Document ID: EPA-R08-OAR-2006-0098-0001
Agency: epa
Document Type: Proposed Rule
Title: Federal Implementation Plan for the Billings/Laurel, Montana, Sulfur Dioxide Area
Posted Date: 2006-07-12T12:51:41Z

[Federal Register: July 12, 2006 (Volume 71, Number 133)]
[Proposed Rules]               
[Page 39259-39278]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12jy06-30]                         

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ENVIRONMENTAL PROTECTION AGENCY

[EPA-R08-OAR-2006-0098; FRL-8191-7]

40 CFR Part 52

RIN 2008-AA00

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

DATES: Comments: Comments on the proposal must be received on or before 
September 11, 2006.
    Public Hearing: If requested by July 26, 2006, EPA will hold a 
public hearing on August 10, 2006. If a public hearing is requested, 
EPA will hold the public hearing at the following time and location: 9 
a.m. to 2 p.m. at the Lewis and Clark Room, MSU--Billings, 1500 
University Drive, Billings, Montana. The purpose of such a hearing 
would be for EPA to receive comments and ask clarifying questions. The 
hearing would not be an opportunity for questioning of EPA officials or 
employees. Call the individual listed in the FOR FURTHER INFORMATION 
CONTACT if you would like to request a hearing, schedule time to speak 
at the hearing, or confirm whether a hearing will occur. If a hearing 
is held, speakers will be limited to 10 minutes. It would be helpful, 
but it is not required, if speakers bring a written copy of their 
comments to leave with us.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R08-
OAR-2006-0098, by one of the following methods:
     Http://http://www.regulations.gov. Follow the on-line 

instructions for submitting comments.
     E-mail: long.richard@epa.gov and ostrand.laurie@epa.gov.

     Fax: (303) 312-6064 (please alert the individual listed in 
the FOR FURTHER INFORMATION CONTACT if you are faxing comments).
     Mail: Richard R. Long, Director, Air and Radiation 
Program, Environmental Protection Agency (EPA), Region 8, Mailcode 8P-
AR, 999 18th Street, Suite 200, Denver, Colorado 80202-2466.
     Hand Delivery: Richard R. Long, Director, Air and 
Radiation Program, Environmental Protection Agency (EPA), Region 8, 
Mailcode 8P-AR, 999 18th Street, Suite 300, Denver, Colorado 80202-
2466. Such deliveries are only accepted Monday through Friday, 8 a.m. 
to 4:55 p.m., excluding Federal holidays. Special arrangements should 
be made for deliveries of boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-R08-OAR-
2006-0098. EPA's policy is that all comments received will be included 
in the public docket without change and may be made available online at 
http://www.regulations.gov, including any personal information 

provided, unless the comment includes information claimed to be 
Confidential Business Information (CBI) or other information whose 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. The http://www.regulations.gov Web site 

is an ``anonymous access'' systems, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA, without 
going through http://www.regulations.gov your e-mail address will be 

automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses. For additional information about EPA's public 
docket visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.
 For additional instructions on submitting 

comments, go to Section I. General Information of the SUPPLEMENTARY 
INFORMATION section of this document.

[[Page 39260]]

http://www.regulations.gov index. Although listed in the index, some 

information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in http://www.regulations.gov or in hard copy at the Air and Radiation 

Program, Environmental Protection Agency (EPA), Region 8, 999 18th 
Street, Suite 300, Denver, Colorado 80202-2466. 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, Mailcode 8P-AR, Environmental Protection Agency (EPA), Region 
8, 999 18th Street, Suite 200, Denver, Colorado 80202-2466, (303) 312-
6437, ostrand.laurie@epa.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents

Definitions
I. General Information
II. Background
    A. General Background
    B. SIP Background
    C. FIP Background
III. FIP Proposal
    A. Flare Requirements Applicable to All Sources
    B. CHS Inc.
    C. ConocoPhillips
    D. ExxonMobil
    E. Montana Sulphur & Chemical Company
IV. Request for Public Comment
V. 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

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 CEMS mean or refer to continuous emission 
monitoring system.
    (iii) The initials CO mean or refer to carbon monoxide.
    (iv) The words EPA, we, us or our mean or refer to the United 
States Environmental Protection Agency.
    (v) The initials FIP mean or refer to Federal Implementation Plan.
    (vi) The initials H2S mean or refer to hydrogen sulfide.
    (vii) The initials MBER mean or refer to the Montana Board of 
Environmental Review.
    (viii) The initials MDEQ mean or refer to the Montana Department of 
Environmental Quality.
    (ix) The initials MSCC mean or refer to the Montana Sulphur & 
Chemical Company.
    (x) The initials NAAQS mean or refer to National Ambient Air 
Quality Standards.
    (xi) The initials SIP mean or refer to State Implementation Plan.
    (xii) The initials SO2 mean or refer to sulfur dioxide.
    (xiii) The words state or Montana mean the State of Montana, unless 
the context indicates otherwise.
    (xiv) The initials SRU mean or refer to sulfur recovery unit.
    (xv) The initials SWS mean or refer to sour water stripper.

I. General Information

A. What Should I Consider as I Prepare My Comments for EPA?

    1. Submitting CBI. Do not submit this information to EPA through 
http:// www.regulations.gov or e-mail. Clearly mark the part or all of 

the information that you claim to be CBI. For CBI information in a disk 
or CD ROM that you mail to EPA, mark the outside of the disk or CD ROM 
as CBI and then identify electronically within the disk or CD ROM the 
specific information that is claimed as CBI. In addition to one 
complete version of the comment that includes information claimed as 
CBI, a copy of the comment that does not contain the information 
claimed as CBI must be submitted for inclusion in the public docket. 
Information so marked will not be disclosed except in accordance with 
procedures set forth in 40 CFR part 2.
    2. Tips for Preparing Your Comments. When submitting comments, 
remember to:
    a. Identify the rulemaking by docket number and other identifying 
information (subject heading, Federal Register date and page number).
    b. Follow directions--The agency may ask you to respond to specific 
questions or organize comments by referencing a Code of Federal 
Regulations (CFR) part or section number.
    c. Explain why you agree or disagree; suggest alternatives and 
substitute language for your requested changes.
    d. Describe any assumptions and provide any technical information 
and/or data that you used.
    e. If you estimate potential costs or burdens, explain how you 
arrived at your estimate in sufficient detail to allow for it to be 
reproduced.
    f. Provide specific examples to illustrate your concerns, and 
suggest alternatives.
    g. Explain your views as clearly as possible, avoiding the use of 
profanity or personal threats.
    h. Make sure to submit your comments by the comment period deadline 
identified.

II. Background

A. General Background

    Billings and Laurel are situated in the Yellowstone River Valley in 
south-central Montana. The Yellowstone River Valley runs from southwest 
to northeast and is the dominant topographical feature influencing 
airflow over the area. Windroses \1\ for the area reflect the valley 
orientation. Southwest winds are the most common, followed by northeast 
winds.
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    \1\ A windrose is a diagram showing the relative frequency or 
frequency and strength of winds from different directions (Websters 
9th New Collegiate Dictionary).
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    The terrain in the vicinity of Billings and Laurel is upland bench 
which is steeply cut by the Yellowstone River and its tributaries. The 
bench lies at an elevation of 4000 feet while the valley in Billings is 
approximately 3000 feet above sea level (asl) and in Laurel is 
approximately 3300 feet asl. A constriction in the Yellowstone Valley 
occurs between central Billings and the Lockwood area located to the 
east. The valley is generally 3 or 4 miles wide but narrows to a little 
over a mile wide at the constriction. Nearby terrain, such as the 
Sacrifice Cliff to the southeast of Billings and the Rimrocks to the 
north, rises abruptly and is often higher than the tallest smoke stack. 
Laurel is located within the Yellowstone Valley approximately 15 miles 
southwest of Billings. The valley near Laurel is 3 or 4 miles wide. 
Nearby terrain to the northwest and southeast of Laurel rises abruptly 
and is often higher than the tallest smoke stack.
    The major sulfur dioxide (SO2) emitting industries in 
the Billings area are the ConocoPhillips \2\ and

[[Page 39261]]

ExxonMobil \3\ Petroleum Refineries, Western Sugar Company, the PPL 
Montana, LLC J.E. Corette Power Plant,\4\ Montana Sulphur & Chemical 
Company (MSCC) (gas processing plant, sulfur recovery and sulfur 
products), and Yellowstone Energy Limited Partnership (YELP) 
(cogeneration power plant). The major SO2 emitting industry 
in the Laurel area is the CHS Inc. Petroleum Refinery.\5\ Although 
Laurel and Billings are 15 miles apart, the industries in Billings have 
some impact on the air quality in Laurel and the industry in Laurel has 
some impact on the air quality in Billings.
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    \2\ When the state originally adopted the Billings/Laurel 
SO2 SIP, the ConocoPhillips Refinery was known as the 
Conoco Refinery. Throughout this document we will refer to the 
refinery as ConocoPhillips.
    \3\ When the state originally adopted the Billings/Laurel 
SO2 SIP, the ExxonMobil Refinery was known as the Exxon 
Refinery. Throughout this document we will refer to the refinery as 
ExxonMobil.
    \4\ When the state originally adopted the Billings/Laurel 
SO2 SIP, the PPL Montana, LLC J.E. Corette Power Plant 
was known as the Montana Power Company, J.E. Corrette Plant. 
Throughout this document we will refer to the power plant as the 
Corette Power Plant.
    \5\ When the state originally adopted the Billings/Laurel 
SO2 SIP, CHS Inc. Petroleum Refinery was known as the 
Cenex Petroleum Refinery. Throughout this document we will refer to 
the refinery as CHS Inc.
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    On March 3, 1978 (43 FR 8962), the Laurel area was designated as 
nonattainment for the primary SO2 national ambient air 
quality standard (NAAQS). See also 40 CFR 81.327. The nonattainment 
area consists of an area with a two-kilometer radius around CHS Inc. 
This designation was based on measured and modeled violations of the 
NAAQS. EPA reaffirmed this nonattainment designation on September 11, 
1978 (43 FR 40412). The 1990 Clean Air Act Amendments, enacted November 
15, 1990, again reaffirmed the nonattainment designation of Laurel with 
respect to the primary SO2 NAAQS. Since the Laurel 
nonattainment area had a fully approved part D plan, the state was not 
required to submit a revised plan for the area under the 1990 
Amendments (see sections 191 and 192 of the Act).
    On March 3, 1978 (43 FR 8962), those areas in the state that had 
not been identified as not meeting the SO2 NAAQS were 
designated as ``Better Than National Standards.'' The Billings area was 
in that portion of the state that was designated as ``Better Than 
National Standards.''
    The Act requires EPA to establish NAAQS which protect public health 
and welfare. NAAQS have been established for SO2. 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.\6\ As a result, EPA 
(pursuant to sections 110(a)(2)(H) and 110(k)(5) of the Act) requested 
the State of Montana to revise its previously approved SIP for the 
Billings/Laurel area. In response, the State submitted revisions to the 
SIP on September 6, 1995, August 27, 1996, April 2, 1997, July 29, 
1998, and May 4, 2000.
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    \6\ See the study for the Billings Gasification, Inc. (BGI) (now 
YELP) permit in 1991 and the GeoResearch, Inc. (GRI) study 
commissioned by the Billings City Council in 1993 (document 
's II.G-13 and II.G-12, respectively, in Docket 
R8-99-01).
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B. SIP Background

