flare.

    We also note that the proposed NSPS Subpart Ja includes a total 
sulfur standard and CEMS requirements for fuel gas combustion devices, 
which are defined to include flares. (See 72 FR 27178 (May 14, 2007), 
reference document SSSSS.)
    (j) Comment (MSCC): MSCC is aware that it may be possible to use 
gas chromatography systems to attempt to meet the proposed FIP 
requirements. Due to time constraints, they were not able to 
investigate this subject thoroughly.
    Response: As indicated in response to II.C.2.(e), ExxonMobil 
reported to the SCAQMD that it is using gas chromatography for its 
total sulfur and higher heating value analyzers. ExxonMobil has advised 
SCAQMD staff that similar instruments have been used on its flares in 
Baytown, TX, and Chalmette, LA, for monitoring H2S and the 
BTU content of vent gases for compliance with EPA and Texas Commission 
on Environmental Quality (TCEQ) regulations. (See reference document 
RRRRR.) Also, see note to Billings/Laurel SO2 FIP File 
regarding conversations with SCAQMD (reference document TTTTT).
    (k) Comment (several commenters): A general concern is expressed 
that the technology is not there to meet performance specifications.
    Response: See responses to above comments II.C.2.(a) and (b).
    (l) Comment (YVAS): YVAS concurs that total sulphur concentrations 
and not just H2S be monitored.
    Response: We acknowledge receipt of the comment and the support for 
our proposal.
3. Miscellaneous Flare Monitoring Concerns
    (a) Comment (COPC, CHS Inc., MSCC): The proposed FIP should allow 
for Alternative Monitoring Plans (AMPs) to determine compliance. 
ConocoPhillips argued that AMPs are technically sound data gathering 
plans that are developed based on site-specific factors. These AMPs 
allow a facility to comply based on equivalent but customized criteria. 
CHS Inc. claimed that uncertainty of the monitoring capabilities and 
the quality assurance/quality control requirements makes it reasonable 
for EPA to allow for AMPs similar to other EPA regulations. MSCC 
indicated that it calculates and reports the amount of SO2 
emitted during each flaring event based on the recent content, and 
estimated flow gas(es) flared, based on reasonable technical judgment 
and indirect metering calculations. MSCC asserted that EPA has failed 
to show any significant errors or omissions with these methods.
    Response: EPA is revising the proposed FIP to allow other methods 
to determine total sulfur concentration in the gas stream going to the 
flare. The other methods allow sources to use grab or integrated 
sampling, followed by sample analysis, to determine total sulfur 
concentration of the gas stream going to the flare. These grab and 
integrated sampling methods are currently allowed in the BAAQMD rule 
(see reference document LL), and similar methods have been allowed by 
the SCAQMD. Two of the refinery companies (ConocoPhillips and 
ExxonMobil) in the Billings area also have refineries in the Bay Area 
and/or the South Coast Area and should be familiar with these manual 
methods.
    Specifically, we are revising the rule to indicate that the total 
sulfur concentration of the gas stream going to the flare can be 
determined by: (1) A total sulfur concentration monitoring system as we 
proposed on July 12, 2006, and including the changes we have identified 
here; or (2) grab sampling or integrated sampling.
    If a source chooses to use the grab or integrated sampling methods, 
the requirement to obtain a grab or integrated sample will be triggered 
if the velocity of the gas stream to the flare in any consecutive 15-
minute period continuously exceeds 0.5 feet per second (fps) and shall 
continue until the flow rate of the gas stream to the flare in any 
consecutive 15-minute period is continuously 0.5 fps or less. 
Additionally, the rule indicates that a grab or integrated sample will 
not be required if any water seal monitoring device indicates that flow 
is not going to the flare. See discussion in response to comment 
II.C.1.(c). Under these conditions, if the water seal monitoring device 
indicates that there is no flow going to the flare, yet the continuous 
flow monitor indicates flow, the presumption will be that no flow is 
going to the flare.
    For grab sampling, a sample shall be collected within 15 minutes 
after the triggering conditions occur (see above), and the sampling 
frequency, thereafter, shall be one sample every 3 hours. For 
integrated sampling, a sample shall be

[[Page 21430]]

collected within 15 minutes after the triggering conditions occur (see 
above), and the sampling frequency, thereafter, shall consist of a 
minimum of 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. For grab and integrated sampling, 
sampling shall continue until sampling is no longer required (see 
above).
    Samples obtained by either grab or integrated sampling shall be 
analyzed for total sulfur concentration using ASTM Method D4468-85 
(Reapproved 2000) ``Standard Test Method for Total Sulfur in Gaseous 
Fuels by Hydrogenolysis and Rateometric Colorimetry'' (see reference 
document MMMMMM); 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'' (reference 
document NNNNNN); 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. Proper 
QA/QC procedures shall be used to assure that the samples are obtained 
and analyzed appropriately.
    We chose the trigger level for two reasons. First, the rule 
indicates that the minimum detectable velocity of the flow monitoring 
device(s) shall be 0.1 fps and the flow monitoring devices shall 
continuously measure the range of flows corresponding to 0.5 to 275 
fps. Since 0.5 fps is the minimum flow measure required, it is a 
reasonable trigger level to ensure protectiveness. Second, flow 
monitoring software averages all the readings in a 15-minute timeframe 
and records/reports the average flow. Using the minimum recorded/
reported timeframe is reasonable to ensure protectiveness.
    With respect to using estimations, technical judgment, and indirect 
metering to calculate emissions from the flare, because this FIP is 
designed to protect the NAAQS, we are choosing to require real-time 
direct monitoring methods to determine emissions. We do not believe 
estimations, technical judgments, and indirect metering are adequate 
substitutes for real-time monitoring for purposes of the FIP.
    (b) Comment (ExxonMobil, WSPA, COPC, CHS Inc., MSCC): The proposed 
requirement for a facility to install, commission, and calibrate flow 
monitoring systems and continuous sulfur analyzer systems within 180 
days after receiving EPA approval of a monitoring plan is a requirement 
that would simply be impossible to meet.
    Response: Based on the comments received, we have revised the FIP 
to allow 365 days, rather than 180 days, after EPA approval of the 
flare monitoring plan to install continuous flow monitors and to begin 
determining total sulfur concentrations on the gas stream to the flare. 
Based on conversations with an ultrasonic flow monitor manufacturer, 
BAAQMD, and SCAQMD (see reference documents MMMMM, OOOOO, and TTTTT, 
respectively), we believe this additional time is reasonable to install 
continuous flow monitors and total sulfur analyzers or to initiate grab 
or integrated sampling.
    (c) Comment (MSCC, ExxonMobil): The FIP implies that pilot and 
purge gas must be monitored. Pilot and purge gas lines are separate 
from the main header vent gas lines. Monitoring these other relatively 
small gas flows to the flare is a waste of effort and resources. The 
pilot gas is usually a small natural gas stream of low flow and 
essentially zero sulfur content. The small purge gas line usually is 
natural gas, refinery fuel gas, or inert gas such as carbon dioxide or 
nitrogen, or mixtures of such gases with air or steam. In either case, 
the flow is not high and usually ExxonMobil does not expect high sulfur 
content. These two stream types (pilot gas, purge gas) cannot 
physically be mixed with the main vent gas stream for measurement of 
flow and sulfur content by one set of monitors, without defeating their 
essential purposes of safety. Given the nature of the pilot gas and 
purge gas streams, it is not reasonable to require flow and sulfur 
monitors which meet the proposed FIP specs on these streams. 
Regulations from other areas allow the flow and sulfur content of pilot 
and purge gas to be estimated/monitored by other devices or sampling 
means. It is recommended that the proposed FIP language be re-written 
to clearly exempt pilot gases and purge line gases from the proposed 
FIP monitoring requirements. Neither can reasonably be considered as a 
significant source of sulfur dioxide. ExxonMobil asserted that EPA's 
proposed FIP requirement for the Billings/Laurel area is neither 
reasonable nor legally supportable.
    Response: In conversations with the SCAQMD, we learned that in some 
instances they had seen copious emissions due to flare pilot and purge 
gas (see reference document TTTTT). SCAQMD indicated, as do the 
commenters above, that in some cases refinery fuel gas is used as a 
purge gas. Refinery fuel gas can have high sulfur content. Because of 
the potential for SO2 emissions from the burning of pilot 
and purge gas, we believe it is necessary to account for these 
emissions and include them when determining the total emissions from 
the flare.
    We agree that the proposed FIP implied that the pilot and purge gas 
should be monitored by the analyzers on the flare line used to measure 
flow and concentration of the gas stream to the flare. We are revising 
the FIP to require flow and H2S concentration monitoring of 
the pilot and purge gas as one possible method to determine sulfur 
dioxide emissions from the burning of such gas in the flare. However, 
the FIP allows sources to forego monitoring if certain requirements are 
met. First, if facilities certify that only natural gas or an inert gas 
is used for the pilot and/or purge gas, then the gas does not need to 
be monitored. Second, if facilities can measure other parameters so 
that volumetric flows, expressed in SCFH, of pilot and purge gas can be 
calculated (based on the design and the parameters), then the flows do 
not need to be monitored. Third, if the H2S concentration of 
the pilot or purge gas can be determined through other methods, then 
the H2S concentration does not need to be monitored. Once 
flow and H2S concentration of the pilot and purge gas are 
determined, sources must then calculate the SO2 emissions 
from the pilot and purge gas. The calculated SO2 emissions 
will then be added to the other SO2 emissions from the flare 
to determine compliance with the flare SO2 emission limits. 
Also, we are revising the reporting requirements to require sources to: 
(1) Certify in the quarterly reports if pilot or purge gas is not 
monitored because only natural gas or an inert gas is used as the pilot 
and/or purge gas; or (2) report flow and H2S concentration 
of the pilot and/or purge gas and the resultant SO2 
emissions.
    (d) Comment (MSCC): Flow and concentration monitoring would be 
costly and there is no justification for such costs and complexity 
given that the area is in attainment for the NAAQS.
    Response: See response to comments II.C.2.(d) and II.C.3.(c), 
above.
    (e) Comment (YVAS): YVAS concurs that each source submit for EPA 
review a quality assurance and quality control plan for each of the 
continuous monitors.
    Response: We acknowledge receipt of the comment and the support for 
our proposal.

[[Page 21431]]

D. Flare Limits

1. Concerns With Flare Emission Limit
    (a) Comment (CHS Inc, MSCC): The proposed flaring limit of 150 lbs 
SO2/3 hour period was used in the model to represent routine flaring 
and background SO2 concentrations. This threshold was never 
intended to and did not account for malfunctions, startups, or 
shutdowns.
    Response: The FIP fills the gap for the provisions of the SIP that 
were disapproved. In its attainment demonstration modeling, the State 
modeled emissions from flares at 150 lbs of SO2/3-hour 
period, yet the SIP did not contain corresponding emission limits for 
the flares. This was the basis for our disapproval of part of the SIP. 
We believe we have appropriately addressed malfunction, startup, and 
shutdown in this final rule. See section II.D.3., below.
    Certain assumptions were made in the State's attainment 
demonstration for the Billings/Laurel SO2 SIP. Included in 
the assumptions was that flares had routine emissions of 150 lbs of 
SO2/3-hour period. To assure attainment and maintenance of 
the NAAQS, the SIP or a FIP must contain enforceable emission limits on 
the flares. This is fully explained in our proposed action on the 
Billings/Laurel SO2 SIP (64 FR 40791, 40801, July 28, 1999) 
and in the response to comments contained in our final action on the 
Billings/Laurel SO2 SIP (67 FR 22168, 22179, May 2, 2002).
    The State of Montana has flare provisions that apply to CHS Inc., 
ConocoPhillips, ExxonMobil, and MSCC. See CHS Inc.'s, ConocoPhillips', 
ExxonMobil's, and MSCC's exhibit A-1, adopted by the Montana Board of 
Environmental Review on June 12, 1998 (reference documents QQQQQQ, 
PPPPPP, UUUUU, and OOOOOO). Exhibit A-1 contains additional State 
requirements that were not submitted for inclusion in the 
SO2 SIP. Among these is an emission limit on flares of 150 
lbs of SO2/3-hour period, the value the State relied on to 
model attainment. These flare provisions do not and would not satisfy 
the SIP/FIP requirements of the CAA for two reasons. First, they were 
never submitted to EPA to be included as part of the SIP. Second, the 
flare provisions contain automatic exemptions for malfunction, startup, 
and shutdown. This is inconsistent with EPA's longstanding 
interpretation of the CAA, which is that, since SIPs must provide for 
attainment and maintenance of the NAAQS and the achievement of the PSD 
increments, all periods of excess emission must be considered 
violations. Accordingly, any provision that allows for an automatic 
exemption for excess emission is prohibited.\8\
---------------------------------------------------------------------------

    \8\ See reference document RRR, September 20, 1999, memorandum 
entitled ``State Implementation Plans: Policy Regarding Excess 
Emissions During Malfunctions, Startup, and Shutdown.''
---------------------------------------------------------------------------

    (b) Comment (NEDA/CAP, MSCC, ExxonMobil): The capriciousness of 
EPA's proposed FIP provision affecting flaring is that EPA recognizes 
in the proposed notice that sources likely will be unable to comply 
with the continuous flaring emission limitations. Yet the proposed FIP 
would allow citizens to bring actions for violations of unattainable 
limits when EPA or the State likely would choose to exercise its 
prosecutorial discretion. Such a regulatory ``Catch-22'' is both 
unreasonable and unlawful.
    Response: We respectfully disagree with the commenter. First, in 
our proposal we did not say that sources will be unable to comply with 
the continuous flaring emission limitations. We note that, after 
receiving the refineries' estimates of routine flare emissions, the 
State established as a State-only limit the same numerical flare limit 
we are adopting, and the refineries and MSCC agreed to the stipulations 
containing those limits. See 67 FR 22180, col. 2, May 2, 2002, and 
reference documents UUUUU, OOOOOO, PPPPPP, QQQQQQ, and SSSSSS. Also, at 
the time of our SIP action, Conoco indicated to us that routine 
emissions from its flare were expected to be less than 150 lbs 
SO2/3-hour period. See 67 FR 22180, col. 2, May 2, 2002, and 
reference document RRRRRR. Based on this information, we have concluded 
that the refineries and MSCC will be able to comply with the 150 lbs 
SO2/3-hour flare limit under normal operating conditions.
    We did say in our proposal that we recognize flares are sometimes 
used as emergency devices and that it may be difficult to comply with 
the flare limits during malfunctions. See 71 FR 39264, col. 1, July 12, 
2006. However, contrary to the commenters' assertions, our decision to 
require an emission limit that may be difficult to meet under certain 
conditions is not capricious, unreasonable, or unlawful.
    There is often a conflict, which is not limited to refinery flare 
emissions, between a source's ability to control emissions during 
certain operating conditions and the CAA's requirement to attain and 
protect the NAAQS. Our fundamental responsibility under the CAA with 
respect to SIPs/FIPs, however, is to ensure the NAAQS are attained and 
other CAA requirements are met. See CAA sections 110(a) and (l), 42 
U.S.C. 7410(a) and (l); reference document RRR, September 20, 1999, 
memorandum titled ``State Implementation Plans: Policy Regarding Excess 
Emissions During Malfunctions, Startup, and Shutdown,'' from Steven A. 
Herman and Robert Perciasepe, to Regional Administrators (hereafter 
``1999 excess emissions memorandum''); City of Santa Rosa v. EPA, 534 
F.2d 150, 155 (9th Cir. 1976), vacated on other grounds, 429 U.S. 990 
(1976). Thus, we have long held that outright or ``automatic'' 
exemptions from emission limits needed to demonstrate attainment of the 
NAAQS are not appropriate, something we indicated in our proposed FIP. 
See our 1999 excess emissions memorandum, reference document RRR, and 
our proposed FIP, 71 FR 39264, col. 1, July 12, 2006. Our 
interpretation on this issue has been upheld by the U.S. Court of 
Appeals for the 6th Circuit: in a 2000 decision, the Court rejected a 
challenge to EPA's disapproval of a Michigan SIP revision that provided 
an automatic exemption from SIP limits during malfunction, startup, and 
shutdown periods. Michigan Department of Environmental Quality v. EPA, 
230 F.3d 181 (6th Cir. 2000).
    As we explained as long ago as 1977, the appropriate approach in 
SIPs/FIPs is to require continuous compliance in order to create an 
incentive for sources to properly operate and maintain their facilities 
and to improve their operation and maintenance practices over time. 
See, e.g., 42 FR 21472, April 27, 1977 (reference document VVVVV), and 
42 FR 58171, November 8, 1977 (reference document WWWWW). We explained 
that an automatic exemption would encourage the source to claim after 
every period of excess emissions that the exemption applied, and that 
instead the proper means to provide relief to sources was through the 
exercise of enforcement discretion in appropriate circumstances. Id.
    Later, in 1999, we indicated that states could include in their 
SIPs, as an alternative to the enforcement discretion approach, 
narrowly tailored affirmative defense provisions to address source 
difficulties meeting emission limits during malfunction, startup, and 
shutdown periods. See reference document RRR, our 1999 excess emissions 
memorandum. In this 1999 memorandum we reiterated our long-held view 
that, ``because excess emissions might aggravate air quality so as to 
prevent attainment or interfere with maintenance of the ambient air 
quality standards, EPA views all excess emissions as violations of 
applicable emission limitation[s].'' We also

