21418 Federal Register / Vol. 73, No. 77 / Monday, April 21, 2008 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R08–OAR–2006–0098; FRL–8551–2] 

RIN 2008–AA01 

Federal Implementation Plan for the 

Billings/Laurel, MT, Sulfur Dioxide 

Area 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is promulgating a Federal 

Implementation Plan (FIP) containing 

emission limits and compliance 

determining methods for several sources 

located in Billings and Laurel, Montana. 

EPA is promulgating a FIP because of 

our previous partial and limited 

disapprovals of the Billings/Laurel 

Sulfur Dioxide (SO2) State 

Implementation Plan (SIP). The 

intended effect of this action is to assure 

attainment of the SO2 National Ambient 

Air Quality Standards (NAAQS) in the 

Billings/Laurel, Montana area. EPA is 

taking this action under sections 110, 

301, and 307 of the Clean Air Act (Act). 

DATES: Effective Date: This final rule is 

effective May 21, 2008. The 

incorporation by reference of certain 

publications listed in this regulation is 

approved by the Director of the Federal 

Register as of May 21, 2008. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–R08–OAR–2006–0098. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., Confidential Business Information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

http://www.regulations.gov or in hard 

copy at the Air and Radiation Program, 

Environmental Protection Agency 

(EPA), Region 8, 1595 Wynkoop Street, 

Denver, Colorado 80202–1129. EPA 

requests that if at all possible, you 

contact the individual listed in the FOR

FURTHER INFORMATION CONTACT section to 

view the hard copy of the docket. You 

may view the hard copy of the docket 

Monday through Friday, 8 a.m. to 4 

p.m., excluding Federal holidays. 

FOR FURTHER INFORMATION CONTACT: 

Laurie Ostrand, Air and Radiation 

Program, Environmental Protection 

Agency (EPA), Region 8, 1595 Wynkoop 

Street, Denver, Colorado 80202–1129, 

(303) 312–6437, ostrand.laurie@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Definitions 

I. Background of the Final Rules 

II. Issues Raised by Commenters and EPA’s 

Response 

A. FIP Not Necessary 

B. EPA Exceeded Its Authority in 

Proposing a FIP 

C. Flare Monitoring 

D. Flare Limits 

E. Concerns With Dispersion Modeling 

F. Miscellaneous Comments 

G. MSCC Specific Issues 

H. ConocoPhillips Specific Issues 

I. ExxonMobil Specific Issues 

J. CHS Inc. Specific Issues 

III. Summary of the Final Rules and Changes 

From the July 12, 2006, Proposal 

A. Flare Requirements Applicable to All 

Sources 

B. CHS Inc. 

C. ConocoPhillips 

D. ExxonMobil 

E. Montana Sulphur & Chemical Company 

(MSCC) 

F. Modeling to Support Emission Limits 

IV. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory 

Planning Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132, Federalism 

F. Executive Order 13175, Coordination 

With Indian Tribal Governments 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211, Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

L. Petitions for Judicial Review 

Definitions 

For the purpose of this document, we 

are giving meaning to certain words or 

initials as follows: 

(i) The words or initials Act or CAA 

mean or refer to the Clean Air Act, 

unless the context indicates otherwise. 

(ii) The initials API mean or refer to 

the American Petroleum Institute. 

(iii) The initials BAAQMD mean or 

refer to the Bay Area Air Quality 

Management District. 

(iv) The initials CEMS mean or refer 

to continuous emission monitoring 

system. 

(v) The initials CO mean or refer to 

carbon monoxide. 

(vi) The initials COPC mean or refer 

to ConocoPhillips. 

(vii) The words EPA, we, us or our 

mean or refer to the United States 

Environmental Protection Agency. 

(viii) The initials FIP mean or refer to 

Federal Implementation Plan. 

(ix) The initials H2S mean or refer to 

hydrogen sulfide. 

(x) The initials MBER mean or refer to 

the Montana Board of Environmental 

Review. 

(xi) The initials MDEQ mean or refer 

to the Montana Department of 

Environmental Quality. 

(xii) The initials MPA mean or refer to 

the Montana Petroleum Association. 

(xiii) The initials MSCC mean or refer 

to the Montana Sulphur & Chemical 

Company. 

(xiv) The initials NAAQS mean or 

refer to National Ambient Air Quality 

Standards 

(xv) The initials NEDA/CAP mean or 

refer to the National Environmental 

Development Association’s Clean Air 

Project. 

(xvi) The initials NPRA mean or refer 

to the National Petrochemical & Refiners 

Association. 

(xvii) The initials SCAQMD mean or 

refer to the South Coast Air Quality 

Management District. 

(xviii) The initials SIP mean or refer 

to State Implementation Plan. 

(xix) The initials SO2 mean or refer to 

sulfur dioxide. 

(xx) The words State or Montana 

mean the State of Montana, unless the 

context indicates otherwise. 

(xxi) The initials SRU mean or refer 

to sulfur recovery unit. 

(xxii) The initials SWS mean or refer 

to sour water stripper. 

(xxiii) The initials WETA mean or 

refer to the Western Environmental 

Trade Association. 

(xxiv) The initials WSPA mean or 

refer to the Western States Petroleum 

Association. 

(xxv) The initials YCC mean or refer 

to the Yellowstone County 

Commissioners. 

(xxvi) The initials YVAS mean or 

refer to the Yellowstone Valley 

Audubon Society. 

I. Background of the Final Rules 

The Clean Air Act (Act) requires EPA 

to establish national ambient air quality 

standards (NAAQS) that protect public 

health and welfare. NAAQS have been 

established for SO2 as follows: 0.030 

parts per million (ppm) annual 

standard, not to be exceeded in a 

calendar year; 0.14 ppm 24-hour 

standard, not to be exceeded more than 

once per calendar year; and 0.5 ppm 3- 

hour standard, not to be exceeded more 


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Federal Register / Vol. 73, No. 77 / Monday, April 21, 2008 / Rules and Regulations 21419 

1Section 110(k)(1) requires the Administrator to 

promulgate minimum criteria that any plan 

submission must meet before EPA is required to act 

on the submission. These completeness criteria are 

set forth at 40 CFR 51, Appendix V. 

than once per calendar year. See 40 CFR 

50.4 and 50.5. The Act also requires 

states to prepare and gain EPA approval 

of a plan, termed a State 

Implementation Plan (SIP), to assure 

that the NAAQS are attained and 

maintained. 

Dispersion modeling completed in 

1991 and 1993 for the Billings/Laurel 

area of Montana predicted that the SO2

NAAQS were not being attained. As a 

result, in March 1993 EPA (pursuant to 

sections 110(a)(2)(H) and 110(k)(5) of 

the Act, 42 U.S.C. 7410(a)(2)(H) and 

7410(k)(5)) requested the State of 

Montana to revise its previously 

approved SO2 SIP for the Billings/Laurel 

area. See 58 FR 41450, August 4, 1993. 

In response, the State submitted 

revisions to the SO2 SIP on September 

6, 1995, August 27, 1996, April 2, 1997, 

July 29, 1998, and May 4, 2000. 

On May 2, 2002 (67 FR 22168) and 

May 22, 2003 (68 FR 27908), we 

partially approved, partially 

disapproved, limitedly approved, and 

limitedly disapproved the Billings/ 

Laurel SO2 SIP. In those actions we 

disapproved the following: 

• The attainment demonstration due 

to issues with various emission limits, 

inappropriate stack height credit, and 

lack of emission limits on flares. 

• The emission limits for Montana 

Sulphur & Chemical Company’s 

(MSCC’s) sulfur recovery unit (SRU) 

100-meter stack and the stack height 

credit on which those limits were based. 

• The emission limits for MSCC’s 

auxiliary vent stacks due to lack of an 

adequate limit on fuel burned in the 

associated heaters and boilers and lack 

of a reliable compliance determining 

method. 

• The emission limits for MSCC’s 30- 

meter stack due to lack of an adequate 

limit on fuel burned in the associated 

heaters and boilers, and lack of a 

reliable compliance determining 

method. 

• Provisions that allowed sour water 

stripper overheads to be burned in the 

flares at CHS Inc. and ExxonMobil. 

• ExxonMobil’s refinery fuel gas 

combustion device emission limits and 

associated compliance determining 

methods. 

• ExxonMobil’s Coker CO Boiler stack 

emission limits and associated 

compliance determining methods. 

• CHS Inc.’s combustion source 

emission limits and certain associated 

compliance determining methods. 

On June 10, 2002, MSCC petitioned 

the United States Court of Appeals for 

the Ninth Circuit for review of EPA’s 

May 2, 2002, final SIP action. 

Subsequently, MSCC and EPA agreed to 

a stay of the litigation pending EPA’s 

final action on this FIP. The case is 

captioned Montana Sulphur & Chemical 

Company v. United States 

Environmental Protection Agency, No. 

02–71657. No petitions for judicial 

review were filed regarding EPA’s May 

22, 2003, SIP action. 

On July 12, 2006 (71 FR 39259), EPA 

proposed Federal Implementation Plan 

(FIP) provisions for the Billings/Laurel, 

Montana area because of our 

disapproval of portions of Montana’s 

Billings/Laurel SO2 SIP. In our proposal, 

we indicated that our FIP would not 

replace the SIP entirely, but instead 

would only replace elements of, or fill 

gaps in, the SIP. 

In promulgating today’s rules, EPA is 

fulfilling its mandatory duty under 

section 110(c) of the Act. Under section 

110(c), whenever we disapprove a SIP, 

in whole or in part, we are required to 

promulgate a FIP. Specifically, section 

110(c) provides: 

‘‘(1) The Administrator shall promulgate a 

Federal implementation plan at any time 

within 2 years after the Administrator—

(A) Finds that a State has failed to make 

a required submission or finds that the plan 

or plan revision submitted by the State does 

not satisfy the minimum criteria established 

under [section 110(k)(1)(A)],1 or 

(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 farreaching consequences in Los Angeles: 

‘‘The authority to regulate pollution 

carries with it the power to do so in a 

manner reasonably calculated to reach 

that end.’’ City of Santa Rosa v. EPA, 

534 F.2d 150, 155 (9th Cir. 1976), 

vacated and remanded on other grounds 

sub nom. Pacific Legal Foundation v. 

EPA, 429 U.S. 990 (1976). 

In addition to giving EPA remedial 

authority, section 110(c) enables EPA to 

assume the powers that the state would 

have to protect air quality, when the 

state fails to adequately discharge its 

planning responsibility. As the Ninth 

Circuit held, when EPA acts to fill in the 

gaps in an inadequate state plan under 

section 110(c), EPA ‘‘ ‘stands in the 

shoes of the defaulting State, and all of 

the rights and duties that would 

otherwise fall to the State accrue instead 

to EPA.’ ’’ Central Arizona Water 

Conservation District v. EPA, 990 F.2d 

1531, 1541 (9th Cir. 1993). As the First 

Circuit held in an early case: 

‘‘[T]he Administrator must promulgate 

promptly regulations setting forth ‘an 

implementation plan for a State’ should the 

state itself fail to propose a satisfactory one 

* * * The statutory scheme would be 

unworkable were it read as giving to EPA, 

when promulgating an implementation plan 

for a state, less than those necessary 

measures allowed by Congress to a state to 

accomplish federal clean air goals. We do not 

adopt any such crippling interpretation.’’

South Terminal Corp. v. EPA, supra, 

at 668 (citing previous version of section 

110(c)). 

The Billings/Laurel SO2 FIP 

establishes emission limits and 

compliance determining methods for 

four sources located in Billings/Laurel, 

Montana, to replace/fill gaps in portions 

of the SIP we disapproved, and to 


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21420 Federal Register / Vol. 73, No. 77 / Monday, April 21, 2008 / Rules and Regulations 

support our attainment demonstration. 

Three of the sources are petroleum 

refineries: CHS Inc., ConocoPhillips 

(including the Jupiter Sulfur facility), 

and ExxonMobil. The fourth source is 

Montana Sulphur & Chemical Company, 

which provides sulfur recovery for the 

ExxonMobil refinery. 

The following is a summary of the 

major components of our FIP rule: 

(1) The FIP establishes flare emission 

limits at all four sources (150 lbs SO2/ 

3-hour period at all but the Jupiter 

Sulfur flare, 75 lbs SO2/3-hour period 

shared limit for the Jupiter Sulfur flare 

and the Jupiter Sulfur SRU/ATS stack) 

and monitoring methods to determine 

compliance with those limits. The FIP 

includes an affirmative defense to 

penalties for violations of the flare 

limits that occur during malfunction, 

startup, and shutdown periods. To 

determine flare emissions, the FIP 

requires concentration monitoring 

(which can consist of continuous 

monitoring, grab sampling, or integrated 

sampling) and continuous flow 

monitoring. 

(2) The FIP prohibits the burning of 

sour water stripper overheads in CHS 

Inc.’s main crude heater and requires 

CHS Inc. to keep the valve between the 

old sour water stripper and the main 

crude heater closed, chained, and 

locked. 

(3) The FIP provides that emission 

limits for identified ExxonMobil 

refinery fuel gas combustion units are 

contained in the SIP, and establishes 

compliance determining methods for 

instances in which the H2S 

concentration in the refinery fuel gas 

stream exceeds 1200 ppmv. These 

methods involve the use of length-ofstain detector tubes on a once-per-hour 

frequency. 

(4) The FIP provides that emission 

limits for ExxonMobil’s Coker CO Boiler 

stack, when ExxonMobil’s Coker unit is 

operating and Coker unit flue gases are 

burned in the Coker CO Boiler, are 

contained in the SIP. The FIP 

establishes compliance determining 

methods for these emission limits that 

require measurement of the SO2

concentration and flow rate in the Coker 

CO Boiler stack using CEMS. 

(5) The FIP establishes emission 

limits on MSCC’s SRU 100-meter stack, 

based on good engineering practice 

(GEP) stack height credit of 65 meters, 

with compliance with these limits to be 

determined using methods already 

approved in the SIP. The FIP does not 

provide variable emission limits for this 

stack. 

(6) The FIP establishes emission 

limits and compliance determining 

methods for MSCC’s auxiliary vent 

stacks and SRU 30-meter stack. In 

addition to mass limits, the FIP 

establishes concentration limits on fuel 

burned in the units that vent to the 

auxiliary vent stacks and SRU 30-meter 

stack. These concentration limits are 

160 ppm H2S per 3-hour period and 100 

ppm H2S per calendar day. When trigger 

events specified in the rule occur, 

MSCC must measure the H2S 

concentration in the fuel using lengthof-stain detector tubes on a once-per-3- 

hour period. 

(7) The FIP establishes various 

recordkeeping and reporting 

requirements. 

It is important to note that, in cases 

where the provisions of the FIP address 

emissions activities differently or 

establish different requirements than 

provisions of the SIP, the provisions of 

the FIP take precedence. We also 

caution that if any of the four sources 

are subject to requirements under other 

provisions of the Act (e.g., section 111 

or 112, part C of title I, or SIP-approved 

permit programs under part A of title I), 

our promulgation of the FIP does not 

excuse any of the sources from meeting 

such requirements. Finally, our 

promulgation of the FIP does not imply 

any sort of applicability determination 

under other provisions of the Act (e.g., 

section 111 or 112, part C of title I, or 

SIP-approved permit programs under 

part A of title I). 

II. Issues Raised by Commenters and 

EPA’s Response 

A. FIP Not Necessary 

1. Ambient Data and Historical 

Modeling Show Attainment 

(a) Comment (CHS Inc., COPC, 

ExxonMobil, NPRA, MPA, MDEQ, 

MSCC, WETA): The FIP is not necessary 

for attainment of the NAAQS because 

ambient data show that the Billings/ 

Laurel area has been for many years and 

continues to be in attainment with both 

the Federal and State SO2 ambient air 

quality standards for all averaging 

periods. 

Response: EPA does not agree that a 

FIP is not necessary because ambient 

data show attainment of the SO2

NAAQS. Ambient monitoring is limited 

in time and in space. Ambient 

monitoring can measure pollutant 

concentrations only as they occur; it 

cannot predict future concentrations 

when emission levels and 

meteorological conditions may differ 

from present conditions. 

EPA has long held that ambient 

monitoring data alone generally are not 

adequate for SO2 attainment 

demonstrations. Additionally, a small 

number of ambient SO2 monitors 

usually are not representative of the air 

quality for an area. (See reference 

document GGGGG, April 21, 1983, 

memorandum from Sheldon Meyers, 

Director, Office of Air Quality Planning 

and Standards (OAQPS), to Regional Air 

and Waste Division Directors, titled 

‘‘Section 107 Designation Policy 

Summary,’’ and reference document 

HHHHH, September 4, 1992, 

memorandum from John Calcagni, 

Director, Air Quality Management 

Division, OAQPS, to Regional Air 

Division Directors, titled ‘‘Procedures 

for Processing Requests to Redesignate 

Areas to Attainment.’’) 

Typically, modeling estimates of 

maximum ambient concentrations are 

based on a fairly infrequent combination 

of meteorological and source operating 

conditions. To capture such results on 

an ambient monitor would normally 

require a prohibitively large and 

expensive network. Therefore, 

dispersion modeling is generally 

necessary to comprehensively evaluate 

sources’ impacts and to determine the 

areas of expected high concentrations. 

(Id.) Air quality modeling results would 

be especially important if sources were 

not emitting at their maximum level 

during the monitoring period or if the 

monitoring period did not coincide with 

potentially worst-case meteorological 

conditions. Further, ambient monitoring 

data are not adequate if sources are 

using stacks with actual heights greater 

than good engineering practice stack 

height (which indeed is the case with 

MSCC and ConocoPhillips) or other 

dispersion techniques for which SIP/FIP 

modeling credit is not allowed. (See also 

our discussion of related issues in our 

final action on the Billings/Laurel SO2

SIP (67 FR 22168, 22185–22187, May 2, 

2002.)) 

Ambient monitoring data and air 

quality modeling data for a particular 

area can sometimes appear to conflict. 

This is primarily due to the fact that 

modeling results may predict maximum 

SO2 concentration at receptors where no 

monitors are located. 

Moreover, our SIP Call for the 

Billings/Laurel area was based on 

modeled violations of the SO2 NAAQS, 

not monitored violations. (See reference 

documents Y and Z.) We took final 

action on the SIP Call in our May 2, 

2002, action on the Billings/Laurel SIP 

(67 FR 22168, 22173), and we are not 

revisiting it in this FIP action. It would 

be inconsistent and inappropriate to 

now rely solely on monitoring to 

determine necessary measures and 

demonstrate attainment. 

It is especially important to recognize 

that, as a result of our partial and 

limited disapproval of the Billings/ 


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2The State can revise construction permits 

without EPA approval, and, while EPA has 

authority to object to Title V permits, that authority 

is only available to ensure that underlying 

applicable requirements are included in the Title V 

permits. Thus, if those underlying requirements 

change, EPA may have no recourse at the Title V 

stage. 

Laurel SO2 SIP, we are legally obligated 

to promulgate a FIP for the area. See 

section 110(c)(1) of the CAA, 42 U.S.C. 

7410(c)(1). However, the SIP 

deficiencies that triggered our partial 

and limited disapproval were varied 

and were not necessarily associated 

with problems that could be measured 

at an ambient monitor. For example, one 

basis for disapproval of the SIP was the 

State’s use of improper (too tall) stack 

height credit for MSCC in modeling 

attainment of the NAAQS. In the real 

world, emissions at the actual (100 

meter) height of the stack create less 

impact on monitored ambient 

concentrations in the Billings/Laurel 

area than if the emissions were emitted 

from a lower stack. Nonetheless, we had 

to partially disapprove the SIP due to 

the State’s inappropriate grant of stack 

height credit, and section 110(c) of the 

CAA requires that we correct the 

deficiency. Since the State did not 

model attainment at the proper stack 

height credit for MSCC’s stack, it was 

necessary that we do so and set 

emission limits for the stack consistent 

with our attainment demonstration. We 

believe MSCC has consistently been 

meeting the emission limits we are 

adopting, so there may be no reduction 

in actual emissions from the stack, but 

that does not mean the CAA allows us 

to forego this aspect of the FIP. 

Likewise, CAA sections 110(a)(2)(A) 

and (C) require that SIP control 

measures be enforceable. We 

disapproved several source monitoring 

methods because they were not 

adequate to determine compliance 

under all operating conditions. It may 

be impossible to measure the impact 

these SIP deficiencies may have on 

ambient SO2 concentrations in the area, 

but the CAA still requires that we 

correct the deficiencies. Regarding the 

emission limits and compliance 

determining methods for the flares, the 

State-only flare limits, which the State 

relied on to demonstrate attainment, 

may have positively impacted flare 

emissions in the past few years. 

However, the State did not include the 

State-only flare limits or adequate 

compliance determining methods in the 

SIP. Thus, the SIP remains deficient. We 

now have the responsibility to ensure 

that emission limits relied on to 

demonstrate attainment are included in 

the SIP and are practically enforceable, 

consistent with the requirements of 

section 110 of the Act. 

(b) Comment (MSCC, MDEQ): The 

State’s SIP modeling, along with 

appropriate emission limits, show 

attainment of the NAAQS. 

Response: EPA addressed this issue in 

its actions on Montana’s SIP 

submissions. As explained in those 

actions, EPA does not agree that the 

State’s SIP modeling, along with 

appropriate emission limits, show 

attainment of the NAAQS. EPA’s formal 

determinations regarding the attainment 

demonstration and emission limits were 

made in final actions on May 2, 2002 

(67 FR 22168) and May 22, 2003 (68 FR 

27908). The FIP fills the gaps for the 

provisions we disapproved. 

We note that we have not reopened 

our SIP actions as part of this action. 

Thus, to the extent the commenters are 

expressing their disagreement with 

EPA’s actions on the SIP, their 

comments are not relevant to this 

action, and EPA is not re-considering 

them here. 

(c) Comment (ExxonMobil): EPA’s 

proposed FIP ignores the substantial 

improvement in air quality in the 

Billings/Laurel area and instead predicts 

exceedances of NAAQS based upon 

modeling performed as long as 15 years 

ago. EPA’s FIP proposal must be further 

examined in light of subsequent 

developments, including correct 

modeling and consideration of currently 

available information indicating 

compliance. 

Response: See response to comment 

II.A.1.(a), above, regarding ambient data 

and response to comments in section 

II.E., below, regarding modeling. 

2. Existing Controls Sufficient 

(a) Comment (MDEQ, MSCC, COPC, 

ExxonMobil, MPA, NPRA, WETA): The 

FIP offers questionable improvements 

because the existing control plan 

provisions submitted by the state are 

adequate and contain sufficient SO2

emission controls and strategies and 

provide for the implementation, 

maintenance, and enforcement of the 

SO2 NAAQS. 