1. SIP Call
    We issued a request that the State of Montana revise the Billings/
Laurel area SO2 SIP by letter to the Governor of Montana, 
dated March 4, 1993 (see reference document Z). The request letter 
reflected our preliminary finding regarding the SIP's substantial 
inadequacy, and was published in the Federal Register on August 4, 1993 
(58 FR 41430) (see reference document Y). We sometimes refer to such a 
request as a SIP Call. In the request letter, we declared that the SIP 
Call would become final agency action when we made a binding 
determination regarding the State of Montana's response to the SIP 
Call. We made such a binding determination regarding the SIP Call when 
we partially and limitedly approved and partially and limitedly 
disapproved the Billings/Laurel SO2 SIP revisions submitted 
by the State of Montana in response to the request letter.\7\ See 67 FR 
22168, 22173 (May 2, 2002) (see reference document AA).
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    \7\ In some cases, a SIP rule may contain certain provisions 
that meet the applicable requirements of the Act, but that are 
inseparable from other provisions that do not meet all the 
requirements. Although the submittal may not meet all of the 
applicable requirements, we may consider whether the rule, as a 
whole, has a strengthening effect on the SIP. If this is the case, 
limited approval may be used to approve a rule that strengthens the 
existing SIP as representing an improvement over what is currently 
in the SIP and as meeting some of the applicable requirements of the 
Act. At the same time we would disapprove the rule for not meeting 
all of the applicable requirements of the Act. Under a limited 
approval/disapproval action, we simultaneously approve and 
disapprove the entire rule even though parts of the rule satisfy, 
and parts do not satisfy, requirements under the Act. The 
disapproval only concerns the failure of the rule to meet a specific 
requirement of the Act and does not affect incorporation of the rule 
as part of the approved, federally enforceable SIP. We use this 
mechanism when the rule, despite its flaws, will strengthen the 
federally enforceable SIP.
    In other cases, a SIP rule may contain certain provisions that 
meet applicable requirements of the Act, but that are separable from 
other provisions that do not meet applicable requirements. Where a 
separable portion of the submittal meets applicable requirements, 
partial approval may be used to approve that part of the submittal 
and partial disapproval to disapprove the provisions that do not 
meet applicable requirements of the Act.
    EPA's interpretation of the Act regarding approving and 
disapproving SIPs is discussed further in a July 9, 1992, memorandum 
title ``Processing of State Implementation Plan (SIP) Submittals,'' 
from John Calcagni to Regional Air Division Directors. (See 
reference document A.)
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2. SIPs Submitted in Response to SIP Call
    Our 1993 SIP Call called for the State of Montana to submit a SIP 
revision for the Billings/Laurel area by September 4, 1994. On 
September 6, 1995, the Governor of Montana submitted a SIP revision in 
response to the SIP Call. The SIP was later amended with revisions 
submitted on August 27, 1996, April 2, 1997, July 29, 1998, and May 4, 
2000. Copies of the complete SIP revisions are contained in the docket 
for our action on the SIP. (See docket R8-99-01.)
3. EPA's Actions on State's Billings/Laurel SO2 SIP
    (a) EPA's May 2, 2002, final action.
    On May 2, 2002 (67 FR 22168) \8\ (see reference document AA), we 
partially approved, partially disapproved, limitedly approved and 
limitedly disapproved provisions of the Billings/Laurel SO2 
SIP.\9\ Specifically:
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    \8\ See also June 7, 2002 corrections notice (67 FR 39473) 
(reference document KKK).
    \9\ See footnote 7.
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    (i) We disapproved the following provisions of the Billings/Laurel 
SO2 SIP: \10\
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    \10\ The SIP was submitted in the form of orders, stipulations, 
exhibits and attachments for each source covered by the plan. The 
majority of the requirements are contained in the exhibits. 
Throughout this document when we refer to an exhibit, we mean 
exhibit A to the stipulation for the specified source. For purposes 
of our May 2, 2002, SIP action the stipulations and exhibits to 
which we refer were adopted by the Montana Board of Environmental 
Review (MBER) on June 12, 1998. MBER adopted revised stipulations 
and exhibits for some sources on March 17, 2000. To distinguish 
between the two sets of stipulations and exhibits, we refer to 
either the 1998 stipulation or exhibit for a particular source, or 
the 2000 stipulation or exhibit.
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     The escape clause (paragraph 22 in the ExxonMobil and MSCC 
1998 stipulations, and paragraph 20 in the CHS Inc., ConocoPhillips, 
Corette Power Plant, Western Sugar, and YELP 1998 stipulations.)
     The MSCC stack height credit and emission limits on the 
sulfur recovery unit (SRU) 100-meter stack (paragraph 1 of the 
ExxonMobil 1998 stipulation, paragraphs 1 and 2 of the MSCC 1998 
stipulation, and sections 3(A)(1)(a) and

[[Page 39262]]

(b) and 3(A)(3) of the MSCC 1998 exhibit).
     The emission limit on MSCC's auxiliary vent stacks, 
section 3(A)(4) of MSCC's 1998 exhibit.
     The attainment demonstration, because of improper stack 
height credit and emission limits at MSCC.
     The attainment demonstration for lack of flare emission 
limits at CHS Inc., ConocoPhillips, ExxonMobil, and MSCC.
     The attainment demonstration, because of the disapproval 
of the emission limit for MSCC's auxiliary vent stacks.
     The Reasonably Available Control Measures (RACM) 
(including Reasonably Available Control Technology (RACT)) and 
Reasonable Further Progress (RFP) requirements for CHS Inc.
     The provisions that allow sour water stripper overheads to 
be burned in the flare at CHS Inc. and ExxonMobil (i.e., the following 
phrase from section 3(B)(2) of CHS Inc.'s 1998 exhibit and section 
3(E)(4) of ExxonMobil's 1998 exhibit: ``or in the flare''; the 
following phrases in section 4(D) of CHS Inc.'s 1998 exhibit and 
section 4(E) of ExxonMobil's 1998 exhibit: ``or in the flare'' and ``or 
the flare''.)
    (ii) We limitedly approved and limitedly disapproved the following 
provision:
     The emission limit for the 30-meter stack at MSCC (section 
3(A)(2) of MSCC's 1998 exhibit) because it lacked a reliable compliance 
monitoring method.
    (iii) We did not act on the following provisions:
     The provisions in section 6(B)(3) of MSCC's 1998 exhibit 
that require certain monitoring equipment to support the variable 
emission limit.\11\
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    \11\ Since we disapproved MSCC's variable emission limit, we did 
not believe it made sense to approve section 6(B)(3) of MSCC's 1998 
exhibit, which requires MSCC to install certain monitoring equipment 
to support the use of the variable limit. Section 6(B)(3) would be 
needed only if we approved MSCC's variable emission limit.
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     YELP's emission limits (in sections 3(A)(1) through (3) of 
YELP's 1998 exhibit).
     ExxonMobil's coker CO-boiler emission limitation (in 
section 3(B)(1) of ExxonMobil's 1998 exhibit).
     ExxonMobil's F-2 crude/vacuum heater stack emission limits 
and attendant compliance monitoring methods (sections 3(A)(2), 3(B)(3), 
4(E) and method 6A of attachment 2 of ExxonMobil's 
1998 exhibit; and the following phrase from section 3(E)(4) of 
ExxonMobil's 1998 exhibit ``except that the sour water stripper 
overheads may be burned in the F-1 Crude Furnace (and exhausted through 
the F-2 Crude/Vacuum Heater stack) or in the flare during periods when 
the FCC CO Boiler is unable to burn the sour water stripper overheads, 
provided that: (a) such periods do not exceed 55 days per calendar year 
and 65 days for any two consecutive calendar years, and (b) during such 
periods the sour water stripper system is operating in a two tower 
configuration.'')
     ExxonMobil's fuel gas combustion emission limits and 
attendant compliance monitoring methods (in sections 3(A)(1), 3(B)(2), 
4(B), and 6(B)(3) of ExxonMobil's 1998 exhibit).
     CHS Inc.'s combustion sources emission limitations and 
attendant compliance monitoring methods (sections 3(A)(1)(d), 4(B), 
4(D) and method 6A of attachment 2 of CHS Inc.'s 1998 
exhibit; and the following phrase from section 3(B)(2) of CHS Inc.'s 
1998 exhibit ``except that those sour water stripper overheads may be 
burned in the main crude heater (and exhausted through the main crude 
heater stack) or in the flare during periods when the FCC CO boiler is 
unable to burn the sour water stripper overheads from the ``old'' SWS, 
provided that such periods do not exceed 55 days per calendar year and 
65 days for any two consecutive calendar years.'')
    (iv) In a separate action published on May 2, 2002 (67 FR 22242) 
\12\ (see reference document BB), we proposed action on some provisions 
of the Billings/Laurel SO2 SIP submitted on July 29, 1998, and May 4, 
2000.\13\ We later finalized action on these provisions on May 22, 2003 
(68 FR 27908) (see discussion below and reference document CC).
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    \12\ See also June 14, 2002 correction notice (67 FR 40897) 
(reference document LLL).
    \13\ On July 28, 1999 (64 FR 40791), we proposed to 
conditionally approve certain provisions of the SIP based on the 
Governor's commitment to address concerns we had raised. The 
Governor submitted a SIP revision on May 4, 2000, which was intended 
to fulfill the commitments. Since the Governor submitted a SIP 
revision to fulfill the commentments, we did not finalize our 
proposed conditional approval and instead proposed separate action 
on parts of the July 29, 1998, submittal (i.e., those parts we 
proposed to conditionally approve on July 28, 1999) and all of the 
May 4, 2000, submission (which in some cases modified the provisions 
of the July 29, 1998, submittal).
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    (v) We approved the following provisions:
     All provisions of the SIP that were not partially 
disapproved, limitedly disapproved, omitted from our action, or 
addressed in our May 2, 2002, proposal.
    (b) EPA's May 22, 2003, final action.
    On May 22, 2003 (68 FR 27908) \14\ (see reference document CC), we 
partially approved, limitedly approved, and limitedly disapproved 
provisions of the Billings/Laurel SO2 SIP. Specifically:
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    \14\ See also June 2, 2003 correction notice (68 FR 32799) 
(reference document MMM).
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    (i) We approved the following provisions:
     YELP's emission limits in sections 3(A)(1) through (3) and 
reporting requirements in section 7(C)(1)(b) of YELP's 2000 exhibit.
     Provisions related to the burning of SWS overheads in the 
F-1 Crude Furnace (and exhausted through the F-2 Crude/Vacuum Heater 
stack) at ExxonMobil in sections 3(E)(4) and 4(E) (excluding ``or in 
the flare'' and ``or the flare'' in both sections), 3(A)(2), and 
3(B)(3) of ExxonMobil's 1998 exhibit, and method 6A-1 of 
attachment 2 of ExxonMobil's 2000 exhibit.
     Minor changes in sections 3, 3(A), and 3(B) (only the 
introductory paragraphs); and sections 3(E)(3), 6(B)(7), 7(B)(1)(d), 
7(B)(1)(j), 7(C)(1)(b), 7(C)(1)(d), 7(C)(1)(f), and 7(C)(1)(l) of 
ExxonMobil's 2000 exhibit.
    (ii) We limitedly approved and limitedly disapproved the following 
provisions:
     Provisions related to the fuel gas combustion emission 
limits at ExxonMobil in sections 3(B)(2), 4(B), and 6(B)(3) of 
ExxonMobil's 1998 exhibit, and section 3(A)(1) of ExxonMobil's 2000 
exhibit.
     Provisions related to ExxonMobil's coker CO-boiler 
emission limit in sections 2(A)(11)(d), 3(B)(1), and 4(C) of 
ExxonMobil's 2000 exhibit.
     Provisions related to the burning of SWS overheads at CHS 
Inc. in sections 3(B)(2) and 4(D) (excluding ``or in the flare'' and 
``or the flare'' in both sections), 3(A)(1)(d), and 4(B) of CHS Inc.'s 
1998 exhibit, and method 6A-1 of attachment 2 of CHS 
Inc.'s 2000 exhibit.
4. Appeal of EPA's Action on Billings/Laurel SO2 SIP
    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.

[[Page 39263]]

C. FIP Background

    Under section 110(c) of the Act, 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)] \15\, or
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    \15\ Section 110(k)(1)(A) 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)).

III. FIP Proposal

    As discussed above, in this proposed rulemaking, EPA is fulfilling 
its mandatory duty under section 110(c) of the Act to propose FIP 
provisions for the Billings/Laurel, Montana area because of our limited 
and partial disapproval of portions of the Billings/Laurel 
SO2 SIP submitted by Montana. Our proposed FIP would not 
replace the SIP entirely, but instead would only replace elements of 
the SIP or fill gaps in the SIP as necessary to ensure attainment and 
maintenance of the SO2 NAAQS. In cases where the provisions 
of the FIP would address emissions activities differently or establish 
different requirements than provisions of the SIP, the provisions of 
the FIP would take precedence.
    Our proposed FIP only impacts four stationary sources: CHS Inc., 
ConocoPhillips, ExxonMobil and Montana Sulphur & Chemical Company 
(MSCC). We caution that if any of these sources are subject to more 
stringent requirements under other provisions of the Act (e.g., section 
111 or 112, part C, or SIP-approved permit programs under Part A), our 
proposal of any FIP requirement would not excuse any of these sources 
from meeting other more stringent requirements. Also, our proposed FIP 
is not meant to imply any sort of applicability determination under 
other provisions of the Act (e.g., section 111 or 112, part C, or SIP-
approved permit programs under Part A).