[[Page 21432]]

repeated our recognition that some malfunctions may be unavoidable.
    Thus, while flares may have unique characteristics, the underlying 
conflict between the ability to comply and need to meet the NAAQS is 
the same. We do not believe the nature of the emission point should 
dictate a different approach to protection of the NAAQS. Whether 
considering stack emissions at a power plant or other source, or flare 
emissions at a refinery, the SIP/FIP should be structured to provide 
the source with the incentive to properly design, operate, and maintain 
its facility. An outright exemption from the emission limits would not 
do this.
    To provide relief to the sources for truly unavoidable violations, 
while still maintaining appropriate incentives for compliance, we are 
providing an affirmative defense to penalties for violations of flare 
limits during malfunctions, startups, and shutdowns. The elements of 
the defense, which a source would have to prove in court or before an 
administrative judge, are enumerated in our final rule and are 
consistent with the elements described in our 1999 excess emissions 
memorandum. The gist of these elements is that a source must take all 
possible steps to prevent exceedances of the limits and to minimize the 
amount, duration, and impact of those exceedances. These same or 
similar criteria have been adopted by other regulatory agencies, 
including the State of Colorado and Maricopa County, Arizona, in excess 
emissions rules. See, e.g., Colorado Air Quality Control Commission 
Common Provisions Regulation, 5 CCR 1001-2, Sections II.E. and J. 
(reference document TTTTTT); Maricopa County Air Pollution Control 
Rules, Rule 140, ``Excess Emissions'', Section 400 (reference document 
ZZZZZ).
    Finally, we reject commenters' assertion that citizens will 
necessarily pursue enforcement where the State and EPA do not, but in 
any event, this possibility is inherent in the structure of the CAA; 
Congress provided citizens with the ability to enforce SIPs and FIPs. 
This inherent structure is not a reason for us in this rulemaking 
action to change our longstanding interpretations regarding the proper 
treatment of excess emissions.
    (c) Comment (NEDA/CAP): Industry contends that it is virtually 
impossible to meet the proposed limits during flaring, since flares 
themselves are not process units when they are treating excess gases 
during malfunction events. EPA has presented no information in this 
notice or elsewhere to the contrary. On this basis alone, if the mass 
emission limits for flares are not made less stringent, the FIP must 
recognize in its final action that flares must be available for use 
during malfunctions and emergencies to protect the safety of employees 
and the public, as well as equipment integrity, regardless of the mass 
emission rate of the time.
    Response: The FIP is not intended to jeopardize the safety of 
refineries, their workers, or neighbors. Our SIP policy \9\ has long 
recognized that imposing penalties for violations of emission 
limitations for sudden and unavoidable malfunctions caused by 
circumstances entirely beyond the control of the owner or operator may 
not be appropriate. States, EPA, and citizens have the ability to 
exercise enforcement discretion to refrain from taking enforcement 
action in these circumstances. In addition, EPA has revised the FIP to 
provide sources with the ability to assert an affirmative defense to 
penalties for violations of flare limits during malfunction, startup, 
and shutdown. However, while we recognize some violations may be 
unavoidable, we also believe that sources have a responsibility to do 
their best to achieve continuous compliance and to minimize the number, 
duration, and severity of malfunctions and other events leading to 
excess emissions.
---------------------------------------------------------------------------

    \9\ See reference document RRR, September 20, 1999, memorandum 
entitled ``State Implementation Plans: Policy Regarding Excess 
Emissions During Malfunctions, Startup, and Shutdown.''
---------------------------------------------------------------------------

    (d) Comment (MSCC): Various jurisdictions have attempted to address 
flare emissions. There is no uniform federal requirement or regulation 
requiring such limits or monitoring, particularly for short term 
limits, or for malfunction, startup, and shutdown controls. It is 
difficult to understand any reason that the Montana SIP for Billings/
Laurel is ``substantially inadequate'' regarding flaring or for 
proposing restrictions going far beyond those in effect in any 
jurisdiction or federal rule.
    Response: Regardless of what other areas are doing with respect to 
flare emissions, we must fulfill our responsibility to fill the gaps of 
the provisions of the SIP that we disapproved. Each area must be 
addressed on a case-by-case basis. The response to comment II.D.1.(a) 
and our notice of proposed rulemaking express why we believe the FIP 
should contain emission limits for flares in the Billings/Laurel area. 
Regarding the comment about substantial inadequacy, please see our 
response to comment II.B.2.(a), above.
    (e) Comment (MSCC): There is no reasonable basis to believe that 
flaring, as practiced in this air-shed, prevents attainment and 
maintenance of NAAQS, or that it is inadequately regulated, or that it 
has an impact on health, welfare, or commerce among states, as years of 
experience confirm. The State of Montana flare provisions are adequate. 
No federal action is needed.
    Response: This comment goes to the validity of our SIP action and 
is not relevant here. See our response to comment II.B.2.(a), above.
    (f) Comment (MDEQ): Imposing a mass-based emission limit (and the 
necessary and ancillary requirements for measuring flows and 
concentration) on a flare increases the regulatory workload while 
providing a marginal benefit. Currently, Montana's Malfunction rule 
(ARM 17.8.110) provides Montana with enforcement discretion during 
malfunction events.
    Response: We note that the State has mass-based emission limits on 
the flares in the Billings/Laurel SO2 area. See CHS Inc.'s, 
ConocoPhillips', ExxonMobil's, and MSCC's exhibit A-1, adopted by the 
Montana Board of Environmental Review on June 12, 1998 (reference 
documents QQQQQQ, PPPPPP, UUUUU, and OOOOOO). Exhibit A-1 contains 
State requirements that were not submitted for inclusion in the 
SO2 SIP. The provisions of exhibit A-1 also appear in the 
sources' Title V permits and are labeled as State-only provisions. See, 
for example, ConocoPhillips' Title V permit (see reference document 
XXXXX).
    The exhibit A-1 requirements indicate that the facilities shall not 
allow SO2 emissions from any flare, unless the emissions are 
a minor flaring event (defined as less than or equal to 150 pounds per 
3-hour period), or the result of start-up, shutdown, or a malfunction. 
Exhibit A-1 does not indicate how compliance with the emission limit is 
determined and only requires reporting of flare emissions that are not 
minor flaring events.
    Presumably, the additional workload provided by the FIP, that the 
State is referring to, is in evaluating the continuous analyzers and 
receiving quarterly reports. We believe the additional workload is 
warranted and necessary to determine compliance with the flare emission 
limits and assure that the SO2 NAAQS will be attained and 
maintained. See, e.g., CAA sections 110(a)(2)(A), (C), and (F), 42 
U.S.C. 7410(a)(2)(A), (C), and (F).
    We do not understand the intent of the comment that indicates MDEQ 
has enforcement discretion under its malfunction rule in ARM 17.8.110

[[Page 21433]]

(reference document YYYYY). Before MDEQ could decide whether or not to 
pursue an enforcement action for violations of the State-only flare 
limit, MDEQ would need to evaluate information submitted by sources.
    Additionally, we note that in response to our proposed action on 
the Billings/Laurel SIP, the State said the following: ``The State 
agrees with EPA that the SIP is incomplete without enforceable emission 
limitations applicable to flares, and that such limitations should 
correspond to the emission rates used in the attainment demonstrations. 
However, after significant effort to address the issue, the State was 
unable to find a workable solution that would meet EPA's concerns.'' 
See document IV.A-23, comment 3, from docket 
R8-99-01; 67 FR 22183, col. 1, May 2, 2002; and reference 
document ZZZZZZ.
    (g) Comment (YVAS): YVAS concurs with EPA's further assumption 
(page 39264), that ``the 3-hour SO2 NAAQS would be 
attained'' if ``the limit for the main flares was established at 500 
pounds of SO2 per calendar day.'' Since there is apparently 
precedent (as noted on page 39263 FR) ``contained in settlements 
between the United States and CHS Inc, ConocoPhillips and ExxonMobil,'' 
YVAS further agrees to and accepts EPA's reasoning that ``the 500 pound 
value for this FIP (should) be imposed as an enforceable limit and not 
just a trigger point for further analysis'' as a starting point. 
However, the ``500 lbs per day limit,'' if extended for any length of 
time, is not acceptable. Based on acquired information, YVAS does not 
think this limit would be punitive, nor would it be impossible for 
industry sources to attain. It is accepted that zero emissions may not 
be possible or attainable, but any lower emissions rate would be a 
public benefit. And, although a compliance drop could create greater 
industry noncompliance and require more enforcement action, YVAS does 
not believe the more stringent standards would create more 
noncompliance problems for the sources.
    Response: We have decided to retain the proposed limit of 150 lbs 
of SO2/3-hour period. A more stringent limit than either 
proposed is unnecessary to ensure attainment of the NAAQS. Thus, we 
believe it is reasonable not to impose a more stringent limit as the 
commenter suggests.
    (h) Comment (Citizen): The proposed rule should not be adopted 
unless recognized medical opinion concerning the cumulative health 
risks of the release of 500 lbs per day of sulphur dioxide into the 
area's airshed is analyzed. Specifically, what justification criteria 
are being used to establish the 500 lb. minimum per day base in the 
Proposed Rule. And, as noted on page 39264 of the Federal Register 
dated July 12 announcing the FIP, EPA says ``if we adopted the 500 
pound value in this FIP, we would impose it as an enforceable emission 
limit.'' If there are still questions concerning the 500 lb per day 
emission limit, why is it being proposed? Is there a lower and perhaps 
``better'' emission limit per day that should be considered?
    Response: The current SO2 NAAQS were set to protect 
public health and welfare after consideration of various scientific 
data. It is not our role here to re-evaluate the NAAQS, but to ensure 
they are met. Through modeling we determined that both limits would 
protect the SO2 NAAQS. While a lower limit might be 
attractive, we are setting the limits at 150 lbs of SO2/3-
hour period, a level sufficient to meet the SO2 NAAQS; we 
think this is reasonable. See response to comment II.A.2.(b). See also 
our response to comments pertaining to SO2 NAAQS and 
SO2 Health Effects (II.F.9. and 10., respectively) below.
    (i) Comment (MDEQ): MDEQ believes that hard cap emission limits on 
flares are good but believes that the flare emission limits will be 
more accepted if malfunction, startup, and shutdown exemptions are 
introduced.
    Response: We acknowledge MDEQ's support for hard cap emission 
limits on flares. Regarding exemptions for malfunction, startup, and 
shutdown, see our responses to comments II.D.1.(b) and (c), above.
    As indicated above, to address industry concerns regarding 
malfunctions, startup, and shutdown, we are revising the FIP to provide 
sources the ability to assert an affirmative defense to penalties for 
violations of flare limits during malfunction, startup, and shutdown.
2. Safety Device
    (a) Comment (CHS Inc., WETA, MPA, NPRA): From a safety standpoint, 
there are concerns with flare limits applying at all times, including 
malfunction, startup, and shutdown. Flares are primarily safety 
devices, designed as a means to ensure the safety of employees and the 
community and to maintain the integrity of refinery equipment during 
situations that are not representative of normal operations. It will be 
precedent setting if the EPA views these infrequent events as 
enforcement situations. It would, in essence, require facilities to 
choose between maintaining a safe, controlled refinery and violating 
the FIP.
    Response: See responses to comments II.D.1.(b) and (c), above. As 
we indicate in our response to comment II.D.1.(c), the FIP is not 
intended to jeopardize the safety of refineries, their workers, or the 
community. However, we believe it would be inconsistent with CAA 
sections 110(a) and (l) to provide an outright exemption from the flare 
limits during malfunction, startup, and shutdown periods. Instead, to 
provide some measure of relief to the sources, we have included an 
affirmative defense to penalties in our final FIP rule. If a source 
takes steps consistent with the elements of the affirmative defense, 
excess flaring emissions during malfunction, startup, and shutdown 
periods would not be penalized. We have considered several additional 
factors: First, historically, the sources have used the flares as part 
of their routine operations, i.e., in non-emergency conditions. See 
September 28, 1995, letter from Bob Raisch to Douglas Skie (reference 
document SSSSSS); 67 FR 22180, col. 2, May 2, 2002. Also, in its 
comments on the FIP (reference document QQQQ), CHS Inc. indicated that 
the 150 lbs/3-hour value was used in the original model to represent 
routine flaring and background SO2 concentrations. MSCC 
indicated in its comments on the FIP (reference document WWWW) that 
flares can be used for handling streams other than those arising from 
malfunction, startup, and shutdown. Second, flaring events have not 
necessarily been as infrequent as the commenter implies. From the first 
quarter of 2005 through the second quarter of 2007, source reports 
indicate that MSCC and the 3 refineries experienced over 150 flaring 
events with SO2 emissions greater than 150 pounds over 3 
hours. See reference document HHHHHH. Third, the emissions during these 
events can be very high--the State estimated that emissions during 
malfunctions could be as high as 6,000 pounds/3-hour period, and the 
sources' own reports for first quarter 2005 through second quarter 2007 
reflect emissions as high as 12,400 pounds over a 2-hour period. See 
reference documents SSSSSS and HHHHHH. The maximum value reported for a 
flaring event during the period was 40,800 pounds of SO2 
over an unknown duration, and there were numerous events in the 
thousands of pounds. See reference document HHHHHH. Fourth, we want to 
ensure that the owners/operators design, operate, and maintain their 
facilities to minimize flare emissions by minimizing the conditions 
that lead to malfunctions,

[[Page 21434]]

startups, and shutdowns. In the FIP context, the appropriate way to do 
this is by establishing a flare emission limit that is not subject to 
outright exemptions. Fifth, the State and EPA have already viewed these 
events as enforcement situations in the context of the refinery 
initiative and, through the consent decrees, have created the 
expectation that the refineries will minimize flare emissions. We 
explain in this preamble why the conditions of the consent decrees, 
while beneficial, are not sufficient for purposes of the FIP. See, 
e.g., responses to comments II.A.2.(b), II.D.4., and II.E.1.(e). We 
also note that MSCC is not subject to a consent decree. Finally, the 
air does not care whether emissions come out of a flare that is used as 
a safety device at a refinery or a stack at a power plant or other 
facility.\10\ In both cases, the emissions of SO2 impact air 
quality, and EPA's charge is to address those impacts so as to protect 
the NAAQS.
---------------------------------------------------------------------------

    \10\ In theory, a smokestack could also be characterized as a 
safety device; among other things, a stack is used to prevent 
harmful ground level concentrations of pollutants. In addition, 
gases are sometimes bypassed around control devices directly to the 
stack to avoid damage to control devices and/or other dangerous 
conditions. In the SIP/FIP context, we do not believe it is 
appropriate to automatically exempt these stack emissions, even 
though the stack may serve a safety purpose. See our 1999 excess 
emissions memorandum, reference document RRR.
---------------------------------------------------------------------------

    (b) Comment (WSPA, MSCC, ExxonMobil): EPA proposes that flare 
limits apply at all times without exception. It would be virtually 
impossible to comply with SOx mass emission limits at all times and for 
all malfunctions for the simple reason that the primary function of a 
refinery flare is to serve as a safety device. Flares must be available 
for use during malfunctions and emergencies to protect equipment and 
the safety of employees and the public.
    Response: See responses to comments II.D.1.(b) and (c), and 
II.D.2.(a), above.
    (c) Comment (NPRA): The U.S. Chemical Safety Board (CSB) urges the 
installation of flares. The CSB sites flares as a ``safer alternative'' 
when compared to other techniques. Clearly the CSB recommendation is at 
odds with Agency's proposal.
    Response: See responses to comments II.D.1.(b) and (c), and 
II.D.2.(a), above. Also, we do not believe our action is at odds with 
the CSB's recommendations. In this action, we are not opining on the 
use of flares versus other techniques. We are not telling the 
refineries or MSCC to stop using their flares. However, flares are an 
emission point at the refineries and MSCC, they have been the source of 
routine emissions historically, and they can be the source of very 
large quantities of emissions in a short period of time. We believe it 
is necessary and appropriate to impose limits on the flare emissions to 
fill one of the gaps in the SIP, to support our attainment 
demonstration, and to create appropriate incentives for the sources in 
the design, operation, and maintenance of their facilities.
3. Malfunction, Startup, and Shutdown
    (a) Comment (WSPA, MSCC, ExxonMobil): In working with the South 
Coast Air Quality Management District, they were careful not to 
compromise safety by restricting, either explicitly or implicitly, the 
use of flares during emergencies through the imposition of mass 
emission limits or otherwise.
    Response: See responses to comments II.D.1.(b) and (c), and 
II.D.2.(a), above. Our FIP does not require or direct the sources to 
not use their flares during emergencies. Unlike the South Coast or Bay 
Area,\11\ however, we are required to promulgate a FIP that 
demonstrates attainment of the SO2 NAAQS. Consequently, it 
is necessary and appropriate that we impose emission limits on the 
flares that are consistent with our modeled attainment demonstration. 
To address industry concerns, we are providing an affirmative defense 
to penalties for excess flare emissions during malfunction, startup, 
and shutdown periods.
---------------------------------------------------------------------------

    \11\ The Bay Area prohibits all refinery flaring unless the 
flaring is consistent with a flare minimization plan or is caused by 
an emergency. See BAAQMD rule 12-12-301 (reference document 
AAAAAAA). The South Coast rule requires minimization of flaring and 
prohibits combustion of vent gas in the flare except during 
emergencies, shutdowns, startups, turnarounds or essential 
operational needs. See SCAQMD rule 1118(c)(4) (reference document 
CCC).
---------------------------------------------------------------------------