Response: EPA addressed the 

adequacy of Montana’s SIP submissions 

in its final actions on the SIP. As 

explained in those actions, EPA does 

not agree that the State’s SIP control 

plan provisions are adequate and 

contain sufficient SO2 emission controls 

to show attainment of the NAAQS. 

EPA’s formal determinations regarding 

the attainment demonstration and 

emission control plan were made in 

final actions on May 2, 2002 (67 FR 

22168) and May 22, 2003 (68 FR 27908). 

In our May 2002 and May 2003 actions 

we disapproved various control plan 

provisions. The FIP fills the gaps for the 

provisions we disapproved. The FIP 

offers necessary improvements to the 

SIP by imposing new emission limits 

and reliable compliance determining 

methods to ensure attainment of the SO2

NAAQS. 

We note that we have not reopened 

our SIP actions as part of this action. 

Thus, to the extent the commenters are 

expressing their disagreement with 

EPA’s actions on the SIP, their 

comments are not relevant to this 

action, and EPA is not re-considering 

them here. 

(b) Comment (CHS Inc., WETA, 

COPC, MDEQ, ExxonMobil, NPRA): In 

addition to the SIP, SO2 emissions in 

the Billings/Laurel area have decreased 

as a result of Consent Decrees and 

Montana Air Quality Permit changes. 

These limits are all federally enforceable 

because there are Title V operating 

permit conditions (CHS Inc.). EPA did 

not consider these emission reductions 

in making its determination that the FIP 

was necessary. The FIP proposal does 

not otherwise acknowledge the practical 

effects of the recent consent decrees 

between the primary refinery parties 

subject to regulation as well as other 

permitting actions that have occurred 

over the past eight years (MSCC, COPC). 

Response: EPA did not consider the 

emission reductions that resulted, or 

will result, from the consent decrees 

and/or State permit revisions to 

determine that the FIP was necessary or 

include the emission reductions in our 

modeling for several reasons. 

First, the FIP is required because we 

disapproved the SIP, and the State has 

not made revisions to the SIP to address 

the SIP’s flaws. As noted in other 

responses, because we disapproved the 

SIP, we have a legal obligation to 

promulgate a FIP. See CAA section 

110(c), 42 U.S.C. 7410(c). 

Second, even though permits and 

consent decrees are federally 

enforceable, some permits can be 

revised without EPA approval and 

consent decrees have a limited 

lifespan.2 To protect the integrity of the 

attainment demonstration, and our 

statutory role in assessing SIP/FIP 

adequacy, we believe that stationary 

source emission limits necessary to 

demonstrate attainment must be 

included in the FIP (or approved SIP). 

See, e.g., CAA sections 110(a)(2)(A), 

110(i), 110(k)(3)–(6), and 110(l), 42 

U.S.C. 7410(a)(2)(A), (i), (k)(3)–(6), and 

(l). This ensures that changes to those 

limits will only be made with EPA’s 

approval as a SIP or FIP revision, 


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following notice and comment 

rulemaking. 

Third, the consent decrees and 

permitting actions, for some emission 

points, do not contain SO2 emission 

limits that are consistent with the 

averaging times of the SO2 NAAQS, 

specifically, the 3-hour and calendar 

day averaging periods. For example, the 

SIP establishes 3-hour, calendar day, 

and calendar year emission limits for 

CHS Inc.’s FCC regenerator/CO boiler 

stack. The January 17, 2007, final State 

construction permit (reference 

document IIIII) and the consent decree 

(reference document JJJJJ) indicate that 

the FCC regenerator stack SO2 emissions 

shall not exceed 50 ppm by volume 

(corrected to 0% O2) for a 7-day rolling 

average [or a fresh feed of 0.3 percent by 

weight] and 25 ppm by volume 

(corrected to 0% O2) for a 365-day 

rolling average. None of the commenters 

has suggested these limits be converted 

to FIP mass limits that would apply over 

a 3-hour averaging period, and the State 

has not submitted a SIP revision with 

such limits. 

It should be noted that EPA did solicit 

comment on whether we should limit 

the main flares to 500 pounds of SO2 per 

calendar day. This value is consistent 

with the trigger point for certain 

analyses contained in settlements (i.e., 

consent decrees) between the United 

States and CHS Inc., ConocoPhillips, 

and ExxonMobil. We received limited 

comments on this proposal and have 

decided to keep the limit at 150 pounds 

of SO2 per 3-hour period to maintain 

consistency with the State’s State-only 

limit. 

B. EPA Exceeded Its Authority in 

Proposing a FIP 

1. State’s Responsibility 

(a) Comment (WETA, MPA, 

ExxonMobil): EPA’s role is limited to 

determining whether or not a SIP is 

attaining and maintaining the NAAQS. 

Selecting the source mix and various 

control measures to achieve these ends 

has been determined by courts to be the 

sole responsibility of the state. EPA’s 

proposed action intrudes on the primary 

responsibility of the state and local 

governments to implement the Clean 

Air Act (MSCC). 

Response: The commenters’

characterization of EPA’s role regarding 

SIPs is not accurate. We lack authority 

to question a state’s choices of 

emissions limitations if they are part of 

a plan that satisfies the standards of the 

Clean Air Act. Train v. Natural 

Resources Defense Council, 95 S.Ct. 

1470, 1481–1482 (1975). In our 2002 

and 2003 actions, we found that 

Montana’s SO2 SIP for Billings/Laurel 

did not fully satisfy CAA requirements. 

See 67 FR 22168, May 2, 2002 and 68 

FR 27908, May 22, 2003. Thus, pursuant 

to section 110(c) of the CAA, 42 U.S.C. 

7410(c), we are required to promulgate 

a FIP. In doing so, we stand in the state’s 

shoes and have authority to determine 

emissions limitations and other 

measures for specific sources to fill gaps 

in the SIP. Central Arizona Water 

Conservation District v. EPA, 990 F.2d 

1531, 1541 (9th Cir. 1993); South 

Terminal Corp. v. EPA, 504 F.2d 646, 

668 (1st Cir. 1974) (citing previous 

version of CAA section 110(c)). 

We note that we have not reopened 

our SIP actions as part of this action. 

Thus, to the extent the commenters are 

expressing their disagreement with 

EPA’s actions on the SIP, their 

comments are not relevant to this 

action, and EPA is not re-considering 

them here. 

(b) Comment (WETA): Since the State 

of Montana has already taken 

appropriate actions to reduce sulfur 

dioxide emissions, EPA does not have 

the authority under the CAA to adopt 

the proposed FIP. 

Response: See response to comment 

II.B.1.(a), above. The adequacy of the 

State of Montana’s actions has already 

been considered by EPA in other 

rulemaking actions that addressed the 

State’s SIP submission. Those actions 

are not the subject of EPA’s present 

rulemaking, which promulgates the 

necessary measures to remedy the 

deficiencies EPA identified in its prior 

SIP reviews. 

(c) Comment (MSCC): States have 

primacy, and because EPA did not 

choose to exercise its rights in the 

comprehensive and competent state 

decision process, EPA may not default 

and then act. 

Response: Under section 110(c) of the 

Act, EPA is not required to participate 

in a state’s administrative process before 

promulgating a FIP. 

(d) Comment (MSCC, MDEQ, 

ExxonMobil): EPA has no authority to 

question the wisdom of a state’s choices 

of emission limitations if they are part 

of a plan that satisfies the standards of 

§ 110(a)(2) of the Act. As long as the 

ultimate effect of a state’s choice of 

emission limitations is compliance with 

the NAAQS, the state is at liberty to 

adopt whatever mix of emission 

limitations it deems best suited to its 

particular situation. There is no 

evidence provided by EPA that Montana 

reached its material conclusions or 

choices in the SIP unreasonably. 

Additionally, EPA has not shown that 

additional controls beyond the SIP 

measures adopted by Montana are 

necessary to meet or assure SO2 NAAQS 

compliance. 

Response: See our responses to 

comments II.A.1.(a) and II.B.1.(a), above. 

Much of this comment pertains to our 

actions on Montana’s SIP. We are not 

revisiting or reopening comment on 

those actions here. Our basis for finding 

that the SIP was not adequate to ensure 

attainment and meet other CAA 

requirements is described in our actions 

on the SIP. Once we disapprove part or 

all of a required SIP, section 110(c) of 

the Act requires that we issue a FIP. Our 

obligation in this action is to correct the 

SIP deficiencies we previously 

identified. Thus, the findings that 

triggered our responsibility to 

promulgate a FIP were established in 

the prior rulemaking actions reviewing 

Montana’s SIP. EPA is not required to 

repeat those findings in the FIP 

rulemaking itself. 

(e) Comment (ExxonMobil): EPA 

cannot propose a FIP to replace a SIP, 

unless the SIP is substantially 

inadequate to ensure compliance with 

the CAA. 

Response: The commenter misstates 

the standard for promulgation of a FIP. 

Section 110(c) of the CAA is 

straightforward—a FIP is required if (1) 

EPA finds that a state has failed to make 

a required submission; (2) EPA finds 

that a plan submission does not satisfy 

the completeness criteria established 

under section 110(k)(1)(A) of the CAA; 

or (3) EPA disapproves a SIP in whole 

or in part. EPA partially disapproved 

the Billings/Laurel SO2 SIP; thus, a FIP 

is required. Contrary to the commenter’s 

assertion, the obligation to promulgate a 

FIP is not contingent on an EPA finding 

of substantial inadequacy. As explained 

above, the findings triggering our 

responsibility to promulgate a FIP were 

made in the prior actions reviewing 

Montana’s SIP. 

(f) Comment (MSCC): The commenter 

claims EPA’s action violates the Tenth 

Amendment to the Constitution. The 

commenter also claims EPA’s FIP is 

dictating the required controls in 

contravention of the holdings in 

Commonwealth of Virginia v. EPA, 108 

F.3d 1397 (D.C. Cir. 1997) and 

Bethlehem Steel v. Gorsuch, 742 F.2d 

1028 (7th Cir. 1984). 

Response: Our FIP compels no action 

on the part of the State and is not 

coercive vis-a`-vis the State. Our FIP 

contains requirements applicable to four 

private companies. The Tenth 

Amendment is not implicated. Nor do 

our actions contravene Commonwealth 

of Virginia or Bethlehem Steel. The 

former case held that EPA cannot, in a 

SIP Call, dictate that a state adopt a 

particular control measure to 


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3 In South Terminal Corporation, EPA had 

determined emissions reductions needed to achieve 

the ozone and carbon dioxide NAAQS based on 

monitored values that the Court found highly 

questionable (petitioners claimed the ozone monitor 

was defective). South Terminal Corporation, 504 

F.2d 646, 662 (1974). The commenter seems to 

suggest that the Court rejected EPA’s modeling 

approach, but in fact, the Court was satisfied with 

the rollback modeling that EPA used. Id. 

4Among other things, the commenter asserts that 

the state SIP requirements are adequate to protect 

the NAAQS. See reference document YYYY, page 

27. 

demonstrate attainment of the NAAQS. 

EPA had issued a SIP Call finding that 

the SIPs of 12 states were inadequate to 

meet the ozone NAAQS and in its SIP 

Call rule, specified that the states 

needed to submit SIPs that included the 

California Low Emission Vehicle 

Program. In this matter, we are 

promulgating a FIP, not issuing a SIP 

Call. We are not directing any action by 

the State. Thus, the Commonwealth of 

Virginia case is not relevant to our FIP. 

Bethlehem Steel is also not relevant to 

our FIP action. In that case, the 7th 

Circuit held that it was improper for 

EPA to partially approve an Indiana SIP 

revision so as to render it more stringent 

than the State intended. We are 

promulgating a FIP in this action, not 

acting on a SIP; thus, Bethlehem Steel 

does not apply. As we note elsewhere, 

once we disapprove a SIP, we are 

required to promulgate a FIP, and in 

promulgating the FIP, we stand in the 

state’s shoes. See section 110(c) of the 

CAA, 42 U.S.C. 7410(c); Central Arizona 

Water Conservation District v. EPA, 990 

F.2d 1531, 1541 (9th Cir. 1993). 

(g) Comment (MSCC): The commenter 

argues that the cases EPA cited in the 

preamble to the proposed Billings/ 

Laurel FIP, regarding its FIP authority, 

do not speak to the central question—

‘‘When and on what authority may the 

EPA undertake the draconian act of 

displacing a state’s implementation 

plan?’’ The commenter argues that the 

question is particularly sensitive in this 

case because the State and the sources 

spent years negotiating the SIP. 

Response: As noted in response to 

comment II.B.1.(e), the CAA requires 

that we promulgate a FIP whenever we 

disapprove a SIP, in whole or in part. 

While we are sensitive to the fact that 

the State and sources spent years 

negotiating the SIP, that does not change 

our obligation under the CAA. 

2. No Adequate Basis for FIP 

(a) Comment (MSCC, ExxonMobil): 

Because EPA must find substantive 

noncompliance with some provision of 

the Clean Air Act, specifically, failure to 

attain NAAQS, and because that finding 

of substantial inadequacy must be 

clearly stated, the present FIP decision 

must fall. It is inadequate on both 

counts. EPA has not provided any 

evidence that the State plan is not 

working. 

Response: See our response to 

comment II.B.1.(e), above. The evidence 

supporting EPA’s determinations 

regarding the adequacy of Montana’s 

SIP is contained in the record for those 

rulemaking actions, and need not be 

repeated here. EPA’s disapproval of the 

SIP triggered the obligation for a FIP. No 

separate showing that the State plan is 

not working or does not meet CAA 

requirements is needed as part of this 

action. Commenters’ comments 

regarding EPA’s SIP actions are not 

relevant for this rulemaking. 

(b) Comment (ExxonMobil): Even 

when the EPA has statutory authority 

for a particular rule, its technical 

decisions about the level of pollutant 

reduction needed to comply with the 

CAA and the control strategies 

necessary to meet the level of pollutant 

reduction must be rational. Courts 

‘‘confronted with important and 

seemingly plausible objections going to 

the heart of a key technical 

determination * * * ’’ will not presume 

that EPA would never behave 

irrationally. South Terminal 

Corporation v. Environmental 

Protection Agency, 504 F.2d 646, 665 

(1st Cir. 1974). In South Terminal 

Corporation, various interested parties 

challenged EPA’s FIP on technical 

grounds. Id. at 662–66. The court held 

that EPA failed to adequately support its 

decision to promulgate the rules 

contained in the FIP and remanded the 

case to EPA to develop the record. Id. 

at 666. The court questioned EPA’s 

position in light of contradictory 

modeling and data, concluding that ‘‘it 

is not clear whether or not the ambient 

air at Logan meets, or will without 

controls by mid-1975 will meet, the 

national primary standard.’’ Id. 664. 

Similarly, in the present FIP proposal, 

EPA has neither determined appropriate 

current modeling nor used currently 

available information. 

Response: The standards for judicial 

review of this rulemaking action are 

contained in section 307(d)(9) of the 

CAA, 42 U.S.C. 7607(d)(9). We believe 

the emission limitations and other 

requirements in this FIP are reasonable 

and that the situation in the cited case 

is not analogous.3 The commenter has 

not identified any modeling that 

contradicts our attainment 

demonstration, which forms the basis 

for the FIP’s emission limitations; nor 

has the commenter shown that a 

different model would result in 

substantially different emission 

limitations. Our responses pertaining to 

model selection and input data are 

contained in section II.E., below. 

Further, we note that it does not appear 

the commenter is suggesting that the 

entire SIP should be re-done based on 

more current modeling and more up-todate information. On the contrary, the 

commenter seems satisfied with the 

EPA-approved emission limitations in 

the SIP,4 which were based on the very 

modeling that the commenter now 

claims is unreliable. 

(c) Comment (ExxonMobil): Citing 

Hall v. United States Environmental 

Protection Agency, 273 F.3d 1146, 1159 

(9th Cir. 2001), the commenter states 

that in acting on a SIP, the test EPA 

applies is to ‘‘measure the existing level 

of pollution, compare it with the 

national standards, and determine the 

effect on this comparison of specified 

emission modifications.’’ The 

commenter argues that in the FIP 

proposal, EPA did not correctly identify 

the existing level of pollution and 

ignored the substantial evidence of 

permanently reduced SO2 emissions 

and levels in the Billings/Laurel area. 

The commenter also argues that EPA’s 

authority is limited by its mandate 

under the CAA to ensure attainment and 

maintenance of the NAAQS as well as 

the CAA’s other general requirements. 

Response: See responses to comments 

II.A.1.(a), II.A.2(b), and II.E.1.(e) and (g). 

Also, the Hall case involved a challenge 

to EPA’s approval of a SIP revision for 

Clark County, Nevada, and EPA’s 

interpretation of section 110(l) of the 

CAA, which provides that EPA may not 

approve a SIP revision if it would 

interfere with attainment or other 

applicable requirements of the CAA. 

EPA asserted that its approval of the 

Clark County SIP revision was 

consistent with section 110(l) because 

the revision did not relax the existing 

SIP. The Court disagreed, holding that 

110(l) requires more—a determination 

that the specific revision, when 

considered in the context of the SIP 

elements already in place, can meet the 

Act’s attainment requirements. Hall at 

1152, 1159. It was in these 

circumstances that the Court expected 

EPA to determine the extent of pollution 

reductions required and evaluate 

whether the reductions resulting from 

the revision would be sufficient to attain 

the NAAQS. 

In its reference to Hall, the commenter 

appears to be conflating two disparate 

concepts. The Hall Court was 

addressing EPA’s action on a SIP 

revision and indicating that EPA was 

not adequately evaluating whether Clark 

County’s rule change would interfere 


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5To the extent the commenter is arguing that we 

may do no more in this FIP than appears minimally 

necessary to attain the NAAQS, we reject that 

notion as well. See, e.g., Central Arizona Water 

Conservation District v. EPA, 990 F.2d 1531, 1541 

(9th Cir. 1993) (EPA ‘‘stands in the shoes of the 

defaulting State, and all of the rights and duties that 

would otherwise fall to the State accrue instead to 

EPA.’’) Under the CAA, states are not restricted to 

barely meeting the NAAQS. In fact, the opposite is 

true—states may exceed minimum requirements. 

See CAA section 116, 42 U.S.C. 7416. In any event, 

our modeled attainment demonstration resulted in 

projected values just at the 24-hour SO2 NAAQS 

(365 μg/m3) and just below the 3-hour SO2 NAAQS 

(1291.5 μg/m3). However, we think we had 

discretion to adopt limits (to replace those we 

disapproved) consistent with modeled ambient 

concentrations further below the NAAQS, if we had 

felt a larger margin of safety was justified to ensure 

attainment and maintenance. 

6As we allude to in sections II.A.2.(b), II.D.4., and 

II.E.1.(e), the consent decree limits would need to 

be translated into limits that support an attainment 

demonstration for the SO2 NAAQS. In sections 

II.A.2.(b) and II.D.4., we identify some of our 

concerns with the consent decree limits. 

with attainment and other CAA 

requirements. The Court was not 

establishing a standard for a FIP or 

indicating that EPA was requiring more 

than necessary for the area, which 

seems to be what the commenter is 

suggesting in the case of the Billings/ 

Laurel FIP. As we explain in greater 

depth elsewhere in this notice, we are 

not starting from scratch with our FIP. 

Instead, we are working within the 

framework of the existing Billings/ 

Laurel SIP to fill the gaps resulting from 

our partial and limited disapproval of 

discrete SIP elements. In this unique 

circumstance, where only discrete 

elements of the SIP were deficient, the 

CAA does not require us to reevaluate 

or replace the entire SIP or the basic 

modeling approach upon which it was 

based. Nothing in the CAA requires EPA 

to reject an entire SIP when only certain 

elements within it are not approvable, 

and doing so, where that is not 

necessary to address a discrete 

deficiency, would be inconsistent with 

the basic scheme of cooperative 

federalism embodied in the CAA. 

Nor are we required as part of this FIP 

to revisit our SIP Call or the bases for 

our SIP disapproval. Our task is to fix 

the portions of the SIP that were 

deficient. It is reasonable to continue to 

treat as valid the factors we found 

adequate to support the portions of the 

SIP we approved, and augment and/or 

replace those factors that we found 

inadequate. In fact, based on the holding 

in Train v. NRDC, 421 U.S. 57 (1975), 

recited by this commenter and others, it 

would be inappropriate for EPA to now 

reject or replace the portions of the SIP 

that we approved as meeting the CAA’s 

requirements, because to do so would be 

to intrude on the State’s authority under 

the CAA to establish the mix of controls 

for the area.5 The State, of course, 

remains free to submit a SIP revision 

that reflects a different mix of controls 

across all the sources. This would be the 

mechanism, for example, whereby the 

State could adopt SIP limits that 

correlate to refinery consent decree 

limits.6 If the State were to submit such 

a revision, we would evaluate the 

revision according to the Act, our 

regulations, and the relevant cases. 

(d) Comment (ExxonMobil): EPA’s 

proposal imposes costly technology 

requirements not rationally designed to 

achieving their stated objectives. While 

EPA has authority to impose an 

emission limitation, the emission 

limitation must be necessary to attain 

NAAQS. City of Santa Rosa v. EPA, 534 

F.2d 150, 155 (9th Cir. 1976), vacated on 

other grounds, 429 U.S. 990 (1976). The 

EPA derived its authority in City of 

Santa Rosa from its statutory mandate 

to ensure compliance with NAAQS and 

the fact that no alternative to its 

proposal was adequate to ensure 

compliance with NAAQS. It is clear that 

Montana’s existing SIP, supplemented 

as it is by further state and federally 

enforceable consent decrees are a more 

than adequate alternative. 

Response: The cited case actually 

stands for the proposition that EPA’s 

authority to adopt measures to meet the 

NAAQS is expansive. EPA adopted a 

FIP provision that would have required 

a substantial reduction (up to 100%) in 

the supply of gasoline to major 

metropolitan areas in California, 

including Los Angeles. Even the EPA 

acknowledged that the rule would cause 

severe social and economic disruption, 

and the EPA Administrator at the time 

publicly advocated amendments to the 

CAA to provide relief from EPA’s own 

FIP rule. Nonetheless, the Court held 

that economic and social disruption are 

not cognizable if (1) a measure is 

necessary to attain the NAAQS; (2) there 

is no statutory limitation on EPA’s 

authority to adopt the measure; and (3) 

there are no equally effective, less 

burdensome alternatives. City of Santa 

Rosa at 151–154. 