A. Flare Requirements Applicable to All Sources

    We disapproved the Billings/Laurel SO2 SIP as it applied 
to the attainment demonstration because the SIP lacked enforceable 
emission limits for flares, while the SIP submission took credit for 
such emission limits. See our May 2, 2002, final rulemaking action at 
67 FR 22168. Because of this disapproval we are proposing emission 
limits and compliance determining methods for flares at CHS Inc., 
ConocoPhillips (including Jupiter Sulfur),\16\ ExxonMobil, and MSCC. 
The flare emission limits and compliance determining methods are being 
proposed for the purpose of assuring attainment and maintenance of the 
SO2 NAAQS.
---------------------------------------------------------------------------

    \16\ The ConocoPhillips Billings Refinery also includes the 
Jupiter Sulfur Recovery Facility (see reference document S).
---------------------------------------------------------------------------

    Since the state's attainment demonstration assumed that the main 
flares at each source were limited to 150 pounds of SO2 per 
three hour period, and that the Jupiter Sulfur SRU flare would share an 
emission limit of 75 pounds of SO2 per three hour period 
with the Jupiter Sulfur SRU/ATS stack, we are proposing to promulgate 
flare emission limits that reflect the state's assumption that 
emissions from these points would not exceed these levels. More 
specific detail regarding each of the sources' emission limits is 
provided below in sections III. B, C, D, and E.
    While we are proposing that 150 pounds of SO2 per three 
hour period be the limit for the main flares, we are soliciting input 
on whether we should instead limit the main flares to 500 pounds of 
SO2 per calendar day. This value is consistent with a 
trigger point for certain analyses contained in settlements between the 
United States and CHS Inc., ConocoPhillips, and ExxonMobil. For 
purposes of our attainment demonstration, we have assumed that the 500 
pounds would be emitted from the four main flares over a three-hour 
period rather than a

[[Page 39264]]

calendar day. Our evaluation shows that even under these conditions, 
the 3-hour SO2 NAAQS would be attained.
    Note that if we adopted the 500 pound value for this FIP, we would 
impose it as an enforceable emission limit, not just a trigger point 
for further analyses.
    We are proposing that the flare limits will apply at all times 
without exception. We recognize that flares are sometimes used as 
emergency devices at refineries and that it may be difficult to comply 
with these flare limits during malfunctions. However, under our 
interpretations of the Clean Air Act, it is not appropriate to create 
automatic exemptions from SIP limits needed to demonstrate attainment. 
(See 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 (referred to hereafter as ``1999 
policy statement'').) 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. If we were to establish such a 
provision, we anticipate it would closely follow the guidance contained 
in our 1999 policy statement.
    We are also proposing that compliance with the emission limits be 
determined by 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. The assumption is that when the gas stream is combusted 
in a flare, all of the sulfur in the gas stream converts to 
SO2 and is emitted to the atmosphere. Also, by knowing the 
volumetric flow rate of the gas stream to the flare(s) we can determine 
the SO2 emitted to the atmosphere over a specified 
timeframe.
    With respect to the volumetric flow rate monitoring systems, we 
developed our proposed approach considering volumetric flow rate 
monitoring requirements established at refinery flares in California 
and Texas, vendor literature, technical articles, and information 
gathered from discussions with vendors. (See reference documents KK 
(Bay Area Air Quality Management District (BAAQMD)--documents related 
to consideration of proposed new regulation 12, Rule 11 Flare 
Monitoring at Petroleum Refineries); LL (final version of BAAQMD 
Regulation 12, Miscellaneous Standards of Performance, Rule 11, Flare 
Monitoring at Petroleum Refineries); BBB (South Coast Area Air Quality 
Management District (SCAQMD)--documents related to consideration of 
revisions to rule 1118, Control of Emissions From Refinery Flares); CCC 
(final version of SCAQMD Rule 1118, Control of Emissions From Refinery 
Flares); MM (Texas Natural Resource Conservation Commission, Chapter 
115--Control of Air Pollution from Volatile Organic Compounds, 
Subchapter H: Highly-Reactive Volatile Organic Compounds, Division 1: 
Vent Gas Control); NN (Fluid Components International LLC (FCI), vendor 
literature from http://www.fluidcomponents.com); OO (GE Sensing, vendor 

literature); PP (``Why and How to measure flare gas'' from Flowmeter 
Directory (http://www.flowmeterdirectory.com)); QQ (``Transit-time Ultrasonic 

Flowmeters for Gases'' Presented at and Published in Part in the Proc. 
41st Annual CGA (Canadian Gas Association) Gas Measurement School, 
Grand Okanagan, Kelowna BC, Canada, June 4-6, 2002); RR (``Flare 
Measurement `Best Practices' To Comply With National & Provincial 
Regulations''); SS (``Ultrasonic Flowmeter Market is Expected to Grow 
Strongly''); TT (Note to Billings/Laurel SO2 FIP File, April 
7, 2004 Discussion with Peter Klorer, GE Infrastructure, Regarding 
Panametrics Mass Flowmeter); HHH (Note to Billings/Laurel 
SO2 FIP File, April 20, 2006 Discussion with Paul Calef, GE 
Sensing, Regarding Flare Flowmeter).) Based on what is required 
elsewhere and what we have learned from vendors and literature, we have 
determined that there is reliable technology available to continuously 
monitor and record the volumetric flow rate of the gas stream to a 
flare. Therefore, we are proposing that sources install, calibrate, 
maintain and operate a continuous flow monitoring system capable of 
measuring the total volumetric flow of the gas stream that is combusted 
in a flare in accordance with the specifications described below. The 
flow monitoring system may require one or more flow monitoring devices 
or flow measurements at one or more header locations if one monitor 
cannot measure all of the volumetric flow to a flare.
    We are proposing the following volumetric flow monitoring 
specifications:
    (1) The minimum detectible velocity of the flow monitoring 
device(s) shall be 0.1 feet per second (fps);
    (2) 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% 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 shall be monitored continuously;
    (4) The temperature and pressure shall be monitored in the same 
location as the flow monitoring device(s) and shall be calibrated to 
meet accuracy specifications as follows: temperature shall be 
calibrated annually to within 2.0% at absolute temperature 
and the pressure monitor shall be calibrated annually to within < plus-
minus>5.0 mmHg;
    (5) Flow monitoring device(s) shall be initially 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 shall be 
calibrated annually according to manufacturer's specifications.\17\
---------------------------------------------------------------------------

    \17\ Volumetric flow monitors meeting the proposed volumetric 
flow monitoring specifications above should be able to measure the 
majority of volumetric flow in the gas streams to the flare. 
However, in rare events (e.g., such as upset conditions) the flow to 
the flare may exceed the range of the monitor. EPA is not suggesting 
that multiple monitors be installed to measure extreme flow rates 
that rarely occur. Rather, in the rare event that the range of the 
monitor is exceeded, reliable flow estimation parameters may be used 
to determine the volumetric flow rate to the flare. Flow determined 
through reliable estimation parameters will be used to calculate 
SO2 emissions. In quarterly reports, sources shall 
indicate when reliable estimation parameters are used and how such 
parameters were derived.
---------------------------------------------------------------------------

    With respect to measuring the total sulfur concentration, we 
developed our proposed approach considering concentration monitoring 
requirements established at refinery flares in California, vendor 
iterature, and information gathered from discussions with vendors. (See 
reference documents UU (Note to Billings/Laurel SO2 FIP 
File, May 11, 2004 Discussion with Robert Hornberger, Galvanic Applied 
Sciences); VV (Galvanic Applied Sciences Inc., H2S & Total 
Sulfur Analyzers, vendor literature printed from http://www.galvanic.ab.ac); 

KK (Bay Area Air Quality Management District (BAAQMD)--documents 
related to consideration of proposed new regulation 12, Rule 11, Flare 
Monitoring

[[Page 39265]]

at Petroleum Refineries); BBB (South Coast Area Air Quality Management 
District (SCAQMD)--documents related to consideration of revisions to 
rule 1118, Control of Emissions From Refinery Flares); CCC (final 
version of SCAQMD Rule 1118, Control of Emissions From Refinery 
Flares); XX (Note to Billings/Laurel SO2 FIP File, May 10 
and May 31, 2006 Discussions with Tom Kimbel, Analytical Systems 
International, Regarding Total Sulfur Analyzers); YY (Analytical 
Systems International, Continuous Sulfur Analyzer, vendor literature 
printed from http://www.ASIWebPage.com); III (Note to Billings/Laurel SO2 FIP 

File, April 19, 2006 Discussion with Bob Kinsella, ThermoElectron, 
Regarding Total Sulfur Analyzer); JJJ (Note to Billings/Laurel 
SO2 FIP File, May 12, 2006, and June 7, 2006 Discussions 
with Eugene Teszler, South Coast Air Quality Management District, 
regarding Total Sulfur Analyzer).) Based on what is required elsewhere 
and what we have learned from vendors, we have determined that there is 
reliable technology available to continuously monitor and record the 
total sulfur concentration of the gas stream to a flare. Also, we are 
proposing that the total sulfur concentrations, rather than just 
H2S concentrations, be monitored continuously. This is 
because we believe there are other sulfur compounds in the gas stream 
to a flare. The total sulfur analyzer system may require one or more 
total sulfur analyzers or total sulfur concentration measurements at 
one or more header locations if one analyzer cannot measure all of the 
total sulfur concentration to a flare.
    Therefore, we are proposing 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 are proposing that the continuous monitoring occur at a 
location(s) that is (are) representative of the gas combusted in the 
flare and be capable of measuring the expected range of total sulfur 
expected in the gas stream to the flare. Vendor literature and 
discussions with vendors indicates this is feasible. The total sulfur 
analyzer shall 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. The source shall notify EPA in writing of each Relative 
Accuracy Test Audit a minimum of twenty-five (25) working days prior to 
the actual testing.
    We are proposing that the volumetric flow and total sulfur 
concentrations determined by the above procedures be used in 
calculations to determine the hourly and three hour SO2 
emissions from the flare(s).
    We are proposing that each source submit for EPA review and 
approval a flare monitoring plan prior to establishing continuous 
monitors on the flare(s). Also, we are proposing that each source 
submit for EPA review a quality assurance/quality control (QA/QC) plan 
for each of the continuous monitors.
    Finally, we are proposing certain 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).

B. CHS Inc.

1. Flare Requirements
    The state's attainment demonstration and our subsequent attainment 
modeling for the FIP assume that CHS Inc.'s flare is limited to 150 
pounds of SO2 per three hour period.18, 19 This 
is the limit we are proposing for CHS Inc.'s flare. Compliance with the 
flare emission limit will be determined as discussed in Section III.A, 
above.
---------------------------------------------------------------------------

    \18\ See Modeling discussion in Section III.E.5, below.
    \19\ Our FIP assumes that CHS Inc. has only one operational 
flare. See reference documents PPP and QQQ.
---------------------------------------------------------------------------

2. Combustion Sources Emission Limits.
    Three of the emission limits contained in CHS Inc.'s portion of the 
Billings/Laurel SO2 SIP are combined emission limits for 
combustion sources. The emission limits, contained in CHS Inc.'s 1998 
exhibit, are in pounds of SO2 per 3-hour, 24-hour and one-
year averaging periods.\20\ Compliance with the emission limits is 
determined by measuring the sulfur and H2S content of the 
fuels combusted (oil and fuel gas) and the flow of the fuels to the 
combustion sources. The state's assumption is that when the sulfur/
H2S in the fuel is combusted, all the sulfur/H2S 
converts to SO2 and is emitted to the atmosphere. By 
measuring sulfur/H2S content of the fuel and the flow of the 
fuel to the combustion sources, the amount of SO2 emitted 
per 3-hour, 24-hour and one-year averaging periods can be calculated. 
CHS Inc.'s 1998 exhibit also allows sour water stripper (SWS) overheads 
(ammonia (NH3) and H2S gases removed from the 
sour water in the sour water stripper), to be combusted in the main 
crude heater. When the SWS overheads are combusted in the main crude 
heater, compliance with the combustion source emission limits is 
determined by summing the SO2 emissions calculated from the 
combustion of the fuels and SWS overheads. The SO2 emissions 
from the SWS overheads are determined by measuring the sulfur compounds 
in, and the flow of, the sour water.
---------------------------------------------------------------------------

    \20\ Section 3(A)(1)(d) of CHS Inc.'s 1998 exhibit. (See 
reference document DD for a copy of the exhibit.)
---------------------------------------------------------------------------

    We were concerned that the method the state established to measure 
the amount of sulfur compounds in the sour water at CHS Inc. would not 
measure all the sulfur compounds in the sour water.\21\ Specifically, 
we concluded that the analytical method submitted in the SIP would not 
measure all of the sulfur compounds in the sour water because of the 
potentially high concentrations of sulfur compounds; there would not be 
enough preservative in the sample container to prevent the loss of the 
sulfur compounds during sampling and analysis. (See reference document 
X.) Therefore, the emissions of SO2 from the combustion of 
SWS overheads in the main crude heater could be underestimated. We 
concluded that the combustion source emission limits were not 
enforceable under all scenarios and, therefore, did not meet the 
requirements of section 110(a)(2)(A) of the Act. On May 22, 2003 (68 FR 
27908), we limitedly approved and limitedly disapproved the combustion 
source emission limits and method used to measure the sulfur compounds 
in the sour water.
---------------------------------------------------------------------------

    \21\ For measuring the sulfur compounds in the sour water, the 
state established Method 6A-1 contained in attachment 
2 of CHS Inc.'s 2000 exhibit. (See reference document EE 
for a copy of the exhibit.)
---------------------------------------------------------------------------

    After the state adopted CHS Inc.'s 1998 and 2000 exhibits as part 
of the SIP, the state modified CHS Inc.'s air quality permit to 
prohibit the burning of ``old'' sour water stripper overheads in the 
FCC CO boiler and the main crude heater. See Air Quality Permit 
1821-11, provision II.C.1. (See reference document B.) The 
state has not modified the SIP to correspond to the changes in CHS 
Inc.'s air quality permit.\22\
---------------------------------------------------------------------------

    \22\ Page 11 of the State's CHS Inc. Permit Analysis, attached 
to Permit 1821-11 (see reference document B) discusses the 
SWS and indicates that a new SWS stripper was constructed, which 
replaced the operation of the older existing SWS. The old SWS cannot 
be removed, however, and functions only as the back-up unit. The 
Permit Analysis further indicates that the stripper overhead gas 
containing H2S and NH3, is sent to the new SRU 
for sulfur recovery and incineration of NH3. This was 
confirmed in a conversation with the DEQ (see reference document 
DDD).