    We note that SCAQMD's rule 1118(d) imposes annual SO2 
performance targets for flare emissions (caps on the amount of 
SO2 emitted from flares in one year). The performance 
targets are based on the crude processing capacity and become more 
stringent over time. Malfunction, startup, and shutdown emissions count 
towards the annual performance targets unless they meet certain 
narrowly defined exemptions in rule 1118(k). Sources that exceed their 
annual performance targets must submit a flare minimization plan and 
are subject to mitigation fees of up to four million dollars a year 
(see reference document CCC).
    (b) Comment (WSPA, MSCC, ExxonMobil): It is essential for EPA to 
recognize the true nature of malfunctions at refineries, and the fact 
that there is no practical way to regulate the release of vent gases 
during malfunctions, or, to treat the emergency vent gases to remove 
sulfur compounds prior to combustion in the flare.
    Response: See responses to comments II.D.1.(b) and (c), II.D.2.(a), 
and II.D.3.(a), above. Also, we understand that while a malfunction is 
underway, it may be impossible to treat the gases prior to combustion 
in the flare. However, we do not agree that all malfunctions are 
categorically unavoidable. We are concerned with the causes leading to 
the malfunctions and the steps taken after the malfunction begins to 
mitigate its effects. We are promulgating an affirmative defense 
provision along with the flare emission limits that should ensure 
sources take all steps within their control to avoid malfunctions and 
minimize their impacts on air quality once they occur. We believe this 
is reasonable and appropriate to ensure protection of the NAAQS.
    (c) Comment (WETA): Pursuing the adoption of this FIP could 
potentially result in the setting of an inconsistent national policy 
for malfunction, startup, and shutdown.
    Response: We do not agree with the comment. The FIP would not be 
setting inconsistent national policy for malfunction, startup, and 
shutdown occurrences. To the contrary, we are following our national 
policy with respect to malfunctions, startup, and shutdown as expressed 
in the 1999 excess emissions memorandum (see reference document RRR).
    (d) Comment (MSCC): MSCC believes that the approach taken by the 
State of Montana in providing for minimization of flaring, above a 
reasonably determined de minimis threshold, and clear exceptions for 
malfunctions, startup, shutdowns and other operational needs is the 
sound approach, to address the reality that there are, and will be 
situations such as malfunctions, startups, and shutdowns and 
emergencies that are beyond the reasonable control of a source, in the 
operation of flares.
    Response: We recognize there may be violations of flare emission 
limits during malfunctions, startups, shutdowns, and emergencies that 
are beyond the control of a source; accordingly, we are providing 
sources with the ability to assert an affirmative defense to penalties 
for violations of flare limits that occur during malfunction, startup, 
and shutdown periods. We believe this is a reasonable approach, 
consistent with our views that automatic exemptions are not appropriate 
for emission limits relied on

[[Page 21435]]

to demonstrate attainment of the NAAQS.
    (e) Comment (COPC): The rule as written will ultimately put 
ConocoPhillips in the position of having to choose between compliance 
with an environmental regulation and maintaining safe operating 
conditions. This is an untenable position which can be avoided by 
acknowledging in rule language that flare SO2 emissions can 
occur during periods of malfunction, startup, and shutdown, provided 
that accepted management systems are followed.
    Response: See responses to comments II.D.1.(b) and (c), and 
II.D.2.(a), above. We believe the provision of the affirmative defense 
to penalties for excess emissions during malfunction, startup, and 
shutdown periods appropriately and reasonably addresses the commenter's 
concerns.
    (f) Comment (COPC): A FIP program that adopts the same evaluation 
procedures for malfunctions, startups, and shutdowns for flares is 
preferred to a fiction that a facility can maintain a flare emission 
limit in all malfunction, startup, or shutdown events regardless of 
size or magnitude.
    Response: See response to comments II.D.3.(a), (b), (c), (d), and 
(e), above.
    (g) Comment (YVAS): Specific to flaring emergencies by the sources, 
any added controls on flaring to protect the public (from 
SO2 exceedences) is essential and is common sense.
    Response: We acknowledge the comment and support for our proposal.
4. Subject to NSPS
    Comment (CHS Inc.) It should be noted that the CHS refinery flare 
is subject to NSPS Subpart J as a result of the consent decree. This 
limits the H2S content of the routine refinery fuel gas 
streams routed to the flare and requires monitoring to demonstrate 
compliance with the limit.
    Response: As indicated by the commenter, the consent decree limits 
the H2S content of the routine refinery fuel gas streams 
routed to the flare. However, there are several reasons why the 
H2S ppm limit alone is not sufficient to support the FIP's 
attainment demonstration.
    First, flow information is needed to translate H2S ppm 
values into pounds of SO2 for a given period of time. Flow 
rates to the flares can vary widely. Without knowing potential worst-
case flows to the flare, we cannot determine whether the consent decree 
H2S ppm limit would assure compliance with the FIP 150 
pounds of SO2/3-hour limit at the 3 refineries. Therefore, 
we cannot conclude that the consent decree H2S limit, even 
absent the additional concerns we discuss below, would assure 
attainment of the SO2 NAAQS.
    Second, during certain situations, as indicated in 40 CFR 60.8(c) 
and 60.104(a)(1), the H2S limit does not apply. 
Specifically, the consent decree indicates that the CHS Inc. refinery 
flare is an affected facility under 40 CFR part 60, subparts A and J 
for fuel gas combustion devices and that fuel gases combusted in the 
refinery flare shall comply with the emission limit of 40 CFR 
60.104(a)(1). However, 40 CFR 60.104(a)(1) exempts process upset gases 
and certain types of fuel gas from the emission limit. Additionally, 
the provisions in 40 CFR 60.8(c) indicate that emissions in excess of 
the level of the applicable emission limit during periods of 
malfunction, startup, and shutdown shall not be considered a violation 
of the applicable emission limit unless otherwise specified in the 
applicable standard. Emission limits for demonstrating attainment and 
maintenance of the NAAQS must apply at all times. (See responses to 
comments II.D.1.(b) and II.D.2.(a), above, and reference document RRR.)
    Third, the alternative monitoring plan (AMP), that was approved 
pursuant to the consent decree and NSPS requirements (see reference 
document LLLLLL) for the refinery flare fuel gas combustion device, 
primarily relies on quarterly measurement of the H2S content 
of some of the refinery fuel gas streams that go to the flare using 
stain tubes; more frequent measurement may be required for a limited 
time depending on the concentration measured. Although this may be 
acceptable under the terms of the consent decree and the NSPS, we 
believe more frequent testing is necessary for determining compliance 
with an emission limit set to assure attainment and maintenance of the 
NAAQS.
5. Affirmative Defense/1999 Excess Emissions Memorandum
    (a) Comment (WSPA): The availability of an affirmative defense is 
desirable. Even though EPA may allow for the assertion of affirmative 
defenses, the affirmative defense would only be allowed for the 
mitigation of penalties. This is an unreasonable position in which to 
place refiners subject to the proposed requirements.
    Response: We are providing an affirmative defense to penalties in 
the final rule, but not to injunctive relief. This is consistent with 
the Clean Air Act interpretations expressed in our 1999 excess 
emissions memorandum. See reference document RRR. We believe it is 
reasonable to retain the authority to seek injunctive relief for all 
exceedances of emission limits so that we remain able to protect the 
NAAQS, regardless of source ``culpability'' for any specific 
exceedance.
    We note that in our proposed FIP preamble, we invited comment 
regarding whether it would be appropriate to extend an affirmative 
defense to the FIP sources for exceedances of their flare limits during 
malfunctions, startup, and shutdown. See 71 FR 39264, July 12, 2006. 
There we said the following:

    ``We do interpret the CAA to allow owners and operators of 
sources to assert an affirmative defense to penalties in appropriate 
circumstances, but normally we would not view such an affirmative 
defense as appropriate in areas where a single source or small group 
of sources has the potential to cause an exceedance of the NAAQS. 
See 1999 policy statement. We solicit comment on whether it would be 
appropriate to include in our final FIP the ability to assert an 
affirmative defense to penalties only (not injunctive relief) for 
violations of the flare limits.''

    We have decided to provide an affirmative defense for violations of 
the flare limits during malfunction, startup, and shutdown. We believe 
this represents a deviation from our 1999 excess emissions memorandum 
because in the Billings/Laurel area, one or more of the FIP sources may 
have the potential to cause an exceedance of the SO2 NAAQS. 
In the unique circumstances of this FIP, with the rule language we are 
adopting, we believe a deviation from the 1999 excess emissions 
memorandum is warranted. For example, we have included rule language 
that indicates the affirmative defense is not available if, during the 
period of the excess emissions, there was an exceedance of the 
SO2 NAAQS that could be attributed to the emitting source. 
At least one other EPA Region has approved an affirmative defense 
provision with this language. See Maricopa County Rule 140 (reference 
document ZZZZZ), which Region 9 approved on August 27, 2002 (67 FR 
54957) (reference document AAAAAA). Although not identical to the 1999 
excess emissions memorandum, this rule language should provide a 
significant incentive to the facilities to take steps to avoid and 
reduce flaring whenever possible.
    Also, based on our experience since the 1999 excess emissions 
memorandum was issued, we believe that the elements of the affirmative 
defense delineated in the 1999 excess emissions memorandum, which 
elements we have adopted in this FIP, provide a very significant 
incentive for

[[Page 21436]]

facilities to do all they can to comply with their emission limits. It 
is not clear that the incentive is significantly different than would 
be present under a traditional enforcement discretion approach, 
particularly when sources assume that enforcement action will rarely be 
taken for infrequent or small violations. Finally, we have considered 
industry comments regarding safety concerns, and while we do not agree 
that emissions from flares should be treated entirely differently from 
emissions from stacks and other points, we think our resolution of this 
issue appropriately and reasonably addresses industry concerns.
    (b) Comment (WETA): Any flare emission limitations should include, 
at the least, an allowance for an affirmative defense for malfunction, 
startup, and shutdown circumstances.
    Response: See response to comment II.D.5.(a), above.
    (c) Comment (NEDA/CAP): EPA should adopt a broad affirmative 
defense for penalties and injunctive relief for malfunctions as part of 
the mass emission limit for flares. MPA indicated that the FIP should 
not be adopted in the proposed form because the failure to include an 
affirmative defense for flaring resulting from malfunctions poses a 
significant safety risk to employees and the public with no 
corresponding benefit.
    Response: See response to comment II.D.5.(a), above.
    (d) Comment (NEDA/CAP): NEDA/CAP is concerned about the potential 
for EPA's establishment of any precedent with regard to limiting the 
availability of affirmative malfunction defenses in nonattainment areas 
generally. NEDA/CAP is also concerned with the application of the 1999 
Malfunction Policy in the Billings/Laurel proposed FIP because the 
Policy has never been subject to notice and comment rulemaking, but the 
application of the policy results in clear legal consequences for 
regulated entities in contravention of Appalachian Power v. EPA, 208 
F.3d 1015 (D.C. Cir. 2000).
    Response: See response to comment II.D.5.(a), above. Also, we 
respectfully disagree with the commenter that we are contravening the 
Appalachian Power case holding. In our proposal, we proposed that the 
flare limits would apply at all times but took comment on the 
application of an affirmative defense to penalties for those limits. In 
this final rulemaking, we have decided to provide the affirmative 
defense to penalties. The commenter had a full opportunity to comment 
on our proposal, which included a discussion of our interpretations of 
the CAA with respect to the treatment of excess emissions during 
malfunction, startup, and shutdown. See 71 FR 39264, col. 1, July 12, 
2006. We have considered the commenter's comments along with all other 
comments.
    (e) Comment (NEDA/CAP): NEDA/CAP is also concerned that EPA has 
made no demonstration that ``a single source or small group of sources 
has the potential to cause an exceedence of the NAAQS,'' or that the 
NAAQS in this air basin is in fact, any more vulnerable to a NAAQS 
exceedence from these sources than any other nonattainment areas is 
from a small group of sources. If finalized, the failure to provide an 
affirmative defense for malfunctions would be entirely arbitrary and 
unreasonable. Moreover, as a national precedent with severe legal 
consequences for sources in other nonattainment areas, adoption of this 
proposed FIP provision would be highly vulnerable to legal challenge 
for failure to meet the Clean Air Act's notice and comment procedures 
under a federal court's recent decision in Environmental Integrity 
Project v. EPA, 425 F.3d 992 (D.C. Cir. 2005).
    Response: In our final action, we are providing an affirmative 
defense to penalties for the flare limits. We disagree with the 
commenter's assertion regarding notice and comment procedures; we 
believe we have met all applicable requirements and provided fair 
notice regarding our intentions in our notice of proposed rulemaking. 
We proposed that the flare limits would apply at all times and also 
invited comment on whether it would be appropriate to extend an 
affirmative defense for the flare limits to the four sources subject to 
the FIP. Our final action is a logical outgrowth of our proposal; we 
have decided to provide an affirmative defense to penalties for 
violations of the flare limits during malfunction, startup, and 
shutdown. While our action on this FIP may have some impact on other 
SIPs and FIPs based on the logic we have applied, our rule is only 
directly applicable to the four sources subject to the FIP. It is 
possible EPA may reach a different decision in future rulemaking.
    (f) Comment (API, COPC, MSCC, ExxonMobil): While EPA's 1999 
Malfunction policy does state EPA's position that affirmative defenses 
are not appropriate ``where a single source or small group of sources 
has the potential to cause an exceedence of the NAAQS,'' API and others 
are unaware of any instance where EPA has utilized this exception from 
its general policy allowing for the assertion of affirmative defenses 
during malfunctions. In this case, EPA has made no demonstration to 
justify an exception to the general allowance for affirmative defenses 
for malfunction events. Consequently, API urges EPA to allow the 
assertion of affirmative defenses in the final FIP. Additionally, 
ConocoPhillips indicated that because of the harsh consequences, EPA 
should only apply this exception to its policy where it is clearly 
demonstrated that there is very real, extended potential for a single 
or small group of sources to cause an exceedence of the NAAQS. This is 
not present in this case. In fact, actual monitoring has shown that 
even during malfunction, ambient NAAQS violations do not occur. 
ConocoPhillips urges EPA to allow the assertion of affirmative defenses 
for both penalties and injunctive relief in the final FIP.
    Response: See our prior responses to comments II.D.5.(a), (d), and 
(e). Also, we note that on two occasions, one in 1985 and one in 1995, 
flaring resulting from malfunctions at ConocoPhillips caused ambient 
exceedances of the SO2 NAAQS (see reference documents 
DDDDDDD and EEEEEEE).
    (g) Comment (NEDA/CAP, MSCC): The proposed FIP appears to 
misinterpret the 1999 Malfunction Policy. The July 12 preamble for 
adoption of the FIP appears to suggest that prosecutorial discretion 
would never be allowed in a nonattainment area where the agency decides 
that ``one or a group of sources are directly implicated in 
nonattainment of a NAAQS.'' In fact, the 1999 Policy recommends that 
such situations have to be addressed in the underlying standards 
themselves through narrowly-tailored SIP revisions. Moreover, in no 
event does the 1999 Malfunction Policy ever prohibit the use of 
prosecutorial discretion.
    Response: Enforcement discretion or prosecutorial discretion is 
always available. The question in this case was whether it was 
appropriate to codify an affirmative defense, which we have done in our 
final rule. We have not misinterpreted our 1999 policy.
    (h) Comment (NEDA/CAP, API): There is no rational basis in the 
proposed FIP or the 1999 Malfunction Policy to limit the affirmative 
defense to penalties. NEDA/CAP asserts that such a limitation is not 
reasonable since the malfunction condition during which the exceedence 
of the applicable limitation occurs would be unavoidable.
    Response: We respectfully disagree. There could be instances in 
which malfunctions are unavoidable based on current plant layout and 
operating parameters but in which some form of corrective action would 
still be

[[Page 21437]]

appropriate. We cannot predict the exact nature of those circumstances, 
but protection of the NAAQS and public health is not an intermittent 
obligation; we are required to assure attainment and maintenance of the 
NAAQS at all times, not just when sources are in normal operation mode 
or when attainment is convenient. See, e.g., City of Santa Rosa v. EPA, 
534 F.2d 150 (9th Cir. 1976), vacated and remanded on other grounds sub 
nom. Pacific Legal Foundation v. EPA, 429 U.S. 990 (1976) (`` `Neither 
EPA nor this court has any right to decide that it is better to 
maintain pollutants at a level hazardous to health than to require the 
degree of public sacrifice needed to reduce them to tolerable limits' 
'', citing South Terminal Corp. v. EPA, 504 F.2d 646, at 656 (1st Cir. 
1974); South Terminal Corp. v. EPA, 504 F.2d 646, 675 (1st Cir. 1974) 
(``[I]t seems plain that Congress intended the Administrator to enforce 
compliance with air quality standards even if the costs were great.'') 
Preserving injunctive remedies ensures that we remain able to protect 
air quality standards and PSD increments in accordance with our 
fundamental responsibilities under the CAA. See CAA sections 110(a) and 
(l), 42 U.S.C. 7410(a) and (l). See, also, the discussion of this issue 
in our 1999 excess emissions memorandum, reference document RRR.
    (i) Comment (MSCC, ExxonMobil): An exception and affirmative 
defense should be available under the FIP that is at least consistent 
with the consent decrees executed by EPA and the State of Montana with 
most of the affected sources.
    Response: As we have noted previously, the consent decrees and the 
FIP serve different purposes. We have adopted an affirmative defense 
provision that is consistent with the protection of the NAAQS.
    (j) Comment (Citizen): On page 39264 is the statement ``We are 
proposing that the flare limits will apply at all times without 
exception.'' Laudable as that seems, EPA then subsequently states, ``We 
solicit comment on whether it would be appropriate to include in our 
final FIP the ability to assert an affirmative defense to penalties 
only (not injunctive relief) for violations of flare limits.'' If the 
former statement is accepted, what are the penalties for exceeding 
flare limits and how will they be imposed and will the public be 
advised which refinery exceeds a flare limit and how often could that 
happen to the detriment of air quality in this area?
    Response: In this final rulemaking action, we have promulgated an 
affirmative defense to penalties for exceedances of the flare limits 
during malfunction, startup, and shutdown. Under this approach all 
excess emissions are considered violations. However, if we or anyone 
else brings an enforcement action, the facility may then assert the 
defense to penalties. To establish the defense, the facility must 
demonstrate to the judge that it took appropriate steps to avoid the 
excess emissions and met other requirements, the details of which are 
contained in our final rule. If the facility cannot establish the 
defense, it may be subject to CAA penalties up to $32,500 per day. We 
do not typically advise the public when a limit is exceeded or which 
facility has exceeded a limit, although we often alert the public 
through the press when we bring an enforcement action. Under the FIP, 
the subject sources must submit reports to EPA identifying their 
emissions. Those reports are available to the public through the 
Freedom of Information Act (FOIA). The establishment of flare 
requirements should help reduce flaring incidents.
6. Installation of Additional SO2 Reduction Equipment
    Comment (ExxonMobil): EPA's proposed FIP does not allow for time 
for the design and installation of facilities necessary to comply with 
the proposed flare emissions limitations. The facilities required for 
compliance with the proposed FIP go above and beyond what was built for 
the SIP or what will be built for the Consent Decree. For EPA's 
proposed FIP, the required controls have not yet been identified.
    Response: It is not clear what facilities the commenter is 
envisioning. Without greater detail, it is difficult to respond to the 
comment. However, the FIP imposes no specific requirement for the 
sources to install control equipment to limit flare emissions, and the 
limit we are imposing is the same one the State imposed on the sources, 
and which continues to be included in their permits. Our expectation is 
that sources will take all steps within their control to avoid flaring 
events and minimize their impacts on air quality if they do occur.
    To the extent that the commenter is referring to the time needed to 
design and install flare monitoring systems required by the FIP, we 
have extended the deadline for installation from 180 days to 365 days 
after EPA approval of the flare monitoring plan.