The measures EPA is promulgating in 

this FIP are in no way comparable to the 

reduction in gasoline supply at issue in 

the City of Santa Rosa case. Our FIP is 

narrowly tailored to fill the gaps in the 

Billings/Laurel SIP. Section 110(c) 

requires us to promulgate the FIP. There 

is no statutory limitation on our 

authority to adopt the measures we are 

adopting. On the contrary, section 

110(a)(2)(A) of the Act requires 

enforceable emission limitations as 

necessary or appropriate to meet the 

applicable requirements of the Act, 

which include attainment and 

maintenance of the SO2 NAAQS. Using 

ISC, the same model the State used to 

set the commenter’s emission limits in 

the SIP, we have determined emission 

levels consistent with attainment and 

established corresponding emission 

limits on the flares, MSCC’s main stack, 

and other emission units, whose 

emission limits we disapproved in our 

SIP action. While the authority to 

require monitoring, recordkeeping, and 

reporting requirements can be inferred 

from CAA sections 110(a)(2)(A) and (C), 

section 110(a)(2)(F) of the Act 

specifically indicates that the EPA 

Administrator may prescribe the 

installation, maintenance, and 

replacement of monitoring equipment 

by stationary sources, as well as 

reporting requirements. Our 

requirement for the refineries and MSCC 

to install monitoring equipment to 

measure flare gas flow and 

concentrations is consistent with this 

authority and is rationally related to the 

goals of the FIP, i.e., to ensure 

attainment and maintenance of the SO2

NAAQS. We do not believe estimating 

flare emissions or emissions from other 

units is a sufficient substitute for realtime monitoring for purposes of this 

FIP; estimation is not an equally 

effective technique. 

The commenter argues that the 

existing SIP and the State and federally 

enforceable consent decrees are a more 

than adequate alternative to our FIP 

requirements. This comment ignores the 

fact that we disapproved portions of the 

SIP as not meeting the CAA’s 

requirements. Elsewhere we explain 

that the consent decree provisions are 

not sufficient to meet the CAA’s 

requirements under section 110 related 

to attainment and maintenance of the 

NAAQS. See, e.g., sections II.A.2.(b), 

II.D.4., and II.E.1.(e). 

(e) Comment (MSCC): EPA’s failure to 

issue the FIP within the CAA’s two-year 

deadline is important in this case. As a 

result of EPA’s delay, EPA should have 

to consider the cleanup of emissions 

that has occurred and significant 

changes in modeling technology. 

Response: We regret that it has taken 

this long to issue the FIP. We disagree 

that missing the two-year deadline 

obviates our duty or the need for the 

FIP. The State has not submitted a SIP 

revision correcting the portions of the 

SIP that we disapproved, despite the 

passage of time. Regarding the argument 

that we should have considered the 

reduction in emissions since we 

disapproved the SIP, see our responses 

to comments in section II.A. In section 

II.E, we respond to comments arguing 


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that we should have used newer 

modeling technology. 

C. Flare Monitoring 

1. Flare Flow Monitoring 

(a) Comment (MSCC): The core 

flowmeter technology application for 

flare systems seems to be an established 

technology, with thousands of 

installations completed around the 

world on other types of gas and liquid 

streams. However, none was identified 

that is following the precise 

specifications of the FIP proposal. 

Installation and operation of a flow 

meter in flare gas service at MSCC are 

probably achievable today, but not at 

the flow range below 1 fps, and not with 

conventional QA/QC procedures. Flow 

monitors have a difficult time 

measuring or reliably detecting low flow 

velocities (under approximately 1.0 fps) 

without false positives or false 

negatives. EPA should revise the 

proposed rule that currently indicates: 

‘‘[t]he minimum detectable velocity of the 

flow monitoring device(s) shall be 0.1 feet 

per second (fps). The flow monitoring 

device(s) shall continuously measure the 

range of flow rates corresponding to 

velocities from 0.5 to 275 fps and have a 

manufacturer’s specified accuracy of ±5% 

over the range of 1 to 275 fps. 

The revised rule should read ‘‘[t]he 

minimum resolution of the flow monitoring 

device(s) shall be 0.1 feet per second (fps) 

when measuring flow rates above 1.0 fps. The 

device(s) shall continuously measure the 

range of flow rates corresponding to 

velocities from 1.0 to 275 fps and have a 

manufacturer’s specified accuracy of ±5% 

over the range of that range.’’

The rule should also clarify if 

‘‘accuracy’’ is intended to be 5% of the 

full-scale range of the instrument (13.7 

fps is 5% of 275 fps), or if this is 

intended to be 5% of the measured flow, 

which would be 0.05 fps at a flow of 1 

fps, and would clearly be nonachievable with a resolution of 0.1 fps. 

Response: EPA proposed the 

volumetric flow monitoring 

specifications based on what we saw 

was achievable in vendor literature (see 

reference documents NN and OO) and 

what was being required by regulation 

in the Bay Area Air Quality 

Management District (BAAQMD) (see 

reference document LL) and South 

Coast Air Quality Management District 

(SCAQMD) (see reference document 

CCC). 

The commenter asserts that 

installation and operation of a flow 

meter at the flow range below 1 fps are 

not achievable. However, various 

sources indicate that ultrasonic flow 

meters can measure in the range of 0.1 

to 1 fps. For example, in ‘‘Flare Gas 

Ultrasonic Flow Meter,’’ J.W. Smalling, 

L.D. Brawsell, L.C. Lynnwoth and D. 

Russel Wallace, Proceedings ThirtyNinth Annual Symposium on 

Instrumentation for the Process 

Industries, 1984, the authors reported 

‘‘initially, a modest objective was 

established to develop an ultrasonic 

flow switch capable of detecting leaks in 

flare lines corresponding to flow 

velocity on the orders of 0.3 ms/ (1 ft/ 

s). As testing continued, however, it 

became apparent that the equipment 

could measure flows below 0.03 m/s 

(0.1ft/s) and up to at least 6 m/s (20 

ft/s) in flare stacks * * *’’ (see reference 

document KKKKK). See also reference 

document OO, ‘‘the DigitalFlowGF868 

meter achieves rangeability of 2750 to 1. 

It measures velocities from 0.1 to 275 

ft/s (0.03 to 85 m/s) in both directions, 

in steady or rapidly changing flow, in 

pipes from 3 in. to 120 in. (76 mm to 

3 m) in diameter.’’

Additionally, the BAAQMD (see 

reference document LL) and SCAQMD 

(see reference document CCC) require 

flow meters on flares. BAAQMD 

requires that the minimum detectable 

velocity shall be 0.1 fps and the 

SCAQMD requires monitors with a 

velocity range of 0.1 to 250 fps. Based 

on conversations with the BAAQMD, it 

appears that the refineries in the Bay 

Area have installed flow meters meeting 

the requirements of the rule (see 

reference document OOOOO). 

Based on the above, we conclude that 

flow meters are available that can 

measure in the velocity range below 1.0 

fps, and other regulatory authorities are 

requiring such flow meters with 

success. 

The commenter also claims that 

installation and operation of a flow 

meter are probably not achievable with 

conventional QA/QC procedures. The 

QA/QC procedures are discussed below 

in response to comment II.C.1.(d). 

The commenter argues that flow 

monitors have a difficult time 

measuring or reliably detecting low flow 

velocities (under approximately 1.0 fps) 

without false positives or false 

negatives. As indicated in the response 

to comment II.C.1.(b) below, there are 

approaches available for improving 

measurement accuracy in the 0.1 to 1.0 

fps range. In addition, as the response 

to comment II.C.1.(b) indicates, in the 

final FIP we are specifying a separate 

accuracy range for the velocity range of 

0.1 to 1 fps. Finally, we describe how 

we are addressing the false positive and 

false negative flows in response to 

comment II.C.1.(c). 

The commenter asked that the rule 

clarify if ‘‘accuracy’’ of the instrument is 

intended to be 5% of the full-scale range 

of the instrument or 5% of the measured 

flow. In the rule, we have clarified that 

‘‘accuracy’’ of the instrument is the 

accuracy of the measured flow and not 

the ‘‘full-scale range’’ of the instrument. 

The commenter also suggests some 

changes to the rule. Apart from adding 

a separate accuracy range for the 

velocity range of 0.1 to 1 fps and 

clarifying that accuracy is based on the 

measured flow, we are not making any 

additional changes to this aspect of the 

rule. We explain our reasoning in the 

response to this comment II.C.1.(a) and 

in the responses to comments II.C.1.(b)–

(d), below. 

(b) Comment (ExxonMobil, WSPA): 

Manufacturers of flow monitoring 

instrumentation publish impressive 

performance specifications regarding 

velocity measurement range and 

accuracy, but often manufacturers’

claims are not actually achieved in 

practice over the long term. To achieve 

a high level of measurement 

performance in the field requires 

adequate lengths of straight flare header 

pipe upstream and downstream of the 

monitor, the absence of flow 

disturbances, etc. Where these criteria 

cannot be met, the advertised or 

predicted performance of the flow 

monitoring system may not be fully 

realized in practice. MSCC claimed that 

significant piping modifications and 

possible flare relocation would be 

required to provide such runs at 

accessible locations. CHS Inc. asserted 

that it is likely that the CHS refinery 

flare header will not have adequate 

distances of undisturbed piping for 

ideal installation. In this case, either 

major, costly piping modification will 

be required or the accuracy criteria will 

not be achievable. 

Response: The commenters are correct 

that piping modifications may be 

appropriate to optimize the 

measurements. Each flare system will 

have unique flow measurement location 

issues and will have to be addressed on 

a case-by-case basis. Sources may need 

to work with the flow monitor 

manufacturer and flow testers to assure 

that the monitors meet the FIP’s 

specifications for accuracy and 

representativeness and manufacturer’s 

requirements for assuring ongoing 

equipment performance. 

In addition to making piping 

modifications (e.g. flow straighteners), 

other approaches are available to 

improve the measurement accuracy in 

the 0.1 to 1.0 fps range. Among the 

approaches are the use of additional 

monitoring paths, monitoring paths of 

longer length, and unconventional 

monitor configurations and path 

locations. Another approach involves 


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7Ultrasonic flow monitors will most likely be the 

monitors installed to meet the FIP’s flow 

monitoring performance specifications. 

the use of Computer Fluid Dynamics 

(CFD) for the existing piping. CFD 

analysis has been used to provide 

correction factors for a series of 

velocities across the range of flow 

velocities. For example, these factors 

have been used to correct flow 

measurement data for disturbances 

caused by upstream pipe irregularities. 

These approaches are discussed in ‘‘A 

Total Approach to Flare Gas Flow 

Measurement for Environmental 

Compliance,’’ Gordon Mackie, Jed 

Matson and Mike Scelzo, Institute of 

Measurement and Control—

Environmental Conference 2006. (See 

reference document LLLLL.) (See also 

Note to Billings/Laurel SO2 FIP File 

regarding conversations with GE 

Sensing (reference document 

MMMMM)). 

Finally, to address concerns regarding 

the measurement accuracy in the 0.1 to 

1.0 fps range, we are revising the rule to 

indicate that the flow monitor must 

have a manufacturer’s specified 

accuracy of ± 20% over the range 0.1 to 

1 fps. Based on conversations with a 

vendor, we believe this is achievable. 

The vendor indicated that they have 

provided methodologies for sources to 

meet the SCAQMD rule, which also 

requires 20% accuracy in the 0.1 to 1.0 

fps range. Methodologies include a 

second interrogation path or 

straightening of pipe. (See reference 

document MMMMM.) 

(c) Comment (ExxonMobil, WSPA, 

NPRA, MSCC): Consistently achieving 

low flow detection limits can be very 

difficult. Spurious signal, resulting in 

‘‘eddy’’ currents and back-and-forth 

flows in the flare header, can easily 

limit the detection and accuracy of low 

flow readings. Furthermore, sometimes 

a flow monitor will show an indication 

of flow even though water seals ahead 

of the flare stack remain intact (i.e., 

there is not flow to the flares). Other 

regulations in other jurisdictions allow 

the sources other means to positively 

determine when the flare is not 

operating (e.g., flare on/off monitoring 

device, pressure of water seal). 

ExxonMobil recommends that similar 

language be considered by the 

stakeholder process for inclusion in the 

EPA’s proposed FIP, and thereby 

remove the uncertainty of low flow 

reading. MSCC claimed that the EPA 

proposed FIP language should be 

revised to allow flare operations to be 

monitored by other means, and to 

disregard low flow readings when the 

flare is not operating to eliminate falsely 

reported SO2 emissions, when in fact 

there are none. 

Response: We agree that it is 

appropriate to include in the regulation 

the ability to use other secondary means 

to determine whether flow is reaching 

the flare when the flow monitor 

indicates low flow. If the secondary 

device indicates that no flow is going to 

the flare, yet the continuous flow 

monitor is indicating flow, the 

presumption will be that no flow is 

going to the flare. We have revised the 

final rule to allow the use of flare water 

seal monitoring devices to determine 

whether there is flow going to the flare, 

in addition to the continuous flow 

monitoring device. See response to 

comment II.F.1.(a) regarding the 

comment seeking a stakeholder process. 

(d) Comment (ExxonMobil, WSPA): A 

limitation of flare gas monitoring 

systems is the inability to provide for an 

independent ‘‘in situ’’ verification of 

accuracy. For example, there is no 

practical way to vary the flare gas flow 

that the monitor sees, and no practical 

way to utilize a reference method. 

Consequently, the calibration of a 

monitor is performed electronically, and 

the demonstration of accuracy is based 

on that calibration method. MSCC 

asserted that the proposed FIP does not 

provide adequate guidance to allow 

development of an acceptable QA/QC 

system for routine calibration or daily 

checks of the system. Without clear 

guidance, it is not possible to specify a 

system for a systems integrator (DAS/ 

reporting) or an end-user to design or 

build a system to accomplish these 

checks. 

Response: Since refinery flares 

contain highly variable flows and highly 

combustible material, in situ 

verification of flow measurement 

accuracy is difficult. For that reason, the 

performance specifications in the FIP 

rely in large part on procedures 

developed by the ultrasonic flow 

monitor manufacturers 7 for 

commissioning monitors to assure the 

monitors will meet performance 

specifications on an ongoing basis. 

Manufacturers have established 

procedures for conducting annual or 

more frequent verifications of the 

performance of installed flow monitors 

as well as for the initial installation and 

performance verification (see reference 

document NNNNN). Based on 

manufacturer established procedures 

(Id.), we expect that the annual 

verification procedures will address 

elements such as: 

1. Verification of the Flowmeter with 

Reference Transducers—the purpose is to 

evaluate all flowmeter subsystems with 

factory-certified ultrasonic transducers; 

2. Mechanical Inspection of Flowmeter 

Transducers—the purpose is to visually 

verify the integrity of the flare gas flowmeter 

transducers and to clean any accumulated 

debris from the transducer faces; 

3. Zero Flow Verification—the purpose is 

to evaluate the operation of the transducer 

pair in the flare gas process (the integrity of 

the original process transducers is tested in 

a controlled environment); 

4. Input/Output Verification—the purpose 

is to verify the calibration of the analog I/O 

of the flare gas flowmeter; 

5. Electronic Flow Simulation—the 

purpose is to demonstrate the operation of 

the flare gas flowmeter over the full 

measurement range of the instrument; and 

6. Flowmeter System Reinstallation and 

Test—the purpose is to verify that all 

mechanical systems were properly aligned. 

It should also be noted that since 

ultrasonic flow monitors do not contain 

any moving parts, their performance is 

not expected to deteriorate over time. 

One ultrasonic flow monitoring vendor 

provided information on the reliability 

and availability of the transducers 

(sensors in the flare that transmit and 

receive the ultrasound) they have 

installed. The information indicates that 

the 3,998 transducers installed between 

first quarter 2005 and first quarter 2007 

had a reliability percentage of 94.32% 

and an availability percentage of 

99.96%. (See reference documents 

MMMMM and XXXXXX.) (See also 

reference document LLLLL, ‘‘A Total 

Approach to Flare Gas Flow 

Measurement for Environmental 

Compliance,’’ Gordon Mackie, Jed 

Matson and Mike Scelzo, GE Sensing, 

Institute of Measurement and Control, 

Environmental Conference 2006, and 

reference document NNNNN, April 5, 

2007, email from Jed Matson, GE 

Sensing, to Laurie Ostrand, EPA, 

containing flare gas flow meter 

procedures. 

(e) Comment (COPC): ConocoPhillips 

asserts it would need to replace a GE 

Panametrics flare flow monitor that is 

well-suited to the variable flow 

conditions it experiences, but does not 

conform precisely to the proposed 

specifications. It is difficult to quantify 

what additional benefit this change 

would provide although the cost is 

significant and quantifiable. The benefit 

evaluation is further clouded because of 

the relatively recent installation of the 

Flare Gas Recovery Unit (FGRU). There 

is no flow to measure in the flare header 

when the FGRU is operating. The FGRU 

operates on a full-time basis, with the 

exception of nominal periods of 

malfunction or maintenance. 

Response: As indicated above, each 

source will have unique issues that will 

have to be addressed on a case-by-case 

basis. 


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We understand that ConocoPhillips 

has a FGRU and ExxonMobil will be 

installing one. We do not agree that a 

source with a FGRU should be 

exempted from monitoring flow to the 

flare. We still believe it is reasonable to 

include this requirement to gain an 

accurate picture of occasions when flow 

is going to the flare. We note that other 

areas that have required refinery flare 

monitoring (SCAQMD and the 

BAAQMD) have not eliminated the flare 

monitoring requirements at sources with 

FGRUs. (See Note to Billings/Laurel SO2

FIP File regarding conversations with 

BAAQMD, reference document 

OOOOO.) However, as indicated below, 

we are providing sources other means to 

determine total sulfur concentrations in 

the gas stream to the flare. 

Additionally, we note that the 

ConocoPhillips refinery in Rodeo, 

California has installed flare flow meters 

and that the refinery also has a flare gas 

recovery system. The ConocoPhillips 

San Francisco Refinery’s July 2007 Flare 

Minimization Plan (FMP), pages 3–7, 

indicates that flow meters have been 

installed on the Main and MP30 flares 

per the BAAQMD Regulation 12–11–

501. EPA’s Billings/Laurel FIP contains 

flare flow monitoring specifications very 

similar to the specifications in 

BAAQMD Regulation 12–11–501. The 

July 2007 FMP indicates ‘‘The 

installation of the flow meters provides 

for enhanced recognition of flaring 

events. The flow meters help reduce 

flaring by providing an accurate means 

to measure and provide indication as to 

when flaring is occurring. The flow 

meters are especially useful for small 

flaring events which may not be 

detectable from visual flare stack 

monitoring only. The meters help to 

track and record all instances of flaring 

as well as giving Unit Operators 

immediate indication that flaring is 

occurring so that they can take action to 

reduce flaring.’’ (See reference 

document PPPPP.) 

(f) Comment (MSCC): The proposed 

40 CFR 52.1392(h)(2)(iii) appears to be 

in error. The rule indicates that ‘‘The 

flare gas stream volumetric flow rate 

shall be measured on an actual wet basis 

in SCFH.’’ Actual wet basis would be 

abbreviated as ACFH. SCFH means 

standard cubic feet per hour, meaning 

that the data has been corrected to 

standard temperature and pressure. The 

SCFH could be replaced with ACFH. 

Alternately, the term ‘‘actual’’ could be 

removed from the section, leaving ‘‘wet 

basis in SCFH.’’ SCFH (corrected for 

temperature and pressure) can also be 

used to compute a mass emission rate of 

sulfur dioxide, provided that any 

concentration measurements of sulfur 

are also made on a ‘‘wet’’ basis. 

Response: The commenter is correct. 

We are revising the regulatory text to 

read: ‘‘The flare gas stream volumetric 

flow rate shall be measured on an actual 

wet basis, converted to Standard 

Conditions, and reported in SCFH.’’

(g) Comment (several commenters): 

Several commenters express a general 

concern that the technology will not be 

able to meet the performance 

specifications. 

Response: See responses to comments 

II.C.1.(a)–(c), above. 

(h) Comment (YVAS): YVAS concurs 

with the proposed volumetric flow 

monitoring requirements. 

Response: We acknowledge receipt of 

the supportive comment. 

2. Flare Total Sulfur Analyzers 

(a) Comment (ExxonMobil, WSPA, 

COPC): SCAQMD staff was not able to 

identify a single commercial sulfur 

analyzer in service on a refinery flare 

system. It is unreasonable for EPA to 

conclude that sulfur analyzer 

technology is either ‘‘available’’ or 

‘‘reliable.’’ MSCC was not able to 

identify any installations where flare gas 

monitoring was, in fact, covering a range 

from 0–100% sulfur. 

Response: EPA has identified two 

sources where analyzers are on lines 

leading to the refinery flare. 

Specifically, the Tesoro refinery in the 

Bay Area, California, has two Thermo 

Electron Tracker XP continuous H2S 

analyzers. The Tesoro analyzers are dual 

range instruments, 0–1% and 0–5% (see 

reference document OOOOO). 

Additionally, the Shell refinery in Puget 

Sound, Washington, uses an analyzer 

that thermally oxidizes total sulfur to 

SO2 and then measures the SO2. The 

analyzer can measure up to 40,000 ppm 

of SO2 (see reference document 

QQQQQ). Finally, as indicated in the 

response to comment II.C.2.(b) below, 

the SCAQMD recently reported on a 

pilot project study, testing a total sulfur 

analyzer at the BP Carson facility in 

southern California, and indicated that 

the ‘‘preliminary results have 

demonstrated the feasibility of 

measuring total sulfur emissions from 

vent gases directed to flares.’’

The proposed FIP did not specifically 

require that an analyzer be capable of 

measuring in the range from 1–100% 

sulfur, although the preamble implied 

and the record reported conversations 

with vendors indicating that analyzers 

could measure in the range from 1–

100% sulfur. We are clarifying the final 

FIP to indicate that the total sulfur 

analyzers should measure in the range 

of concentrations that are normally 

present in the gas stream to the flare. In 

cases when the total sulfur analyzer is 

not working or where the concentration 

of the total sulfur exceeds the range of 

the monitor, methods established in the 

flare monitoring plan required by the 

FIP shall be used to determine total 

sulfur concentrations, which shall then 

be used to calculate SO2 emissions. In 

quarterly reports, sources shall indicate 

when these other methods are used. 

(b) Comment (ExxonMobil, WSPA): 

SCAQMD Rule 1118 had an important 

provision requiring an analyzer pilot 

project, and one Los Angeles area 

refiner is currently engaged with a 

sulfur analyzer demonstration project. It 

is conceivable that the pilot project 

could result in the conclusion that the 

analyzer being evaluated could not 

provide sufficient accuracy, that the 

system was not maintainable, or that 

there were other problems. 

Response: On June 1, 2007, the 

SCAQMD presented to its Governing 

Board an ‘‘Implementation Status 

Report for 2006 for Rule 1118—Control 

of Emissions from Refinery Flares.’’