---------------------------------------------------------------------------

[[Page 39266]]

    To address our limited disapproval of the combustion source 
emission limits in the SIP, we are proposing a prohibition in the FIP 
on the burning of SWS overheads in the main crude heater. Prohibiting 
the burning of SWS overheads in the main crude heater will eliminate 
our concern regarding the method used to measure the amount of sulfur 
compounds in the sour water. We believe it is reasonable to make this 
proposal because the state and CHS Inc. have already agreed to such 
restrictions in CHS Inc.'s air quality permit.
    Compliance with the prohibition to not burn SWS overheads in the 
main crude heater will be based on methods similar to those contained 
in CHS Inc.'s 1998 exhibit. Specifically, section 3(B)(3) of the 1998 
exhibit requires CHS Inc. to install 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 cannot be opened unless the chain 
and lock are removed. Under our proposed FIP, CHS Inc. would be 
required to maintain the chain and lock in place and keep the valve 
closed at all times. CHS Inc. would be required to log and report any 
noncompliance with this provision.

C. ConocoPhillips

1. Flare Requirements
    The state's attainment demonstration and our subsequent attainment 
modeling for the FIP assume that ConocoPhillips' main refinery flare is 
limited to 150 pounds of SO2 per three hour period.\23\ We 
understand that ConocoPhillips actually has two main flares--a north 
main flare and a south main flare--but only operates one at a time and 
that Jupiter Sulfur, ConocoPhillips' sulfur recovery unit (SRU), also 
has one flare. Correspondence from ConocoPhillips, dated February 4, 
2004, indicates that the north flare is currently in use but the south 
flare has been used in alternating 4-year cycles, with switches at full 
plant turnarounds. (See reference document C.) Conversations with the 
MDEQ on September 1, 2004, confirm that only one flare is used at a 
time and that a section of the pipe going to the unused flare is 
removed during the turnaround. (See reference document W.) Therefore, 
with respect to ConocoPhillips, in lieu of establishing a separate 
emission limit for each main flare, we are proposing one emission limit 
for the main flare. At any one time, ConocoPhillips may only use either 
the north or south main flare.
---------------------------------------------------------------------------

    \23\ See Modeling discussion in Section III.E.5, below.
---------------------------------------------------------------------------

    We are proposing that compliance with the main flare emission limit 
at ConocoPhillips be determined by measuring the total sulfur 
concentration and volumetric flow rate of the gas stream to the flare. 
To the extent that a single monitoring location cannot be used for both 
the north and south main flare, ConocoPhillips will need to monitor 
flow and measure total sulfur concentration at more than one location 
to determine compliance with the main flare emission limit.
    Regarding the flare at the Jupiter Sulfur Recovery facility located 
at ConocoPhillips, the SRU flare and SRU/ATS \24\ stack, which are 
roughly the same height, share an emission limit in Montana's air 
quality permit for ConocoPhillips; the Jupiter SRU/ATS stack and the 
SRU flare each have an SO2 emission limit of 25.00 lb/hr and 
0.300 tons/day. Emissions from the SRU flare are only permitted during 
times that the ATS plant is not operating. See Air Quality Permit 
2619-19, dated May 27, 2004, section II.B.1.a and b. (See 
reference document S.)
---------------------------------------------------------------------------

    \24\ ATS stands for Ammonium Thiosulfate.
---------------------------------------------------------------------------

    However, the Billings/Laurel SO2 SIP is not clear with 
respect to the relationship between the SRU flare and SRU/ATS stack. 
The SIP contains emission limits on the Jupiter Sulfur SRU stack but 
does not indicate that the limits are shared between the SRU flare and 
SRU/ATS stack.\25\ Since the SIP is not clear, we are proposing to 
clarify in the FIP that emissions can only be vented from the SRU flare 
when emissions are not being vented from the SRU/ATS stack. We believe 
that our proposal is consistent with what the state and ConocoPhillips 
intended in the SIP. First, the SRU flare and SRU/ATS stack were 
modeled as one point in the state's attainment demonstration. Second, 
Air Quality Permit 2619-19, dated May 27, 2004, indicates that 
emissions from the SRU flare can only occur during times that the ATS 
plant is not operating.
---------------------------------------------------------------------------

    \25\ See section 3(A)(3) of ConocoPhillips' 1998 exhibit. (See 
document FF for a copy of the exhibit.)
---------------------------------------------------------------------------

    We are proposing that compliance with the SRU flare emission limit, 
when Jupiter Sulfur vents 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.\26\ Our proposal regarding the SRU flare supports our attainment 
demonstration.
---------------------------------------------------------------------------

    \26\ 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
    The state's attainment demonstration and our subsequent attainment 
modeling for the FIP assume that ExxonMobil's primary process and 
turnaround flares are limited to 150 pounds of SO2 per three 
hour period.\27\ From correspondence from ExxonMobil, dated February 4, 
2004, we understand that ExxonMobil has a turnaround flare that is only 
used about 30-40 days every five to six years, when the facility's 
major SO2 source, the fluid catalytic cracking unit, is not 
normally operating. (See reference document E.) Therefore, in lieu of 
establishing a separate emission limit for the turnaround flare, we are 
proposing one combined emission limit for the primary process and 
turnaround flares.
---------------------------------------------------------------------------

    \27\ See Modeling discussion in Section III.E.5, below.
---------------------------------------------------------------------------

    Our assumption is that the flow and concentration monitoring 
devices installed to measure the gas stream to the primary process 
flare will also be able to measure the gas stream to the turnaround 
flare. To the extent that a single monitoring location cannot be used 
to measure the gas stream to both the primary process flare and the 
turnaround flare, we may allow alternative measures to determine 
volumetric flow rate and total sulfur concentrations of the gas stream 
to the turnaround flare if the turnaround flare is used infrequently--
e.g., only for refinery turnarounds once every five to six years. Such 
alternative measures could include using good engineering judgment to 
determine volumetric flow rate to the flare or manually sampling the 
gas stream to the flare to determine total sulfur concentrations.
2. Compliance Monitoring of Refinery Fuel Gas Combustion Emission 
Limits
    Two of the emission limits contained in the ExxonMobil portion of 
the Billings/Laurel SO2 SIP are combined emission limits for 
refinery fuel gas combustion sources. The emission limits, contained in 
ExxonMobil's 1998 and 2000 exhibits, are in pounds of SO2 
per 3-hour and 24-hour averaging periods.\28\ Compliance with the 
emission limits is determined by measuring the H2S content 
of the refinery fuel gas combusted and the flow of the fuel gas to the 
combustion

[[Page 39267]]

sources.\29\ The state's assumption is that when the fuel is combusted, 
all the H2S converts to SO2 and is emitted to the 
atmosphere. By measuring H2S content of the fuel and the 
flow of the fuel to the combustion sources, the amount of 
SO2 emitted per 3-hour and 24-hour averaging periods can be 
calculated.
---------------------------------------------------------------------------

    \28\ 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.)
    \29\ See section 4(B) of ExxonMobil's 1998 exhibit. (See 
reference document GG for a copy of the exhibit.)
---------------------------------------------------------------------------

    We were concerned that the method the state established to measure 
the H2S concentration was not adequate under all scenarios. 
Specifically, we determined that the H2S concentrations in 
refinery fuel gas could exceed the levels which the H2S 
continuous emission monitoring system (CEMS) would be able to 
monitor.\30\ Therefore, the emissions of SO2 from the 
refinery fuel gas combustion sources could be underestimated. We 
concluded that the refinery fuel gas combustion sources emission limits 
were not enforceable under all scenarios and, therefore, did not meet 
the requirements of section 110(a)(2)(A) of the Act. On May 22, 2003 
(68 FR 27908), we limitedly approved and limitedly disapproved the 
refinery fuel gas combustion emission limits and method used to measure 
the H2S in the refinery fuel gas.
---------------------------------------------------------------------------

    \30\ Section 6(B)(3) of ExxonMobil's 1998 exhibit indicates that 
ExxonMobil shall insure that the H2S concentration 
monitor at the refinery fuel header is capable of measuring 
H2S concentrations in the range of 0-1200 ppmv. (See 
document GG for a copy of the exhibit.) The information available to 
us indicated that the H2S concentrations in the refinery 
fuel gas could exceed 1200 ppmv. (See reference document JJ.)
---------------------------------------------------------------------------

    Because of this limited disapproval, we are proposing a new 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 are 
proposing is identical to the method included in CHS Inc.'s 1998 
exhibit.\31\
---------------------------------------------------------------------------

    \31\ See section 6(B)(3) of CHS Inc.'s 1998 exhibit. (See 
reference document DD for a copy of the exhibit.)
---------------------------------------------------------------------------

    Specifically, we are proposing that within 4 hours of the initial 
determination that the H2S concentrations in the refinery 
fuel gas stream exceed the upper range of the H2S CEMS, 
ExxonMobil shall initiate sampling of the refinery fuel gas stream at 
the fuel header on a once-per-three-hour-period frequency using the 
Tutwiler method in 40 CFR 60.648. The Tutwiler method will determine 
the H2S concentration in the refinery fuel gas. We are also 
proposing 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 exceed the upper range 
of the H2S CEMS.\32\
---------------------------------------------------------------------------

    \32\ 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.)
---------------------------------------------------------------------------

    We are also proposing reporting requirements similar to the 
requirements adopted by the state for CHS Inc. and those contained in 
40 CFR 60.7(c).
3. Compliance Monitoring of Coker CO-Boiler Emission Limits
    Two of the emission limits contained in the ExxonMobil portion of 
the Billings/Laurel SO2 SIP are emission limits on the coker 
CO-boiler stack. The emission limits contained in ExxonMobil's 2000 
exhibit are in pounds of SO2 per 3-hour and 24-hour 
averaging periods.\33\ In the SIP, compliance with the emission limits 
is based on an equation that was derived from historical testing and 
CEMS data, whereby one can determine pounds of SO2 emitted 
from the coker CO-boiler by multiplying a constant by the coker fresh 
feed rate (in barrels/day).\34\
---------------------------------------------------------------------------

    \33\ See section 3(B)(1) of ExxonMobil's 2000 exhibit. (See 
reference document HH for a copy of the exhibit.)
    \34\ See section 4(c) of ExxonMobil's 2000 exhibit. (See 
reference document HH for a copy of the exhibit.)
---------------------------------------------------------------------------

    We had three concerns with the state's empirical method for 
determining compliance with ExxonMobil's coker CO-boiler stack emission 
limits and they were as follows: (1) The empirical method did not 
apply, and hence there was no compliance monitoring method, when the 
sulfur content of the reactor feed exceeded 5.11 percent by weight. We 
believed the SIP should contain a compliance monitoring method for all 
operating scenarios; (2) The compliance monitoring equation was 
basically the ``best fit'' line through the test data. To be more 
conservative, we believed the compliance monitoring equation should be 
the upper bound of the 95% confidence level of the equation; and (3) 
Finally, since a feed-rate meter for the coker unit was required for 
the compliance monitoring method, the feed-rate meter should have been 
subject to Quality Assurance/Quality Control (QA/QC) requirements 
similar to those for the FCC feed-rate meter. Therefore, we concluded 
that the emission limits under section 3(B)(1) of ExxonMobil's 2000 
exhibit were enforceable under some but not all scenarios and did not 
satisfy the requirements of section 110(a)(2)(A) of the Act. (See 67 FR 
22242, at 22244, col. 2 (May 2, 2002).) On May 22, 2003 (68 FR 27908), 
we limitedly approved and limitedly disapproved the coker CO-boiler 
stack emission limits and method used to monitor compliance.
    ExxonMobil's 1998 exhibit requires ExxonMobil to install portable 
CEMS to monitor the SO2 and flow to the coker CO-boiler 
stack or implement an Alternative Monitoring Plan approved by the 
Department and EPA if ExxonMobil exhausts coker unit flue gas through 
the coker CO-boiler stack more than 336 hours in a calendar 
quarter.\35\ ExxonMobil exceeded the 336 hours per calendar quarter, 
and on March 20, 2002, the state required ExxonMobil to install 
SO2 and flow CEMS on the coker CO-boiler stack. On October 
21, 2002, the state sent a letter to ExxonMobil indicating that the 
reported test results of the monitors demonstrated that the 
SO2 CEMS and flow monitors met the testing requirements. 
(See reference documents T & U, respectively.)
---------------------------------------------------------------------------