E. Concerns With Dispersion Modeling

1. Policy Issues
    (a) Comment (MSCC, ExxonMobil): Out-of-Date and Invalid Model 
Choice. (i) The proposed FIP uses the same model as that used in the 
SIP. EPA's models have changed since the time the SIP was developed. It 
is inappropriate to propose and justify more restrictive requirements 
on sources without considering more current modeling techniques and 
requirements. The older model may be more appropriate to confirm an 
existing situation or permit minor changes. However, the FIP goes 
beyond minor changes.
    Response: The commenter is correct that a newer model is now 
available. For new SIPs, we would require states to use EPA's most 
recent model. However, this is a unique situation. The State developed 
the Billings/Laurel SO2 SIP using the ISC model, which was 
current at that time, and we approved various source-specific emission 
limits in the SIP based on the State's modeling effort. The purpose of 
this FIP is to fill gaps in the approved SIP. We are not intending or 
required to re-do the entire SIP. See, e.g., section 302(y) of the CAA, 
42 U.S.C. 7602(y) (``Federal implementation plan'' means a plan (or 
portion thereof) promulgated by the Administrator to fill all or a 
portion of a gap or otherwise correct all or a portion of an inadequacy 
in a State implementation plan * * *''); McCarthy v. Thomas, 27 F.3d 
1363, 1365 (9th Cir. 1994) (A FIP is ``a set of enforceable federal 
regulations that stand in the place of deficient portions of a SIP.'') 
Accordingly, we think it is reasonable to rely on the same model the 
State used to develop the SIP. That way, all emission limits in the SIP 
and FIP will have been established on the same basis.
    We note that MDEQ tested the performance of the ISC model when the 
Billings/Laurel SO2 SIP was being developed, and the results 
showed that the model performance exceeded the performance criteria for 
models of this type. The FIP modeling represents a minor change to 
MDEQ's basic approach. The sources in the SIP modeling are 
characterized in the modeling inputs as 25 point and volume sources 
and, except for minor corrections provided by the sources, the major 
FIP-related change in modeling involves only one source: The MSCC 100-
meter stack. We had to change the inputs for MSCC's 100-meter stack 
because the State gave too much stack height credit to MSCC's stack in 
the SIP modeling, and we, consequently, disapproved MSCC's SIP emission 
limits and the SIP attainment

[[Page 21438]]

demonstration. Otherwise, the FIP modeling uses meteorology data, 
receptors, and stack parameters for sources other than MSCC that are 
nearly identical to those used in the SIP modeling.
    We also note that ISC remained an accepted EPA model at the time we 
proposed our FIP, and it is reasonable to finalize the FIP based on the 
same model. Switching models after our proposal would have required us 
to re-propose the FIP and would have delayed the FIP further.
    (ii) A newer model, ``AERMOD,'' has been adopted as the EPA 
regulatory default model. It is clear that AERMOD is now preferred for 
regulatory use over the model used in the SIP development. 
Consideration needs to be afforded to models available today, and 
particularly to the model reasonably believed to give the most accurate 
results. The stakeholder process should be used to determine which 
dispersion model should be used for the FIP (ExxonMobil).
    Response: See our response to comment II.E.1.(a)(i), above. We also 
note that AERMOD has more complex software than ISC and, as a result, 
it would be extremely difficult to perform the 1320 model simulations 
necessary to establish emission limitations that would address buoyancy 
flux variations that were included in the State's SIP. A stakeholder 
process is not required by the CAA and would merely serve to delay 
issuance of the FIP.
    (b) Comment (MSCC): Out-of-Date Model Input. Any dispersion 
modeling used for the proposed FIP must include improved techniques 
regarding building downwash. A new method for calculating the downwash 
effects buildings have on predicted ambient concentrations has been 
developed. The new technique is known as ``Plume Rise Model 
Enhancement'' (PRIME) algorithm. This technique is now commonly in 
practice in both ISC-PRIME and AERMOD. EPA's FIP modeling does not use 
this technique.
    Response: The PRIME downwash technique was never formally adopted 
by EPA for use in ISC. In order for states to employ this technique, 
EPA regional offices needed to authorize its use on a case-by-case 
basis until ISC was replaced as the reference model on December 9, 
2006. The plume rise technique used in ISC was the recommended approach 
at the time the State developed the SIP, and the technique served the 
modeling community well for many years.
    (c) Comment (MSCC, ExxonMobil): Modeling Violates EPA's Own 
Requirements. The modeling used for the proposed FIP does not meet 
EPA's own guidelines and requirements because of the model used, lack 
of current building profile, and numerous other problems found 
elsewhere.
    Response: See our response to comment II.E.1.(a)(i), above. The 
modeling approach was extensively discussed with regulatory agencies 
and the public when the SIP was developed, and the ISC-based modeling 
approach met the requirements of EPA's Guideline on Air Quality Models.
    (d) Comment (MSCC): Modeling File Naming Convention. EPA's modeling 
files and Technical Support Document, both contained in the docket, do 
not provide a reference to the naming conventions used in the modeling 
effort. While it is possible to dissect some of the naming conventions, 
it was not possible to discern each and every file and its purpose. 
Therefore, the reviewers are not certain that all the modeling 
attempts, purposes and nuances have been accounted for in the analysis. 
The commenter recommends a more complete description of the naming 
convention and the purpose behind each modeling effort needs to be 
explained.
    Response: At the recommendation of industry, MDEQ allowed the use 
of buoyancy flux in establishing emission limits, which made the 
modeling far more complex. As a result, many more modeling files are 
included than is typically the case in SIP modeling applications. To 
improve documentation, some extraneous modeling files have been removed 
and a text file added to explain naming conventions. The naming 
convention used for the Billings/Laurel SO2 FIP modeling 
files is typical of that used by the modeling community. To a modeler, 
the naming convention helps define the purpose behind the modeling 
effort. 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.
    (e) Comment (MSCC, ExxonMobil): Out-of-date and Invalid Emissions 
Rates. Federally enforceable emission rates from refinery consent 
decrees have not been included in the FIP modeling. EPA has used 10-
year-old emission inventory data that compromise the accuracy of the 
results. Reductions that have occurred in the past ten years have been 
ignored. The settlement documents related to the 1998 SIP contain 
requirements that substantially change the SO2 emission 
limits, and, therefore, the results of any modeling demonstration 
(ExxonMobil). Without including these existing emission reductions from 
the SIP and near term future reductions from consent decrees, EPA's 
proposed FIP ignores state and federally enforceable SO2 
emission reductions already in place.
    Response: See our responses to comments II.A.2.(b), II.B.2.(d) and 
II.D.4. The FIP modeling accounts for the limits that we approved in 
the Billings/Laurel SO2 SIP and those we are promulgating in 
the FIP. We cannot include State requirements that were not submitted 
with the SIP. Additionally, the ExxonMobil consent decree limits have 
not been translated into short term emission limits by MDEQ and made a 
part of the SIP. Short term emission limits are required to ensure 
compliance with the 3-hour and 24-hour average SO2 NAAQS. 
Also, the consent decrees do not address all of the stacks/sources 
involved in the SIP/FIP.
    (f) Comment (MSCC): MSCC has concerns with using the SIP modeling. 
The predecessor model routines had been discredited (``invalidated'') 
in this valley following a study done years earlier by the State. The 
model, even in the 1990's, did not represent state of the art in 
modeling science and was admittedly prone to serious over-predictions, 
particularly in so-called intermediate and complex terrain.
    Response: As noted above, the modeling was EPA's preferred model at 
the time of the SIP, has been validated for use in the Billings/Laurel 
area, and has been used extensively throughout the United States in 
setting emission limits for nearly two decades. The model has not been 
``invalidated'' for use in the Billings/Laurel area. See also our 
discussion of related issues in our May 2, 2002, final action on the 
Billings/Laurel SO2 SIP, 67 FR 22168, 22183.
    (g) Comment (ExxonMobil): Only the current actually existing 
emission sources with proper geographical coordinates should be used as 
inputs to the dispersion model.
    Response: We do not understand what the commenter is referring to 
when they indicate ``only the current actually existing emission 
sources * * * should be used as inputs to the dispersion model.'' With 
respect to geographical coordinates used in the modeling, they were 
provided by the sources in response to EPA's CAA Section 114 
information request. The incorrect source coordinate for MSCC in the 
modeling files has been corrected.\12\ On

[[Page 21439]]

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. To the extent the commenter is 
asserting that actual emission rates should be used as inputs to the 
dispersion model, we respectfully disagree. As described more fully in 
our response to comment II.E.1.(e), above, potential emissions rather 
than actual emissions are used in SO2 attainment 
demonstrations, per longstanding EPA policy and 40 CFR part 51, 
Appendix W requirements. Accordingly, in our attainment demonstration, 
we modeled the emission limits we approved in the SIP and any new 
emission limits we are promulgating in the FIP. Thus, with the 
exception of certain units at MSCC, we modeled the same emission rates 
that the State used in its SIP modeling.
---------------------------------------------------------------------------

    \12\ In reference document WW, Technical Support Document, 
Dispersion Modeling to Support Sulfur Dioxide (SO2) 
Emission Limits in Federal Implementation Plan (FIP) for Billings/
Laurel, Montana, June 2006, we indicated that one suggested change 
that was not incorporated into the EPA FIP modeling involved the 
coordinate system used in the model to identify source location. 
MDEQ developed the original source locations based on the UTM NAD27 
(North America Datum of 1927) coordinate system, and EPA has 
retained that coordinate system in our modeling. It appeared that 
several of the suggested changes to source locations were based on 
NAD83 values. The newer coordinate system can affect source 
locations by up to 200 meters. In dispersion modeling on the scale 
of the current modeling domain, consistency between the source and 
receptor locations is the most important consideration. For this 
reason, suggested changes that appeared to be based on the NAD83 
were not included in the modeling. However, changes that address 
local inconsistencies in measured distances between fixed stacks 
(such as at MSCC) on a specific property were incorporated in EPA's 
modeling using UTM NAD27. Sensitivity testing of the model showed 
that even the NAD27/NAD83 differences did not significantly affect 
total predicted concentrations; the principal effect was, in some 
instances, to shift the location of the maximum impact to a 
different receptor. An electronic record (compact disk) of EPA's 
sensitivity testing of the model is contained in the docket. See 
reference document EEE in Docket Number EPA-R08-OAR-2006-0098.
---------------------------------------------------------------------------

    (h) Comment (ExxonMobil): Only the verified actual stack heights 
should be used as inputs to the dispersion model.
    Response: Stack height regulations determine the stack height 
values that are used as inputs to dispersion models in SIP attainment 
demonstrations. In some cases this value may not be the same as the 
actual stack height. See 40 CFR 51.118. For example, under our stack 
height regulations, 65 meters is the appropriate stack height value for 
MSCC's SRU stack, even though the stack is 100 meters tall. We believe 
we have used the correct stack height values in all cases, and the 
commenter did not indicate that any specific stack height value we used 
in our modeling was incorrect.
    (i) Comment (ExxonMobil): The meteorological data to be used as 
input to the dispersion model should reflect the most representative 
information. The meteorological set to be used should be chosen based 
on availability and based on those monitored parameters that are best 
able to take full advantage of the latest dispersion modeling 
techniques.
    Response: EPA believes that the meteorological data from the 
Billings airport that was used in the SIP/FIP modeling is 
representative of conditions within the modeling domain. The Billings 
airport is located in an open area with good exposure to prevailing 
wind flow and has a long period of record. Five years of historical 
weather data (1984, 1986, 1987, 1988, and 1989) were used in the 
modeling to ensure that the full range of possible meteorological 
conditions were evaluated in the modeling. To our knowledge the 
Billings airport data have the longest period of record of any site in 
the Billings area. When the State developed the SIP modeling approach 
that EPA has now used for the FIP, the State tested ISC model 
performance using the Billings airport data. That evaluation showed 
acceptable model performance.
    (j) Comment (ExxonMobil): EPA should be modeling emission rates to 
levels that predict values slightly less than the NAAQS. This modeling 
concept is referred to as ``pushing the model to failure.'' This 
approach is designed to determine the maximum emission limits allowed 
by regulation under acceptable modeling protocol. By proposing mass 
emission limits on flares of 150 pounds of SO2 per 3-hour 
period or 500 pounds of SO2 per calendar day, EPA has chosen 
to use, without further consideration, mass emission limits that do not 
``push the model to failure'' but instead arbitrarily limit the sources 
to mass emission limits that go far beyond protecting the NAAQS.
    Response: Emission inputs to the model were established using 
criteria contained in 40 CFR part 51, Appendix W, Section 8. The 
emission limits set by the modeling analysis are based on emission 
rates that would just meet the NAAQS. They are not based on ``arbitrary 
limits'' that go ``far beyond protecting the NAAQS''. For example, with 
the limits we are establishing and the SIP limits we approved, our 
modeling resulted in a high value of 354 [mu]g/m\3\ which would exactly 
meet the 24-hour SO2 NAAQS of 365 [mu]g/m\3\ when background 
concentrations of 11 [mu]g/m\3\ are considered.
    (k) Comment (MDEQ): Montana continues to affirm the use of the ICS3 
model.
    Response: We acknowledge receipt of the comment and the support for 
the model used.
    (l) Comment (ExxonMobil): EPA has not used current accurate process 
and meteorological inputs in its modeling. This is contrary to EPA's 
assurance in its May 2002 final rule that: ``Any future modeling in the 
Billings/Laurel area should incorporate all corrections. The SIP 
limitations are based on the best information available at the time the 
attainment demonstration was modeled, and the same will be true for any 
FIP limitations that are developed.'' 67 FR 22189. Also, in its May 
2002 final rule, EPA stated that: ``We agree that future modeling 
should include all corrected data.'' 67 FR 22189. However, EPA has 
ignored critical factual data for purposes of developing the proposed 
FIP.
    Response: The commenter ignores the context and meaning of EPA's 
statements in its 2002 SIP action. The cited quotes were part of our 
response to specific comments from one source that there were errors in 
the State modeling numbers used for that source's stack parameters. The 
comment was: ``CEMS data now indicate an error in the assumed buoyancy 
flux for MSCC's main stack; the current modeling protocol contains an 
assumption which significantly underestimates the average rise in 
emissions. Any revised modeling should correct this assumption.'' 67 FR 
22189. We were merely agreeing that future modeling should include 
corrected stack parameters based on CEMS measurements: ``CEMS 
measurements of flow and temperature data provide the best estimates of 
stack parameters, and values based on CEMS data should be used in any 
future SIP modeling for Billings provided the CEMS data are accurate.'' 
Id. We were not indicating we would use a new model, different 
meteorological data, or consider entirely new structures. In fact, on 
the same page of our 2002 notice, we said the following:

    ``In addition, dispersion models and data bases are continually 
being improved. The task of demonstrating attainment could never be 
completed if we or the State were compelled to update the analysis 
with each new refinement. For the FIP, we intend to continue to use 
ISC2 as the applicable model to fill in the gaps in the State's 
attainment demonstration created by our disapproval of the emission 
limitations for MSCC's 100-meter stack. Some source parameters have 
been corrected since the 1994 modeling analysis (see Response 
V.D.4.(d), above), but we intend to use the same meteorological

[[Page 21440]]

data and modeling protocols the State used, so that the results will 
be comparable.''