Agenda No. 27 discusses the total sulfur 

(TS) analyzer pilot project at the BP 

refinery in Carson and indicates: 

The TS pilot project is in the final step 

prior to certification of the analyzer. 

Although several adjustments and redesign of 

sampling equipment were required; [sic] 

preliminary results have demonstrated the 

feasibility of measuring total sulfur emissions 

from vent gases directed to flares. Based on 

these results, two refineries have already 

placed purchase orders for their TS 

analyzers. 

In the May 15, 2007, ‘‘Implementation 

Status Report for 2006 for Rule 1118—

Control of Emissions From Refinery 

Flares,’’ attached to Agenda No. 27, the 

SCAQMD concludes: 

Although they are behind schedule to 

comply with the July 1, 2007 monitoring 

requirements, the pilot projects are moving 

ahead convincingly towards completion by 

the end of 2007. As the rule is forcing new 

technologies for flare emission reporting, 

analyzer vendors have responded to the 

challenge and several options are now 

available, such as calorimeters, gas 

chromatographs, mass spectrometers and 

Pulsed UV Fluorescence analyzers, for 

continuously measuring HHV [higher heating 

value] and TS. Therefore, staff expects full 

implementation of the continuous 

monitoring provisions of the rule once the 

pilot projects are complete. Since the 

refineries could not meet the monitoring 

requirements by July 1, 2007, the refineries 

petitioned and were granted variances in late 

April 2007 by the AQMD Hearing Board to 

install and operate their flare monitoring 

systems over the next two years. 

See reference document RRRRR. 

Based on the above information, the 

total sulfur pilot project did not 


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conclude that the analyzer being 

evaluated could not provide sufficient 

accuracy, that the system was not 

maintainable, or that there were other 

insurmountable problems. 

(c) Comment (ExxonMobil): EPA and 

industry need more time to review the 

SCAQMD pilot project test results and 

conclusions as they become available 

over the next few months and to 

determine if the technology that was 

tested is technically viable and whether 

or not a more cost effective alternative 

technology may be available. MSCC 

recommends that the implementation of 

total sulfur monitoring on the flares be 

delayed at least until the full results 

from the long-term program in 

California are available, and the 

capability of the market to supply and 

support such systems in severe weather 

locations such as Montana is 

demonstrated. At that point EPA should 

revise and then issue the final rule, after 

full stakeholder involvement in the 

process and full consideration of 

realistically available options. 

Response: See responses to comments 

II.C.2.(a) and (b), above. Also, as noted 

in response to comment II.C.3.(a), 

below, EPA is revising the proposed FIP 

to allow other methods to determine 

total sulfur concentration in the gas 

stream to the flare. See response to 

comment II.F.1.(a) regarding the request 

for a stakeholder process. 

(d) Comment (ExxonMobil): 

Recognizing that these total sulfur 

analyzer systems do not, by themselves, 

provide any air quality benefit, and 

considering that there are alternatives to 

continuous analyzers (e.g., individual 

grab samples, etc.), ExxonMobil submits 

that the proposed requirement to install 

continuous analyzers requires further 

evaluation in the stakeholder process. 

Response: As discussed under 

response to comment II.C.1.(a), below, 

our final FIP allows other methods to 

determine total sulfur concentration in 

the gas stream going to the flare, 

including grab or integrated sampling 

methods. This should address the 

commenter’s concerns. However, we 

note that whether or not total sulfur 

analyzer systems provide any air quality 

benefit by themselves is immaterial; the 

FIP establishes emission limits to assure 

that the SO2 NAAQS are attained and 

maintained and it is essential that the 

FIP include reliable mechanisms to 

determine compliance with the limits. 

See, e.g., CAA section 110(a)(2)(F), 42 

U.S.C. 7410(a)(2)(F). Finally, as we 

noted in our May 14, 2007, proposal to 

revise subpart J of the new source 

performance standards (NSPS), and to 

adopt new subpart Ja, the requirement 

to monitor flare emissions in the 

SCAQMD in fact resulted in reduced 

flaring (72 FR 27178, at 27195) (see 

reference document SSSSS). 

(e) Comment (ExxonMobil, WSPA): 

Cost of installing total sulfur analyzers 

should be further evaluated given that 

the analyzers themselves do not provide 

an air quality benefit. Costs of total 

sulfur analyzer pilot project in the 

South Coast area expected to be in the 

range of 3 to 5 million dollars. 

Response: See response to comment 

II.C.2.(d), above. Additionally, the cost 

of the South Coast pilot project was 

higher than expected because it was a 

pilot study and because some 

difficulties were encountered during the 

study. (See also note to Billings/Laurel 

SO2 FIP File regarding conversations 

with SCAQMD, reference document 

TTTTT.) 

Also, in its ‘‘Implementation Status 

Report for 2006 for Rule 1118—Control 

of Emissions From Refinery Flares,’’

May 15, 2007, the SCAQMD reported 

that refineries involved in the pilot 

projects reported that monitoring costs 

were estimated to be about 2 to 4.7 

million dollars per flare. After looking at 

the breakdown of the costs, SCAQMD 

staff concluded that the total sulfur and 

higher heating value analyzer costs were 

comparable to staff’s original estimates. 

However, the costs to design and build 

the monitoring system were 

significantly different. Research and 

development (R&D), engineering, labor/ 

oversight, piping/electrical, analyzer 

shelters, and contingencies stated by the 

refineries represented approximately 75 

to 85 percent of the flare monitoring 

system cost. (See reference document 

RRRRR.) 

SCAQMD also indicated that in a 

related development, ExxonMobil 

informed staff in January 2007 that 

ExxonMobil was taking a different 

approach and was going to use a 

different technology, namely, gas 

chromatography (GC) for both the TS 

and the HHV analyzer; the estimated 

cost given to SCAQMD staff was 1 to 2 

million dollars. ExxonMobil advised 

SCAQMD staff that similar instruments 

had been used at ExxonMobil’s flares in 

Baytown, TX, and Chalmette, LA, for 

monitoring H2S and the BTU content of 

vent gases for compliance with EPA and 

Texas Commission on Environmental 

Quality (TCEQ) regulations. (Id.) 

(f) Comment (CHS Inc.): Analysis of 

total sulfur in a flare system is 

challenging because of the wide range of 

sulfur concentrations possible as well as 

the number of individual sulfur 

compounds potentially present. It is the 

understanding of CHS that there is not 

one commercial total sulfur analyzer in 

service on a refinery flare. 

Response: See response to comment 

II.C.2.(a), above. 

(g) Comment (MSCC): Since H2S is 

believed to be the principal 

(overwhelming) sulfur component of 

candidate flares, further consideration is 

warranted as to whether the ‘‘total’’

sulfur component is the appropriate 

methodology, given the clear lack of 

existing equipment for the full potential 

range of concentrations of flare gases, 

and the complexity involved in 

continuously converting a variable 

mixture into a single component such as 

SO2 or H2S. EPA should evaluate 

whether there is a real, necessary, and 

significant need to require total sulfur 

analysis instead of allowing a somewhat 

simpler H2S analysis of flare gases. 

Response: The commenter has not 

provided any technical analyses 

supporting the notion that H2S is the 

overwhelming component of the total 

sulfur in the gas stream to its flares or 

other flares in the area. EPA reported in 

the May 14, 2007, proposed new source 

performance standards (NSPS) for 

Subpart Ja (72 FR 27178, at 27194) (see 

reference document SSSSS) that ‘‘based 

on available data, we understand that a 

significant portion of the sulfur in fuel 

gas from coking units is in the form of 

methyl mercaptan and other reduced 

sulfur compounds. These compounds 

will also be converted to SO2 in the fuel 

gas combustion unit, which means the 

SO2 emissions will be higher than the 

amount predicted when H2S is the only 

sulfur-containing compound in the fuel 

gas.’’ See also the response to comment 

II.C.2.(a), above. Therefore, in the FIP 

we are still requiring that the gas stream 

to the flare be analyzed for total sulfur. 

(h) Comment (ConocoPhillips, MSCC): 

In a typical CEMS installation, the 

analyzers are subjected to frequent 

testing with gases intended to represent 

a ‘‘zero’’ condition and a ‘‘span’’

condition which is specified as a 

significant percent of full scale of the 

analyzer. ‘‘Total Sulfur’’ analyzers, 

operating over a wide range of 

concentrations, present some special 

concerns for span gases. If the proposed 

FIP requires high concentration 

analyzers, it also needs to incorporate 

protocols to establish calibration 

standards for these analyzers. 

ConocoPhillips indicates that flare gas 

sulfur concentrations can be highly 

variable, which makes the comparison 

required by the Relative Accuracy Test 

Audit (RATA) difficult. The sulfur 

analyzer captures samples in a series of 

periodic discrete ‘‘grab’’ samples, to be 

averaged over the period of total sample 

time. Comparison sample techniques 

vary, but in general involve getting a 

continuous sample over a period of 


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time, with the concentration averaged 

over that time period. Depending on the 

variability of the concentration over this 

time period, the average of the discrete 

‘‘grab’’ samples has the potential to be 

different than the average of the 

continuous RATA sample. When the 

concentrations are numerically low, this 

difference is compounded and skews 

the accuracy calculations. This poses a 

significant risk of failing the RATA 

specifications, thereby voiding the 

monitor data and imposing a 

compliance issue (even if the difference 

is a few parts per million). 

ConocoPhillips believes that this 

requirement is not technically valid for 

the operations for which it is being 

proposed. 

Response: As indicated in response to 

II.C.2.(b), above, the BP Pilot Project is 

nearing completion and expected to be 

a success. Also, see note to Billings/ 

Laurel SO2 FIP File regarding 

conversations with SCAQMD (reference 

document TTTTT). With respect to the 

calibration of the analyzer, SCAQMD 

indicated that there are several issues 

that need to be addressed. Specifically, 

one needs to assure that (1) the correct 

calibration gas is in the bottle, (2) the 

sample lines do not absorb or desorb 

sulfur, (3) the probe is positioned 

appropriately, and (4) all flow testing or 

other sample collection is correlated 

temporally with the analyzer 

measurements to ensure representative 

comparisons. 

(i) Comment (ExxonMobil): EPA 

recognized the impracticality of 

concentration monitoring for flares 

during the recent Consent Decree 

negotiations. CEMS were deemed 

unnecessary and impractical for flares, 

unless the flare was in continuous use. 

Response: The basis for the FIP is 

different than the consent decrees. The 

FIP assures attainment of the SO2

NAAQS, a health-based standard, and 

the consent decrees assure that the new 

source performance standards (NSPS), 

technology-based standards, are met. 

Because of these differences, we believe 

it is appropriate to take a different 

approach. 

We disagree with the commenter’s 

statement that ‘‘EPA recognized the 

impracticality of concentration 

monitoring for flares during the recent 

Consent Decree negotiations. CEMS 

were deemed unnecessary and 

impractical for flares.’’ The CDs 

required that compliance with 40 CFR 

60.104(a) be determined by several 

options, one of which was to install and 

operate a CEMS per 40 CFR supbart J 

(e.g. see paragraph 77 of CHS Inc.’s CD, 

reference document JJJJJ): 

77. All continuous or intermittent, 

routinely-generated refinery fuel gas streams 

that are routed to the flare header at Cenex 

shall be equipped with a CEMS as required 

by 40 CFR § 60.105(a)(4) or with a parametric 

monitoring system approved by EPA as an 

alternative monitoring plan (‘‘AMP’’) under 

40 CFR § 60.13(i), at the combined juncture 

prior to the flare. Cenex shall comply with 

the reporting requirements of 40 CFR Part 60, 

Subpart J, for the Refinery Flare. 

We also note that the proposed NSPS 

Subpart Ja includes a total sulfur 

standard and CEMS requirements for 

fuel gas combustion devices, which are 

defined to include flares. (See 72 FR 

27178 (May 14, 2007), reference 

document SSSSS.) 

(j) Comment (MSCC): MSCC is aware 

that it may be possible to use gas 

chromatography systems to attempt to 

meet the proposed FIP requirements. 

Due to time constraints, they were not 

able to investigate this subject 

thoroughly. 

Response: As indicated in response to 

II.C.2.(e), ExxonMobil reported to the 

SCAQMD that it is using gas 

chromatography for its total sulfur and 

higher heating value analyzers. 

ExxonMobil has advised SCAQMD staff 

that similar instruments have been used 

on its flares in Baytown, TX, and 

Chalmette, LA, for monitoring H2S and 

the BTU content of vent gases for 

compliance with EPA and Texas 

Commission on Environmental Quality 

(TCEQ) regulations. (See reference 

document RRRRR.) Also, see note to 

Billings/Laurel SO2 FIP File regarding 

conversations with SCAQMD (reference 

document TTTTT). 

(k) Comment (several commenters): A 

general concern is expressed that the 

technology is not there to meet 

performance specifications. 

Response: See responses to above 

comments II.C.2.(a) and (b). 

(l) Comment (YVAS): YVAS concurs 

that total sulphur concentrations and 

not just H2S be monitored. 

Response: We acknowledge receipt of 

the comment and the support for our 

proposal. 

3. Miscellaneous Flare Monitoring 

Concerns 

(a) Comment (COPC, CHS Inc., 

MSCC): The proposed FIP should allow 

for Alternative Monitoring Plans (AMPs) 

to determine compliance. 

ConocoPhillips argued that AMPs are 

technically sound data gathering plans 

that are developed based on site-specific 

factors. These AMPs allow a facility to 

comply based on equivalent but 

customized criteria. CHS Inc. claimed 

that uncertainty of the monitoring 

capabilities and the quality assurance/ 

quality control requirements makes it 

reasonable for EPA to allow for AMPs 

similar to other EPA regulations. MSCC 

indicated that it calculates and reports 

the amount of SO2 emitted during each 

flaring event based on the recent 

content, and estimated flow gas(es) 

flared, based on reasonable technical 

judgment and indirect metering 

calculations. MSCC asserted that EPA 

has failed to show any significant errors 

or omissions with these methods. 

Response: EPA is revising the 

proposed FIP to allow other methods to 

determine total sulfur concentration in 

the gas stream going to the flare. The 

other methods allow sources to use grab 

or integrated sampling, followed by 

sample analysis, to determine total 

sulfur concentration of the gas stream 

going to the flare. These grab and 

integrated sampling methods are 

currently allowed in the BAAQMD rule 

(see reference document LL), and 

similar methods have been allowed by 

the SCAQMD. Two of the refinery 

companies (ConocoPhillips and 

ExxonMobil) in the Billings area also 

have refineries in the Bay Area and/or 

the South Coast Area and should be 

familiar with these manual methods. 

Specifically, we are revising the rule 

to indicate that the total sulfur 

concentration of the gas stream going to 

the flare can be determined by: (1) A 

total sulfur concentration monitoring 

system as we proposed on July 12, 2006, 

and including the changes we have 

identified here; or (2) grab sampling or 

integrated sampling. 

If a source chooses to use the grab or 

integrated sampling methods, the 

requirement to obtain a grab or 

integrated sample will be triggered if the 

velocity of the gas stream to the flare in 

any consecutive 15-minute period 

continuously exceeds 0.5 feet per 

second (fps) and shall continue until the 

flow rate of the gas stream to the flare 

in any consecutive 15-minute period is 

continuously 0.5 fps or less. 

Additionally, the rule indicates that a 

grab or integrated sample will not be 

required if any water seal monitoring 

device indicates that flow is not going 

to the flare. See discussion in response 

to comment II.C.1.(c). Under these 

conditions, if the water seal monitoring 

device indicates that there is no flow 

going to the flare, yet the continuous 

flow monitor indicates flow, the 

presumption will be that no flow is 

going to the flare. 

For grab sampling, a sample shall be 

collected within 15 minutes after the 

triggering conditions occur (see above), 

and the sampling frequency, thereafter, 

shall be one sample every 3 hours. For 

integrated sampling, a sample shall be 


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collected within 15 minutes after the 

triggering conditions occur (see above), 

and the sampling frequency, thereafter, 

shall consist of a minimum of 1 aliquot 

for each 15-minute period until the 

sample container is full, or until the end 

of a 3-hour period is reached, whichever 

comes sooner. Within 30 minutes 

thereafter, a new sample container shall 

be placed in service. For grab and 

integrated sampling, sampling shall 

continue until sampling is no longer 

required (see above). 

Samples obtained by either grab or 

integrated sampling shall be analyzed 

for total sulfur concentration using 

ASTM Method D4468–85 (Reapproved 

2000) ‘‘Standard Test Method for Total 

Sulfur in Gaseous Fuels by 

Hydrogenolysis and Rateometric 

Colorimetry’’ (see reference document 

MMMMMM); ASTM Method D5504–01 

(Reapproved 2006) ‘‘Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Chemiluminescence’’ (reference 

document NNNNNN); or 40 CFR part 

60, Appendix A–5, Method 15A 

‘‘Determination of Total Reduced Sulfur 

Emissions From the Sulfur Recovery 

Plants in Petroleum Refineries.’’ Total 

sulfur concentration shall be reported as 

H2S or SO2 in ppm. Proper QA/QC 

procedures shall be used to assure that 

the samples are obtained and analyzed 

appropriately. 

We chose the trigger level for two 

reasons. First, the rule indicates that the 

minimum detectable velocity of the flow 

monitoring device(s) shall be 0.1 fps and 

the flow monitoring devices shall 

continuously measure the range of flows 

corresponding to 0.5 to 275 fps. Since 

0.5 fps is the minimum flow measure 

required, it is a reasonable trigger level 

to ensure protectiveness. Second, flow 

monitoring software averages all the 

readings in a 15-minute timeframe and 

records/reports the average flow. Using 

the minimum recorded/reported 

timeframe is reasonable to ensure 

protectiveness. 

With respect to using estimations, 

technical judgment, and indirect 

metering to calculate emissions from the 

flare, because this FIP is designed to 

protect the NAAQS, we are choosing to 

require real-time direct monitoring 

methods to determine emissions. We do 

not believe estimations, technical 

judgments, and indirect metering are 

adequate substitutes for real-time 

monitoring for purposes of the FIP. 

(b) Comment (ExxonMobil, WSPA, 

COPC, CHS Inc., MSCC): The proposed 

requirement for a facility to install, 

commission, and calibrate flow 

monitoring systems and continuous 

sulfur analyzer systems within 180 days 

after receiving EPA approval of a 

monitoring plan is a requirement that 

would simply be impossible to meet. 

Response: Based on the comments 

received, we have revised the FIP to 

allow 365 days, rather than 180 days, 

after EPA approval of the flare 

monitoring plan to install continuous 

flow monitors and to begin determining 

total sulfur concentrations on the gas 

stream to the flare. Based on 

conversations with an ultrasonic flow 

monitor manufacturer, BAAQMD, and 

SCAQMD (see reference documents 

MMMMM, OOOOO, and TTTTT, 

respectively), we believe this additional 

time is reasonable to install continuous 

flow monitors and total sulfur analyzers 

or to initiate grab or integrated 

sampling. 

(c) Comment (MSCC, ExxonMobil): 

The FIP implies that pilot and purge gas 

must be monitored. Pilot and purge gas 

lines are separate from the main header 

vent gas lines. Monitoring these other 

relatively small gas flows to the flare is 

a waste of effort and resources. The pilot 

gas is usually a small natural gas stream 

of low flow and essentially zero sulfur 

content. The small purge gas line 

usually is natural gas, refinery fuel gas, 

or inert gas such as carbon dioxide or 

nitrogen, or mixtures of such gases with 

air or steam. In either case, the flow is 

not high and usually ExxonMobil does 

not expect high sulfur content. These 

two stream types (pilot gas, purge gas) 

cannot physically be mixed with the 

main vent gas stream for measurement 

of flow and sulfur content by one set of 

monitors, without defeating their 

essential purposes of safety. Given the 

nature of the pilot gas and purge gas 

streams, it is not reasonable to require 

flow and sulfur monitors which meet 

the proposed FIP specs on these 

streams. Regulations from other areas 

allow the flow and sulfur content of 

pilot and purge gas to be estimated/ 

monitored by other devices or sampling 

means. It is recommended that the 

proposed FIP language be re-written to 

clearly exempt pilot gases and purge 

line gases from the proposed FIP 

monitoring requirements. Neither can 

reasonably be considered as a 

significant source of sulfur dioxide. 

ExxonMobil asserted that EPA’s 

proposed FIP requirement for the 

Billings/Laurel area is neither 

reasonable nor legally supportable. 

Response: In conversations with the 

SCAQMD, we learned that in some 

instances they had seen copious 

emissions due to flare pilot and purge 

gas (see reference document TTTTT). 

SCAQMD indicated, as do the 

commenters above, that in some cases 

refinery fuel gas is used as a purge gas. 

Refinery fuel gas can have high sulfur 

content. Because of the potential for SO2

emissions from the burning of pilot and 

purge gas, we believe it is necessary to 

account for these emissions and include 

them when determining the total 

emissions from the flare. 

We agree that the proposed FIP 

implied that the pilot and purge gas 

should be monitored by the analyzers 

on the flare line used to measure flow 

and concentration of the gas stream to 

the flare. We are revising the FIP to 

require flow and H2S concentration 

monitoring of the pilot and purge gas as 

one possible method to determine sulfur 

dioxide emissions from the burning of 

such gas in the flare. However, the FIP 

allows sources to forego monitoring if 

certain requirements are met. First, if 

facilities certify that only natural gas or 

an inert gas is used for the pilot and/or 

purge gas, then the gas does not need to 

be monitored. Second, if facilities can 

measure other parameters so that 

volumetric flows, expressed in SCFH, of 

pilot and purge gas can be calculated 

(based on the design and the 

parameters), then the flows do not need 

to be monitored. Third, if the H2S 

concentration of the pilot or purge gas 

can be determined through other 

methods, then the H2S concentration 

does not need to be monitored. Once 

flow and H2S concentration of the pilot 

and purge gas are determined, sources 

must then calculate the SO2 emissions 

from the pilot and purge gas. The 

calculated SO2 emissions will then be 

added to the other SO2 emissions from 

the flare to determine compliance with 

the flare SO2 emission limits. Also, we 

are revising the reporting requirements 

to require sources to: (1) Certify in the 

quarterly reports if pilot or purge gas is 

not monitored because only natural gas 

or an inert gas is used as the pilot and/ 

or purge gas; or (2) report flow and H2S 

concentration of the pilot and/or purge 

gas and the resultant SO2 emissions. 

(d) Comment (MSCC): Flow and 

concentration monitoring would be 

costly and there is no justification for 

such costs and complexity given that 

the area is in attainment for the NAAQS. 

Response: See response to comments 

II.C.2.(d) and II.C.3.(c), above. 

(e) Comment (YVAS): YVAS concurs 

that each source submit for EPA review 

a quality assurance and quality control 

plan for each of the continuous 

monitors. 