    \35\ See section 6(B)(4) of ExxonMobil's 1998 exhibit (See 
reference document GG for a copy of the exhibit.)
---------------------------------------------------------------------------

    Since SO2 and flow CEMS have already been installed on 
the coker CO-boiler stack, we are proposing that these 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 are proposing 
that 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 are proposing 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 shall notify EPA in writing of each annual Relative Accuracy 
Test Audit a minimum of twenty five (25) working days prior to actual 
testing.
    We are proposing that compliance with ExxonMobil's coker CO boiler 
emission limits \36\ be determined using the data from the CEMS 
mentioned above and in accordance with the appropriate calculations 
described in

[[Page 39268]]

ExxonMobil's 1998 exhibit.\37\ We are also proposing reporting 
requirements similar to the requirements adopted in the Billings/Laurel 
SO2 SIP and those contained in 40 CFR 60.7(c).
---------------------------------------------------------------------------

    \36\ See section 3(B)(1) of ExxonMobil's 2000. (See reference 
document HH for a copy of the exhibit.)
    \37\ 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
    The state's attainment demonstration and our subsequent attainment 
modeling for the FIP assume that MSCC's flares are limited to a 
combined total of 150 pounds of SO2 per three-hour 
period.\38\ We understand that MSCC actually has three flares at the 
plant that serve a common flare system. Correspondence from MSCC, dated 
February 4, 2004, indicates that there is an 80-foot west flare, 125-
foot east flare, and 100-meter flare. (See reference document H.) In 
discussions with MSCC on March 9, 2004, we confirmed that MSCC 
understood that the state's 150 lbs of SO2/3-hour limit was 
intended to be a ``bubble'' or combined limit for all three flares. 
(See reference document V.) Therefore, in lieu of establishing a 
separate emission limit for each of the three flares, we are proposing 
one combined emission limit for the three flares. Compliance with the 
flare emission limit will be determined as discussed in Section III.A, 
above. In the event MSCC cannot monitor all three flares from a single 
monitoring location, MSCC will need to establish multiple monitoring 
locations.
---------------------------------------------------------------------------

    \38\ See Modeling discussion in Section III.E.5, below.
---------------------------------------------------------------------------

2. SRU 100-Meter Stack
    On May 2, 2002, EPA disapproved SIP emission limits the state 
established for the sulfur recovery unit (SRU) 100-meter stack because 
of improper stack height credit (see 67 FR 22168).\39\
---------------------------------------------------------------------------

    \39\ The emission limits were contained in sections 3(A)(1)(a) 
and (b) and 3(A)(3) of MSCC's 1998 exhibit. (See reference document 
II for a copy of the exhibit.)
---------------------------------------------------------------------------

    Because we disapproved the emission limits, we are proposing the 
following emission limits for the SRU 100-meter stack: emissions of 
SO2 shall not exceed (a) 3,003.1 pounds per three-hour 
period, (b) 24,025.0 pounds per calendar day, and (c) 9,088,000.0 
pounds per calendar year.\40\ The emission limits for the SRU 100-meter 
stack are based on modeling conducted by EPA to show attainment of the 
SO2 NAAQS in the Billings/Laurel area. A detailed discussion 
of the modeling is contained in Section III.E.5 of this document.
---------------------------------------------------------------------------

    \40\ Our FIP proposes to retain the calendar year emission limit 
contained in section 3(A)(1)(a)(iv) of MSCC's 1998 exhibit. (See 
reference document II.)
---------------------------------------------------------------------------

    We are also proposing that compliance with the above emission 
limits be determined according to the methods established in MSCC's 
1998 exhibit. Finally, we are proposing certain 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).
    In the Billings/Laurel SO2 SIP, the State of Montana 
adopted variable emission limits for several sources, including MSCC's 
SRU 100-meter stack, which depend on the ``buoyancy flux'' of the 
SO2 gas plume as it exits the stack. Buoyancy flux is a 
function of gas flow rate and gas temperature in the stack, which 
varies within certain parameters. While we approved variable emission 
limits for several sources, other than MSCC, we did so with 
reservations. (See our July 28, 1999, proposed rulemaking action on the 
Billings/Laurel SO2 SIP, 64 FR 40791, starting at 64 FR 
40794, col. 3, and our May 2, 2002, final rulemaking action, 67 FR 
22168, starting 67 FR 22206, col. 2, for a full discussion of our 
concerns with the variable emission limit concept.) We 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. For example, the state's original modeling effort 
to determine emissions limits that included three variable emission 
limited sources required a total of 1320 modeling runs. A conventional 
SIP modeling analysis with fixed emission limits for each source 
requires only a single modeling run. Additionally, based on actual 
emissions data for MSCC's SRU 100-meter stack for 2003, 2004 and 2005, 
MSCC can meet the fixed 3-hour and 24-hour emission limits we are 
proposing (see reference documents FFF and GGG).
3. SRU 30-Meter Stack
    On May 2, 2002, EPA limitedly approved and limitedly disapproved 
the SRU 30-meter stack emission limits because the SIP did not 
adequately limit the fuel burned in the boilers and heaters that 
exhaust through the SRU 30-meter stack, and did not provide a 
monitoring method that would make the emission limits practically 
enforceable (see 67 FR 22168, at 22171).\41\
---------------------------------------------------------------------------

    \41\ The emission limit is contained in section 3(A)(2) of 
MSCC's 1998 exhibit. (See reference document II for a copy of the 
exhibit.)
---------------------------------------------------------------------------

    Because of this limited disapproval, we are proposing that 
H2S concentrations in the fuel gas burned in the boilers and 
heaters while any boiler or heater is exhausting through the SRU 30-
meter stack be limited to 100 ppm or less, averaged over a three-hour 
period. Our information indicates that limiting H2S 
concentrations to this level should assure compliance with the SRU 30-
meter stack emission limits. Worst-case conditions would be when all 
the heaters and boilers are exhausting to the SRU 30-meter stack, 
operating at maximum heat input capacity, and using fuel with the 
lowest nominal fuel gas value. Under these conditions, MSCC would be 
using the maximum volume of fuel, and potential emissions of 
SO2 from the SRU 30-meter stack would be greatest.
    Using a heat input capacity value of 83 MM Btu/hour and a nominal 
fuel gas value of 350 Btu/scf, we determined that a limit of 100 ppm 
H2S would just ensure compliance with the SRU 30-meter 
stack's 12.0 pounds of SO2/3-hour limit.\42\ \43\ Since the 
daily and annual limits are merely multiples of the 3-hour limit, this 
concentration limit would also ensure compliance with the daily and 
annual limits.
---------------------------------------------------------------------------

    \42\ See reference documents TTT and UUU. Reference document TTT 
contains information supplied by MDEQ, including heat input 
capacities for the various heaters and boilers, and nominal fuel gas 
values. These are the values we used in our calculations in 
reference document UUU.
    \43\ The state's technical review document for MSCC's Title V 
operating permit indicates that the maximum heat input capacity for 
some of the heaters and boilers could be greater than their 
``Bigelow'' ratings (see reference document VVV). To ensure 
attainment even at potentially higher heat input capacities, we 
modeled the SRU 30-meter stack at an emission rate of 15 lbs of 
SO2/3-hours (0.63 g/s), 25% higher than the 12 lbs of 
SO2/3-hour emission limit. At 0.63 g/s, we still modeled 
attainment of the 3-hour and 24-hour SO2 NAAQS. Thus, the 
100 ppm H2S concentration would be consistent with 
attainment even if the total heat input capacity of the heaters and 
boilers were significantly higher.
---------------------------------------------------------------------------

    To determine compliance with the 100 ppm H2S limit, we 
are proposing that any time fuel other than natural gas is burned in a 
heater or boiler that exhausts to the SRU 30-meter stack, MSCC must 
measure the H2S content of the fuel burned within one hour 
from when a heater or boiler begins exhausting to the SRU 30-meter 
stack and on a once-per-three-hour-period frequency until no heater or 
boiler is exhausting to the SRU 30-meter stack. We are proposing that 
MSCC use a portable H2S monitor to determine the 
H2S content of the fuel burned. The monitor must have a 
range of 0-500 ppm of H2S and an accuracy of +/-2% of full 
scale (i.e., the design range of the monitor--in this case 500 ppm). 
(See

[[Page 39269]]

reference documents ZZ and AAA for vendor literature and discussion 
notes with vendor.)
    While we are proposing the foregoing approach for determining 
compliance with the SRU 30-meter stack emission limits, we are 
soliciting input on whether we should promulgate a different compliance 
determining method. One alternative approach would involve the 
measurement of H2S concentrations as described above, but 
would not create a concentration limit. MSCC would be required to 
install a fuel gas flow rate monitor that would measure the flow of all 
the fuel burned in the heaters and boilers, and keep logs of (a) the 
dates and time periods that emissions were exhausted through the SRU 
30-meter stack, (b) the heaters and boilers exhausting to the SRU 30-
meter stack, (c) all the heaters and boilers operating during such 
periods, and (d) the type of fuel that is burned in any heater or 
boiler at the time that emissions were exhausted to the SRU 30-meter 
stack.
    SO2 emissions from the SRU 30-meter stack would be 
calculated based on the H2S content of the fuel burned and 
the flow of the fuel to the heaters and boilers. Since the fuel flow 
meter would be installed in the fuel gas header and would measure all 
the fuel gas burned regardless of whether or not all the heaters or 
boilers were exhausting to the SRU 30-meter stack, the calculations of 
SO2 emissions from the SRU 30-meter stack would be pro-rated 
based on the estimated percentage of fuel burned in the heaters and 
boilers exhausting to the SRU 30-meter stack versus fuel burned in all 
operating heaters and boilers.
    We envision that one way to calculate this pro-ration factor would 
be to divide the maximum heat input capacity of the heaters and boilers 
exhausting to the SRU 30-meter stack by the maximum heat input capacity 
of all operating heaters and boilers during such periods. In order to 
ensure compliance with the three-hour emission limits, this pro-ration 
factor would have to be calculated on an hourly or, at most, three-
hourly basis.
    We solicit input on other possible approaches for determining 
compliance with the SRU 30-meter stack emission limits.
    Finally, we are proposing 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).
4. Combined SO2 Emission Limit From the Auxiliary Vent 
Stacks
    On May 2, 2002, EPA disapproved the combined SO2 
emission limit from the auxiliary vent stacks because the SIP did not 
restrict the sulfur content of the fuel burned in the heaters and 
boilers when they exhaust through the auxiliary vent stacks, and lacked 
a monitoring method that would make the emission limit practically 
enforceable (see 67 FR 22168, at 22171).\44\ Because of this 
disapproval, we are proposing combined SO2 emission limits 
for the auxiliary vent stacks and a method for determining compliance 
with the emission limits.
---------------------------------------------------------------------------

    \44\ The emission limits are contained in section 3(A)(4) of 
MSCC's 1998 exhibit. (See document II for a copy of the exhibit.)
---------------------------------------------------------------------------

    The emission limits we are proposing are based on the emission 
limit in MSCC's 1998 exhibit \45\ and apply to the auxiliary vent 
stacks associated with the Railroad Boiler, the H-1 Unit, the H1-A 
Unit, the H1-1 Unit, and the H1-2 Unit. The issues associated with 
monitoring compliance with these limits are essentially the same as 
those associated with monitoring compliance with the SRU 30-meter stack 
emission limits (see 67 FR 22168, at 22202, May 2, 2002, reference 
document AA). Thus, we are proposing the same approach for monitoring 
compliance with these emission limits as we describe in section 
III.E.3, above--H2S concentrations in the fuel gas burned in 
the boilers and heaters while any boiler or heater is exhausting to the 
auxiliary vent stacks would be limited to 100 ppm or less, averaged 
over a three-hour period, and the same monitoring requirements would 
apply. Similarly, we are soliciting input on whether we should 
promulgate a different compliance determining method, as described in 
section III.E.3 above.
---------------------------------------------------------------------------

    \45\ The emission limit is contained in section 3(A)(4) of 
MSCC's 1998 exhibit. (See document II for a copy of the exhibit.)
---------------------------------------------------------------------------

