Federal Implementation Plan for the Billings/Laurel, Montana, Sulfur Dioxide Area, 39259-39278 [06-6096]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 71, Number 133 (Wednesday, July 12, 2006)]
[Proposed Rules]
[Pages 39259-39278]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-6096]


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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:
     https://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 
https://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 https://
www.regulations.gov or e-mail. The https://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 https://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 https://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.
    Docket: All documents in the docket are listed in the https://

[[Page 39260]]

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 https://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 
https://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 www.fluidcomponents.com); OO (GE Sensing, vendor 
literature); PP (``Why and How to measure flare gas'' from Flowmeter 
Directory (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 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 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 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