For a more complete discussion of our basis for selecting the model and 
data inputs we have used, please refer to the other responses to 
comments in this section II.E, our proposed FIP, and our TSD for the 
proposed FIP.
2. Technical Issues
    (a) Comment (MSCC, ExxonMobil): Incorrect Source Location. The 
location of the small boiler stacks at MSCC that are modeled as a 
volume source is incorrect. The error occurs by the nature in which the 
X and Y coordinates are entered into the SRI file. The entry is off by 
one column.
    Response: This has been corrected. 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.
    (b) Comment (MSCC): Incorrect Emission Rate. Table 2 of EPA's 
Dispersion Modeling Technical Support Document shows the modeling value 
of 136.21 g/sec for MSCC's SRU-100-meter stack. An emission rate of 
150.0 g/sec was modeled in the majority of the EPA modeling. If the 
proposed emission limit of 3003.1 lb/3-hours (126.13 g/sec) is correct, 
then the number that should appear in both the table and the input 
files is 126.13 (g/sec) to be consistent with the emission limit.
    Response: In the State's original SIP modeling submittal there were 
1,320 modeling scenarios with various buoyancy flux combinations that 
were tested, and it was determined that only a few of these resulted in 
concentrations that threatened the NAAQS. EPA conducted screening to 
eliminate the need for refined modeling of those scenarios where the 
NAAQS were not threatened. The 150 g/sec emission rate was used 
provisionally to determine which modeling scenarios would result in the 
maximum ground level concentrations, and was not used to set MSCC's 
proposed emission limit. Once the appropriate modeling scenarios were 
determined by EPA, only those scenarios were used to conduct the 
refined modeling to establish an emission limit of 126.13 g/sec. The 
commenter is correct that there is a discrepancy between Table 2 in 
EPA's Dispersion Modeling Technical Support Document (reference 
document WW) and the modeling input files. The input files for the 
limited modeling scenarios reflected the correct value, 126.13 g/sec. 
Table 2 of the TSD contains the wrong value.
    (c) Comment (MSCC, ExxonMobil): Missing Modeling Files. Three 
source input files (SRI files) were not included in Reference Document 
EEE, the basis for the modeling conclusion and the proposed emission 
limit for MSCC's 100 meter stack. It appears that these files were 
actually used in model runs.
    Response: We have added the referenced modeling files. 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.
    (d) Comment (MSCC, ExxonMobil): Hanging Modeling Files. A source 
input file (ref--5t.sri) is included in Reference Document EEE. 
However, this input file does not appear to be used in any input (RUN) 
and output files (OPF) files. It is not possible to comment effectively 
on the adequacy of the model without knowing the file's purpose.
    Response: This was a test file inadvertently included in the 
electronic record. It has now been 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.
    (e) Comment (MSCC, ExxonMobil): Outdated Building Profile Data. The 
dispersion modeling runs do not contain up-to-date information 
regarding building profile data. EPA's use of 10-year old historical 
data is not logical considering the agency requested and received 
certain building data in its December 2003 request.
    Response: Building profile data were current at the time the MDEQ 
prepared the SIP. EPA is not updating the inputs to reflect recent 
changes in building dimensions or changes in dispersion models. We are 
simply correcting deficiencies in the MDEQ's SIP modeling. If we were 
to follow the commenters' suggestion, we would have to revisit the 
entire SIP, including SIP limits we approved. The CAA does not require 
us to re-open the entire SIP. See response to comment II.E.1.(a), 
above.
    (f) Comment (MSCC): Variable ``HB'' and ``PW'' Not Used. In order 
to execute the FIP model, EPA requested source specific information 
including the modeling terms HB and PW. These values may be input into 
the IGM model, however, this information is superseded by direction-
specific building parameters by the model while executing in all cases 
(stacks) of interest. In other words, the data that was coded by EPA in 
the model runs were ignored by IGM (in favor of other information) and 
therefore of no value. Instead, specific building data (discussed 
above) should have been entered into the program. There is at least one 
substantial building, the YELP coke barn, that should have been 
included in the 2006 model runs.
    Response: See responses to comments II.E.1.(a) and II.E.2.(e), 
above. As noted above, to the extent possible, EPA is using the model 
inputs and model settings selected by the State at the time of SIP 
preparation and used in the IGM code. The model input selections 
reflect modeling practice and conditions at the time of the SIP. The 
coke barn did not exist at the time the SIP was prepared.
    HB and PW values reflect the dimensions of the facilities that had 
large structures nearby and that MDEQ included for downwash processing 
in their SIP modeling. While the commenter is correct that, in the IGM 
model, these values were superseded by other data, obtaining these 
values was useful to us as a screening tool, and inputting these values 
into the model did not affect the validity of the results.
    (g) Comment (MSCC, ExxonMobil): Compliance Analysis Not Valid. The 
FIP proposal notes that there is a ``trigger point'' of 500 lb/calendar 
day in various ``settlements'' between EPA and refineries. The proposal 
goes on to assert that a modeling analysis was conducted assuming the 
flares emitted SO2 at a rate of 500 lb/3-hours and that the 
model demonstrated compliance to this alternative. A review of the 
modeling files, however, indicates that the ``controlling'' model run 
that defined MSCC's emission limit for the 100-meter stack (modeled at 
65 meters) did not include this 500 lb/3-hour flare emission rate 
option.
    Response: We solicited comment on whether we should limit the 
flares to 500 lbs of SO2 per calendar day. We have not 
adopted that option. But, for purposes of the attainment demonstration, 
we modeled the 500 lbs as if it were emitted over a 3-hour period 
rather than a calendar day. We wanted to assure that if all the 
calendar-day allowed emissions were emitted in a 3-hour period, the 3-
hour NAAQS would still be protected. Those modeling files are contained 
in the docket.
    However, the controlling model run that defined MSCC's emission 
limit for the SRU 100-meter stack was for the 24-hour NAAQS. There was 
no need to model the 500 lbs of SO2/calendar day to show 
compliance with the 24-hour NAAQS since we had already modeled the 
flares at 1200 lbs of SO2/calendar

[[Page 21441]]

day. Since attainment of the 24-hour NAAQS was shown at 1200 lbs of 
SO2/calendar day, the area would still show attainment at 
500 lbs of SO2/calendar day.

F. Miscellaneous Comments

1. Stakeholder Process
    (a) Comment (CHS Inc.): If EPA intends to regulate malfunctions, 
startups, and shutdowns, a stakeholder's process should be used to 
accurately develop a reasonable flare limit.
    Response: EPA announced its proposed FIP in the Federal Register on 
July 12, 2006, invited public comment, and identified the time and 
place for a public hearing. A public hearing was held in Billings, 
Montana, on August 10, 2006. Only one person from industry spoke at the 
hearing. Prior to the hearing and at the hearing itself, no one 
mentioned the concept of a stakeholder process. In addition, we 
provided nearly four months for the affected facilities and other 
members of the public to submit written comments and suggestions 
regarding our proposed FIP, including a substantial extension to our 
original 60-day comment period in an attempt to reasonably accommodate 
State and industry requests. We have made a number of changes in 
response to comments received. If the affected facilities had other 
ideas about how we could better structure the FIP, they had ample 
opportunity to express those concepts.
    We have complied with the requirements of the CAA as set forth in 
section 307(d) regarding public participation for the FIP. We are not 
required to hold a stakeholder process. Issues regarding malfunctions, 
startups, and shutdowns are addressed above.
    (b) Comment (CHS Inc., ExxonMobil, MPA): It would be in the best 
interest of all involved that a stakeholder process be used to 
determine what, if any, enhancements to the Montana SIP are 
appropriate.
    Response: See response to comment II.F.1.(a), above.
    (c) Comment (WETA, COPC): If the EPA feels strongly that 
consideration should be given to different controls for SO2, 
then a stakeholder process should be utilized to consider issues and 
relevant information in deciding if a further SIP or FIP is necessary.
    Response: See response to comment II.F.1.(a), above.
    (d) Comment (MSCC, ExxonMobil): EPA has developed the proposed FIP 
in a vacuum as to the affected parties. It is inappropriate for EPA to 
not consult the affected facilities in any meaningful way. The process 
used by Montana in developing the SIP should be used in the FIP. A 
stakeholder process will allow all parties an opportunity to ensure 
that the best available information is considered in formulating any 
proposed requirements.
    Response: See response to comment II.F.1.(a), above.
2. Ripple Effect
    (a) Comment (WETA): The commenter is concerned not only with the 
impact of the FIP on the refineries in the area but the potential 
ripple effect on the businesses, workers, and other consumers who daily 
use and depend on the variety of products produced by the petroleum 
refineries in the Billings/Laurel area.
    Response: We acknowledge the commenter's concerns. We recognize 
that our FIP will result in costs to MSCC and the refineries, which 
they may or may not pass on to consumers. We have tried to be sensitive 
to the costs MSCC and the refineries may incur to meet the FIP's 
requirements, which potentially would affect the costs of products to 
consumers. For example, where we determined less costly methods to 
monitor SO2 concentrations could achieve similar results, we 
are allowing these other methods to be used. However, our ultimate 
charge under the CAA is to protect the SO2 NAAQS, 
recognizing that cost impacts to sources and consumers may occur. See, 
e.g., City of Santa Rosa v. EPA, 534 F.2d 150 (9th Cir.1976), vacated 
and remanded on other grounds sub nom. Pacific Legal Foundation v. EPA, 
429 U.S. 990 (1976).
    (b) Comment (citizen): The commenter is a dryland farmer and uses 
an ammonium sulfate (thiasol) fertilizer, which is a by-product of the 
refinery process. He says he is doing as much as he can to be 
environmentally conscientious and not introduce metals into the soils 
found in other fertilizers. This requires him to use the thiasol that 
is refinery-produced. He requests that EPA not exacerbate a bad 
situation for agriculture, which increases costs to a major industry 
which is marginal in profitability and major in importance to the State 
of Montana.
    Response: See response to comment II.F.2.(a), above.
3. Extend Comment Period
    Comment (COPC, ExxonMobil, MSCC, WETA, YCC): Commenters asked for 
additional time to comment on the proposed FIP, until at least December 
11, 2006.
    Response: The public comment period on the FIP proposal ran from 
July 12, 2006, through November 3, 2006--almost four months. 
Additionally, a public hearing was held in Billings, Montana, on August 
10, 2006. EPA believes it provided sufficient time and opportunity for 
all commenters to provide comments on the proposed FIP.
4. EPA's Strategic Plan
    Comment (COPC): The proposed FIP, which contains inflexible flare 
emission limits and strictly-specified monitor installations 
requirements, is inconsistent with EPA's Strategic Plan, which commits 
EPA to ``finding innovative solutions and collaborating with others.''
    Response: We acknowledge the commenter's concerns. However, we are 
charged with meeting the CAA's requirement to assure that the 
SO2 NAAQS are met and maintained. Accordingly, the FIP 
adopts flare emission limits and compliance determining methods.
    It should be noted that the discussion on Innovation and 
Collaboration in the ``2006-2011 EPA Strategic Plan, Charting Our 
Course,'' September 2006 (reference document BBBBBB), pertains to 
complex environmental challenges where broad-based problems cannot be 
solved with conventional regulatory controls. We do not think this is 
relevant here. We are merely establishing limits on flares and methods 
to determine compliance with those limits.
5. FIP Provisions in Title V Permits
    Comment (MDEQ): Montana acknowledges that the FIP provisions, if 
promulgated, will be incorporated in Title V permits. However, Montana 
expects EPA will take the lead on implementing and enforcing the FIP 
provisions.
    Response: EPA intends to assume primary responsibility to implement 
and enforce the FIP. However, the FIP requirements will be ``applicable 
requirements'' under Title V, which, therefore, must be included in 
Title V permits for the affected sources and be enforceable by the 
State.
6. Length of Time it Took EPA To Propose FIP
    Comment (YVAS): Since the 1990 Clean Air Act requires NAAQS for 
SO2 to protect public health, YVAS deplores this 
``inadequacy [sic] and ``non-attainment'' and deplores further that the 
EPA did not adequately and in timely fashion, take necessary steps to 
enforce the CAA's provisions to protect the air quality in the 
Billings/Laurel area in a reasonably suitable time period regardless of 
any mitigating circumstances. A specific justification explaining this 
lapse in EPA's

[[Page 21442]]

responsibilities for not acting in the public interest is essential to 
the residents of the Billings/Laurel area given that at the time, the 
Billings/Laurel Sulphur Dioxide Area was subject to excessive amounts--
estimated to be over 35,000 tons (1993)--of SO2 atmospheric 
pollution.
    Response: We believe EPA's SIP Call and subsequent State and EPA 
actions to address the SIP Call have helped reduce SO2 
emissions in the Billings/Laurel area. There is no question that this 
process has taken longer than it should have.
7. EPA Enforcement
    Comment (YVAS): YVAS insists that the EPA consistently monitor 
industry emissions in order that industry sources continue to comply 
with the SIP and/or the ``more stringent requirements under other 
provisions of the CAA'' or ``SIP-approved permit programs.''
    Response: EPA intends to take the lead in enforcing the emission 
limits and monitoring requirements contained in the FIP. Congress 
intended that states have primary responsibility for implementing and 
enforcing their SIPs. Additionally, states may take the lead in 
implementing and enforcing other CAA programs (e.g., News Source 
Performance Standards (NSPS), Maximum Achievable Control Technology 
(MACT) standards, Title V permitting), either through EPA delegation or 
program approvals. In the latter cases, we have an oversight role and 
may take enforcement action under section 113 of the CAA for violations 
of a SIP or other CAA requirements when a state does not take action or 
when its action is considered ineffective.
    EPA Region 8 communicates regularly with the MDEQ regarding 
sources. We have regular meetings with MDEQ regarding sources that are 
violating emission limit requirements and discuss the MDEQ's proposed 
or ongoing actions to address these violations. We intend to continue 
to carry out our oversight responsibility for the SIP and other CAA 
requirements for the Billings/Laurel sources. If we determine that the 
MDEQ is not taking appropriate action for violations of the SIP, or 
other CAA requirements, we will take appropriate action.
8. Further Emission Reductions
    Comment (YVAS): Although the industry is attaining lower yearly 
decreases of SO2 since 1994, with presumably a better and 
``healthier'' air quality in the area thereby, the assumption logically 
follows that industry should be required to comply with further reduced 
SO2 release levels. Nowhere in this FIP is there an attempt 
to address the issue of a further reduction in the total emissions of 
the industrial sources in the Billings/Laurel area. Accordingly, YVAS 
believes that all anti-lower SO2 emission arguments are 
irrelevant against the demand for protecting public health standards 
and additional reduction of SO2 emissions is mandatory under 
the CAA. Failing to address a further SO2 emissions 
reduction should be considered another serious breach of your 
responsibility to the Billings/Laurel public. Why did EPA not include a 
discussion towards reducing the total SO2 emissions in the 
Billings/Laurel Sulphur Dioxide area in this FIP and since EPA did not 
include that discussion here, does EPA plan to do that and if so, when?
    Response: The 1970 CAA established the air quality management 
process as a basic philosophy for air pollution control in this 
country. Under this system, we establish air quality goals (NAAQS) for 
criteria pollutants. States develop control programs (termed SIPs) to 
attain and maintain these NAAQS. Our fundamental obligation in the SIP/
FIP context is to ensure that the NAAQS are met, not reduce emissions 
to zero. Thus a reduction of SO2 emissions is mandatory only 
to the extent needed to attain the NAAQS. However, under section 116 of 
the CAA, states may adopt and enforce any air pollutant standard, 
limitation, or control requirement so long as it is no less stringent 
than that required by the CAA. Put another way, states can require that 
the air be cleaner than the NAAQS. Our goal in the FIP is to ensure 
attainment of the SO2 NAAQS.
9. SO2 NAAQS
    (a) Comment (YVAS): Nowhere in this FIP is any reference made to 
what clean air standards should be under the CAA or NAAQS. Commenters 
should have been informed as to those standards in this FIP in order to 
fairly judge as acceptable or non-acceptable the release standards 
proposed for the sources in this FIP. How can the public adequately 
comment on clean air issues when those standards are unknown to the 
public? Further, referring the general public to sources where those 
standards would be found is a disservice to the public since many of 
those sources of such information may be unattainable or unavailable.
    Response: The July 12, 2006, proposed FIP did identify the 24-hour 
and 3-hour SO2 NAAQS under the modeling discussion (71 FR 
39259, starting at 71 FR 39270, col. 1). The SO2 NAAQS were 
previously established (see discussion below), and EPA was not seeking 
comment on any changes to the NAAQS in this FIP action.
    Two sections of the CAA govern the establishment and revision of 
NAAQS. Section 108 (42 U.S.C. 7408) directs the Administrator to 
identify pollutants which ``may reasonably be anticipated to endanger 
public health or welfare'' and to issue air quality criteria for them. 
These air quality criteria are to ``reflect the latest scientific 
knowledge useful in indicating the kind and extent of all identifiable 
effects on public health or welfare which may be expected from the 
presence of [a] pollutant in the ambient air.''
    Section 109 (42 U.S.C. 7409) directs the Administrator to propose 
and promulgate ``primary'' and ``secondary'' NAAQS for pollutants 
identified under section 108. Section 109(b)(1) defines a primary 
standard as one ``the attainment and maintenance of which, in the 
judgement of the Administrator, based on the criteria and allowing an 
adequate margin of safety, [is] requisite to protect the public 
health.'' A secondary standard, as defined in section 109(b)(2), must 
``specify a level of air quality the attainment and maintenance of 
which, in the judgement of the Administrator, based on [the] criteria, 
is requisite to protect the public welfare from any known or 
anticipated adverse effects associated with the presence of [the] 
pollutant in the ambient air.'' Welfare effects are defined in section 
302(h), 42 U.S.C. 7602(h), to include ``effects on soils, water, crops, 
vegetation, manmade materials, animals, wildlife, weather, visibility 
and climate, damage to and deterioration of property, and hazards to 
transportation, as well as effects on economic values and on personal 
comfort and well-being.''
    On April 30, 1971 (reference document CCCCCC), the Environmental 
Protection Agency (EPA) promulgated primary and secondary NAAQS for 
sulfur oxides (SOx) (measured as SO2) (then 
codified as 40 CFR 410.4 and 410.5). The primary standards were set at 
365 micrograms per cubic meter ([mu]g/m3) (0.14 parts per million 
(ppm)), averaged over a 24-hour period and not to be exceeded more than 
once per year, and 80 [mu]g/m3 (0.03 ppm) annual arithmetic mean. The 
secondary standard was set at 1,300 [mu]g/m3 (0.5 ppm) averaged over a 
period of 3 hours and not to be exceeded more than once per year. In 
accordance with sections 108 and 109 of the CAA, in the 1990's, EPA 
reviewed and revised the health and welfare criteria upon which these 
primary and secondary SO2 standards were based. On April 21, 
1993 (58 FR 21351) (reference document DDDDDD),

[[Page 21443]]