    Finally, we are proposing quarterly reporting requirements. The 
quarterly reporting requirements are similar to reporting requirements 
contained in the Billings/Laurel SO2 SIP and those contained 
in 40 CFR 60.7(c).
5. Modeling To Support Emission Limits
    To establish MSCC's SRU 100-meter stack emission limits, EPA re-ran 
Montana's 1996 SIP modeling analysis with some modifications explained 
below. Our intent was to retain the state's original attainment 
modeling analysis (which supports the emission limits established for 
sources in the Billings/Laurel SO2), but modify the files as 
necessary to establish SO2 emission limits at MSCC's SRU 
100-meter stack based on a 65 meter stack height credit and a fixed 
buoyancy flux. We used the same dispersion model that the state used 
(per EPA 1996 modeling guidance (i.e., ISC2/Complex1)) and the same 
meteorological data.
    There were several minor modeling input changes made for some of 
the sources. In December 2003, EPA sent letters (pursuant to section 
114 of the Act) to all of the sources in the Billings/Laurel area 
requesting clarification on the appropriate emission point parameters 
for modeling. (See reference documents L through R.) Based on the 
responses to the 114 letters, we modified some of the emission point 
modeling parameters contained in the state's modeling analysis. The 
June 2006 Technical Support Document titled ``Dispersion Modeling to 
Support Sulfur Dioxide (SO2) Emission Limits in Federal 
Implementation Plan (FIP) for Billings/Laurel, Montana'' (see reference 
document WW) identifies the emission point modeling parameters used in 
our modeling analysis. The document also identifies changes that were 
recommended by sources but for various reasons were not incorporated 
into EPA's modeling. An electronic record (CD) of EPA's modeling input 
and output files is contained in the docket (see reference document 
EEE).
    In the state's 1996 modeling, MSCC's SRU 100-meter stack was 
modeled with a 97 meter stack height credit and a variable emission 
limit linked to 10 stack buoyancy flux values. We modeled MSCC's SRU 
100-meter stack with a 65 meter stack height credit and a single 
representative buoyancy flux value. Buoyancy flux is a function of gas 
flow rate and temperature in the stack. The stack temperature we used 
in our modeling, 540.0[deg]K, was the mean stack temperature measured 
with CEMS from October 1, 2001, to September 30, 2003. The mean stack 
velocity we used in our modeling, 14.0 m/s, was back-calculated from 
the buoyancy flux equation using the buoyancy flux and temperature 
values from October 1, 2001, to September 30, 2003.\46\ \47\ It is 
EPA's modeling practice to select mean values from historical data 
because, unless there is some change in plant

[[Page 39270]]

configuration, future operations are likely to reflect similar values.
---------------------------------------------------------------------------

    \46\ The buoyancy flux (F) is defined as: F = (2.45 
VD2 (Ts-T))/Ts. Where: F = buoyancy 
flux in m4/m3; V = stack gas exit velocity in 
meters per second at actual conditions; D = inside stack-top 
diameter in meters (1.07 m); Ts = stack gas temperature 
in Kelvin; and T = ambient air temperature in Kelvin (assumed at 
281.2 [deg]K). (See reference document II)
    \47\ See reference document FFF for temperature and buoyancy 
flux values.
---------------------------------------------------------------------------

    It should be noted that with the changes mentioned above, the 24-
hour highest receptor point modeled showed the 24-hour and 3-hour 
SO2 high-second-high (HSH) values to be 365 [mu]g/m\3\ and 
1243.6 [mu]g/m\3\, respectively. The 3-hour highest receptor point 
modeled showed the 3-hour SO2 HSH value to be 1291.5 [mu]g/
m\3\. The SO2 24-hour and 3-hour SO2 NAAQS are 
365 [mu]g/m\3\ and 1300 [mu]g/m\3\, respectively. Therefore, the FIP 
shows attainment of the NAAQS.
    When we modeled the four process flares at 500 lbs/3-hour period 
instead of 150 lbs/3-hour period, the 3-hour HSH concentration at the 
highest 3-hour receptor point only increased by 2 [mu]g/m\3\, to 1293.5 
[mu]g/m\3\. This means that even if the four process flares were 
allowed to emit SO2 at 500 lbs/3-hour period, the FIP would 
still show attainment of the 3-hour NAAQS. (We modeled this alternative 
emissions rate because, as discussed earlier, we are inviting comment 
on whether we should consider an emissions limit for the process flares 
of 500 lbs SO2/calendar day instead of 150 lbs/3-hour 
period. We modeled the 500 pounds of SO2 emissions over a 3-
hour period to ensure attainment of the 3-hour SO2 NAAQS.)
    In the state's modeling analysis submitted with the SIP, the 
highest receptor point modeled had 24-hour and 3-hour HSH 
SO2 values of 354 [mu]g/m\3\ and 1245 [mu]g/m\3\, 
respectively. This difference in FIP and SIP modeling outputs is due 
largely to the fact that EPA modeled MSCC's 100-meter SRU stack at 65 
meters. In addition, in their responses to the section 114 letters 
mentioned above, some sources provided updated locations of emission 
points. (It was not that emission points had moved; the technology used 
to describe the emission point locations had changed.) Therefore, peak 
receptor locations changed in the FIP versus SIP modeling.

IV. Request for Public Comment

    EPA is soliciting public comment on all aspects of this proposed 
FIP. Interested parties should submit comments according to the 
procedures outlined earlier in the ADDRESSES section and in Part (I)(A) 
of the SUPPLEMENTARY INFORMATION section. Comments received on or 
before September 11, 2006 will be considered in the final action taken 
by EPA.

V. 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 proposed FIP is not subject to OMB review under E.O. 12866 
because it applies to only four specifically named facilities 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

    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 * * *'' 44 U.S.C. 3502(3)(A). Because the proposed 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. Sec. Sec.  603, 604 and 605(b).
    This proposed FIP will not have a significant economic impact on a 
substantial number of small entities because this proposed 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 for which EPA 
published a notice of proposed rulemaking, if those rules contain 
``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. If section 202 
requires a written statement, section 205 of UMRA generally requires 
EPA to identify and consider a reasonable number of regulatory 
alternatives. Under section 205, EPA must adopt the least costly, most 
cost-effective, or least burdensome alternative that achieves the 
objectives of the rule, unless the Administrator publishes with the 
final rule an explanation why EPA did not adopt that alternative. The 
provisions of section 205 do not apply when they are inconsistent with 
applicable law. Section 204 of UMRA requires EPA to develop a process 
to allow elected officers of state, local, and tribal governments (or 
their designated, authorized employees), to provide meaningful and 
timely input in the development of EPA regulatory proposals containing 
significant Federal intergovernmental mandates.
    EPA has determined that the proposed FIP contains no federal 
mandates on state, local or tribal governments, because it will not 
impose any enforceable duties on any of these entities. EPA further has 
determined that the proposed FIP will not result in the expenditure of 
$100 million or more by the private sector in any one year. Although 
the proposed 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. Consequently, sections 202, 204, and 205 of UMRA do not 
apply to the proposed FIP.
    Before EPA establishes any regulatory requirements that might 
significantly or uniquely affect small 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

[[Page 39271]]

intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    EPA has determined that the proposed FIP will not significantly or 
uniquely affect small governments, because it imposes no requirements 
on small governments. Therefore, the requirements of section 203 do not 
apply to the proposed FIP.

E. Executive Order 13132, Federalism

    Executive Order 13132, Federalism (64 FR 43255, August 10, 1999), 
revokes and replaces Executive Orders 12612 (Federalism) and 12875 
(Enhancing the Intergovernmental Partnership). Executive Order 13132 
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 proposed rule does not have federalism implications. This FIP 
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 proposes 
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.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communication between EPA and State and local 
governments, EPA specifically solicits comments on the proposed rule 
from State and local officials.

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 proposed rule does not have tribal implications, as specified 
in Executive Order 13175. It will not have substantial direct effects 
on tribal governments, on the relationship between the Federal 
government and Indian tribes, or on the distribution of power and 
responsibilities between the Federal government and Indian tribes as 
specified in Executive Order 13175. This Action does not involve or 
impose any requirements that affect Indian Tribes. Thus, Executive 
Order 13175 does not apply to this rule.
    EPA specifically solicits comment on this proposed rule from tribal 
officials.

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

    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 proposed 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 proposed 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

    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 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.
    While the proposed rulemaking involves technical standards, no 
voluntary consensus standards have been identified. EPA welcomes 
comments on this aspect of the proposed FIP and, specifically, invites 
the public to identify potentially-applicable voluntary consensus 
standards and to explain why such standards should be used in this 
regulation.

List of Subjects in 40 CFR Part 52

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

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

    Dated: June 29, 2006.
Kerrigan G. Clough,
Acting Regional Administrator, Region 8.

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

PART 52--[AMENDED]

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

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

Subpart BB--Montana

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

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

    (a) Applicability. This section applies to the owner(s) or 
operator(s), including any new owner(s) or operator(s) in the event of 
a change in ownership or operation, of the following facilities in the 
Billings/Laurel, Montana area: CHS Inc. Petroleum Refinery, Laurel 
Refinery, 803 Highway 212 South, Laurel, MT; ConocoPhillips Petroleum 
Refinery, Billings Refinery, 401 South 23rd St., Billings, MT; 
ExxonMobil Petroleum Refinery, 700 ExxonMobil Road, Billings, MT; and 
Montana

[[Page 39272]]

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) 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.

    (2) Calendar Day means a 24-hour period starting at 12:00 midnight 
and ending at 12:00 midnight, 24 hours later.
    (3) 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 through 
twelve.
    (4) 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.
    (5) Daily Emissions (i) means the amount of SO2 emitted 
in a calendar day, expressed in pounds per day rounded to the nearest 
tenth of a pound.

Where:

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

    (ii) Each calendar day is comprised of eight non-overlapping three-
hour periods. The three hour emissions from all the three-hour periods 
in a calendar day shall be used to determine the day's emissions.
    (6) Exhibit means for a given facility named in 40 CFR 52.1392(a), 
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.
    (7) 1998 Exhibit means for a given facility named in 40 CFR 
52.1392(a), the exhibit adopted by the Montana Board of Environmental 
Review on June 12, 1998.
    (8) 2000 Exhibit means for a given facility named in 40 CFR 
52.1392(a), the exhibit adopted by the Montana Board of Environmental 
Review on March 17, 2000.
    (9) 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.
    (10) The initials Hg mean mercury.
    (11) Hourly means or refers to each clock hour in a calendar day.
    (12) 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 and source per clock hour.
    Exclusive of the above definition, an hourly average may be 
determined with two valid and complete 15-minute data blocks, for two 
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.
    (13) Hourly Emissions means the pounds per clock hour of 
SO2 emissions from a source (flare, stack, fuel oil system, 
sour water system, or fuel gas system) determined using hourly averages 
and rounded to the nearest tenth of a pound.
    (14) The initials H2S mean hydrogen sulfide.
    (15) The initials MBER mean the Montana Board of Environmental 
Review.
    (16) The initials MDEQ mean the Montana Department of Environmental 
Quality.
    (17) The initials mm mean millimeters.
    (18) The initials MSCC mean the Montana Sulphur & Chemical Company.
    (19) The initials ppm mean parts per million.
    (20) The initials SCFH mean standard cubic feet per hour.
    (21) The initials SCFM mean standard cubic feet per minute.
    (22) Standard Conditions means (a) 20 [deg]C (293.2 [deg]K, 527.7 
[deg]R, or 68.0 [deg]F) and 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 1 atmosphere 
pressure (29.92 inches Hg or 760 mm Hg) for refinery fuel gas emission 
calculations.
    (23) The initials SO2 mean sulfur dioxide.
    (24) The initials SWS mean sour water stripper.
    (25) Three hour emissions means the amount of SO2 
emitted in each of the eight non-overlapping three-hour periods in a 
calendar day, expressed in pounds and rounded to the nearest tenth of a 
pound.

Where:

Three hour emissions = [Sigma] Hourly emissions within the three hour 
period.