Response: We acknowledge receipt of 

the comment and the support for our 

proposal. 


jlentini on PROD1PC65 with RULES2
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8See reference document RRR, September 20, 

1999, memorandum entitled ‘‘State Implementation 

Plans: Policy Regarding Excess Emissions During 

Malfunctions, Startup, and Shutdown.’’

D. Flare Limits 

1. Concerns With Flare Emission Limit 

(a) Comment (CHS Inc, MSCC): The 

proposed flaring limit of 150 lbs SO2/3 

hour period was used in the model to 

represent routine flaring and 

background SO2 concentrations. This 

threshold was never intended to and did 

not account for malfunctions, startups, 

or shutdowns. 

Response: The FIP fills the gap for the 

provisions of the SIP that were 

disapproved. In its attainment 

demonstration modeling, the State 

modeled emissions from flares at 150 

lbs of SO2/3-hour period, yet the SIP did 

not contain corresponding emission 

limits for the flares. This was the basis 

for our disapproval of part of the SIP. 

We believe we have appropriately 

addressed malfunction, startup, and 

shutdown in this final rule. See section 

II.D.3., below. 

Certain assumptions were made in the 

State’s attainment demonstration for the 

Billings/Laurel SO2 SIP. Included in the 

assumptions was that flares had routine 

emissions of 150 lbs of SO2/3-hour 

period. To assure attainment and 

maintenance of the NAAQS, the SIP or 

a FIP must contain enforceable emission 

limits on the flares. This is fully 

explained in our proposed action on the 

Billings/Laurel SO2 SIP (64 FR 40791, 

40801, July 28, 1999) and in the 

response to comments contained in our 

final action on the Billings/Laurel SO2

SIP (67 FR 22168, 22179, May 2, 2002). 

The State of Montana has flare 

provisions that apply to CHS Inc., 

ConocoPhillips, ExxonMobil, and 

MSCC. See CHS Inc.’s, ConocoPhillips’, 

ExxonMobil’s, and MSCC’s exhibit A–1, 

adopted by the Montana Board of 

Environmental Review on June 12, 1998 

(reference documents QQQQQQ, 

PPPPPP, UUUUU, and OOOOOO). 

Exhibit A–1 contains additional State 

requirements that were not submitted 

for inclusion in the SO2 SIP. Among 

these is an emission limit on flares of 

150 lbs of SO2/3-hour period, the value 

the State relied on to model attainment. 

These flare provisions do not and would 

not satisfy the SIP/FIP requirements of 

the CAA for two reasons. First, they 

were never submitted to EPA to be 

included as part of the SIP. Second, the 

flare provisions contain automatic 

exemptions for malfunction, startup, 

and shutdown. This is inconsistent with 

EPA’s longstanding interpretation of the 

CAA, which is that, since SIPs must 

provide for attainment and maintenance 

of the NAAQS and the achievement of 

the PSD increments, all periods of 

excess emission must be considered 

violations. Accordingly, any provision 

that allows for an automatic exemption 

for excess emission is prohibited.8

(b) Comment (NEDA/CAP, MSCC, 

ExxonMobil): The capriciousness of 

EPA’s proposed FIP provision affecting 

flaring is that EPA recognizes in the 

proposed notice that sources likely will 

be unable to comply with the 

continuous flaring emission limitations. 

Yet the proposed FIP would allow 

citizens to bring actions for violations of 

unattainable limits when EPA or the 

State likely would choose to exercise its 

prosecutorial discretion. Such a 

regulatory ‘‘Catch-22’’ is both 

unreasonable and unlawful. 

Response: We respectfully disagree 

with the commenter. First, in our 

proposal we did not say that sources 

will be unable to comply with the 

continuous flaring emission limitations. 

We note that, after receiving the 

refineries’ estimates of routine flare 

emissions, the State established as a 

State-only limit the same numerical 

flare limit we are adopting, and the 

refineries and MSCC agreed to the 

stipulations containing those limits. See 

67 FR 22180, col. 2, May 2, 2002, and 

reference documents UUUUU, 

OOOOOO, PPPPPP, QQQQQQ, and 

SSSSSS. Also, at the time of our SIP 

action, Conoco indicated to us that 

routine emissions from its flare were 

expected to be less than 150 lbs SO2/3- 

hour period. See 67 FR 22180, col. 2, 

May 2, 2002, and reference document 

RRRRRR. Based on this information, we 

have concluded that the refineries and 

MSCC will be able to comply with the 

150 lbs SO2/3-hour flare limit under 

normal operating conditions. 

We did say in our proposal that we 

recognize flares are sometimes used as 

emergency devices and that it may be 

difficult to comply with the flare limits 

during malfunctions. See 71 FR 39264, 

col. 1, July 12, 2006. However, contrary 

to the commenters’ assertions, our 

decision to require an emission limit 

that may be difficult to meet under 

certain conditions is not capricious, 

unreasonable, or unlawful. 

There is often a conflict, which is not 

limited to refinery flare emissions, 

between a source’s ability to control 

emissions during certain operating 

conditions and the CAA’s requirement 

to attain and protect the NAAQS. Our 

fundamental responsibility under the 

CAA with respect to SIPs/FIPs, 

however, is to ensure the NAAQS are 

attained and other CAA requirements 

are met. See CAA sections 110(a) and 

(l), 42 U.S.C. 7410(a) and (l); reference 

document RRR, September 20, 1999, 

memorandum titled ‘‘State 

Implementation Plans: Policy Regarding 

Excess Emissions During Malfunctions, 

Startup, and Shutdown,’’ from Steven 

A. Herman and Robert Perciasepe, to 

Regional Administrators (hereafter 

‘‘1999 excess emissions 

memorandum’’); City of Santa Rosa v. 

EPA, 534 F.2d 150, 155 (9th Cir. 1976), 

vacated on other grounds, 429 U.S. 990 

(1976). Thus, we have long held that 

outright or ‘‘automatic’’ exemptions 

from emission limits needed to 

demonstrate attainment of the NAAQS 

are not appropriate, something we 

indicated in our proposed FIP. See our 

1999 excess emissions memorandum, 

reference document RRR, and our 

proposed FIP, 71 FR 39264, col. 1, July 

12, 2006. Our interpretation on this 

issue has been upheld by the U.S. Court 

of Appeals for the 6th Circuit: in a 2000 

decision, the Court rejected a challenge 

to EPA’s disapproval of a Michigan SIP 

revision that provided an automatic 

exemption from SIP limits during 

malfunction, startup, and shutdown 

periods. Michigan Department of 

Environmental Quality v. EPA, 230 F.3d 

181 (6th Cir. 2000). 

As we explained as long ago as 1977, 

the appropriate approach in SIPs/FIPs is 

to require continuous compliance in 

order to create an incentive for sources 

to properly operate and maintain their 

facilities and to improve their operation 

and maintenance practices over time. 

See, e.g., 42 FR 21472, April 27, 1977 

(reference document VVVVV), and 42 

FR 58171, November 8, 1977 (reference 

document WWWWW). We explained 

that an automatic exemption would 

encourage the source to claim after 

every period of excess emissions that 

the exemption applied, and that instead 

the proper means to provide relief to 

sources was through the exercise of 

enforcement discretion in appropriate 

circumstances. Id. 

Later, in 1999, we indicated that 

states could include in their SIPs, as an 

alternative to the enforcement discretion 

approach, narrowly tailored affirmative 

defense provisions to address source 

difficulties meeting emission limits 

during malfunction, startup, and 

shutdown periods. See reference 

document RRR, our 1999 excess 

emissions memorandum. In this 1999 

memorandum we reiterated our longheld view that, ‘‘because excess 

emissions might aggravate air quality so 

as to prevent attainment or interfere 

with maintenance of the ambient air 

quality standards, EPA views all excess 

emissions as violations of applicable 

emission limitation[s].’’ We also 


jlentini on PROD1PC65 with RULES2
21432 Federal Register / Vol. 73, No. 77 / Monday, April 21, 2008 / Rules and Regulations 

9See reference document RRR, September 20, 

1999, memorandum entitled ‘‘State Implementation 

Plans: Policy Regarding Excess Emissions During 

Malfunctions, Startup, and Shutdown.’’

repeated our recognition that some 

malfunctions may be unavoidable. 

Thus, while flares may have unique 

characteristics, the underlying conflict 

between the ability to comply and need 

to meet the NAAQS is the same. We do 

not believe the nature of the emission 

point should dictate a different 

approach to protection of the NAAQS. 

Whether considering stack emissions at 

a power plant or other source, or flare 

emissions at a refinery, the SIP/FIP 

should be structured to provide the 

source with the incentive to properly 

design, operate, and maintain its 

facility. An outright exemption from the 

emission limits would not do this. 

To provide relief to the sources for 

truly unavoidable violations, while still 

maintaining appropriate incentives for 

compliance, we are providing an 

affirmative defense to penalties for 

violations of flare limits during 

malfunctions, startups, and shutdowns. 

The elements of the defense, which a 

source would have to prove in court or 

before an administrative judge, are 

enumerated in our final rule and are 

consistent with the elements described 

in our 1999 excess emissions 

memorandum. The gist of these 

elements is that a source must take all 

possible steps to prevent exceedances of 

the limits and to minimize the amount, 

duration, and impact of those 

exceedances. These same or similar 

criteria have been adopted by other 

regulatory agencies, including the State 

of Colorado and Maricopa County, 

Arizona, in excess emissions rules. See, 

e.g., Colorado Air Quality Control 

Commission Common Provisions 

Regulation, 5 CCR 1001–2, Sections II.E. 

and J. (reference document TTTTTT); 

Maricopa County Air Pollution Control 

Rules, Rule 140, ‘‘Excess Emissions’’, 

Section 400 (reference document 

ZZZZZ). 

Finally, we reject commenters’

assertion that citizens will necessarily 

pursue enforcement where the State and 

EPA do not, but in any event, this 

possibility is inherent in the structure of 

the CAA; Congress provided citizens 

with the ability to enforce SIPs and 

FIPs. This inherent structure is not a 

reason for us in this rulemaking action 

to change our longstanding 

interpretations regarding the proper 

treatment of excess emissions. 

(c) Comment (NEDA/CAP): Industry 

contends that it is virtually impossible 

to meet the proposed limits during 

flaring, since flares themselves are not 

process units when they are treating 

excess gases during malfunction events. 

EPA has presented no information in 

this notice or elsewhere to the contrary. 

On this basis alone, if the mass emission 

limits for flares are not made less 

stringent, the FIP must recognize in its 

final action that flares must be available 

for use during malfunctions and 

emergencies to protect the safety of 

employees and the public, as well as 

equipment integrity, regardless of the 

mass emission rate of the time. 

Response: The FIP is not intended to 

jeopardize the safety of refineries, their 

workers, or neighbors. Our SIP policy 9

has long recognized that imposing 

penalties for violations of emission 

limitations for sudden and unavoidable 

malfunctions caused by circumstances 

entirely beyond the control of the owner 

or operator may not be appropriate. 

States, EPA, and citizens have the 

ability to exercise enforcement 

discretion to refrain from taking 

enforcement action in these 

circumstances. In addition, EPA has 

revised the FIP to provide sources with 

the ability to assert an affirmative 

defense to penalties for violations of 

flare limits during malfunction, startup, 

and shutdown. However, while we 

recognize some violations may be 

unavoidable, we also believe that 

sources have a responsibility to do their 

best to achieve continuous compliance 

and to minimize the number, duration, 

and severity of malfunctions and other 

events leading to excess emissions. 

(d) Comment (MSCC): Various 

jurisdictions have attempted to address 

flare emissions. There is no uniform 

federal requirement or regulation 

requiring such limits or monitoring, 

particularly for short term limits, or for 

malfunction, startup, and shutdown 

controls. It is difficult to understand any 

reason that the Montana SIP for 

Billings/Laurel is ‘‘substantially 

inadequate’’ regarding flaring or for 

proposing restrictions going far beyond 

those in effect in any jurisdiction or 

federal rule. 

Response: Regardless of what other 

areas are doing with respect to flare 

emissions, we must fulfill our 

responsibility to fill the gaps of the 

provisions of the SIP that we 

disapproved. Each area must be 

addressed on a case-by-case basis. The 

response to comment II.D.1.(a) and our 

notice of proposed rulemaking express 

why we believe the FIP should contain 

emission limits for flares in the Billings/ 

Laurel area. Regarding the comment 

about substantial inadequacy, please see 

our response to comment II.B.2.(a), 

above. 

(e) Comment (MSCC): There is no 

reasonable basis to believe that flaring, 

as practiced in this air-shed, prevents 

attainment and maintenance of NAAQS, 

or that it is inadequately regulated, or 

that it has an impact on health, welfare, 

or commerce among states, as years of 

experience confirm. The State of 

Montana flare provisions are adequate. 

No federal action is needed. 

Response: This comment goes to the 

validity of our SIP action and is not 

relevant here. See our response to 

comment II.B.2.(a), above. 

(f) Comment (MDEQ): Imposing a 

mass-based emission limit (and the 

necessary and ancillary requirements for 

measuring flows and concentration) on 

a flare increases the regulatory workload 

while providing a marginal benefit. 

Currently, Montana’s Malfunction rule 

(ARM 17.8.110) provides Montana with 

enforcement discretion during 

malfunction events. 

Response: We note that the State has 

mass-based emission limits on the flares 

in the Billings/Laurel SO2 area. See CHS 

Inc.’s, ConocoPhillips’, ExxonMobil’s, 

and MSCC’s exhibit A–1, adopted by the 

Montana Board of Environmental 

Review on June 12, 1998 (reference 

documents QQQQQQ, PPPPPP, 

UUUUU, and OOOOOO). Exhibit A–1 

contains State requirements that were 

not submitted for inclusion in the SO2

SIP. The provisions of exhibit A–1 also 

appear in the sources’ Title V permits 

and are labeled as State-only provisions. 

See, for example, ConocoPhillips’ Title 

V permit (see reference document 

XXXXX). 

The exhibit A–1 requirements 

indicate that the facilities shall not 

allow SO2 emissions from any flare, 

unless the emissions are a minor flaring 

event (defined as less than or equal to 

150 pounds per 3-hour period), or the 

result of start-up, shutdown, or a 

malfunction. Exhibit A–1 does not 

indicate how compliance with the 

emission limit is determined and only 

requires reporting of flare emissions that 

are not minor flaring events. 

Presumably, the additional workload 

provided by the FIP, that the State is 

referring to, is in evaluating the 

continuous analyzers and receiving 

quarterly reports. We believe the 

additional workload is warranted and 

necessary to determine compliance with 

the flare emission limits and assure that 

the SO2 NAAQS will be attained and 

maintained. See, e.g., CAA sections 

110(a)(2)(A), (C), and (F), 42 U.S.C. 

7410(a)(2)(A), (C), and (F). 

We do not understand the intent of 

the comment that indicates MDEQ has 

enforcement discretion under its 

malfunction rule in ARM 17.8.110 


jlentini on PROD1PC65 with RULES2
Federal Register / Vol. 73, No. 77 / Monday, April 21, 2008 / Rules and Regulations 21433 

(reference document YYYYY). Before 

MDEQ could decide whether or not to 

pursue an enforcement action for 

violations of the State-only flare limit, 

MDEQ would need to evaluate 

information submitted by sources. 

Additionally, we note that in response 

to our proposed action on the Billings/ 

Laurel SIP, the State said the following: 

‘‘The State agrees with EPA that the SIP 

is incomplete without enforceable 

emission limitations applicable to flares, 

and that such limitations should 

correspond to the emission rates used in 

the attainment demonstrations. 

However, after significant effort to 

address the issue, the State was unable 

to find a workable solution that would 

meet EPA’s concerns.’’ See document 

#IV.A–23, comment #3, from docket 

#R8–99–01; 67 FR 22183, col. 1, May 2, 

2002; and reference document ZZZZZZ. 

(g) Comment (YVAS): YVAS concurs 

with EPA’s further assumption (page 

39264), that ‘‘the 3-hour SO2 NAAQS 

would be attained’’ if ‘‘the limit for the 

main flares was established at 500 

pounds of SO2 per calendar day.’’ Since 

there is apparently precedent (as noted 

on page 39263 FR) ‘‘contained in 

settlements between the United States 

and CHS Inc, ConocoPhillips and 

ExxonMobil,’’ YVAS further agrees to 

and accepts EPA’s reasoning that ‘‘the 

500 pound value for this FIP (should) be 

imposed as an enforceable limit and not 

just a trigger point for further analysis’’

as a starting point. However, the ‘‘500 

lbs per day limit,’’ if extended for any 

length of time, is not acceptable. Based 

on acquired information, YVAS does 

not think this limit would be punitive, 

nor would it be impossible for industry 

sources to attain. It is accepted that zero 

emissions may not be possible or 

attainable, but any lower emissions rate 

would be a public benefit. And, 

although a compliance drop could 

create greater industry noncompliance 

and require more enforcement action, 

YVAS does not believe the more 

stringent standards would create more 

noncompliance problems for the 

sources. 

Response: We have decided to retain 

the proposed limit of 150 lbs of SO2/3- 

hour period. A more stringent limit than 

either proposed is unnecessary to 

ensure attainment of the NAAQS. Thus, 

we believe it is reasonable not to impose 

a more stringent limit as the commenter 

suggests. 

(h) Comment (Citizen): The proposed 

rule should not be adopted unless 

recognized medical opinion concerning 

the cumulative health risks of the 

release of 500 lbs per day of sulphur 

dioxide into the area’s airshed is 

analyzed. Specifically, what 

justification criteria are being used to 

establish the 500 lb. minimum per day 

base in the Proposed Rule. And, as 

noted on page 39264 of the Federal 

Register dated July 12 announcing the 

FIP, EPA says ‘‘if we adopted the 500 

pound value in this FIP, we would 

impose it as an enforceable emission 

limit.’’ If there are still questions 

concerning the 500 lb per day emission 

limit, why is it being proposed? Is there 

a lower and perhaps ‘‘better’’ emission 

limit per day that should be considered? 

Response: The current SO2 NAAQS 

were set to protect public health and 

welfare after consideration of various 

scientific data. It is not our role here to 

re-evaluate the NAAQS, but to ensure 

they are met. Through modeling we 

determined that both limits would 

protect the SO2 NAAQS. While a lower 

limit might be attractive, we are setting 

the limits at 150 lbs of SO2/3-hour 

period, a level sufficient to meet the SO2

NAAQS; we think this is reasonable. 

See response to comment II.A.2.(b). See 

also our response to comments 

pertaining to SO2 NAAQS and SO2

Health Effects (II.F.9. and 10., 

respectively) below. 

(i) Comment (MDEQ): MDEQ believes 

that hard cap emission limits on flares 

are good but believes that the flare 

emission limits will be more accepted if 

malfunction, startup, and shutdown 

exemptions are introduced. 

Response: We acknowledge MDEQ’s 

support for hard cap emission limits on 

flares. Regarding exemptions for 

malfunction, startup, and shutdown, see 

our responses to comments II.D.1.(b) 

and (c), above. 

As indicated above, to address 

industry concerns regarding 

malfunctions, startup, and shutdown, 

we are revising the FIP to provide 

sources the ability to assert an 

affirmative defense to penalties for 

violations of flare limits during 

malfunction, startup, and shutdown. 

2. Safety Device 

(a) Comment (CHS Inc., WETA, MPA, 

NPRA): From a safety standpoint, there 

are concerns with flare limits applying 

at all times, including malfunction, 

startup, and shutdown. Flares are 

primarily safety devices, designed as a 

means to ensure the safety of employees 

and the community and to maintain the 

integrity of refinery equipment during 

situations that are not representative of 

normal operations. It will be precedent 

setting if the EPA views these infrequent 

events as enforcement situations. It 

would, in essence, require facilities to 

choose between maintaining a safe, 

controlled refinery and violating the 

FIP. 

Response: See responses to comments 

II.D.1.(b) and (c), above. As we indicate 

in our response to comment II.D.1.(c), 

the FIP is not intended to jeopardize the 

safety of refineries, their workers, or the 

community. However, we believe it 

would be inconsistent with CAA 

sections 110(a) and (l) to provide an 

outright exemption from the flare limits 

during malfunction, startup, and 

shutdown periods. Instead, to provide 

some measure of relief to the sources, 

we have included an affirmative defense 

to penalties in our final FIP rule. If a 

source takes steps consistent with the 

elements of the affirmative defense, 

excess flaring emissions during 

malfunction, startup, and shutdown 

periods would not be penalized. We 

have considered several additional 

factors: First, historically, the sources 

have used the flares as part of their 

routine operations, i.e., in nonemergency conditions. See September 

28, 1995, letter from Bob Raisch to 

Douglas Skie (reference document 

SSSSSS); 67 FR 22180, col. 2, May 2, 

2002. Also, in its comments on the FIP 

(reference document QQQQ), CHS Inc. 

indicated that the 150 lbs/3-hour value 

was used in the original model to 

represent routine flaring and 

background SO2 concentrations. MSCC 

indicated in its comments on the FIP 

(reference document WWWW) that 

flares can be used for handling streams 

other than those arising from 

malfunction, startup, and shutdown. 

Second, flaring events have not 

necessarily been as infrequent as the 

commenter implies. From the first 

quarter of 2005 through the second 

quarter of 2007, source reports indicate 

that MSCC and the 3 refineries 

experienced over 150 flaring events 

with SO2 emissions greater than 150 

pounds over 3 hours. See reference 

document HHHHHH. Third, the 

emissions during these events can be 

very high—the State estimated that 

emissions during malfunctions could be 

as high as 6,000 pounds/3-hour period, 

and the sources’ own reports for first 

quarter 2005 through second quarter 

2007 reflect emissions as high as 12,400 

pounds over a 2-hour period. See 

reference documents SSSSSS and 

HHHHHH. The maximum value 

reported for a flaring event during the 

period was 40,800 pounds of SO2 over 

an unknown duration, and there were 

numerous events in the thousands of 

pounds. See reference document 

HHHHHH. Fourth, we want to ensure 

that the owners/operators design, 

operate, and maintain their facilities to 

minimize flare emissions by minimizing 

the conditions that lead to malfunctions, 


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10 In theory, a smokestack could also be 

characterized as a safety device; among other 

things, a stack is used to prevent harmful ground 

level concentrations of pollutants. In addition, gases 

are sometimes bypassed around control devices 

directly to the stack to avoid damage to control 

devices and/or other dangerous conditions. In the 

SIP/FIP context, we do not believe it is appropriate 

to automatically exempt these stack emissions, even 

though the stack may serve a safety purpose. See 

our 1999 excess emissions memorandum, reference 

document RRR. 