EPA announced its final decision under section 109(d)(1) of the CAA 
that the revisions of the secondary SO2 NAAQS were not 
appropriate at that time. On May 22, 1996 (61 FR 25566) (reference 
document EEEEEE), EPA announced its final decision under section 
109(d)(1) of the CAA that the revision of the primary SO2 
NAAQS was not appropriate at that time. EPA is currently reviewing the 
primary and secondary standards again to determine whether they should 
be revised.
    The Code of Federal Regulations (CFR) is available at most public 
libraries and on the internet at: http://ecfr.gpoaccess.gov/. Likewise, 
the CAA is also available at most public libraries and on the internet 
at EPA's Web site: http://www.epa.gov/air/caa/.
    (b) Comment (citizen): The rejection of Montana's Plan to control 
air quality in the Billings/Laurel air shed 4 years previously has left 
a serious gap in the air quality in this air shed.
    Response: We acknowledge this comment. See response to comment 
II.F.6., above.
10. SO2 Health Effects
    (a) Comment (Citizen): The air is so bad near the commenter's house 
that she needs to close the windows. She has headaches and burning eyes 
and sinuses. How safe is it for the families? Commenter is concerned 
that air emissions affect landscape and river areas. Commenter would 
like EPA to assure that refineries do not off-gas unmeasureable blasts 
of pollution as she has seen them do over her water, county, and home.
    Response: We acknowledge this comment. The FIP, along with other 
requirements contained in the SIP, will provide an enforceable 
mechanism to assure that the SO2 NAAQS in the future will be 
protected in the Billings/Laurel area. Since EPA initially requested 
the State to revise the Billings/Laurel SO2 SIP, actual 
SO2 emissions from companies have been cut by more than half 
and there have been measured improvements in air quality. The SIP and 
FIP contain an enforceable control strategy to help ensure that the 
SO2 NAAQS are attained and maintained.
    (b) Comment (Citizen): Since national air quality standards are 
more stringent than Montana requires, serious health risks to area 
residents is probable and cannot be ignored.
    Response: See response to comment II.F.10.(a), above. Note that the 
State's ambient standards, in some cases, are more stringent than the 
national standards. Subchapter 2 of the Administrative Rules of Montana 
(ARM) contains the Montana ambient air quality standards (MAAQS). The 
MAAQS are not contained in the federally-approved SIP; the CAA does not 
require that the standards be in the federally-approved SIP. The 
SO2 MAAQS are contained in ARM 17.8.210 (see reference 
document FFFFFF) and are as follows: (1)(a) Hourly average--0.50 ppm, 
not to be exceeded more than 18 times in any 12 consecutive months; 
(1)(b) 24-hour average--0.10 ppm, not to be exceeded more than once per 
year; and (1)(c) annual average--0.02 ppm, not to be exceeded. The 24-
hour and annual SO2 MAAQS are more stringent than EPA's 24-
hour and annual SO2 NAAQS. The State has a 1-hour average 
SO2 MAAQS and EPA has a 3-hour average SO2 NAAQS. 
The State does not require that plans be developed to assure attainment 
and maintenance of the MAAQS, whereas, EPA does require plans to assure 
that the NAAQS are attained and maintained.
    (c) Comment (Citizen): Commenter works the evening shift near the 
industrial sector and the refineries and the coke plant. He notices 
that at night the air becomes more sour. Depending upon which way the 
wind is blowing or whatever is occurring in the area, it will burn his 
eyes and nose. It will start to burn his lungs and inflame his chest 
and it will make it harder for him to breathe. The air is like a smoke-
filled barroom. He used to live in this area as well. Commenter feels 
it degrades the quality of his life. He's standing up for his lungs.
    Response: See response to comment II.F.10.(a)., above.
11. Public Process
    (a) Comment (Citizen): Since there has been no public disclosure of 
the EPA's plans for complying with the standards (considered as minimal 
by local public health advocates) as set forth in the National 
standards (which also have not been provided publicity to create public 
awareness of those standards), the EPA should not proceed with any rule 
making unless the public receives an opportunity to comment.
    Response: EPA announced its proposed FIP in the Federal Register on 
July 12, 2006. In the July 12, 2006 Federal Register notice, EPA 
provided for the opportunity of a public hearing. A public hearing was 
held in Billings, Montana on August 10, 2006. At the hearing, EPA 
discussed its proposed FIP. Additionally, EPA's proposed notice 
indicated that detailed information regarding the proposed FIP was 
available on the Internet. We have complied with the requirements of 
section 307(d) of the CAA regarding public disclosure and the 
administrative requirements for proposing the FIP. We are announcing 
this final FIP in the Federal Register as well. A discussion of the 
SO2 NAAQS is provided above.
    (b) Comment (Citizen): Plans for controlling emissions ``at the 
source'' must be provided by the EPA at any public meeting announced by 
the EPA and those plans should be announced publicly in advance of the 
meeting in order for the public to understand what the effects and 
results of such plans will be on the air shed quality of the Billings/
Laurel metropolitan area.
    Response: See response to comment II.F.11.(a), above.
12. Stack Height
    (a) Comment (Citizen): Included in EPA's emission control plans 
must be a stringent requirement that none of the three area refineries 
or the Montana Sulphur and Chemical company may construct any emissions 
stack or flaring system of 100 meters or higher. Information concerning 
the probable effects, distance, wind patterns, content etc. of the 
dispersal plumes of stacks of this height should be provided to the 
public at any hearing in order that public comment on this crucial 
aspect of the emission control plan may be properly analyzed. Under no 
circumstances should the 100-meter height be considered as a minimum 
permissible height by the EPA or by the companies involved for any 
stack or flaring system.
    Response: EPA does not restrict the physical height of a smoke 
stack. See 40 CFR 51.118(a). However, we do restrict the credit a 
company receives for its stack height in the modeling used to determine 
whether a SIP will meet national standards for specific air pollutants. 
Id. The stack height credit is based on the greater of the following: 
(1) A height of 65 meters, (2) a height based on a formula that 
considers the surrounding buildings, or (3) a height based on technical 
modeling studies which show a certain height is necessary to avoid high 
levels of pollutants in the nearby area. See 40 CFR 51.100(ii).
    EPA has rules that apply to tall stacks; otherwise, companies could 
avoid installing needed pollution control equipment. Industry could 
simply build higher stacks and emit into the air additional pollutant 
levels that would not violate local air quality standards, but could 
eventually affect the air quality of communities farther downwind. This 
is because the higher the stack height, the greater the dispersion of 
pollutants and the less likely they will reach the ground in the

[[Page 21444]]

vicinity of the stack. EPA does allow increases to stack height credits 
when the stacks meet the conditions noted above.
    EPA disapproved part of the Billings/Laurel SO2 SIP 
because MSCC's stack height credit did not meet the conditions noted 
above. EPA believes that the appropriate stack height credit for the 
MSCC SRU 100-meter stack is 65 meters. The 65-meter stack height credit 
was used in the modeling for the FIP. We did not identify any other 
concerns with the stack height credit used for other sources in the 
SIP.
    (b) Comment (Citizen): Studies, including wind roses of the 
dispersal pattern of all stacks of 65 meters and higher should be 
provided to the public at a hearing of the final FIP, in order that the 
public comment on this crucial aspect of the emission control plan may 
be properly analyzed.
    Response: The CAA directs EPA to take public comment on proposed 
FIPs, not final FIPs. See CAA section 307(d). EPA's modeling studies 
for the proposed FIP were contained in the docket for the proposed FIP 
and available for review during the comment period on the proposed FIP. 
Additionally, 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.
13. General Support
    (a) Comment (Citizen): The commenter wants to lend support to what 
EPA is trying to do here and the proposals that EPA is making, and he 
thinks it is very much on target and for his benefit, and he would hope 
the industries who are being regulated in this sense will find a way to 
make it worth their while to do it also.
    Response: We acknowledge receipt of the comment and the support for 
our proposal.
    (b) Comment (Citizen): Commenter encourages EPA to carry on the 
work we have been doing, to encourage movement in the positive 
direction of reducing emissions.
    Response: We acknowledge receipt of the comment and the support for 
our proposal.
    (c) Comment (Citizen): Commenter appreciates the changes that EPA 
is making and thinks the people in Billings deserve them. Commenter 
feels the industries need to step up to the plate and be responsible 
for their emissions.
    Response: We acknowledge receipt of the comment and the support for 
our proposal.
14. SIP Escape Clause
    Comment (MSCC): The SIP contains an important ``escape clause'' by 
which there was a general agreement that if the State provided more 
favorable treatment to one facility, the same accommodation would be 
offered to the other facilities. The present proposed FIP which 
proposes to reduce MSCC's stack height credit and drastically reduce 
MSCC's emission limits will violate that clause. This unwarranted 
intrusion into a carefully-bargained agreement among multiple parties, 
violates both the letter and the spirit of the CAA.
    Response: We are not bound by the escape clause that the State 
approved; in fact, we disapproved this aspect of the SIP. See 67 FR 
22168, May 2, 2002. Instead, we are obligated to correct the portions 
of the SIP we disapproved. We disapproved MSCC's main stack emission 
limits because they were based on inappropriate stack height credit. 
The FIP establishes new limits for MSCC's main stack that are 
consistent with our modeled attainment demonstration, based on a Good 
Engineering Practice (GEP) stack height credit of 65 meters. While it 
is not clear to us how this violates the State-approved escape clause, 
setting emission limits for MSCC's main stack consistent with our stack 
height regulations and necessary to demonstrate attainment of the NAAQS 
does not violate the CAA. On the contrary, setting such limits is 
required by the CAA, regardless of the State-approved escape clause.

G. MSCC Specific Issues

1. Variable Emission Limit
    (a) Comment (MSCC): EPA offers surprisingly little discussion as to 
why a variable limit was not proposed for Montana Sulphur. EPA's 
reasoning seems to ignore that MSCC has been operating under a variable 
emissions limit that has been modeled, monitored, and enforced for 
close to a decade.
    Response: EPA's reasoning for not offering a variable limit is 
discussed in the July 12, 2006, proposal notice (see 71 FR 39259, 
starting at 39268, col. 2) and reference document WW ``Technical 
Support Document'' contained in EPA Docket No. EPA-R08-OAR-2006-0098. 
Additionally, to our knowledge, the SIP limits for two sources in 
Billings (ExxonMobil and Montana Power) are the only instances in the 
United States where variable emission limits based on buoyancy flux 
have been adopted, approved, and implemented. The thousands of other 
emission limitations nationwide are based on a single fixed buoyancy 
flux value similar to what we proposed for MSCC.
    (b) Comment (MSCC): Complicated to Model. (i) MSCC agrees that it 
is more complicated to model a variable emission rate than a fixed 
emission rate. That alone is not sufficient reason to deny MSCC the 
variable emission rate. Also, much has changed since the original 
modeling effort. Computer speed, memory, data handling, and storage are 
all improved.
    Response: Modeling was one of the reasons we offered for not 
providing a variable emission limit; however, it was not the only 
reason. Although computer speed, data handling, and storage are 
improved since the MDEQ developed the Billings/Laurel SO2 
SIP, there would still be a considerable effort on EPA's part to model 
a variable emission limit for the SRU 100-meter stack. Therefore, we 
used EPA's historical practice of selecting mean values of historical 
data.
    Individual stationary sources in SIP attainment demonstrations are 
typically modeled assuming a single representative value for the model 
input parameters that affect plume rise. Model input parameters that 
affect plume rise include stack gas temperature and volume flow, or 
buoyancy flux. If emissions are held constant, ground level 
concentrations would tend to decrease during periods with higher plume 
rise associated with elevated stack gas temperature and increased stack 
flow velocities. Conversely, ground level concentrations would tend to 
increase during periods with reduced stack gas temperatures and stack 
flow velocities. The State opted to set emission limitations based on 
variable buoyancy flux values for three of the sources. MDEQ identified 
a total of 11 buoyancy flux modeling scenarios for MSCC, 12 for 
ExxonMobil, and 10 for the Corette Power Plant. Modeling all possible 
combinations of scenarios required the State to model a total of 1,320 
combinations for each year of meteorological data processed. EPA used a 
fixed buoyancy flux value for modeling MSCC and that reduced the number 
of potential modeling scenarios to 120. EPA reviewed the modeling 
results in the State's attainment modeling to identify which scenarios 
(of the 120 possible scenarios) would produce the highest 
concentrations. Based on this selection process, EPA modeled 
approximately 50 scenarios in the FIP modeling, and we believe that 
these scenarios represent the limiting

[[Page 21445]]

(i.e. maximum predicted concentration) case.
    (ii) It is completely arbitrary to create, model, approve, monitor, 
and enforce variable limits at other Billings facilities but to deny 
the same courtesy for MSCC claiming that it is, in this case alone, too 
complicated a modeling effort.
    Response: Again, modeling was not the sole reason for not providing 
a variable emission limit for MSCC's SRU 100-meter stack. Although EPA 
approved the variable emission limits at other Billings facilities, we 
did so with reservations. (See our July 28, 1999, proposed rulemaking 
action on the Billings/Laurel SO2 SIP, 64 FR 40791, starting 
at 40794, col. 3, and our May 2, 2002, final rulemaking action, 67 FR 
22168, starting at 22206, col. 2, for a full discussion of our concerns 
with the variable emission limit concept.) Since EPA is taking the lead 
in establishing emission limits for MSCC's SRU 100-meter stack and will 
take the lead in enforcing the FIP, EPA has chosen not to model and 
provide a variable emission limit. We believe our exercise of 
discretion so as to simplify FIP development and enforcement is 
reasonable, particularly where the data indicate MSCC will be able to 
comply with a fixed emission limit without additional controls and 
where fixed limits are the norm in SIPs throughout the country.
    (c) Comment (MSCC): Complicated to Monitor. Buoyancy flux has been 
measured and reported to DEQ for a period of about eight years, with 
very high reliability. It is simply illogical to argue or imply that 
monitoring buoyancy flux is a task not worthy or too complicated in 
nature. One cannot deny the historical evidence that it has been 
measured successfully for many years and that it does not require any 
monitor instrumentation not already required to measure sulfur dioxide.
    Response: See response to comment II.G.1.(b)(ii), above.
    (d) Comment (MSCC): Complicated to Enforce. EPA's reason for not 
proposing a variable limit for MSCC due to enforcement is puzzling. If 
EPA approved variable emission limits for other sources, even though 
the same enforcement concern exists, it should also be approved for 
MSCC.
    Response: The State developed the original SIP that allows variable 
emissions for several sources. The State takes the lead in enforcing 
the SIP, and EPA takes an oversight role. EPA approved portions of the 
SIP, including variable emission limits at two sources, and we did so 
with reservations. Since we would be taking the lead in enforcing the 
FIP, we have chosen not to place an increased burden on ourselves to 
enforce a variable limit. See also the response to comment II.G.1.(e), 
below.
    (e) Comment (MSCC): Variable Limit is Better Science. Though it 
involves incremental initial work, from a modeling perspective, the use 
of variable limits is better science. It replaces a false assumption in 
modeling (constant, average stack conditions under all operating 
scenarios) with factual information so that plume height, which is 
variable, can be more accurately represented. Plume height, just like 
mass emissions, is normally variable and is critical to calculation of 
downwind concentrations.
    Response: In addition to looking at air quality impacts of the FIP, 
we also need to assure that the FIP is enforceable. Although we may 
agree with the commenter that the variable emission limitation will 
result in fewer emissions when the buoyancy of the plume is lower, it 
will also result in higher emissions when the buoyancy of the plume is 
higher. Additionally, a variable emission limit is more difficult to 
enforce. Granted the same instruments would be used to determine 
compliance whether the emission limit is fixed or variable. However, in 
addition to confirming that the source is in compliance with a variable 
emission limit, agencies will also need to confirm that the variable 
emission limitation was determined correctly. Therefore, we believe 
that variable emission limits increase the workload and add a layer of 
complexity that is not found with fixed emission limitations. Because 
of this enforcement complexity, we do not agree with the commenter that 
variable emission limitations are a superior approach to setting 
emission limitations.
    (f) Comment (MSCC): Fixed Limit Compliance. Although MSCC has been 
able to meet the proposed FIP limit for several years, it must be noted 
that MSCC has not always been able to operate within such limits, and 
that MSCC was not operating its sulfur plant at maximum capacity during 
the time periods cited by EPA. The primary reason MSCC can operate 
under EPA's proposed limit arises from MSCC's voluntary installation of 
SuperClaus TM. The SuperClaus unit must be shut down 
periodically for repair. MSCC needs the variable limit to be in 
compliance when SuperClaus unit is shut down. MSCC should not be 
punished for its good behavior by requiring control technology and 
lower emissions than is necessary to maintain NAAQS.
    Response: EPA's proposed FIP limit for MSCC's SRU 100-meter stack 
was determined through modeling as the limit needed to assure 
attainment of the SO2 NAAQS. Since the NAAQS are health-
based standards, as a general matter, SIPs/FIPs must assure attainment 
of the NAAQS on a continuous basis.
    We note that apparently MSCC was able to conduct maintenance on the 
SuperClaus unit in 2003, 2004, and 2005 without exceeding the proposed 
3-hour and 24-hour FIP SRU 100-meter limits. MSCC may be able to 
perform its maintenance on the SuperClaus unit when other process 
equipment at ExxonMobil is down for maintenance. Additionally, we 
understand that MSCC intends to install a second SuperClaus unit to 
provide redundancy to the existing SuperClaus equipment. Installation 
is expected to begin in the fourth quarter 2007, at the earliest 
(reference documents GGGGGG and BBBBBBB). Concerns about additional 
emissions during maintenance should be eliminated with the addition of 
a second SuperClaus unit.
2. 100-Meter Stack Height Credit and Emission Limit
    (a) Comment: MSCC submitted summary comments regarding its position 
concerning good engineering practice stack height credit for the 100-
meter SRU stack. MSCC noted that these comments had generally been 
submitted previously to both EPA and Montana. MSCC claimed that it has 
not received the proper stack height credit for the 100-meter SRU stack 
in the proposed FIP.
    Response: EPA disapproved the State's determination of stack height 
credit for MSCC's 100-meter SRU stack on May 2, 2002 (67 FR 22168). In 
the May 2, 2002, notice, starting on page 22209, we responded to all 
the stack height comments MSCC previously submitted. We hereby 
incorporate by reference our responses from that notice. We indicated 
in the May 2, 2002, notice that ``[w]e considered the comments received 
and still believe we should finalize our proposed disapproval of the 
MSCC's stack height credit and SRU 100-meter stack emission 
limitations. None of the adverse comments has convinced us that our 
interpretation of the CAA and our regulations is unreasonable or that 
we should change our proposed course of action.'' See our May 2002 
final action (67 FR 22168). EPA has determined that the GEP stack 
height credit for the 100-meter SRU stack is 65 meters and has used 
that height in establishing the 100-meter SRU stack emission limit. Our 
stack height regulations, codified at 40 CFR 51.100