    (26) Three hour period means any of the eight non-overlapping 
three-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.
    (27) 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.
    (28) Valid means data that is 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 40 CFR 
52.1392.
    (d) CHS Inc. emission limits and compliance determining methods.
    (1) Introduction: The provisions for CHS Inc. cover the following 
units:
    (i) The flare.
    (ii) Combustion sources, which consist of those sources identified 
in the combustion sources emission limit in section 3(A)(1)(d) of CHS 
Inc.'s 1998 exhibit.
    (2) Flare requirements: (i) Emission limit: The total emissions of 
SO2 from the flare shall not exceed 150.0 pounds per three 
hour period.
    (ii) Compliance determining method: Compliance with the emission 
limit in 40 CFR 52.1392(d)(2)(i) shall be determined in accordance with 
40 CFR 52.1392(h).
    (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

[[Page 39273]]

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 40 CFR 52.1392(d)(3)(i).
    (4) Data reporting requirements: (i) CHS Inc. shall submit 
quarterly reports beginning with the first calendar quarter following 
[DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE Federal 
Register]. The quarterly reports shall be submitted within 30 days of 
the end of each calendar quarter. The quarterly reports shall be 
submitted to the Air Program Contact at EPA's 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 format shall 
consist of both a comprehensive electronic-magnetic report and a 
written hard copy data summary report.
    (ii) The electronic report submitted to the EPA shall be on 
magnetic or optical media, and such submittal shall follow the 
reporting format of electronic data being submitted to the MDEQ. The 
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 the EPA, CHS Inc. shall 
also record, organize and archive for at least five years the same 
data, and upon request by the EPA, CHS Inc. shall provide the EPA with 
any data archived in accordance with this provision. The electronic 
report shall contain the following:
    (A) Hourly average total sulfur concentrations in ppm in the gas 
stream to the flare;
    (B) Hourly average volumetric flow rates in SCFH of the gas stream 
to the flare;
    (C) Hourly average temperature (in (F) and pressure (in mm or 
inches of Hg) of the gas stream to the flare;
    (D) Hourly emissions from the flare in pounds per clock hour; and
    (E) Daily calibration data for flare CEMS.
    (iii) The quarterly written report format submitted to the EPA 
shall contain the following information:
    (A) Three hour emissions in pounds per three hour period from the 
flare;
    (B) The results of the quarterly Cylinder Gas Audits (CGA) or 
Relative Accuracy Audits (RAA) required by 40 CFR part 60, Appendix F, 
and the annual Relative Accuracy Test Audit (RATA) for the total sulfur 
analyzer(s);
    (C) For all periods of flare volumetric flow rate monitoring system 
or total sulfur analyzer system downtime, the written report shall 
identify:
    (1) Dates and times of downtime;
    (2) Reasons for downtime; and
    (3) Corrective actions taken to mitigate downtime;
    (D) For each three 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 three hour emissions;
    (3) All information regarding reasons for operating with excess 
emissions; and
    (4) Corrective actions taken to mitigate excess emissions.
    (E) For all periods that the range of the volumetric flare flow 
rate monitor(s) is (are) exceeded, the quarterly written report shall 
identify:
    (1) Date and time when the range of the flare volumetric flow 
monitor(s) is (are) exceeded and
    (2) The reliable estimation parameters used to determine flow in 
the gas stream to the flare and how the estimation parameters were 
derived.
    (F) The date and time of any noncompliance with the requirements of 
40 CFR 52.1392(d)(3)(i).
    (G) When no excess emissions have occurred or the continuous 
monitoring 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) 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 three 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 three hour period, 
600.0 pounds per calendar day, and 219,000 pounds per calendar year. At 
any one time, ConocoPhillips may only vent emissions from either the 
Jupiter Sulfur SRU flare or the Jupiter Sulfur SRU/ATS stack, but not 
both simultaneously.
    (ii) Compliance determining method: (A) Compliance with the 
emission limit in 40 CFR 52.1392(e)(2)(i)(A) shall be determined in 
accordance with 40 CFR 52.1392(h). In the event that a single 
monitoring location cannot be used for both the north and south main 
flare, ConocoPhillips shall monitor the flow and measure the total 
sulfur concentration at more than one location in order to determine 
compliance with the main flare emission limit. ConocoPhillips shall log 
and report any instances when emissions are vented from the north main 
flare and south main flare simultaneously.
    (B) Compliance with the emission limits and requirements in 40 CFR 
52.1392(e)(2)(i)(B) shall be determined pursuant to ConocoPhillips' 
1998 exhibit (see section 4(A) of the exhibit) for the Jupiter Sulfur 
SRU/ATS stack and in accordance with 40 CFR 52.1392(h) for the Jupiter 
Sulfur SRU flare. ConocoPhillips shall log and report any instances 
when emissions are vented from the Jupiter Sulfur SRU flare and the 
Jupiter Sulfur SRU/ATS stack simultaneously.
    (3) Data reporting requirements: (i) ConocoPhillips shall submit 
quarterly reports on a calendar year basis, beginning with the first 
calendar quarter following [DATE 30 DAYS AFTER PUBLICATION OF THE FINAL 
RULE IN THE Federal Register]. The quarterly reports shall be submitted 
within 30 days of the end of each calendar quarter. The quarterly 
reports shall be submitted to the Air Program Contact at EPA's 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 format shall consist of both a comprehensive electronic-magnetic 
report and a written hard copy data summary report.
    (ii) The electronic report submitted to the EPA shall be on 
magnetic or optical media, and such submittal shall follow the 
reporting format of electronic data being submitted to the MDEQ. The 
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 the EPA, 
ConocoPhillips shall also record, organize and archive for at least 
five years the same data, and upon request by the EPA, ConocoPhillips 
shall provide the EPA with any data archived in accordance with this 
provision. The electronic report shall contain the following:

[[Page 39274]]

    (A) Hourly average total sulfur concentrations in ppm in the gas 
stream to the ConocoPhillips main flare and Jupiter Sulfur SRU flare;
    (B) Hourly average volumetric flow rates in SCFH of the gas streams 
to the ConocoPhillips main flare and Jupiter Sulfur SRU flare;
    (C) 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;
    (D) Hourly emissions in pounds per clock hour from the 
ConocoPhillips main flare and Jupiter Sulfur SRU flare; and
    (E) Daily calibration data for the flare CEMS.
    (iii) The quarterly written report submitted to the EPA shall 
contain the following information:
    (A) Three hour emissions in pounds per three hour period from the 
ConocoPhillips main flare and Jupiter Sulfur SRU flare;
    (B) The results of the quarterly Cylinder Gas Audits (CGA) or 
Relative Accuracy Audits (RAA) required by 40 CFR part 60, Appendix F, 
and the annual Relative Accuracy Test Audit (RATA) for total sulfur 
analyzer(s);
    (C) For all periods of flare volumetric flow rate monitoring system 
or total sulfur analyzer system downtime, the written report shall 
identify:
    (1) Dates and times of downtime;
    (2) Reasons for downtime; and
    (3) Corrective actions taken to mitigate downtime;
    (D) For each three 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 three hour emissions;
    (3) All information regarding reasons for operating with excess 
emissions; and
    (4) Corrective actions taken to mitigate excess emissions.
    (E) For all periods that the range of the volumetric flare flow 
rate monitor(s) is (are) exceeded, the quarterly written report shall 
identify:
    (1) Date and time when the range of the flare volumetric flow 
monitor(s) is (are) exceeded and
    (2) The reliable estimation parameters used to determine flow in 
the gas stream(s) to the flare and how the estimation parameters were 
derived.
    (F) Identification of dates, times, and duration of any instances 
when emissions are vented from the north and south main flares 
simultaneously or from the Jupiter Sulfur SRU flare and the Jupiter 
Sulfur SRU/ATS stack simultaneously.
    (G) When no excess emissions have occurred or the continuous 
monitoring 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 30-40 days every five to 
six 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 three hour period.
    (ii) Compliance determining method: Compliance with the emission 
limit in 40 CFR 52.1392(f)(2)(i) shall be determined in accordance with 
40 CFR 52.1392(h). If volumetric flow monitoring device(s) installed 
and concentration monitoring methods used to measure the gas stream to 
the Primary Process flare cannot measure the gas stream to the 
Turnaround flare, ExxonMobil may apply to EPA for alternative measures 
to determine the volumetric flow rate and total sulfur concentration of 
the gas stream to the Turnaround flare. Before EPA will approve such 
alternative measures, ExxonMobil must agree that the Turnaround flare 
will be used only during refinery turnarounds of limited duration and 
frequency--no more than 60 days once every five 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 40 
CFR 52.1392(f)(3)(i), 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 40 CFR 
52.1392(f)(3)(ii)(B) and calculate the emissions according to the 
equations in 40 CFR 52.1392(f)(3)(ii)(C).
    (B) Within 4 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-three-hour-period frequency using the 
Tutwiler method contained in 40 CFR 60.648. ExxonMobil shall continue 
to use the Tutwiler 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 three-hour period.
    (C) When the Tutwiler method is required, SO2 emissions 
from refinery fuel gas combustion shall be calculated as follows: the 
Hourly emissions shall be calculated using equation 1, Three 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 = Fuel gas H2S concentration in ppm 
determined by the Tutwiler method as required by 40 CFR 
52.1392(f)(3)(ii)(B) (since only one sample is taken every three (3) 
hours, the value for such sample shall be substituted for each hour 
of the 3-hour period during which the sample is taken); 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 three hour emissions) = 
[Sigma] (Hourly

[[Page 39275]]

emissions within the three-hour period as determined by equation 1).
Equation 3: (Refinery fuel gas combustion daily emissions) = [Sigma] 
(Three 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 40 CFR 52.1392(f)(4)(i) shall be 
determined by measuring the SO2 concentration and flow rate 
in the coker CO-boiler stack according to the procedures in 40 CFR 
52.1392(f)(4)(ii)(B) and (C) and calculating emissions according to the 
equations in 40 CFR 52.1392(f)(4)(ii)(D).
    (B) Beginning on [DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE 
IN THE Federal Register], ExxonMobil shall at all times operate and 
maintain a CEMS to measure sulfur dioxide concentrations in the coker 
CO-boiler stack. This CEMS shall achieve a temporal sampling resolution 
of at least one concentration measurement per minute, meet the 
requirements expressed in the definition of ``hourly average'' in 40 
CFR 52.1392(c)(12), and meet the CEMS Performance Specifications 
contained in section 6(C) of ExxonMobil's 1998 exhibit, except that 
ExxonMobil shall also notify EPA in writing of each annual Relative 
Accuracy Test Audit a minimum of twenty-five (25) working days prior to 
actual testing.
    (C) Beginning on [DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE 
IN THE Federal Register], ExxonMobil shall at all times operate and 
maintain a continuous stack flow rate monitor to measure the stack gas 
flow rates in the coker CO-boiler stack. This CEMS shall achieve a 
temporal sampling resolution of at least one flow rate measurement per 
minute, meet the requirements expressed in the definition of ``hourly 
average'' in 40 CFR 52.1392(c)(12), and meet the Stack Gas Flow Rate 
Monitor Performance Specifications of section 6(D) of ExxonMobil's 1998 
exhibit, except that ExxonMobil shall also notify EPA in writing of 
each annual Relative Accuracy Test Audit a minimum of twenty-five (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 
[DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE Federal 
Register]. The quarterly reports shall be submitted within 30 days of 
the end of each calendar quarter. The quarterly reports shall be 
submitted to the Air Program Contact at EPA's 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 format shall 
consist of both a comprehensive electronic-magnetic report and a 
written hard copy data summary report.
    (ii) The electronic report submitted to the EPA shall be on 
magnetic or optical media, and such submittal shall follow the 
reporting format of electronic data being submitted to the MDEQ. The 
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 the EPA, ExxonMobil 
shall also record, organize and archive for at least five years the 
same data, and upon request by the EPA, ExxonMobil shall provide the 
EPA with any data archived in accordance with this provision. The 
electronic report shall contain the following:
    (A) Hourly average total sulfur concentrations in ppm in the gas 
stream to the flare(s);
    (B) Hourly average SO2 concentrations in ppm from the 
coker CO-boiler stack;
    (C) Hourly average volumetric flow rates in SCFH in the gas stream 
to the flare(s) and in the coker CO-boiler stack;
    (D) Hourly average H2S concentrations in ppm from the 
refinery fuel gas system;
    (E) Hourly average refinery fuel gas combustion units' actual fuel 
firing rate in SCFH;
    (F) Hourly average temperature (in [deg]F) and pressure (in mm or 
inches of Hg) of the gas stream to the flare(s);
    (G) Hourly emissions in pounds per clock hour from the flare(s), 
coker CO-boiler stack, and refinery fuel gas combustion system;
    (H) Daily calibration data for the CEMS required by 40 CFR 
52.1392(f)(2)(ii), (f)(3)(ii) and (f)(4)(ii).
    (iii) The quarterly written report submitted to the EPA shall 
contain the following information:
    (A) Three hour emissions in pounds per three hour period from the 
flares, coker CO-boiler stack, and refinery fuel gas combustion system;
    (B) Daily emissions in pounds per calendar day from the coker CO-
boiler stack and refinery fuel gas combustion system;
    (C) The results of the quarterly Cylinder Gas Audits (CGA) or 
Relative Accuracy Audits (RAA) required by 40 CFR part 60, Appendix F, 
and the annual Relative Accuracy Test Audit (RATA) for the CEMS 
required by 40 CFR 52.1392(f)(2)(ii) (total sulfur analyzer(s) only), 
(f)(3)(ii) and (f)(4)(ii);
    (D) For all periods of flare volumetric flow rate monitoring system 
or concentration analyzer system downtime, coker CO-boiler stack CEMS 
downtime, or refinery fuel gas combustion system CEMS downtime, the 
written report shall identify:
    (1) Dates and times of downtime;
    (2) Reasons for downtime; and
    (3) Corrective actions taken to mitigate downtime;
    (E) For each three 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 three 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.
    (F) For all periods that the range of the volumetric flare flow 
rate monitor(s) is (are) exceeded, the quarterly written report shall 
identify:
    (1) Date and time when the range of the flare volumetric flow 
monitor(s) is (are) exceeded and
    (2) The reliable estimation parameters used to determine flow in 
the gas stream to the flare and how the estimation parameters were 
derived.
    (G) When no excess emissions have occurred or the continuous 
monitoring 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 which consist of the vent stacks 
associated