11The Bay Area prohibits all refinery flaring 

unless the flaring is consistent with a flare 

minimization plan or is caused by an emergency. 

See BAAQMD rule 12–12–301 (reference document 

AAAAAAA). The South Coast rule requires 

minimization of flaring and prohibits combustion of 

vent gas in the flare except during emergencies, 

shutdowns, startups, turnarounds or essential 

operational needs. See SCAQMD rule 1118(c)(4) 

(reference document CCC). 

startups, and shutdowns. In the FIP 

context, the appropriate way to do this 

is by establishing a flare emission limit 

that is not subject to outright 

exemptions. Fifth, the State and EPA 

have already viewed these events as 

enforcement situations in the context of 

the refinery initiative and, through the 

consent decrees, have created the 

expectation that the refineries will 

minimize flare emissions. We explain in 

this preamble why the conditions of the 

consent decrees, while beneficial, are 

not sufficient for purposes of the FIP. 

See, e.g., responses to comments 

II.A.2.(b), II.D.4., and II.E.1.(e). We also 

note that MSCC is not subject to a 

consent decree. Finally, the air does not 

care whether emissions come out of a 

flare that is used as a safety device at a 

refinery or a stack at a power plant or 

other facility.10 In both cases, the 

emissions of SO2 impact air quality, and 

EPA’s charge is to address those impacts 

so as to protect the NAAQS. 

(b) Comment (WSPA, MSCC, 

ExxonMobil): EPA proposes that flare 

limits apply at all times without 

exception. It would be virtually 

impossible to comply with SOx mass 

emission limits at all times and for all 

malfunctions for the simple reason that 

the primary function of a refinery flare 

is to serve as a safety device. Flares 

must be available for use during 

malfunctions and emergencies to protect 

equipment and the safety of employees 

and the public. 

Response: See responses to comments 

II.D.1.(b) and (c), and II.D.2.(a), above. 

(c) Comment (NPRA): The U.S. 

Chemical Safety Board (CSB) urges the 

installation of flares. The CSB sites 

flares as a ‘‘safer alternative’’ when 

compared to other techniques. Clearly 

the CSB recommendation is at odds 

with Agency’s proposal. 

Response: See responses to comments 

II.D.1.(b) and (c), and II.D.2.(a), above. 

Also, we do not believe our action is at 

odds with the CSB’s recommendations. 

In this action, we are not opining on the 

use of flares versus other techniques. 

We are not telling the refineries or 

MSCC to stop using their flares. 

However, flares are an emission point at 

the refineries and MSCC, they have been 

the source of routine emissions 

historically, and they can be the source 

of very large quantities of emissions in 

a short period of time. We believe it is 

necessary and appropriate to impose 

limits on the flare emissions to fill one 

of the gaps in the SIP, to support our 

attainment demonstration, and to create 

appropriate incentives for the sources in 

the design, operation, and maintenance 

of their facilities. 

3. Malfunction, Startup, and Shutdown 

(a) Comment (WSPA, MSCC, 

ExxonMobil): In working with the South 

Coast Air Quality Management District, 

they were careful not to compromise 

safety by restricting, either explicitly or 

implicitly, the use of flares during 

emergencies through the imposition of 

mass emission limits or otherwise. 

Response: See responses to comments 

II.D.1.(b) and (c), and II.D.2.(a), above. 

Our FIP does not require or direct the 

sources to not use their flares during 

emergencies. Unlike the South Coast or 

Bay Area,11 however, we are required to 

promulgate a FIP that demonstrates 

attainment of the SO2 NAAQS. 

Consequently, it is necessary and 

appropriate that we impose emission 

limits on the flares that are consistent 

with our modeled attainment 

demonstration. To address industry 

concerns, we are providing an 

affirmative defense to penalties for 

excess flare emissions during 

malfunction, startup, and shutdown 

periods. 

We note that SCAQMD’s rule 1118(d) 

imposes annual SO2 performance targets 

for flare emissions (caps on the amount 

of SO2 emitted from flares in one year). 

The performance targets are based on 

the crude processing capacity and 

become more stringent over time. 

Malfunction, startup, and shutdown 

emissions count towards the annual 

performance targets unless they meet 

certain narrowly defined exemptions in 

rule 1118(k). Sources that exceed their 

annual performance targets must submit 

a flare minimization plan and are 

subject to mitigation fees of up to four 

million dollars a year (see reference 

document CCC). 

(b) Comment (WSPA, MSCC, 

ExxonMobil): It is essential for EPA to 

recognize the true nature of 

malfunctions at refineries, and the fact 

that there is no practical way to regulate 

the release of vent gases during 

malfunctions, or, to treat the emergency 

vent gases to remove sulfur compounds 

prior to combustion in the flare. 

Response: See responses to comments 

II.D.1.(b) and (c), II.D.2.(a), and 

II.D.3.(a), above. Also, we understand 

that while a malfunction is underway, it 

may be impossible to treat the gases 

prior to combustion in the flare. 

However, we do not agree that all 

malfunctions are categorically 

unavoidable. We are concerned with the 

causes leading to the malfunctions and 

the steps taken after the malfunction 

begins to mitigate its effects. We are 

promulgating an affirmative defense 

provision along with the flare emission 

limits that should ensure sources take 

all steps within their control to avoid 

malfunctions and minimize their 

impacts on air quality once they occur. 

We believe this is reasonable and 

appropriate to ensure protection of the 

NAAQS. 

(c) Comment (WETA): Pursuing the 

adoption of this FIP could potentially 

result in the setting of an inconsistent 

national policy for malfunction, startup, 

and shutdown. 

Response: We do not agree with the 

comment. The FIP would not be setting 

inconsistent national policy for 

malfunction, startup, and shutdown 

occurrences. To the contrary, we are 

following our national policy with 

respect to malfunctions, startup, and 

shutdown as expressed in the 1999 

excess emissions memorandum (see 

reference document RRR). 

(d) Comment (MSCC): MSCC believes 

that the approach taken by the State of 

Montana in providing for minimization 

of flaring, above a reasonably 

determined de minimis threshold, and 

clear exceptions for malfunctions, 

startup, shutdowns and other 

operational needs is the sound 

approach, to address the reality that 

there are, and will be situations such as 

malfunctions, startups, and shutdowns 

and emergencies that are beyond the 

reasonable control of a source, in the 

operation of flares. 

Response: We recognize there may be 

violations of flare emission limits 

during malfunctions, startups, 

shutdowns, and emergencies that are 

beyond the control of a source; 

accordingly, we are providing sources 

with the ability to assert an affirmative 

defense to penalties for violations of 

flare limits that occur during 

malfunction, startup, and shutdown 

periods. We believe this is a reasonable 

approach, consistent with our views 

that automatic exemptions are not 

appropriate for emission limits relied on 


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to demonstrate attainment of the 

NAAQS. 

(e) Comment (COPC): The rule as 

written will ultimately put 

ConocoPhillips in the position of having 

to choose between compliance with an 

environmental regulation and 

maintaining safe operating conditions. 

This is an untenable position which can 

be avoided by acknowledging in rule 

language that flare SO2 emissions can 

occur during periods of malfunction, 

startup, and shutdown, provided that 

accepted management systems are 

followed. 

Response: See responses to comments 

II.D.1.(b) and (c), and II.D.2.(a), above. 

We believe the provision of the 

affirmative defense to penalties for 

excess emissions during malfunction, 

startup, and shutdown periods 

appropriately and reasonably addresses 

the commenter’s concerns. 

(f) Comment (COPC): A FIP program 

that adopts the same evaluation 

procedures for malfunctions, startups, 

and shutdowns for flares is preferred to 

a fiction that a facility can maintain a 

flare emission limit in all malfunction, 

startup, or shutdown events regardless 

of size or magnitude. 

Response: See response to comments 

II.D.3.(a), (b), (c), (d), and (e), above. 

(g) Comment (YVAS): Specific to 

flaring emergencies by the sources, any 

added controls on flaring to protect the 

public (from SO2 exceedences) is 

essential and is common sense. 

Response: We acknowledge the 

comment and support for our proposal. 

4. Subject to NSPS 

Comment (CHS Inc.) It should be 

noted that the CHS refinery flare is 

subject to NSPS Subpart J as a result of 

the consent decree. This limits the H2S 

content of the routine refinery fuel gas 

streams routed to the flare and requires 

monitoring to demonstrate compliance 

with the limit. 

Response: As indicated by the 

commenter, the consent decree limits 

the H2S content of the routine refinery 

fuel gas streams routed to the flare. 

However, there are several reasons why 

the H2S ppm limit alone is not sufficient 

to support the FIP’s attainment 

demonstration. 

First, flow information is needed to 

translate H2S ppm values into pounds of 

SO2 for a given period of time. Flow 

rates to the flares can vary widely. 

Without knowing potential worst-case 

flows to the flare, we cannot determine 

whether the consent decree H2S ppm 

limit would assure compliance with the 

FIP 150 pounds of SO2/3-hour limit at 

the 3 refineries. Therefore, we cannot 

conclude that the consent decree H2S 

limit, even absent the additional 

concerns we discuss below, would 

assure attainment of the SO2 NAAQS. 

Second, during certain situations, as 

indicated in 40 CFR 60.8(c) and 

60.104(a)(1), the H2S limit does not 

apply. Specifically, the consent decree 

indicates that the CHS Inc. refinery flare 

is an affected facility under 40 CFR part 

60, subparts A and J for fuel gas 

combustion devices and that fuel gases 

combusted in the refinery flare shall 

comply with the emission limit of 40 

CFR 60.104(a)(1). However, 40 CFR 

60.104(a)(1) exempts process upset 

gases and certain types of fuel gas from 

the emission limit. Additionally, the 

provisions in 40 CFR 60.8(c) indicate 

that emissions in excess of the level of 

the applicable emission limit during 

periods of malfunction, startup, and 

shutdown shall not be considered a 

violation of the applicable emission 

limit unless otherwise specified in the 

applicable standard. Emission limits for 

demonstrating attainment and 

maintenance of the NAAQS must apply 

at all times. (See responses to comments 

II.D.1.(b) and II.D.2.(a), above, and 

reference document RRR.) 

Third, the alternative monitoring plan 

(AMP), that was approved pursuant to 

the consent decree and NSPS 

requirements (see reference document 

LLLLLL) for the refinery flare fuel gas 

combustion device, primarily relies on 

quarterly measurement of the H2S 

content of some of the refinery fuel gas 

streams that go to the flare using stain 

tubes; more frequent measurement may 

be required for a limited time depending 

on the concentration measured. 

Although this may be acceptable under 

the terms of the consent decree and the 

NSPS, we believe more frequent testing 

is necessary for determining compliance 

with an emission limit set to assure 

attainment and maintenance of the 

NAAQS. 

5. Affirmative Defense/1999 Excess 

Emissions Memorandum 

(a) Comment (WSPA): The availability 

of an affirmative defense is desirable. 

Even though EPA may allow for the 

assertion of affirmative defenses, the 

affirmative defense would only be 

allowed for the mitigation of penalties. 

This is an unreasonable position in 

which to place refiners subject to the 

proposed requirements. 

Response: We are providing an 

affirmative defense to penalties in the 

final rule, but not to injunctive relief. 

This is consistent with the Clean Air 

Act interpretations expressed in our 

1999 excess emissions memorandum. 

See reference document RRR. We 

believe it is reasonable to retain the 

authority to seek injunctive relief for all 

exceedances of emission limits so that 

we remain able to protect the NAAQS, 

regardless of source ‘‘culpability’’ for 

any specific exceedance. 

We note that in our proposed FIP 

preamble, we invited comment 

regarding whether it would be 

appropriate to extend an affirmative 

defense to the FIP sources for 

exceedances of their flare limits during 

malfunctions, startup, and shutdown. 

See 71 FR 39264, July 12, 2006. There 

we said the following: 

‘‘We do interpret the CAA to allow owners 

and operators of sources to assert an 

affirmative defense to penalties in 

appropriate circumstances, but normally we 

would not view such an affirmative defense 

as appropriate in areas where a single source 

or small group of sources has the potential 

to cause an exceedance of the NAAQS. See 

1999 policy statement. We solicit comment 

on whether it would be appropriate to 

include in our final FIP the ability to assert 

an affirmative defense to penalties only (not 

injunctive relief) for violations of the flare 

limits.’’

We have decided to provide an 

affirmative defense for violations of the 

flare limits during malfunction, startup, 

and shutdown. We believe this 

represents a deviation from our 1999 

excess emissions memorandum because 

in the Billings/Laurel area, one or more 

of the FIP sources may have the 

potential to cause an exceedance of the 

SO2 NAAQS. In the unique 

circumstances of this FIP, with the rule 

language we are adopting, we believe a 

deviation from the 1999 excess 

emissions memorandum is warranted. 

For example, we have included rule 

language that indicates the affirmative 

defense is not available if, during the 

period of the excess emissions, there 

was an exceedance of the SO2 NAAQS 

that could be attributed to the emitting 

source. At least one other EPA Region 

has approved an affirmative defense 

provision with this language. See 

Maricopa County Rule 140 (reference 

document ZZZZZ), which Region 9 

approved on August 27, 2002 (67 FR 

54957) (reference document AAAAAA). 

Although not identical to the 1999 

excess emissions memorandum, this 

rule language should provide a 

significant incentive to the facilities to 

take steps to avoid and reduce flaring 

whenever possible. 

Also, based on our experience since 

the 1999 excess emissions 

memorandum was issued, we believe 

that the elements of the affirmative 

defense delineated in the 1999 excess 

emissions memorandum, which 

elements we have adopted in this FIP, 

provide a very significant incentive for 


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facilities to do all they can to comply 

with their emission limits. It is not clear 

that the incentive is significantly 

different than would be present under a 

traditional enforcement discretion 

approach, particularly when sources 

assume that enforcement action will 

rarely be taken for infrequent or small 

violations. Finally, we have considered 

industry comments regarding safety 

concerns, and while we do not agree 

that emissions from flares should be 

treated entirely differently from 

emissions from stacks and other points, 

we think our resolution of this issue 

appropriately and reasonably addresses 

industry concerns. 

(b) Comment (WETA): Any flare 

emission limitations should include, at 

the least, an allowance for an affirmative 

defense for malfunction, startup, and 

shutdown circumstances. 

Response: See response to comment 

II.D.5.(a), above. 

(c) Comment (NEDA/CAP): EPA 

should adopt a broad affirmative 

defense for penalties and injunctive 

relief for malfunctions as part of the 

mass emission limit for flares. MPA 

indicated that the FIP should not be 

adopted in the proposed form because 

the failure to include an affirmative 

defense for flaring resulting from 

malfunctions poses a significant safety 

risk to employees and the public with 

no corresponding benefit. 

Response: See response to comment 

II.D.5.(a), above. 

(d) Comment (NEDA/CAP): NEDA/ 

CAP is concerned about the potential for 

EPA’s establishment of any precedent 

with regard to limiting the availability 

of affirmative malfunction defenses in 

nonattainment areas generally. NEDA/ 

CAP is also concerned with the 

application of the 1999 Malfunction 

Policy in the Billings/Laurel proposed 

FIP because the Policy has never been 

subject to notice and comment 

rulemaking, but the application of the 

policy results in clear legal 

consequences for regulated entities in 

contravention of Appalachian Power v. 

EPA, 208 F.3d 1015 (D.C. Cir. 2000). 

Response: See response to comment 

II.D.5.(a), above. Also, we respectfully 

disagree with the commenter that we are 

contravening the Appalachian Power 

case holding. In our proposal, we 

proposed that the flare limits would 

apply at all times but took comment on 

the application of an affirmative defense 

to penalties for those limits. In this final 

rulemaking, we have decided to provide 

the affirmative defense to penalties. The 

commenter had a full opportunity to 

comment on our proposal, which 

included a discussion of our 

interpretations of the CAA with respect 

to the treatment of excess emissions 

during malfunction, startup, and 

shutdown. See 71 FR 39264, col. 1, July 

12, 2006. We have considered the 

commenter’s comments along with all 

other comments. 

(e) Comment (NEDA/CAP): NEDA/ 

CAP is also concerned that EPA has 

made no demonstration that ‘‘a single 

source or small group of sources has the 

potential to cause an exceedence of the 

NAAQS,’’ or that the NAAQS in this air 

basin is in fact, any more vulnerable to 

a NAAQS exceedence from these 

sources than any other nonattainment 

areas is from a small group of sources. 

If finalized, the failure to provide an 

affirmative defense for malfunctions 

would be entirely arbitrary and 

unreasonable. Moreover, as a national 

precedent with severe legal 

consequences for sources in other 

nonattainment areas, adoption of this 

proposed FIP provision would be highly 

vulnerable to legal challenge for failure 

to meet the Clean Air Act’s notice and 

comment procedures under a federal 

court’s recent decision in 

Environmental Integrity Project v. EPA, 

425 F.3d 992 (D.C. Cir. 2005). 

Response: In our final action, we are 

providing an affirmative defense to 

penalties for the flare limits. We 

disagree with the commenter’s assertion 

regarding notice and comment 

procedures; we believe we have met all 

applicable requirements and provided 

fair notice regarding our intentions in 

our notice of proposed rulemaking. We 

proposed that the flare limits would 

apply at all times and also invited 

comment on whether it would be 

appropriate to extend an affirmative 

defense for the flare limits to the four 

sources subject to the FIP. Our final 

action is a logical outgrowth of our 

proposal; we have decided to provide an 

affirmative defense to penalties for 

violations of the flare limits during 

malfunction, startup, and shutdown. 

While our action on this FIP may have 

some impact on other SIPs and FIPs 

based on the logic we have applied, our 

rule is only directly applicable to the 

four sources subject to the FIP. It is 

possible EPA may reach a different 

decision in future rulemaking. 

(f) Comment (API, COPC, MSCC, 

ExxonMobil): While EPA’s 1999 

Malfunction policy does state EPA’s 

position that affirmative defenses are 

not appropriate ‘‘where a single source 

or small group of sources has the 

potential to cause an exceedence of the 

NAAQS,’’ API and others are unaware 

of any instance where EPA has utilized 

this exception from its general policy 

allowing for the assertion of affirmative 

defenses during malfunctions. In this 

case, EPA has made no demonstration to 

justify an exception to the general 

allowance for affirmative defenses for 

malfunction events. Consequently, API 

urges EPA to allow the assertion of 

affirmative defenses in the final FIP. 

Additionally, ConocoPhillips indicated 

that because of the harsh consequences, 

EPA should only apply this exception to 

its policy where it is clearly 

demonstrated that there is very real, 

extended potential for a single or small 

group of sources to cause an exceedence 

of the NAAQS. This is not present in 

this case. In fact, actual monitoring has 

shown that even during malfunction, 

ambient NAAQS violations do not 

occur. ConocoPhillips urges EPA to 

allow the assertion of affirmative 

defenses for both penalties and 

injunctive relief in the final FIP. 

Response: See our prior responses to 

comments II.D.5.(a), (d), and (e). Also, 

we note that on two occasions, one in 

1985 and one in 1995, flaring resulting 

from malfunctions at ConocoPhillips 

caused ambient exceedances of the SO2

NAAQS (see reference documents 

DDDDDDD and EEEEEEE). 

(g) Comment (NEDA/CAP, MSCC): 

The proposed FIP appears to 

misinterpret the 1999 Malfunction 

Policy. The July 12 preamble for 

adoption of the FIP appears to suggest 

that prosecutorial discretion would 

never be allowed in a nonattainment 

area where the agency decides that ‘‘one 

or a group of sources are directly 

implicated in nonattainment of a 

NAAQS.’’ In fact, the 1999 Policy 

recommends that such situations have 

to be addressed in the underlying 

standards themselves through narrowlytailored SIP revisions. Moreover, in no 

event does the 1999 Malfunction Policy 

ever prohibit the use of prosecutorial 

discretion. 

Response: Enforcement discretion or 

prosecutorial discretion is always 

available. The question in this case was 

whether it was appropriate to codify an 

affirmative defense, which we have 

done in our final rule. We have not 

misinterpreted our 1999 policy. 

(h) Comment (NEDA/CAP, API): 

There is no rational basis in the 

proposed FIP or the 1999 Malfunction 

Policy to limit the affirmative defense to 

penalties. NEDA/CAP asserts that such 

a limitation is not reasonable since the 

malfunction condition during which the 

exceedence of the applicable limitation 

occurs would be unavoidable. 

Response: We respectfully disagree. 

There could be instances in which 

malfunctions are unavoidable based on 

current plant layout and operating 

parameters but in which some form of 

corrective action would still be 


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appropriate. We cannot predict the 

exact nature of those circumstances, but 

protection of the NAAQS and public 

health is not an intermittent obligation; 

we are required to assure attainment 

and maintenance of the NAAQS at all 

times, not just when sources are in 

normal operation mode or when 

attainment is convenient. See, e.g., City 

of Santa Rosa v. EPA, 534 F.2d 150 (9th 

Cir. 1976), vacated and remanded on 

other grounds sub nom. Pacific Legal 

Foundation v. EPA, 429 U.S. 990 (1976) 

(‘‘ ‘Neither EPA nor this court has any 

right to decide that it is better to 

maintain pollutants at a level hazardous 

to health than to require the degree of 

public sacrifice needed to reduce them 

to tolerable limits’ ’’, citing South 

Terminal Corp. v. EPA, 504 F.2d 646, at 

656 (1st Cir. 1974); South Terminal 

Corp. v. EPA, 504 F.2d 646, 675 (1st Cir. 

1974) (‘‘[I]t seems plain that Congress 

intended the Administrator to enforce 

compliance with air quality standards 

even if the costs were great.’’) Preserving 

injunctive remedies ensures that we 

remain able to protect air quality 

standards and PSD increments in 

accordance with our fundamental 

responsibilities under the CAA. See 

CAA sections 110(a) and (l), 42 U.S.C. 

7410(a) and (l). See, also, the discussion 

of this issue in our 1999 excess 

emissions memorandum, reference 

document RRR. 

(i) Comment (MSCC, ExxonMobil): An 

exception and affirmative defense 

should be available under the FIP that 

is at least consistent with the consent 

decrees executed by EPA and the State 

of Montana with most of the affected 

sources. 

Response: As we have noted 

previously, the consent decrees and the 

FIP serve different purposes. We have 

adopted an affirmative defense 

provision that is consistent with the 

protection of the NAAQS. 

(j) Comment (Citizen): On page 39264 

is the statement ‘‘We are proposing that 

the flare limits will apply at all times 

without exception.’’ Laudable as that 

seems, EPA then subsequently states, 

‘‘We solicit comment on whether it 

would be appropriate to include in our 

final FIP the ability to assert an 

affirmative defense to penalties only 

(not injunctive relief) for violations of 

flare limits.’’ If the former statement is 

accepted, what are the penalties for 

exceeding flare limits and how will they 

be imposed and will the public be 

advised which refinery exceeds a flare 

limit and how often could that happen 

to the detriment of air quality in this 

area? 