[[Page 21446]]

and 51.118, provide that the degree of emission limitation required for 
pollutant control under an applicable SIP shall not be affected by 
stack height in excess of GEP stack height. The central component of 
the regulations consists of definitions of the term ``good engineering 
practice stack height.'' GEP stack height is the greater of (1) 65 
meters (known as ``de minimis'' stack height), (2) the height 
calculated using a formula specified by regulations (``formula 
height''), or (3) the height demonstrated using fluid modeling or a 
field study (``non-formula height'' or ``above-formula height''). See 
40 CFR 51.100(ii)(1)-(3). Prior to our SIP action, the State calculated 
the formula height for the SRU 100-meter stack to be 47.8 meters (see 
reference documents VVVVVV and WWWWWW). Per our regulations, since this 
is lower than 65 meters, GEP stack height is 65 meters. We have not 
received any new information to indicate formula height should be 
higher than 47.8 meters, nor have we received a valid demonstration for 
above-formula stack height credit. See our proposed and final actions 
on the Billings/Laurel SO2 SIP, 64 FR 40791 (July 28, 1999) 
and 67 FR 22168 (May 2, 2002), respectively. In light of our prior 
decision on the fluid modeling in the SIP action, and in the absence of 
a new, valid, GEP stack height demonstration, it would be inappropriate 
in this FIP for us to use a stack height value for MSCC that is 
inconsistent with our prior action.
    (b) Comment (YVAS): YVAS believes the annual emission limit of 
9,088,000 lbs of sulphur is too excessive because YVAS believes this 
``proposed'' emission to be a major contribution to the total emissions 
of sulphur dioxide in the Billings/Laurel area and is, therefore, not 
acceptable. In addition, EPA states that: ``We (EPA) are proposing 
fixed emission limits rather than variable emission limits on MSCC's 
SRU 100 meter stack because they are less complicated to model monitor 
and enforce.'' This proposal is inadequate and does not address the 
continuing high total SO2 emission limits you intend 
permitting MSCC to continue to release.
    Response: Stack emission limits are set to assure that the 
SO2 NAAQS are met. As seen in the SIP and FIP, there are 3-
hour, 24-hour, and annual SO2 emission limits on most 
stacks. These emission limits assure that the 3-hour, 24-hour, and 
annual SO2 NAAQS are attained and maintained. As indicated 
in the response to comment II.F.8., above, we cannot require states to 
adopt provisions that go beyond attaining and maintaining the NAAQS. 
The annual emission limit we proposed for the SRU 100-meter stack, and 
that we are now promulgating in the FIP, assures that the annual 
SO2 NAAQS will be attained and maintained. Additionally, the 
3-hour and 24-hour SO2 NAAQS are more controlling than the 
annual SO2 NAAQS. This means that more stringent emission 
limits must be placed on stacks to assure that the 3-hour and 24-hour 
SO2 NAAQS are attained and maintained than would be required 
to assure that the annual SO2 NAAQS are met.
    (c) Comment (Citizen): Commenter appreciates the logic of not 
allowing increases in stack height credit.
    Response: We acknowledge the support for our proposal. Also, please 
see our response to comment II.G.2.(a), above.
3. 30-Meter Stack and Auxiliary Vent Stack
    (a) Comment (MSCC): Emissions monitoring for 30-meter Stack and 
Auxiliary Vent Stacks. EPA has proposed unnecessarily complex, 
redundant, and unneeded monitoring and reporting requirements for both 
the 30-meter stack and the auxiliary vent stacks. The emissions from 
these units have minimal impact on model results. These predicted 
concentrations are less than 1% of the NAAQS. The emission limit 
applicable is miniscule in comparison with other uncertainties in the 
implementation plan. Emissions from these units, although authorized, 
are infrequent. Venting to the boiler stack is generally associated 
with events such as maintenance. For operational reliability and 
flexibility, MSCC needs to be able to vent these boilers locally. 
Monitoring these units is an expense and requirement that serves no 
real or useful purpose. Essentially the same information is already 
gathered under the State plan.
    Response: As we indicated in our July 12, 2006, proposed FIP (71 FR 
39259, 39268), it is necessary for EPA to require methods to assure 
that the emission limits for the 30-meter stack and auxiliary vent 
stacks are met. However, since MSCC has already established a method to 
monitor these emissions using length-of-stain detector tubes (e.g., 
Dr[auml]ger Tubes),\13\ and since length-of-stain detector tubes are 
widely-used and reliable, we have revised the FIP to make its 
requirements similar to those MSCC must already meet under the State's 
operating permit. Specifically, we have revised the method by which 
MSCC shall determine the H2S content of the fuel burned. Our 
final FIP indicates that on a once-per-3-hour period frequency until no 
heater or boiler is exhausting to the 30-meter stack or an auxiliary 
vent stack, MSCC shall determine the H2S content of the fuel 
burned using length-of-stain detector tubes with the appropriate sample 
tube range pursuant to ASTM Method D4810-06, ``Standard Test Method for 
Hydrogen Sulfide in Natural Gas Using Length-of-Stain Detector Tubes'' 
(see reference document UUUUUU). 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.
---------------------------------------------------------------------------

    \13\ See MSCC's ``Hydrogen Sulfide Fuel Gas Monitoring Plan,'' 
dated September 2000, that fulfilled requirements of Montana Air 
Quality Operating Permit 2611-00, Appendix H. (See reference 
document IIIIII.)
---------------------------------------------------------------------------

    (b) Comment (MSCC): Emission Limit--100 ppm H2S--A Redundant Limit. 
Having both a 12 lb/3-hour limit and 100 ppm H2S limit creates double-
jeopardy. Both limits are for solely and exactly the same thing. If a 
particular 3-hour period were to indicate 120 ppm, it would be in 
violation of both limits. This could (and is very likely to) occur even 
if the units were not, in fact, operating anywhere near an actual 
emission rate of 12 lbs/3-hours. This result is overkill and is not 
appropriate or necessary for protection of the NAAQS.
    Response: In our FIP proposal, we were attempting to simplify the 
method to determine compliance with the mass emission limits. The 
assumption in the proposal was that if the H2S concentration 
was below 100 ppm H2S, then the source would be in 
compliance with the mass emission limits. We were not trying to create 
``double jeopardy'' for MSCC. It appears that the commenter believes 
the 100 ppm H2S limit is too restrictive because the source 
could be in compliance with the mass emission limit but out of 
compliance with the ppm limit.
    In our final FIP we are keeping the simplified method to determine 
compliance with the mass emission limits. We believe determining direct 
compliance with the mass emission limits would either require 
additional monitoring equipment or methods and/or would be unreliable 
due to potential variation in boiler use and venting practices. 
However, to address the commenter's concern, we are increasing the 
H2S concentration limit to 160 ppm per 3-hour period. We are 
adding a calendar day H2S concentration limit of 100 ppm.
    We selected the 160 ppm H2S per 3-hour period limit for 
the following reasons. First, as explained in greater detail below, 
this value will protect the 3-hour SO2 NAAQS. Second, 160 
ppm

[[Page 21447]]

of H2S per 3-hour period is the current NSPS limit for fuel 
gas combustion devices. EPA reported the following in its May 14, 2007, 
proposal to revise subpart J of the new source performance standards 
(NSPS), and to adopt new subpart Ja:

after consideration of current operating practices, we concluded 
that amine scrubbing units are still the predominant technology for 
reduction of H2S in fuel gas (and SO2 
emissions from subsequent fuel gas combustion). Considering the 
variability of the fuel gas streams from various refinery processing 
units, 160 ppmv also is still a realistic short term H2S 
concentration limit. However, one California Air Quality Management 
District rule sets a 40 ppmv H2S limit in fuel gas 
(averaged over 4 hours), and several refiners have reported that the 
typical fuel gas H2S concentrations (after scrubbing) are 
in the same range.

(See 72 FR 27178, 27193.) Third, the State's SIP indicates that MSCC 
shall burn only low sulfur fuel gas or natural gas in any unit being 
exhausted through the 30-meter stack (see MSCC's exhibit A, reference 
document II). Low sulfur fuel gas is not defined in exhibit A. However, 
an MDEQ staff member indicated that the term ``low sulfur fuel gas'' in 
the SIP would be gas with an H2S concentration much lower 
than the NSPS subpart J limit of 160 ppm (see reference document 
GGGGGG). This suggests that MSCC should already be achieving a daily 
limit of 100 ppm.
    To test the use of a 160 ppm limit, 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 three 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 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 mass emission limits remain the same as proposed. The 
revised modeling files are indexed in the electronic docket contained 
on http://www.regulations.gov, and a compact disk containing the 
modeling files has been placed in the docket for this action. See 
reference document KKKKKK.
    (c) Comment (MSCC): Emission Limit--100 ppm H2S--Overly 
Stringent. The 100 ppm H2S limit, which is a surrogate for 
the pound/hour SO2 limit, is far too restrictive. EPA 
developed the 100 ppm H2S limit based on conditions that 
have a miniscule probability of occurring. It has the effect of 
introducing a new, strict ``performance standard'' into the mix of 
limits, where such standard is not applicable.
    Response: See response to II.G.3.(b), above. Also, in order to 
protect the NAAQS, it is reasonable to consider potential worst-case 
conditions in setting emission limits and compliance determining 
methods.
    (d) Comment (MSCC): Monitoring Requirements. The requirement to 
monitor the auxiliary vent stacks has already been addressed through 
the State plan; there is no inadequacy or other basis to FIP this. The 
current system already periodically measures the H2S content 
in the fuel gas header for gas that is not natural gas, using a simple 
portable detector (non-electronic) such as a Dr[auml]ger tube or Gas-
Tec tube. The frequency of testing necessity was determined through the 
State's plan and the frequency of such testing steps up in response to 
high measurements until the measurements have returned to low levels. 
The present plan also reasonably estimates the volume of gas used in 
each boiler to permit calculation of the SO2 emitted by each 
auxiliary vent when in use, and logs the venting location, as the State 
plan provides.
    Response: In large part, this comment appears to pertain to our 
disapproval of the relevant portion of the SIP. We note that we have 
not reopened our SIP action as part of this action and are not 
considering comments on that action here. To the extent the comment is 
relevant to our FIP action, see response to comment II.G.3.(b), above. 
As we explain there, the FIP retains the requirement that MSCC measure 
the H2S content of the fuel burned but increases the 3-hour 
concentration limit to 160 ppm. The FIP also allows MSCC to use length-
of-stain detector tubes in lieu of portable analyzers. However, based 
on comments received, we are not convinced that MSCC's current methods 
for determining direct compliance with the mass emission limits are 
sufficiently reliable or accurate for purposes of the FIP due to 
potential variation in boiler use and venting practices and lack of 
equipment to directly measure relevant parameters at or emissions from 
each boiler. We believe additional monitoring equipment would need to 
be installed, or additional monitoring would need to be performed, at 
greater expense to MSCC, to achieve adequate methods to determine 
direct compliance with the mass emission limits. The concentration 
limits we are imposing are reasonable, can be monitored at reasonable 
cost, and will ensure protection of the NAAQS.
    (e) Comment (MSCC): Monitoring Cost. EPA proposes imposing 
significant overly burdensome on-going costs to track a minuscule 
amount of potential or actual SO2 emissions.
    Response: As we indicate in response to comment II.G.3.(a), we have 
revised the FIP to allow MSCC to use the same devices to determine 
H2S concentrations in the gas going to the 30-meter stack 
and auxiliary vent stacks as MSCC is using to meet State requirements 
(length-of-stain detector tubes). While the frequency of monitoring may 
be somewhat different than the frequency under the State's permit, the 
final FIP should not result in any substantial additional monitoring 
costs for the 30-meter stack and the auxiliary vent stacks, 
particularly since MSCC indicates emissions from these stacks are 
infrequent.

H. ConocoPhillips Specific Issues

SRU/ATS Stack and Jupiter Flare
    Comment (COPC): ConocoPhillips urges EPA to delete the proposed 
prohibition of simultaneous emissions from the SRU/ATS stack and the 
Jupiter flare even if the combined SO2 emissions are less 
than 25 lb/hr. This merely imposes a compliance risk and produces no 
environmental benefit. Logic does not dictate that because both sources 
were modeled as one point, that combined, simultaneous emissions from 
both are prohibited. Quite the contrary, having modeled both sources as 
one point supports and endorses the option of both sources being able 
to emit a combined total of the amount of SO2 which was 
modeled.
    Response: EPA agrees that it is not necessary to prohibit 
simultaneous emissions from both emission points. Attainment of the 
SO2 NAAQS would be assured so long as the combined emissions 
from both emission points do not exceed 75.0 pounds per 3-hour period. 
Since both emission points have methods for determining emissions, 
compliance with the emission limit would be assured. We are revising 
the regulatory text to eliminate the restriction on simultaneous 
emissions and any corresponding language. Additionally, in the final 
regulatory text we are clarifying the reporting

[[Page 21448]]

requirements to correspond to this change.

I. ExxonMobil Specific Issues

1. Coker CO Boiler
    Comment (ExxonMobil): The proposed FIP would require that the Coker 
CO Boiler stack CEMS operate at all times. This is unnecessary because 
the Coker Process gas is exhausted through the nearby Yellowstone 
Energy Limited Partnership Co-Generation facility. During those hours, 
Coker CO Boiler stack SO2 emissions are monitored by the 
existing fuel gas CEM for fuel gas combustion devices. The existing 
SO2 SIP requires that a SO2 CEMS be operated on 
the Coker CO Boiler stack during those few hours that the Coker Process 
Gas is exhausted through the Coker CO Boiler and stack. Given that a 
CEMS is already required for this source, nothing is served by 
requiring ExxonMobil to report the emissions and compliance assurance 
data for this source to both EPA and MDEQ. Nothing is served by 
requiring ExxonMobil to notify both EPA and MDEQ of required Relative 
Accuracy Test Audits (RATA).
    Response: It was not EPA's intent to require that the Coker CO 
Boiler stack CEMS be operated at all times. Our intent was to clarify 
that the Coker CO Boiler CEMS already installed, in conjunction with 
the appropriate equations, must be used to determine compliance with 
the emission limits established in section 3(B)(1) of ExxonMobil's 2000 
exhibit.
    We are clarifying the FIP to indicate that the Coker CO Boiler CEMS 
only needs to be operating when ExxonMobil's Coker unit is operating 
and Coker unit flue gases are exhausted through the Coker CO Boiler 
stack. We are also clarifying that whenever ExxonMobil's Coker unit is 
operating and Coker unit flue gases are exhausted through the Coker CO 
Boiler stack, the CEMS shall immediately be operational. Also, with 
respect to the SO2 CEMS, we indicate 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 8 
hours of when the Coker unit flue gases begin exhausting through the 
Coker CO Boiler stack. Finally, for both the SO2 and flow 
CEMS, we indicate that ExxonMobil shall perform an annual RATA, on the 
CEMS.
    Because we will have primary responsibility to enforce the FIP, we 
have retained the requirements that ExxonMobil submit emissions and 
compliance assurance data to both EPA and MDEQ and notify EPA and MDEQ 
of RATAs.
2. Tutwiler Analysis
    Comment (ExxonMobil): The proposed FIP would require that 
ExxonMobil measure the H2S concentration of the fuel gas 
once every three hours using the Tutwiler method contained in 40 CFR 
60.648 any time the refinery fuel gas H2S CEMS measures a 
concentration of greater than 1200 ppmv. The proposed once per 3-hour 
Tutwiler analysis is less protective than the existing requirement 
identified in the alternative monitoring plan (AMP) submitted to DEQ. 
The AMP requires measurement of the fuel gas H2S 
concentration with Dr[auml]ger tubes on an hourly basis anytime the 
fuel gas H2S CEMS data are expected to be unavailable for 
any reason for more than one 3-hour block.
    Response: In our proposed FIP, EPA proposed a method for 
determining H2S concentrations when the range of the 
H2S CEMS is exceeded. ExxonMobil commented that they 
currently use another method for determining H2S 
concentrations when the H2S CEMS is not available. This 
other method has been identified in an AMP submitted to DEQ (reference 
document JJJJJJ). Since ExxonMobil already has procedures established 
for determining H2S concentrations when the H2S 
CEMS is not available, namely, the use of Dr[auml]ger Tubes, a type of 
length-of-stain detector tube, and since length-of-stain detector tubes 
are widely-used and reliable, EPA is revising its FIP to incorporate 
the other method identified by ExxonMobil.
    Specifically, we are revising the FIP to indicate that when the 
H2S concentration in the refinery fuel gas exceeds 1200 ppmv 
as measured by the H2S CEMS, ExxonMobil shall measure the 
H2S concentration on an hourly basis 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.'' The length-of-stain detector tubes shall have 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. 
The hourly length-of-stain detector tubes data will then be used to 
calculate SO2 emissions from refinery fuel gas combustion 
and to determine compliance with the emission limits in 40 CFR 
52.1392(f)(3)(i).
3. ExxonMobil Emissions
    Comment (YVAS): The question must be asked that since ExxonMobil's 
emissions are appreciably higher than its two closest competitors, that 
a significant lowering in total SO2 emissions in the 
Yellowstone Valley could be attained if ExxonMobil would be required to 
use that equipment under either Federal EPA standards or under the 
State of Montana emissions requirements as well. That there is no 
requirement to insist that ExxonMobil use equipment/refining processes 
that would lower its future SO2 emissions is a deplorable 
lack of public concern to YVAS' best interests and should be publicly 
examined by the EPA.
    Response: EPA acknowledges this comment. See response to comment 
II.F.8., above.