[[Page 39276]]

with 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. 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 three hour 
period.
    (ii) Compliance determining method: Compliance with the emission 
limit in 40 CFR 52.1392(g)(2)(i) shall be determined in accordance with 
40 CFR 52.1392(h). 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) 3,003.1 pounds per three hour period,
    (B) 24,025.0 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 40 CFR 52.1392(g)(3)(i) 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 40 CFR 52.1392(g)(3)(ii)(A) shall 
achieve a temporal sampling resolution of at least one concentration 
and flow rate measurement per minute, meet the requirements expressed 
in the definition of ``hourly average'' in 40 CFR 52.1392(c)(12), 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 twenty five (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 three 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 gas 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 100 ppm per three hour period.
    (ii) Compliance determining method: (A) Compliance with the 
emission limits in 40 CFR 52.1392(g)(4)(i) 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 40 CFR 
52.1392(g)(4)(ii)(C).
    (B) Beginning [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN 
THE Federal Register], 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 [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN 
THE Federal Register], 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 hour from when a heater or boiler begins exhausting 
to an auxiliary vent stack and on a once-per-three-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 a portable H2S monitor with a range of 0--500 ppm 
of H2S and an accuracy of ( 2% of 500 ppm. H2S 
concentrations shall be measured on an actual wet basis in ppm.
    (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 three 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 gas burned in the 
heaters and boilers identified in 40 CFR 52.1392(g)(1)(iv) while any of 
these units is exhausting to the SRU 30-meter stack shall not exceed 
100 ppm per three hour period.
    (ii) Compliance determining method: (A) Compliance with the 
emission limits in 40 CFR 52.1392(g)(5)(i) shall be determined by 
measuring the H2S concentration of the fuel burned in the 
heaters and boilers identified in 40 CFR 52.1392(g)(1)(iv) (when fuel 
other than natural gas is burned in one or more of these heaters or 
boilers) according to the procedures in 40 CFR 52.1392(g)(5)(ii)(C).
    (B) Beginning [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN 
THE Federal Register], 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 [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN 
THE Federal Register], 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 hour from when any heater or boiler begins exhausting 
to the SRU 30-meter stack and on a once-per-three-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 
a portable H2S monitor with a range of 0--500 ppm of 
H2S and an accuracy of +/-2% of 500 ppm. H2S 
concentrations shall be measured on an actual wet basis in ppm.
    (6) Data reporting requirements: (i) MSCC shall submit quarterly 
reports beginning with the first calendar quarter following [DATE 30 
DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE Federal Register]. The 
quarterly reports shall be submitted within 30 days of the end of each 
calendar quarter. The quarterly reports shall be submitted to Air 
Program Contact at EPA's 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 format shall consist of both a 
comprehensive electronic-magnetic report and a written hard copy data 
summary report.
    (ii) The electronic report submitted to the EPA shall be on 
magnetic or optical media, and such submittal shall follow the 
reporting format of electronic data

[[Page 39277]]

being submitted to the MDEQ. The 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 the EPA, MSCC shall also record, organize and archive for at 
least five years the same data, and upon request by the EPA, MSCC shall 
provide the EPA with any data archived in accordance with this 
provision. The electronic report shall contain the following:
    (A) Hourly average total sulfur concentrations in ppm, in the gas 
stream to the flare(s);
    (B) Hourly average SO2 concentrations in ppm from the 
SRU 100-meter stack.
    (C) Hourly average volumetric flow rates in SCFH in the gas stream 
to the flare(s) and in the SRU 100-meter stack;
    (D) Hourly average temperature (in [deg]F) and pressure (in mm or 
inches of Hg) in the gas stream to the flare(s);
    (E) Hourly emissions in pounds per clock hour from the flare(s) and 
SRU 100-meter stack;
    (F) Daily calibration data for flare CEMS, and the SRU 100-meter 
stack CEMS;
    (iii) The quarterly written report submitted to the EPA shall 
contain the following information:
    (A) Three hour emissions in pounds per three hour period from the 
flares and SRU 100-meter stack, and three hour H2S 
concentrations in the fuel gas burned in the heaters and boilers 
identified in 40 CFR 52.1392(g)(1)(iii) and (iv) 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) Daily emissions in pounds per calendar day from the SRU 100-
meter stack;
    (C) Annual emissions of SO2 in pounds per calendar year 
from the SRU 100-meter stack;
    (D) The results of the quarterly Cylinder Gas Audits (CGA) or 
Relative Accuracy Audits (RAA) required by 40 CFR part 60, Appendix F, 
the annual Relative Accuracy Test Audit (RATA) for total sulfur 
analyzer(s) and for the SRU 100-meter stack CEMS;
    (E) For all periods of flare volumetric flow rate monitoring system 
or concentration analyzer system downtime, SRU 100-meter CEMS downtime, 
or failure to obtain an H2S concentration sample as required 
by 40 CFR 52.1392(g)(4)(ii)(C) and (g)(5)(ii)(C), the written report 
shall identify:
    (1) Dates and times of downtime or failure;
    (2) Reasons for downtime or failure; and
    (3) Corrective actions taken to mitigate downtime or failure;
    (F) For each three 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 three 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.
    (G) For all periods that the range of the volumetric flare flow 
rate monitor(s) is (are) exceeded, the quarterly written report shall 
identify:
    (1) Date and time when the range of the flare volumetric flow 
monitor(s) is (are) exceeded and
    (2) The reliable estimation parameters used to determine flow in 
the gas stream to the flare and how the estimation parameters were 
derived.
    (H) Identification of dates:
    (1) The dates and time periods that emissions are exhausted through 
the auxiliary vent stacks or the 30-meter stack;
    (2) The heaters and boilers that are 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.
    (I) When no excess emissions have occurred, the continuous 
monitoring system(s) have not been inoperative, repaired, or adjusted, 
or all H2S concentration samples for the heaters and boilers 
have been taken as required, such information shall be stated in the 
report.
    (h) Flare compliance determining method:
    (1) Compliance with the emission limits in 40 CFR 52.1392(d)(2)(i), 
(e)(2)(i), (f)(2)(i) and (g)(2)(i) shall be determined by measuring the 
total sulfur concentration and volumetric flow rate of the gas stream 
to the flare(s) (corrected to 1 atmosphere pressure and 68 [deg]F) and 
using the methods contained in the flare monitoring plan required by 40 
CFR 52.1392(h)(5). Volumetric gas stream flow rate to the flare(s) 
shall be determined in accordance with the requirements in 40 CFR 
52.1392(h)(2) and the total sulfur concentration of the gas stream to 
the flare(s) shall be determined in accordance with 40 CFR 
52.1392(h)(3).
    (2) Flare flow monitoring: (i) Within 180 days after receiving EPA 
approval of the flare monitoring plan required by 40 CFR 52.1392(h)(5), 
each facility named in 40 CFR 52.1392(a) shall install and calibrate, 
and thereafter calibrate, maintain and operate, a continuous flow 
monitoring system capable of measuring the total volumetric flow of the 
gas stream to the flare(s) over the full range of operation. The flow 
monitoring system may require one or more flow monitoring devices or 
flow measurements at one or more locations 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., such as upset conditions) it is possible for the flow to 
the flare to exceed the range of the monitor. In such cases, reliable 
flow estimation parameters may 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 reliable 
estimation parameters are used and how such parameters were derived.
    (iii) The flare gas stream volumetric flow rate shall be measured 
on an actual wet basis 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% over the range of 1 
to 275 fps. The volumetric flow monitor(s) shall feature automated 
daily calibrations at low and high ranges. The volumetric flow monitors 
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. The temperature and pressure shall be 
monitored in the same location as the flow monitoring device(s) and 
shall be calibrated to meet accuracy specifications as follows: 
temperature shall be calibrated annually to within 2.0% at 
absolute temperature and the pressure monitor shall be calibrated 
annually to within 5.0 mmHg.
    (v) The flow monitoring device(s) shall be initially calibrated, 
prior to installation, to demonstrate accuracy to within 5.0% at flow 
rates equivalent to 30%, 60% and 90% of monitor full scale.

[[Page 39278]]

    (vi) Each flow monitoring device shall achieve a temporal sampling 
resolution of at least one flow rate measurement per minute, meet the 
requirements expressed in the definition of hourly average in 40 CFR 
52.1392(c)(12), 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.
    (3) Flare concentration monitoring:
    (i) Within 180 days after receiving EPA approval of the flare 
monitoring plan required by 40 CFR 52.1392(h)(5), each facility named 
in 40 CFR 52.1392(a) 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(s) that is (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. The concentration 
monitoring system may require one or more concentration monitoring 
devices or concentration measurements at one or more locations if one 
monitor cannot measure the total sulfur concentration to each flare.
    (ii) The total sulfur analyzer(s) shall achieve a temporal sampling 
resolution of at least one concentration measurement per fifteen 
minutes, meet the requirements expressed in the definition of ``hourly 
average'' in 40 CFR 52.1392(c)(12), 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.
    (iii) Each affected facility named in 40 CFR 52.1392(a) 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 twenty-five 
(25) working days prior to the actual testing.
    (4) Calculation of SO2 emissions from flares. Methods for 
calculating hourly and three hour SO2 emissions from flares 
shall be submitted with the flare monitoring plan discussed in 40 CFR 
52.1392(h)(5).
    (5) By [DATE 180 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE 
Federal Register], each facility named in 40 CFR 52.1392(a) 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) Information regarding pilot and purge gas for each flare; what 
is used for pilot and purge gas and how the concentration and 
volumetric flow rate monitors are analyzing the pilot and purge gases.
    (iii) 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, ignition system, assist 
system, water seal, knockout drum and molecular seal.
    (iv) A representative flow diagram showing the interconnections of 
the flare system(s) with vapor recovery system(s), process units and 
other equipment as applicable.
    (v) A complete description of the assist system process control, 
flame detection system and pilot ignition system.
    (vi) A complete description of the gas flaring process for an 
integrated gas flaring system that describes the method of operation of 
the flares.
    (vii) 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.
    (viii) Drawing(s) with dimensions, preferably to scale, showing the 
following information for proposed flare gas stream monitoring system:
    (A) Sampling locations; and
    (B) Flow monitoring device and total sulfur analyzer locations and 
the methods used to determine the locations.
    (ix) A detailed description of manufacturer's specifications, 
including but not limited to, make, model, type, range, precision, 
accuracy, calibration, maintenance, a quality assurance procedure and 
any other relevant specifications and information referenced in 40 CFR 
52.1392(h)(2) and (3) for all existing and proposed flow monitoring 
devices and total sulfur analyzers.
    (x) A complete description of the proposed data recording, 
collection and management and any other relevant specifications and 
information referenced in 40 CFR 52.1392(h)(2) and (3) for each flare 
monitoring system.
    (xi) A complete description of the proposed method to determine, 
monitor and record total volume and total sulfur concentration of gases 
combusted in the flare.
    (xii) A complete description of the method and equations used to 
calculate the amount of total sulfur, including all conversion factors. 
The total sulfur concentrations will be used in the methods referenced 
in 40 CFR 52.1392(h)(4) to determine compliance with the three-hour 
emission limit.
    (xiii) A schedule for the installation and operation of each flare 
monitoring system consistent with the deadline in 40 CFR 52.1392(h)(2).
    (xiv) A complete description of the methods to be used to estimate 
flare emissions when either the flow monitoring device or total sulfur 
analyzer are not working or the operating range of the monitor or 
analyzer is exceeded.
    (xv) A complete description of the methods to be used for 
calculating, and hourly and three-hour SO2 emission from 
flares.
    (6) Thirty days prior to installing the continuous monitors 
required by 40 CFR 52.1392(h)(2) and (3), each facility named in 40 CFR 
52.1392(a) shall submit for EPA review a quality assurance/quality 
control (QA/QC) plan for each monitor being installed.

[FR Doc. 06-6096 Filed 7-11-06; 8:45 am]

BILLING CODE 6560-50-P