Response: In this final rulemaking 

action, we have promulgated an 

affirmative defense to penalties for 

exceedances of the flare limits during 

malfunction, startup, and shutdown. 

Under this approach all excess 

emissions are considered violations. 

However, if we or anyone else brings an 

enforcement action, the facility may 

then assert the defense to penalties. To 

establish the defense, the facility must 

demonstrate to the judge that it took 

appropriate steps to avoid the excess 

emissions and met other requirements, 

the details of which are contained in our 

final rule. If the facility cannot establish 

the defense, it may be subject to CAA 

penalties up to $32,500 per day. We do 

not typically advise the public when a 

limit is exceeded or which facility has 

exceeded a limit, although we often 

alert the public through the press when 

we bring an enforcement action. Under 

the FIP, the subject sources must submit 

reports to EPA identifying their 

emissions. Those reports are available to 

the public through the Freedom of 

Information Act (FOIA). The 

establishment of flare requirements 

should help reduce flaring incidents. 

6. Installation of Additional SO2

Reduction Equipment 

Comment (ExxonMobil): EPA’s 

proposed FIP does not allow for time for 

the design and installation of facilities 

necessary to comply with the proposed 

flare emissions limitations. The 

facilities required for compliance with 

the proposed FIP go above and beyond 

what was built for the SIP or what will 

be built for the Consent Decree. For 

EPA’s proposed FIP, the required 

controls have not yet been identified. 

Response: It is not clear what facilities 

the commenter is envisioning. Without 

greater detail, it is difficult to respond 

to the comment. However, the FIP 

imposes no specific requirement for the 

sources to install control equipment to 

limit flare emissions, and the limit we 

are imposing is the same one the State 

imposed on the sources, and which 

continues to be included in their 

permits. Our expectation is that sources 

will take all steps within their control 

to avoid flaring events and minimize 

their impacts on air quality if they do 

occur. 

To the extent that the commenter is 

referring to the time needed to design 

and install flare monitoring systems 

required by the FIP, we have extended 

the deadline for installation from 180 

days to 365 days after EPA approval of 

the flare monitoring plan. 

E. Concerns With Dispersion Modeling 

1. Policy Issues 

(a) Comment (MSCC, ExxonMobil): 

Out-of-Date and Invalid Model Choice. 

(i) The proposed FIP uses the same 

model as that used in the SIP. EPA’s 

models have changed since the time the 

SIP was developed. It is inappropriate to 

propose and justify more restrictive 

requirements on sources without 

considering more current modeling 

techniques and requirements. The older 

model may be more appropriate to 

confirm an existing situation or permit 

minor changes. However, the FIP goes 

beyond minor changes. 

Response: The commenter is correct 

that a newer model is now available. For 

new SIPs, we would require states to 

use EPA’s most recent model. However, 

this is a unique situation. The State 

developed the Billings/Laurel SO2 SIP 

using the ISC model, which was current 

at that time, and we approved various 

source-specific emission limits in the 

SIP based on the State’s modeling effort. 

The purpose of this FIP is to fill gaps in 

the approved SIP. We are not intending 

or required to re-do the entire SIP. See, 

e.g., section 302(y) of the CAA, 42 

U.S.C. 7602(y) (‘‘Federal 

implementation plan’’ means a plan (or 

portion thereof) promulgated by the 

Administrator to fill all or a portion of 

a gap or otherwise correct all or a 

portion of an inadequacy in a State 

implementation plan * * *’’); McCarthy 

v. Thomas, 27 F.3d 1363, 1365 (9th Cir. 

1994) (A FIP is ‘‘a set of enforceable 

federal regulations that stand in the 

place of deficient portions of a SIP.’’) 

Accordingly, we think it is reasonable to 

rely on the same model the State used 

to develop the SIP. That way, all 

emission limits in the SIP and FIP will 

have been established on the same basis. 

We note that MDEQ tested the 

performance of the ISC model when the 

Billings/Laurel SO2 SIP was being 

developed, and the results showed that 

the model performance exceeded the 

performance criteria for models of this 

type. The FIP modeling represents a 

minor change to MDEQ’s basic 

approach. The sources in the SIP 

modeling are characterized in the 

modeling inputs as 25 point and volume 

sources and, except for minor 

corrections provided by the sources, the 

major FIP-related change in modeling 

involves only one source: The MSCC 

100-meter stack. We had to change the 

inputs for MSCC’s 100-meter stack 

because the State gave too much stack 

height credit to MSCC’s stack in the SIP 

modeling, and we, consequently, 

disapproved MSCC’s SIP emission 

limits and the SIP attainment 


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12 In reference document WW, Technical Support 

Document, Dispersion Modeling to Support Sulfur 

Dioxide (SO2) Emission Limits in Federal 

demonstration. Otherwise, the FIP 

modeling uses meteorology data, 

receptors, and stack parameters for 

sources other than MSCC that are nearly 

identical to those used in the SIP 

modeling. 

We also note that ISC remained an 

accepted EPA model at the time we 

proposed our FIP, and it is reasonable 

to finalize the FIP based on the same 

model. Switching models after our 

proposal would have required us to repropose the FIP and would have 

delayed the FIP further. 

(ii) A newer model, ‘‘AERMOD,’’ has 

been adopted as the EPA regulatory 

default model. It is clear that AERMOD 

is now preferred for regulatory use over 

the model used in the SIP development. 

Consideration needs to be afforded to 

models available today, and particularly 

to the model reasonably believed to give 

the most accurate results. The 

stakeholder process should be used to 

determine which dispersion model 

should be used for the FIP 

(ExxonMobil). 

Response: See our response to 

comment II.E.1.(a)(i), above. We also 

note that AERMOD has more complex 

software than ISC and, as a result, it 

would be extremely difficult to perform 

the 1320 model simulations necessary to 

establish emission limitations that 

would address buoyancy flux variations 

that were included in the State’s SIP. A 

stakeholder process is not required by 

the CAA and would merely serve to 

delay issuance of the FIP. 

(b) Comment (MSCC): Out-of-Date 

Model Input. Any dispersion modeling 

used for the proposed FIP must include 

improved techniques regarding building 

downwash. A new method for 

calculating the downwash effects 

buildings have on predicted ambient 

concentrations has been developed. The 

new technique is known as ‘‘Plume Rise 

Model Enhancement’’ (PRIME) 

algorithm. This technique is now 

commonly in practice in both ISC–

PRIME and AERMOD. EPA’s FIP 

modeling does not use this technique. 

Response: The PRIME downwash 

technique was never formally adopted 

by EPA for use in ISC. In order for states 

to employ this technique, EPA regional 

offices needed to authorize its use on a 

case-by-case basis until ISC was 

replaced as the reference model on 

December 9, 2006. The plume rise 

technique used in ISC was the 

recommended approach at the time the 

State developed the SIP, and the 

technique served the modeling 

community well for many years. 

(c) Comment (MSCC, ExxonMobil): 

Modeling Violates EPA’s Own 

Requirements. The modeling used for 

the proposed FIP does not meet EPA’s 

own guidelines and requirements 

because of the model used, lack of 

current building profile, and numerous 

other problems found elsewhere. 

Response: See our response to 

comment II.E.1.(a)(i), above. The 

modeling approach was extensively 

discussed with regulatory agencies and 

the public when the SIP was developed, 

and the ISC-based modeling approach 

met the requirements of EPA’s 

Guideline on Air Quality Models. 

(d) Comment (MSCC): Modeling File 

Naming Convention. EPA’s modeling 

files and Technical Support Document, 

both contained in the docket, do not 

provide a reference to the naming 

conventions used in the modeling effort. 

While it is possible to dissect some of 

the naming conventions, it was not 

possible to discern each and every file 

and its purpose. Therefore, the 

reviewers are not certain that all the 

modeling attempts, purposes and 

nuances have been accounted for in the 

analysis. The commenter recommends a 

more complete description of the 

naming convention and the purpose 

behind each modeling effort needs to be 

explained. 

Response: At the recommendation of 

industry, MDEQ allowed the use of 

buoyancy flux in establishing emission 

limits, which made the modeling far 

more complex. As a result, many more 

modeling files are included than is 

typically the case in SIP modeling 

applications. To improve 

documentation, some extraneous 

modeling files have been removed and 

a text file added to explain naming 

conventions. The naming convention 

used for the Billings/Laurel SO2 FIP 

modeling files is typical of that used by 

the modeling community. To a modeler, 

the naming convention helps define the 

purpose behind the modeling effort. On 

July 13, 2007, the revised modeling files 

were indexed in the electronic docket 

contained on http:// 

www.regulations.gov, and a compact 

disk containing the modeling files was 

placed in the docket for this action. See 

reference document FFFFF. 

(e) Comment (MSCC, ExxonMobil): 

Out-of-date and Invalid Emissions 

Rates. Federally enforceable emission 

rates from refinery consent decrees have 

not been included in the FIP modeling. 

EPA has used 10-year-old emission 

inventory data that compromise the 

accuracy of the results. Reductions that 

have occurred in the past ten years have 

been ignored. The settlement documents 

related to the 1998 SIP contain 

requirements that substantially change 

the SO2 emission limits, and, therefore, 

the results of any modeling 

demonstration (ExxonMobil). Without 

including these existing emission 

reductions from the SIP and near term 

future reductions from consent decrees, 

EPA’s proposed FIP ignores state and 

federally enforceable SO2 emission 

reductions already in place. 

Response: See our responses to 

comments II.A.2.(b), II.B.2.(d) and II.D.4. 

The FIP modeling accounts for the 

limits that we approved in the Billings/ 

Laurel SO2 SIP and those we are 

promulgating in the FIP. We cannot 

include State requirements that were 

not submitted with the SIP. 

Additionally, the ExxonMobil consent 

decree limits have not been translated 

into short term emission limits by 

MDEQ and made a part of the SIP. Short 

term emission limits are required to 

ensure compliance with the 3-hour and 

24-hour average SO2 NAAQS. Also, the 

consent decrees do not address all of the 

stacks/sources involved in the SIP/FIP. 

(f) Comment (MSCC): MSCC has 

concerns with using the SIP modeling. 

The predecessor model routines had 

been discredited (‘‘invalidated’’) in this 

valley following a study done years 

earlier by the State. The model, even in 

the 1990’s, did not represent state of the 

art in modeling science and was 

admittedly prone to serious overpredictions, particularly in so-called 

intermediate and complex terrain. 

Response: As noted above, the 

modeling was EPA’s preferred model at 

the time of the SIP, has been validated 

for use in the Billings/Laurel area, and 

has been used extensively throughout 

the United States in setting emission 

limits for nearly two decades. The 

model has not been ‘‘invalidated’’ for 

use in the Billings/Laurel area. See also 

our discussion of related issues in our 

May 2, 2002, final action on the 

Billings/Laurel SO2 SIP, 67 FR 22168, 

22183. 

(g) Comment (ExxonMobil): Only the 

current actually existing emission 

sources with proper geographical 

coordinates should be used as inputs to 

the dispersion model. 

Response: We do not understand what 

the commenter is referring to when they 

indicate ‘‘only the current actually 

existing emission sources * * * should 

be used as inputs to the dispersion 

model.’’ With respect to geographical 

coordinates used in the modeling, they 

were provided by the sources in 

response to EPA’s CAA Section 114 

information request. The incorrect 

source coordinate for MSCC in the 

modeling files has been corrected.12 On 


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Implementation Plan (FIP) for Billings/Laurel, 

Montana, June 2006, we indicated that one 

suggested change that was not incorporated into the 

EPA FIP modeling involved the coordinate system 

used in the model to identify source location. 

MDEQ developed the original source locations 

based on the UTM NAD27 (North America Datum 

of 1927) coordinate system, and EPA has retained 

that coordinate system in our modeling. It appeared 

that several of the suggested changes to source 

locations were based on NAD83 values. The newer 

coordinate system can affect source locations by up 

to 200 meters. In dispersion modeling on the scale 

of the current modeling domain, consistency 

between the source and receptor locations is the 

most important consideration. For this reason, 

suggested changes that appeared to be based on the 

NAD83 were not included in the modeling. 

However, changes that address local inconsistencies 

in measured distances between fixed stacks (such 

as at MSCC) on a specific property were 

incorporated in EPA’s modeling using UTM 

NAD27. Sensitivity testing of the model showed 

that even the NAD27/NAD83 differences did not 

significantly affect total predicted concentrations; 

the principal effect was, in some instances, to shift 

the location of the maximum impact to a different 

receptor. An electronic record (compact disk) of 

EPA’s sensitivity testing of the model is contained 

in the docket. See reference document EEE in 

Docket Number EPA–R08–OAR–2006–0098. 

July 13, 2007, the revised modeling files 

were indexed in the electronic docket 

contained on http:// 

www.regulations.gov and a compact 

disk containing the modeling files was 

placed in the docket for this action. See 

reference document FFFFF. To the 

extent the commenter is asserting that 

actual emission rates should be used as 

inputs to the dispersion model, we 

respectfully disagree. As described more 

fully in our response to comment 

II.E.1.(e), above, potential emissions 

rather than actual emissions are used in 

SO2 attainment demonstrations, per 

longstanding EPA policy and 40 CFR 

part 51, Appendix W requirements. 

Accordingly, in our attainment 

demonstration, we modeled the 

emission limits we approved in the SIP 

and any new emission limits we are 

promulgating in the FIP. Thus, with the 

exception of certain units at MSCC, we 

modeled the same emission rates that 

the State used in its SIP modeling. 

(h) Comment (ExxonMobil): Only the 

verified actual stack heights should be 

used as inputs to the dispersion model. 

Response: Stack height regulations 

determine the stack height values that 

are used as inputs to dispersion models 

in SIP attainment demonstrations. In 

some cases this value may not be the 

same as the actual stack height. See 40 

CFR 51.118. For example, under our 

stack height regulations, 65 meters is the 

appropriate stack height value for 

MSCC’s SRU stack, even though the 

stack is 100 meters tall. We believe we 

have used the correct stack height 

values in all cases, and the commenter 

did not indicate that any specific stack 

height value we used in our modeling 

was incorrect. 

(i) Comment (ExxonMobil): The 

meteorological data to be used as input 

to the dispersion model should reflect 

the most representative information. 

The meteorological set to be used 

should be chosen based on availability 

and based on those monitored 

parameters that are best able to take full 

advantage of the latest dispersion 

modeling techniques. 

Response: EPA believes that the 

meteorological data from the Billings 

airport that was used in the SIP/FIP 

modeling is representative of conditions 

within the modeling domain. The 

Billings airport is located in an open 

area with good exposure to prevailing 

wind flow and has a long period of 

record. Five years of historical weather 

data (1984, 1986, 1987, 1988, and 1989) 

were used in the modeling to ensure 

that the full range of possible 

meteorological conditions were 

evaluated in the modeling. To our 

knowledge the Billings airport data have 

the longest period of record of any site 

in the Billings area. When the State 

developed the SIP modeling approach 

that EPA has now used for the FIP, the 

State tested ISC model performance 

using the Billings airport data. That 

evaluation showed acceptable model 

performance. 

(j) Comment (ExxonMobil): EPA 

should be modeling emission rates to 

levels that predict values slightly less 

than the NAAQS. This modeling 

concept is referred to as ‘‘pushing the 

model to failure.’’ This approach is 

designed to determine the maximum 

emission limits allowed by regulation 

under acceptable modeling protocol. By 

proposing mass emission limits on 

flares of 150 pounds of SO2 per 3-hour 

period or 500 pounds of SO2 per 

calendar day, EPA has chosen to use, 

without further consideration, mass 

emission limits that do not ‘‘push the 

model to failure’’ but instead arbitrarily 

limit the sources to mass emission 

limits that go far beyond protecting the 

NAAQS. 

Response: Emission inputs to the 

model were established using criteria 

contained in 40 CFR part 51, Appendix 

W, Section 8. The emission limits set by 

the modeling analysis are based on 

emission rates that would just meet the 

NAAQS. They are not based on 

‘‘arbitrary limits’’ that go ‘‘far beyond 

protecting the NAAQS’’. For example, 

with the limits we are establishing and 

the SIP limits we approved, our 

modeling resulted in a high value of 354 

μg/m3 which would exactly meet the 24- 

hour SO2 NAAQS of 365 μg/m3 when 

background concentrations of 11 μg/m3

are considered. 

(k) Comment (MDEQ): Montana 

continues to affirm the use of the ICS3 

model. 

Response: We acknowledge receipt of 

the comment and the support for the 

model used. 

(l) Comment (ExxonMobil): EPA has 

not used current accurate process and 

meteorological inputs in its modeling. 

This is contrary to EPA’s assurance in 

its May 2002 final rule that: ‘‘Any future 

modeling in the Billings/Laurel area 

should incorporate all corrections. The 

SIP limitations are based on the best 

information available at the time the 

attainment demonstration was modeled, 

and the same will be true for any FIP 

limitations that are developed.’’ 67 FR 

22189. Also, in its May 2002 final rule, 

EPA stated that: ‘‘We agree that future 

modeling should include all corrected 

data.’’ 67 FR 22189. However, EPA has 

ignored critical factual data for purposes 

of developing the proposed FIP. 

Response: The commenter ignores the 

context and meaning of EPA’s 

statements in its 2002 SIP action. The 

cited quotes were part of our response 

to specific comments from one source 

that there were errors in the State 

modeling numbers used for that source’s 

stack parameters. The comment was: 

‘‘CEMS data now indicate an error in 

the assumed buoyancy flux for MSCC’s 

main stack; the current modeling 

protocol contains an assumption which 

significantly underestimates the average 

rise in emissions. Any revised modeling 

should correct this assumption.’’ 67 FR 

22189. We were merely agreeing that 

future modeling should include 

corrected stack parameters based on 

CEMS measurements: ‘‘CEMS 

measurements of flow and temperature 

data provide the best estimates of stack 

parameters, and values based on CEMS 

data should be used in any future SIP 

modeling for Billings provided the 

CEMS data are accurate.’’ Id. We were 

not indicating we would use a new 

model, different meteorological data, or 

consider entirely new structures. In fact, 

on the same page of our 2002 notice, we 

said the following: 

‘‘In addition, dispersion models and data 

bases are continually being improved. The 

task of demonstrating attainment could never 

be completed if we or the State were 

compelled to update the analysis with each 

new refinement. For the FIP, we intend to 

continue to use ISC2 as the applicable model 

to fill in the gaps in the State’s attainment 

demonstration created by our disapproval of 

the emission limitations for MSCC’s 100- 

meter stack. Some source parameters have 

been corrected since the 1994 modeling 

analysis (see Response V.D.4.(d), above), but 

we intend to use the same meteorological 


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data and modeling protocols the State used, 

so that the results will be comparable.’’

For a more complete discussion of our 

basis for selecting the model and data 

inputs we have used, please refer to the 

other responses to comments in this 

section II.E, our proposed FIP, and our 

TSD for the proposed FIP. 

2. Technical Issues 

(a) Comment (MSCC, ExxonMobil): 

Incorrect Source Location. The location 

of the small boiler stacks at MSCC that 

are modeled as a volume source is 

incorrect. The error occurs by the nature 

in which the X and Y coordinates are 

entered into the SRI file. The entry is off 

by one column. 

Response: This has been corrected. 

On July 13, 2007, the revised modeling 

files were indexed in the electronic 

docket contained on http:// 

www.regulations.gov and a compact 

disk containing the modeling files was 

placed in the docket for this action. See 

reference document FFFFF. 

(b) Comment (MSCC): Incorrect 

Emission Rate. Table 2 of EPA’s 

Dispersion Modeling Technical Support 

Document shows the modeling value of 

136.21 g/sec for MSCC’s SRU-100-meter 

stack. An emission rate of 150.0 g/sec 

was modeled in the majority of the EPA 

modeling. If the proposed emission 

limit of 3003.1 lb/3-hours (126.13 g/sec) 

is correct, then the number that should 

appear in both the table and the input 

files is 126.13 (g/sec) to be consistent 

with the emission limit. 

Response: In the State’s original SIP 

modeling submittal there were 1,320 

modeling scenarios with various 

buoyancy flux combinations that were 

tested, and it was determined that only 

a few of these resulted in concentrations 

that threatened the NAAQS. EPA 

conducted screening to eliminate the 

need for refined modeling of those 

scenarios where the NAAQS were not 

threatened. The 150 g/sec emission rate 

was used provisionally to determine 

which modeling scenarios would result 

in the maximum ground level 

concentrations, and was not used to set 

MSCC’s proposed emission limit. Once 

the appropriate modeling scenarios 

were determined by EPA, only those 

scenarios were used to conduct the 

refined modeling to establish an 

emission limit of 126.13 g/sec. The 

commenter is correct that there is a 

discrepancy between Table 2 in EPA’s 

Dispersion Modeling Technical Support 

Document (reference document WW) 

and the modeling input files. The input 

files for the limited modeling scenarios 

reflected the correct value, 126.13 g/sec. 

Table 2 of the TSD contains the wrong 

value. 

(c) Comment (MSCC, ExxonMobil): 

Missing Modeling Files. Three source 

input files (SRI files) were not included 

in Reference Document EEE, the basis 

for the modeling conclusion and the 

proposed emission limit for MSCC’s 100 

meter stack. It appears that these files 

were actually used in model runs. 

Response: We have added the 

referenced modeling files. On July 13, 

2007, the revised modeling files were 

indexed in the electronic docket 

contained on http:// 

www.regulations.gov and a compact 

disk containing the modeling files was 

placed in the docket for this action. See 

reference document FFFFF. 

(d) Comment (MSCC, ExxonMobil): 

Hanging Modeling Files. A source input 

file (ref_5t.sri) is included in Reference 

Document EEE. However, this input file 

does not appear to be used in any input 

(RUN) and output files (OPF) files. It is 

not possible to comment effectively on 

the adequacy of the model without 

knowing the file’s purpose. 

Response: This was a test file 

inadvertently included in the electronic 

record. It has now been deleted. On July 

13, 2007, the revised modeling files 

were indexed in the electronic docket 

contained on http:// 

www.regulations.gov and a compact 

disk containing the modeling files was 

placed in the docket for this action. See 

reference document FFFFF. 

(e) Comment (MSCC, ExxonMobil): 

Outdated Building Profile Data. The 

dispersion modeling runs do not 

contain up-to-date information 

regarding building profile data. EPA’s 

use of 10-year old historical data is not 

logical considering the agency requested 

and received certain building data in its 

December 2003 request. 