J. CHS Inc. Specific Issues

Particulate Issues
    Comment (YVAS): YVAS is concerned that the Coker production unit at 
CHS Inc. will not have to provide a containment system shielding the 
nearby area from the effects of particulate pollution. This is a 
deplorable lack of proper protection of the public and, although 
addressing this particular issue was apparently not important to this 
FIP, since it was completely omitted from this FIP, either through 
oversight or deliberate omission, YVAS seeks a ruling from the EPA that 
could require CHS, Inc. to address this issue and provide relief to the 
public from this oversight.
    Response: EPA acknowledges the comment. However, the FIP addresses 
only the provisions of the SO2 SIP that we disapproved. 
Under CAA section 110(c), EPA's authority is to remedy the deficiencies 
we identified in the SO2 SIP.

III. Summary of the Final Rules and Changes From the July 12, 2006, 
Proposal

    The following summarizes the final FIP and the major changes from 
our July 12, 2006, FIP proposal. Generally, the reasons for the changes 
made in the final FIP appear in section II, above, ``Issues Raised by 
Commenters and EPA's Response.'' In some cases, the reasons appear 
below. We also describe some minor changes to the FIP in this section.

A. Flare Requirements Applicable to All Sources

    Since the State's attainment demonstration assumed that the main 
flares at each source were limited to 150 pounds of SO2 per 
3-hour period, and that the Jupiter Sulfur SRU flare would share an 
emission limit of 75 pounds of SO2 per 3-hour period with 
the Jupiter

[[Page 21449]]

Sulfur SRU/ATS \14\ stack, we proposed flare emission limits that 
reflected the State's assumption that emissions from these points would 
not exceed these levels. While we proposed that 150 pounds of 
SO2 per 3-hour period be the limit for the main flares, we 
also solicited input on whether we should instead limit the main flares 
to 500 pounds of SO2 per calendar day. The final FIP 
requires that the main flares at each source be limited to 150 pounds 
of SO2 per 3-hour period and that the Jupiter Sulfur flare 
share an emission limit of 75 pounds of SO2 per 3-hour 
period with the Jupiter Sulfur SRU/ATS stack.
---------------------------------------------------------------------------

    \14\ ATS stands for Ammonium Thiosulfate.
---------------------------------------------------------------------------

    We also proposed that the flare limits would apply at all times 
without exception. We also solicited comment on whether it would be 
appropriate to include in our final FIP the ability to assert an 
affirmative defense to penalties only (not injunctive relief) for 
violations of the flare limits. Under the final FIP, flare limits apply 
at all times. However, we have changed the proposed rule to provide the 
ability for sources to assert an affirmative defense to penalties only 
(not injunctive relief) for violations of the flare limits. The 
affirmative defense provision includes notification requirements that 
are distinct from the FIP's quarterly reporting requirements.
    We proposed that compliance with the flare emission limits would be 
determined by continuous measurement of the total sulfur concentration 
and volumetric flow rate of the gas stream to the flare(s), followed by 
calculation, using appropriate equations, of SO2 emitted per 
3-hour period.
    We proposed that sources install, calibrate, maintain, and operate 
a continuous flow monitoring system capable of measuring the total 
volumetric flow of the gas stream combusted in a flare in accordance 
with the specifications described below. We indicated that the flow 
monitoring system could require one or more flow monitoring devices or 
flow measurements at one or more header locations if one monitor could 
not measure all of the volumetric flow to a flare.
    We proposed the following volumetric flow monitoring 
specifications:
    (1) The minimum detectible velocity of the flow monitoring 
device(s) would be 0.1 feet per second (fps);
    (2) The device(s) would 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% over the range of 
1 to 275 fps;
    (3) For correcting flow rate to standard conditions (defined as 
68[deg]F and 760 millimeters of mercury (mmHg)), temperature and 
pressure would be monitored continuously;
    (4) The temperature and pressure would be monitored in the same 
location as the flow monitoring device(s) and be calibrated to meet 
accuracy specifications as follows: Temperature would be calibrated 
annually to within  2.0% at absolute temperature and the 
pressure monitor would be calibrated annually to within  
5.0 mmHg;
    (5) Flow monitoring device(s) would be calibrated prior to 
installation to demonstrate accuracy to within 5.0% at flow rates 
equivalent to 30%, 60%, and 90% of monitor full scale; and
    (6) After installation, the flow monitoring devices would be 
calibrated annually according to manufacturer's specifications.
    The final FIP flow monitoring provisions are the same as proposed 
except that we are revising the following provisions:
    (1) With respect to the accuracy of the flow monitor, the final FIP 
indicates that the 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 to 275 fps and  20% of the 
measured flow over the range of 0.1 to 1.0 fps.
    (2) With respect to measurement of volumetric flow rate, the final 
FIP indicates that volumetric flow rate shall be measured on an actual 
wet basis and converted to standard conditions, and reported in SCFH.
    (3) With respect to temperature and pressure monitors, the final 
FIP indicates that temperature and pressure monitors should be 
calibrated prior to installation according to manufacturer's 
specifications. We inadvertently omitted this requirement in our 
proposal.
    We proposed that in cases where the flow to the flare exceeds the 
range of the monitor, other methods could be used to determine the 
volumetric flow rate. In the final FIP, we have clarified this 
provision to read that in cases when the volumetric flow monitor is not 
working or where the flow exceeds the range of the monitor, methods 
established in the flare monitoring plan required by the FIP shall be 
used to determine the volumetric flow rate to the flare, which shall 
then be used to calculate SO2 emissions. Additionally, we 
have revised the quarterly reporting requirements to be consistent with 
these changes. The final FIP now indicates that in quarterly reports, 
sources shall indicate the date and time when a monitor is not working 
or the range is exceeded, and the other methods used to determine flare 
emissions. We have made these revisions to the final FIP so that these 
provisions are consistent with what we require in the flare monitoring 
plan.
    The final FIP also adds the ability for sources to use means other 
than the flow monitor to determine that the flare is not operating when 
the flow monitor registers low flow. Specifically, the final FIP allows 
sources to use devices that monitor the integrity of the flare water 
seal. If these devices indicate that no flow is going to the flare, yet 
the flow monitor indicates there is flow, the presumption will be that 
no flow is going to the flare. We have also revised the flare 
monitoring plan and reporting requirements to recognize the use of, and 
require reporting on, these other flare flow devices.
    We proposed that sources install, calibrate, maintain, and operate 
an on-line analyzer system capable of continuously determining the 
total sulfur concentration of the gas stream sent to a flare. We 
proposed that the continuous monitoring occur at a location or 
locations that are representative of the gas combusted in the flare and 
be capable of measuring the expected range of total sulfur in the gas 
stream to the flare. We proposed that the total sulfur analyzer 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. 
Additionally, we proposed that sources notify EPA in writing of each 
Relative Accuracy Test Audit (RATA) a minimum of 25 working days prior 
to the actual testing. In the final FIP, we are retaining the above 
provisions, but are allowing the use of other methods to determine 
total sulfur concentration. See discussion below. The final FIP also 
clarifies that the total sulfur concentration monitor should measure in 
the range of concentrations that are normally present in the gas stream 
to the flare.
    In the final FIP, we are adding provisions that indicate that, in 
cases when the total sulfur analyzer is not working or where the 
concentration of the total sulfur exceeds the range of the monitor, 
methods established in the flare monitoring plan required by the FIP 
shall be used to determine the total sulfur concentrations, which shall 
than

[[Page 21450]]

be used to calculate SO2 emissions. Additionally, the final 
FIP indicates that in quarterly reports, sources shall indicate the 
date and time when a monitor is not working, or the range is exceeded, 
and the other methods used to determine flare emissions. We have made 
this addition to the FIP so that these provisions are consistent with 
what we require in the flare monitoring plan.
    In lieu of continuous total sulfur concentration analyzers, the 
final FIP allows sources to determine the total sulfur concentration 
through grab or integrated sampling. If a source chooses to use one of 
these methods, the final FIP provides a trigger by which sources must 
begin the sampling and indicates the analytical methods to be used to 
determine the total sulfur concentration in the sample. The final FIP 
also provides that in cases where a grab or integrated sample is not 
obtained or analyzed, methods established in the flare monitoring plan 
required by the FIP shall be used to determine total sulfur 
concentrations, which will then be used to calculate SO2 
emissions. The flare monitoring plan and reporting requirements have 
also been revised to recognize the potential use of grab or integrated 
sampling.
    We proposed that within 180 days after receiving EPA approval of 
the flare monitoring plan, sources install and calibrate, and 
thereafter calibrate, maintain, and operate continuous flow monitors 
and total sulfur concentration analyzers. The final FIP has been 
revised to allow sources 365 days after receiving EPA approval of the 
flare monitoring plan to install and calibrate, and thereafter 
calibrate, maintain, and operate the continuous volumetric flow 
monitors and to start determining total sulfur concentrations of the 
gas stream by either continuous total sulfur concentration analyzers or 
grab or integrated sampling monitoring.
    We proposed that each facility submit a flare monitoring plan 
including, among other things, information regarding pilot and purge 
gas at each flare and how the concentration and volumetric flow 
monitors would analyze the pilot and purge gases. The final FIP 
indicates that if the facility certifies that only natural gas or an 
inert gas is used as pilot and/or purge gas, monitoring the stream(s) 
consisting of only natural gas or inert gas is not required. However, 
if natural gas or inert gas is not used for pilot and/or purge gas, 
then the source must measure the flow and H2S concentration 
of the gas streams that do not consist of only natural gas or inert gas 
or use other methods approved by EPA in the flare monitoring plan to 
estimate flow and H2S concentration. Pilot and purge gas 
SO2 emissions will then be calculated and added to the other 
SO2 emissions from the flare to determine compliance with 
the SO2 flare emission limits. We have revised the reporting 
requirements accordingly to require sources to either: (1) Certify in 
the quarterly reports if pilot and/or purge gas is not monitored 
because only natural gas or inert gas is used as the pilot and/or purge 
gas; or (2) report flow, H2S concentration of, and 
SO2 emissions from, the pilot and/or purge gas.
    We also added provisions that indicate that in cases when any pilot 
or purge gas flow monitor or H2S analyzer is not working, or 
where the flow or concentration of the H2S exceeds the range 
of the monitor or analyzer, methods established in the flare monitoring 
plan required by the FIP shall be used to determine the pilot and purge 
gas flow and/or H2S concentrations, which shall then be used 
to calculate SO2 emissions. The FIP indicates that in 
quarterly reports, sources shall indicate the date and time when a 
monitor or analyzer is not working, or the range is exceeded, and the 
other methods used to determine flare emissions.
    The flare monitoring plan requirements have been revised to be 
consistent with the pilot and purge gas provisions described above.
    We have added definitions of Aliquot, Integrated sampling, Pilot 
gas, and Purge gas to clarify the FIP's flare monitoring requirements. 
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). We added to the reporting 
requirements as necessary to address the changes to other requirements.

B. CHS Inc.

1. Flare Requirements
    We proposed that CHS Inc.'s flare be limited to 150 pounds of 
SO2 per 3-hour period and that compliance with the limit be 
determined as discussed above. The final FIP is the same as proposed 
except for the flare monitoring changes applicable to all sources 
mentioned above.
2. Combustion Sources Emission Limits
    We proposed a prohibition in the FIP on the burning of SWS 
overheads in the main crude heater. We proposed that compliance with 
the prohibition to not burn SWS overheads in the main crude heater be 
determined by CHS Inc. installing a chain and lock on the valve that 
supplies sour water stripper overheads from the ``old'' SWS to the main 
crude heater to insure that the valve could not be opened. The proposed 
FIP also required CHS Inc. to maintain the chain and lock in place, 
keep the valve closed at all times, and log and report any 
noncompliance with this provision. The final FIP is the same as 
proposed.

C. ConocoPhillips

Flare Requirements
    We proposed that ConocoPhillips's main flare be limited to 150 
pounds of SO2 per 3-hour period and that compliance with the 
limit be determined as discussed above. We also proposed that at any 
one time, ConocoPhillips could only use either the north or south main 
flare. The final FIP is the same as proposed except for the flare 
monitoring changes applicable to all sources mentioned above.
    We proposed an emission limit of 75 pounds of SO2 per 3-
hour period for the Jupiter Sulfur SRU flare and SRU/ATS stack and that 
emissions could only be vented from the SRU flare when emissions were 
not being vented from the SRU/ATS stack. We proposed that compliance 
with the SRU flare emission limit, when Jupiter Sulfur vented emissions 
to the SRU flare rather than the SRU/ATS stack, be determined by 
measuring the total sulfur concentration and volumetric flow rate of 
the gas stream to the flare.\15\ Our final FIP is the same as proposed 
except that we have removed the restriction that emissions could only 
be vented from the SRU flare when emissions were not being vented from 
the SRU/ATS stack. Our final FIP indicates that compliance with the 
combined emission limit be determined by summing the emissions from the 
Jupiter Sulfur SRU flare and SRU/ATS stack.
---------------------------------------------------------------------------

    \15\ Note that the SRU/ATS stack has an SO2 CEMS and 
flow monitor to determine compliance when emissions are vented 
through that stack.
---------------------------------------------------------------------------

D. ExxonMobil

1. Flare Requirements
    We proposed that ExxonMobil's primary process and turnaround flares 
be limited to 150 pounds of SO2 per 3-hour period and that 
compliance with the limit be determined as discussed above. Our 
proposal indicated that we understood that the turnaround flare is only 
used about 30-40 days every 5 to 6 years and is not normally operating. 
Therefore, we proposed to establish one combined emission limit for the 
primary process and turnaround flares. Our

[[Page 21451]]

assumption was that the flow and concentration monitoring devices 
installed to measure the gas stream to the primary process flare would 
also be able to measure the gas stream to the turnaround flare. 
However, we indicated that if that was not the case, ExxonMobil could 
propose another method to determine emissions from the turnaround 
flare. The final FIP is the same as proposed except for the flare 
monitoring changes applicable to all sources mentioned above.
2. Compliance Monitoring of Refinery Fuel Gas Combustion Emission 
Limits
    We proposed a method for measuring the H2S 
concentrations in the refinery fuel gas when the H2S 
concentrations in the refinery fuel gas exceed the range of the 
H2S CEMS. The method we proposed is identical to the method 
included in CHS Inc.'s 1998 exhibit.\16\
    Specifically, we proposed that within four hours of the initial 
determination that the H2S concentrations in the refinery 
fuel gas stream exceed the upper range of the H2S CEMS, 
ExxonMobil would have to initiate sampling of the refinery fuel gas 
stream at the fuel header on a once-per-3-hour-period frequency using 
the Tutwiler method in 40 CFR 60.648. The Tutwiler method determines 
the H2S concentration in the refinery fuel gas. We also 
proposed that the Tutwiler-derived H2S refinery fuel gas 
concentration be used in calculations to determine the hourly, 3-hour, 
and 24-hour SO2 emission rates, in pounds, from refinery 
fuel gas combustion. These emission rates would then be used to 
determine compliance with the refinery fuel gas combustion emission 
limits in ExxonMobil's 1998 and 2000 exhibits when the H2S 
concentrations in the refinery fuel gas stream exceeded the upper range 
of the H2S CEMS.\17\
---------------------------------------------------------------------------

    \16\ See section 6(B)(3) of CHS Inc.'s 1998 exhibit. (See 
reference document DD for a copy of the exhibit.)
    \17\ See sections 3(A)(1) and 3(B)(2) of ExxonMobil's 1998 and 
2000 exhibits. (See reference documents GG and HH for copies of the 
exhibits.)
---------------------------------------------------------------------------

    In our final FIP we have revised the method by which ExxonMobil 
shall obtain the H2S concentration of the refinery fuel gas 
when the H2S concentrations in the refinery fuel gas exceed 
the range of the H2S CEMS. Specifically, our final FIP 
indicates that within four hours after the H2S CEMS measures 
an H2S concentration in the fuel gas stream greater than 
1200 ppmv, ExxonMobil shall initiate sampling of the fuel gas stream at 
the fuel header on a once-per-hour-period frequency using length-of-
stain detector tubes 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 
fuel gas stream equal to or less than 1200 ppmv continuously over a 3-
hour period. We also revised the equation used to calculate the 
SO2 emissions because of the change in the H2S 
analysis method.
    We proposed reporting requirements similar to the requirements 
adopted by the State for CHS Inc. and those contained in 40 CFR 
60.7(c). We added a provision that requires ExxonMobil to report 
information for periods when the range of the refinery fuel gas CEMS is 
exceeded.
3. Compliance Monitoring of Coker CO Boiler Emission Limits
    We proposed that existing SO2 and flow CEMS, in 
conjunction with the appropriate calculations mentioned below, be used 
to determine compliance with the emission limits established in section 
3(B)(1) of ExxonMobil's 2000 exhibit. Specifically, we proposed that at 
all times ExxonMobil operate and maintain CEMS to measure 
SO2 concentrations from the Coker CO Boiler stack and a 
continuous stack flow rate monitor to measure stack gas flow rates from 
the Coker CO Boiler stack. We proposed that the SO2 and flow 
rate CEMS meet the CEM Performance Specifications contained in sections 
6(C) and (D), respectively, of ExxonMobil's 1998 exhibit, except that 
ExxonMobil would have to notify EPA in writing of each annual RATA a 
minimum of 25 working days prior to actual testing.
    Our final FIP is the same as proposed except that we have deleted 
the requirement that the flow and SO2 CEMS be operated at 
all times and added the requirement that whenever ExxonMobil's Coker 
unit is operating and Coker unit flue gases are exhausted through the 
Coker CO Boiler stack, the flow and SO2 CEMS shall be 
immediately operational. We have also clarified that ExxonMobil shall 
meet the 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 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

[[Page 21452]]

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

[[Page 21453]]

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

[[Page 21454]]

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

[[Page 21455]]

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

[[Page 21456]]

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

[[Page 21457]]

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

[[Page 21458]]

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.

[[Page 21459]]

    (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

[[Page 21460]]

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:

[[Page 21461]]

    (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

[[Page 21462]]

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

[[Page 21463]]

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

[[Page 21464]]

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;

[[Page 21465]]

    (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 202-741-6030, 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 (610) 832-9585.
    (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