Response: Building profile data were 

current at the time the MDEQ prepared 

the SIP. EPA is not updating the inputs 

to reflect recent changes in building 

dimensions or changes in dispersion 

models. We are simply correcting 

deficiencies in the MDEQ’s SIP 

modeling. If we were to follow the 

commenters’ suggestion, we would have 

to revisit the entire SIP, including SIP 

limits we approved. The CAA does not 

require us to re-open the entire SIP. See 

response to comment II.E.1.(a), above. 

(f) Comment (MSCC): Variable ‘‘HB’’

and ‘‘PW’’ Not Used. In order to execute 

the FIP model, EPA requested source 

specific information including the 

modeling terms HB and PW. These 

values may be input into the IGM 

model, however, this information is 

superseded by direction-specific 

building parameters by the model while 

executing in all cases (stacks) of interest. 

In other words, the data that was coded 

by EPA in the model runs were ignored 

by IGM (in favor of other information) 

and therefore of no value. Instead, 

specific building data (discussed above) 

should have been entered into the 

program. There is at least one 

substantial building, the YELP coke 

barn, that should have been included in 

the 2006 model runs. 

Response: See responses to comments 

II.E.1.(a) and II.E.2.(e), above. As noted 

above, to the extent possible, EPA is 

using the model inputs and model 

settings selected by the State at the time 

of SIP preparation and used in the IGM 

code. The model input selections reflect 

modeling practice and conditions at the 

time of the SIP. The coke barn did not 

exist at the time the SIP was prepared. 

HB and PW values reflect the 

dimensions of the facilities that had 

large structures nearby and that MDEQ 

included for downwash processing in 

their SIP modeling. While the 

commenter is correct that, in the IGM 

model, these values were superseded by 

other data, obtaining these values was 

useful to us as a screening tool, and 

inputting these values into the model 

did not affect the validity of the results. 

(g) Comment (MSCC, ExxonMobil): 

Compliance Analysis Not Valid. The FIP 

proposal notes that there is a ‘‘trigger 

point’’ of 500 lb/calendar day in various 

‘‘settlements’’ between EPA and 

refineries. The proposal goes on to 

assert that a modeling analysis was 

conducted assuming the flares emitted 

SO2 at a rate of 500 lb/3-hours and that 

the model demonstrated compliance to 

this alternative. A review of the 

modeling files, however, indicates that 

the ‘‘controlling’’ model run that 

defined MSCC’s emission limit for the 

100-meter stack (modeled at 65 meters) 

did not include this 500 lb/3-hour flare 

emission rate option. 

Response: We solicited comment on 

whether we should limit the flares to 

500 lbs of SO2 per calendar day. We 

have not adopted that option. But, for 

purposes of the attainment 

demonstration, we modeled the 500 lbs 

as if it were emitted over a 3-hour 

period rather than a calendar day. We 

wanted to assure that if all the calendarday allowed emissions were emitted in 

a 3-hour period, the 3-hour NAAQS 

would still be protected. Those 

modeling files are contained in the 

docket. 

However, the controlling model run 

that defined MSCC’s emission limit for 

the SRU 100-meter stack was for the 24- 

hour NAAQS. There was no need to 

model the 500 lbs of SO2/calendar day 

to show compliance with the 24-hour 

NAAQS since we had already modeled 

the flares at 1200 lbs of SO2/calendar 


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day. Since attainment of the 24-hour 

NAAQS was shown at 1200 lbs of SO2/ 

calendar day, the area would still show 

attainment at 500 lbs of SO2/calendar 

day. 

F. Miscellaneous Comments 

1. Stakeholder Process 

(a) Comment (CHS Inc.): If EPA 

intends to regulate malfunctions, 

startups, and shutdowns, a stakeholder’s 

process should be used to accurately 

develop a reasonable flare limit. 

Response: EPA announced its 

proposed FIP in the Federal Register on 

July 12, 2006, invited public comment, 

and identified the time and place for a 

public hearing. A public hearing was 

held in Billings, Montana, on August 10, 

2006. Only one person from industry 

spoke at the hearing. Prior to the hearing 

and at the hearing itself, no one 

mentioned the concept of a stakeholder 

process. In addition, we provided nearly 

four months for the affected facilities 

and other members of the public to 

submit written comments and 

suggestions regarding our proposed FIP, 

including a substantial extension to our 

original 60-day comment period in an 

attempt to reasonably accommodate 

State and industry requests. We have 

made a number of changes in response 

to comments received. If the affected 

facilities had other ideas about how we 

could better structure the FIP, they had 

ample opportunity to express those 

concepts. 

We have complied with the 

requirements of the CAA as set forth in 

section 307(d) regarding public 

participation for the FIP. We are not 

required to hold a stakeholder process. 

Issues regarding malfunctions, startups, 

and shutdowns are addressed above. 

(b) Comment (CHS Inc., ExxonMobil, 

MPA): It would be in the best interest of 

all involved that a stakeholder process 

be used to determine what, if any, 

enhancements to the Montana SIP are 

appropriate. 

Response: See response to comment 

II.F.1.(a), above. 

(c) Comment (WETA, COPC): If the 

EPA feels strongly that consideration 

should be given to different controls for 

SO2, then a stakeholder process should 

be utilized to consider issues and 

relevant information in deciding if a 

further SIP or FIP is necessary. 

Response: See response to comment 

II.F.1.(a), above. 

(d) Comment (MSCC, ExxonMobil): 

EPA has developed the proposed FIP in 

a vacuum as to the affected parties. It is 

inappropriate for EPA to not consult the 

affected facilities in any meaningful 

way. The process used by Montana in 

developing the SIP should be used in 

the FIP. A stakeholder process will 

allow all parties an opportunity to 

ensure that the best available 

information is considered in 

formulating any proposed requirements. 

Response: See response to comment 

II.F.1.(a), above. 

2. Ripple Effect 

(a) Comment (WETA): The commenter 

is concerned not only with the impact 

of the FIP on the refineries in the area 

but the potential ripple effect on the 

businesses, workers, and other 

consumers who daily use and depend 

on the variety of products produced by 

the petroleum refineries in the Billings/ 

Laurel area. 

Response: We acknowledge the 

commenter’s concerns. We recognize 

that our FIP will result in costs to MSCC 

and the refineries, which they may or 

may not pass on to consumers. We have 

tried to be sensitive to the costs MSCC 

and the refineries may incur to meet the 

FIP’s requirements, which potentially 

would affect the costs of products to 

consumers. For example, where we 

determined less costly methods to 

monitor SO2 concentrations could 

achieve similar results, we are allowing 

these other methods to be used. 

However, our ultimate charge under the 

CAA is to protect the SO2 NAAQS, 

recognizing that cost impacts to sources 

and consumers may occur. See, e.g., City 

of Santa Rosa v. EPA, 534 F.2d 150 (9th 

Cir.1976), vacated and remanded on 

other grounds sub nom. Pacific Legal 

Foundation v. EPA, 429 U.S. 990 (1976). 

(b) Comment (citizen): The 

commenter is a dryland farmer and uses 

an ammonium sulfate (thiasol) fertilizer, 

which is a by-product of the refinery 

process. He says he is doing as much as 

he can to be environmentally 

conscientious and not introduce metals 

into the soils found in other fertilizers. 

This requires him to use the thiasol that 

is refinery-produced. He requests that 

EPA not exacerbate a bad situation for 

agriculture, which increases costs to a 

major industry which is marginal in 

profitability and major in importance to 

the State of Montana. 

Response: See response to comment 

II.F.2.(a), above. 

3. Extend Comment Period 

Comment (COPC, ExxonMobil, MSCC, 

WETA, YCC): Commenters asked for 

additional time to comment on the 

proposed FIP, until at least December 

11, 2006. 

Response: The public comment 

period on the FIP proposal ran from July 

12, 2006, through November 3, 2006—

almost four months. Additionally, a 

public hearing was held in Billings, 

Montana, on August 10, 2006. EPA 

believes it provided sufficient time and 

opportunity for all commenters to 

provide comments on the proposed FIP. 

4. EPA’s Strategic Plan 

Comment (COPC): The proposed FIP, 

which contains inflexible flare emission 

limits and strictly-specified monitor 

installations requirements, is 

inconsistent with EPA’s Strategic Plan, 

which commits EPA to ‘‘finding 

innovative solutions and collaborating 

with others.’’

Response: We acknowledge the 

commenter’s concerns. However, we are 

charged with meeting the CAA’s 

requirement to assure that the SO2

NAAQS are met and maintained. 

Accordingly, the FIP adopts flare 

emission limits and compliance 

determining methods. 

It should be noted that the discussion 

on Innovation and Collaboration in the 

‘‘2006–2011 EPA Strategic Plan, 

Charting Our Course,’’ September 2006 

(reference document BBBBBB), pertains 

to complex environmental challenges 

where broad-based problems cannot be 

solved with conventional regulatory 

controls. We do not think this is 

relevant here. We are merely 

establishing limits on flares and 

methods to determine compliance with 

those limits. 

5. FIP Provisions in Title V Permits 

Comment (MDEQ): Montana 

acknowledges that the FIP provisions, if 

promulgated, will be incorporated in 

Title V permits. However, Montana 

expects EPA will take the lead on 

implementing and enforcing the FIP 

provisions. 

Response: EPA intends to assume 

primary responsibility to implement 

and enforce the FIP. However, the FIP 

requirements will be ‘‘applicable 

requirements’’ under Title V, which, 

therefore, must be included in Title V 

permits for the affected sources and be 

enforceable by the State. 

6. Length of Time it Took EPA To 

Propose FIP 

Comment (YVAS): Since the 1990 

Clean Air Act requires NAAQS for SO2

to protect public health, YVAS deplores 

this ‘‘inadequacy [sic] and ‘‘nonattainment’’ and deplores further that 

the EPA did not adequately and in 

timely fashion, take necessary steps to 

enforce the CAA’s provisions to protect 

the air quality in the Billings/Laurel 

area in a reasonably suitable time period 

regardless of any mitigating 

circumstances. A specific justification 

explaining this lapse in EPA’s 


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responsibilities for not acting in the 

public interest is essential to the 

residents of the Billings/Laurel area 

given that at the time, the Billings/ 

Laurel Sulphur Dioxide Area was 

subject to excessive amounts—estimated 

to be over 35,000 tons (1993)—of SO2

atmospheric pollution. 

Response: We believe EPA’s SIP Call 

and subsequent State and EPA actions 

to address the SIP Call have helped 

reduce SO2 emissions in the Billings/ 

Laurel area. There is no question that 

this process has taken longer than it 

should have. 

7. EPA Enforcement 

Comment (YVAS): YVAS insists that 

the EPA consistently monitor industry 

emissions in order that industry sources 

continue to comply with the SIP and/or 

the ‘‘more stringent requirements under 

other provisions of the CAA’’ or ‘‘SIPapproved permit programs.’’

Response: EPA intends to take the 

lead in enforcing the emission limits 

and monitoring requirements contained 

in the FIP. Congress intended that states 

have primary responsibility for 

implementing and enforcing their SIPs. 

Additionally, states may take the lead in 

implementing and enforcing other CAA 

programs (e.g., News Source 

Performance Standards (NSPS), 

Maximum Achievable Control 

Technology (MACT) standards, Title V 

permitting), either through EPA 

delegation or program approvals. In the 

latter cases, we have an oversight role 

and may take enforcement action under 

section 113 of the CAA for violations of 

a SIP or other CAA requirements when 

a state does not take action or when its 

action is considered ineffective. 

EPA Region 8 communicates regularly 

with the MDEQ regarding sources. We 

have regular meetings with MDEQ 

regarding sources that are violating 

emission limit requirements and discuss 

the MDEQ’s proposed or ongoing 

actions to address these violations. We 

intend to continue to carry out our 

oversight responsibility for the SIP and 

other CAA requirements for the 

Billings/Laurel sources. If we determine 

that the MDEQ is not taking appropriate 

action for violations of the SIP, or other 

CAA requirements, we will take 

appropriate action. 

8. Further Emission Reductions 

Comment (YVAS): Although the 

industry is attaining lower yearly 

decreases of SO2 since 1994, with 

presumably a better and ‘‘healthier’’ air 

quality in the area thereby, the 

assumption logically follows that 

industry should be required to comply 

with further reduced SO2 release levels. 

Nowhere in this FIP is there an attempt 

to address the issue of a further 

reduction in the total emissions of the 

industrial sources in the Billings/Laurel 

area. Accordingly, YVAS believes that 

all anti-lower SO2 emission arguments 

are irrelevant against the demand for 

protecting public health standards and 

additional reduction of SO2 emissions is 

mandatory under the CAA. Failing to 

address a further SO2 emissions 

reduction should be considered another 

serious breach of your responsibility to 

the Billings/Laurel public. Why did EPA 

not include a discussion towards 

reducing the total SO2 emissions in the 

Billings/Laurel Sulphur Dioxide area in 

this FIP and since EPA did not include 

that discussion here, does EPA plan to 

do that and if so, when? 

Response: The 1970 CAA established 

the air quality management process as a 

basic philosophy for air pollution 

control in this country. Under this 

system, we establish air quality goals 

(NAAQS) for criteria pollutants. States 

develop control programs (termed SIPs) 

to attain and maintain these NAAQS. 

Our fundamental obligation in the SIP/ 

FIP context is to ensure that the NAAQS 

are met, not reduce emissions to zero. 

Thus a reduction of SO2 emissions is 

mandatory only to the extent needed to 

attain the NAAQS. However, under 

section 116 of the CAA, states may 

adopt and enforce any air pollutant 

standard, limitation, or control 

requirement so long as it is no less 

stringent than that required by the CAA. 

Put another way, states can require that 

the air be cleaner than the NAAQS. Our 

goal in the FIP is to ensure attainment 

of the SO2 NAAQS. 

9. SO2 NAAQS 

(a) Comment (YVAS): Nowhere in this 

FIP is any reference made to what clean 

air standards should be under the CAA 

or NAAQS. Commenters should have 

been informed as to those standards in 

this FIP in order to fairly judge as 

acceptable or non-acceptable the release 

standards proposed for the sources in 

this FIP. How can the public adequately 

comment on clean air issues when those 

standards are unknown to the public? 

Further, referring the general public to 

sources where those standards would be 

found is a disservice to the public since 

many of those sources of such 

information may be unattainable or 

unavailable. 

Response: The July 12, 2006, 

proposed FIP did identify the 24-hour 

and 3-hour SO2 NAAQS under the 

modeling discussion (71 FR 39259, 

starting at 71 FR 39270, col. 1). The SO2

NAAQS were previously established 

(see discussion below), and EPA was 

not seeking comment on any changes to 

the NAAQS in this FIP action. 

Two sections of the CAA govern the 

establishment and revision of NAAQS. 

Section 108 (42 U.S.C. 7408) directs the 

Administrator to identify pollutants 

which ‘‘may reasonably be anticipated 

to endanger public health or welfare’’

and to issue air quality criteria for them. 

These air quality criteria are to ‘‘reflect 

the latest scientific knowledge useful in 

indicating the kind and extent of all 

identifiable effects on public health or 

welfare which may be expected from the 

presence of [a] pollutant in the ambient 

air.’’

Section 109 (42 U.S.C. 7409) directs 

the Administrator to propose and 

promulgate ‘‘primary’’ and ‘‘secondary’’

NAAQS for pollutants identified under 

section 108. Section 109(b)(1) defines a 

primary standard as one ‘‘the attainment 

and maintenance of which, in the 

judgement of the Administrator, based 

on the criteria and allowing an adequate 

margin of safety, [is] requisite to protect 

the public health.’’ A secondary 

standard, as defined in section 

109(b)(2), must ‘‘specify a level of air 

quality the attainment and maintenance 

of which, in the judgement of the 

Administrator, based on [the] criteria, is 

requisite to protect the public welfare 

from any known or anticipated adverse 

effects associated with the presence of 

[the] pollutant in the ambient air.’’

Welfare effects are defined in section 

302(h), 42 U.S.C. 7602(h), to include 

‘‘effects on soils, water, crops, 

vegetation, manmade materials, 

animals, wildlife, weather, visibility and 

climate, damage to and deterioration of 

property, and hazards to transportation, 

as well as effects on economic values 

and on personal comfort and wellbeing.’’

On April 30, 1971 (reference 

document CCCCCC), the Environmental 

Protection Agency (EPA) promulgated 

primary and secondary NAAQS for 

sulfur oxides (SOx) (measured as SO2) 

(then codified as 40 CFR 410.4 and 

410.5). The primary standards were set 

at 365 micrograms per cubic meter (μg/ 

m3) (0.14 parts per million (ppm)), 

averaged over a 24-hour period and not 

to be exceeded more than once per year, 

and 80 μg/m3 (0.03 ppm) annual 

arithmetic mean. The secondary 

standard was set at 1,300 μg/m3 (0.5 

ppm) averaged over a period of 3 hours 

and not to be exceeded more than once 

per year. In accordance with sections 

108 and 109 of the CAA, in the 1990’s, 

EPA reviewed and revised the health 

and welfare criteria upon which these 

primary and secondary SO2 standards 

were based. On April 21, 1993 (58 FR 

21351) (reference document DDDDDD), 


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EPA announced its final decision under 

section 109(d)(1) of the CAA that the 

revisions of the secondary SO2 NAAQS 

were not appropriate at that time. On 

May 22, 1996 (61 FR 25566) (reference 

document EEEEEE), EPA announced its 

final decision under section 109(d)(1) of 

the CAA that the revision of the primary 

SO2 NAAQS was not appropriate at that 

time. EPA is currently reviewing the 

primary and secondary standards again 

to determine whether they should be 

revised. 

The Code of Federal Regulations 

(CFR) is available at most public 

libraries and on the internet at: http:// 

ecfr.gpoaccess.gov/. Likewise, the CAA 

is also available at most public libraries 

and on the internet at EPA’s Web site: 

http://www.epa.gov/air/caa/. 

(b) Comment (citizen): The rejection 

of Montana’s Plan to control air quality 

in the Billings/Laurel air shed 4 years 

previously has left a serious gap in the 

air quality in this air shed. 

Response: We acknowledge this 

comment. See response to comment 

II.F.6., above. 

10. SO2 Health Effects 

(a) Comment (Citizen): The air is so 

bad near the commenter’s house that 

she needs to close the windows. She has 

headaches and burning eyes and 

sinuses. How safe is it for the families? 

Commenter is concerned that air 

emissions affect landscape and river 

areas. Commenter would like EPA to 

assure that refineries do not off-gas 

unmeasureable blasts of pollution as she 

has seen them do over her water, 

county, and home. 

Response: We acknowledge this 

comment. The FIP, along with other 

requirements contained in the SIP, will 

provide an enforceable mechanism to 

assure that the SO2 NAAQS in the 

future will be protected in the Billings/ 

Laurel area. Since EPA initially 

requested the State to revise the 

Billings/Laurel SO2 SIP, actual SO2

emissions from companies have been 

cut by more than half and there have 

been measured improvements in air 

quality. The SIP and FIP contain an 

enforceable control strategy to help 

ensure that the SO2 NAAQS are attained 

and maintained. 

(b) Comment (Citizen): Since national 

air quality standards are more stringent 

than Montana requires, serious health 

risks to area residents is probable and 

cannot be ignored. 

Response: See response to comment 

II.F.10.(a), above. Note that the State’s 

ambient standards, in some cases, are 

more stringent than the national 

standards. Subchapter 2 of the 

Administrative Rules of Montana (ARM) 

contains the Montana ambient air 

quality standards (MAAQS). The 

MAAQS are not contained in the 

federally-approved SIP; the CAA does 

not require that the standards be in the 

federally-approved SIP. The SO2

MAAQS are contained in ARM 17.8.210 

(see reference document FFFFFF) and 

are as follows: (1)(a) Hourly average—

0.50 ppm, not to be exceeded more than 

18 times in any 12 consecutive months; 

(1)(b) 24-hour average—0.10 ppm, not to 

be exceeded more than once per year; 

and (1)(c) annual average—0.02 ppm, 

not to be exceeded. The 24-hour and 

annual SO2 MAAQS are more stringent 

than EPA’s 24-hour and annual SO2

NAAQS. The State has a 1-hour average 

SO2 MAAQS and EPA has a 3-hour 

average SO2 NAAQS. The State does not 

require that plans be developed to 

assure attainment and maintenance of 

the MAAQS, whereas, EPA does require 

plans to assure that the NAAQS are 

attained and maintained. 

(c) Comment (Citizen): Commenter 

works the evening shift near the 

industrial sector and the refineries and 

the coke plant. He notices that at night 

the air becomes more sour. Depending 

upon which way the wind is blowing or 

whatever is occurring in the area, it will 

burn his eyes and nose. It will start to 

burn his lungs and inflame his chest 

and it will make it harder for him to 

breathe. The air is like a smoke-filled 

barroom. He used to live in this area as 

well. Commenter feels it degrades the 

quality of his life. He’s standing up for 

his lungs. 

Response: See response to comment 

II.F.10.(a)., above. 

11. Public Process 

(a) Comment (Citizen): Since there has 

been no public disclosure of the EPA’s 

plans for complying with the standards 

(considered as minimal by local public 

health advocates) as set forth in the 

National standards (which also have not 

been provided publicity to create public 

awareness of those standards), the EPA 

should not proceed with any rule 

making unless the public receives an 

opportunity to comment. 

Response: EPA announced its 

proposed FIP in the Federal Register on 

July 12, 2006. In the July 12, 2006 

Federal Register notice, EPA provided 

for the opportunity of a public hearing. 

A public hearing was held in Billings, 

Montana on August 10, 2006. At the 

hearing, EPA discussed its proposed 

FIP. Additionally, EPA’s proposed 

notice indicated that detailed 

information regarding the proposed FIP 

was available on the Internet. We have 

complied with the requirements of 

section 307(d) of the CAA regarding 

public disclosure and the administrative 

requirements for proposing the FIP. We 

are announcing this final FIP in the 

Federal Register as well. A discussion 

of the SO2 NAAQS is provided above. 

(b) Comment (Citizen): Plans for 

controlling emissions ‘‘at the source’’

must be provided by the EPA at any 

public meeting announced by the EPA 

and those plans should be announced 

publicly in advance of the meeting in 

order for the public to understand what 

the effects and results of such plans will 

be on the air shed quality of the 

Billings/Laurel metropolitan area. 

Response: See response to comment 

II.F.11.(a), above. 

12. Stack Height 

(a) Comment (Citizen): Included in 

EPA’s emission control plans must be a 

stringent requirement that none of the 

three area refineries or the Montana 

Sulphur and Chemical company may 

construct any emissions stack or flaring 

system of 100 meters or higher. 

Information concerning the probable 

effects, distance, wind patterns, content 

etc. of the dispersal plumes of stacks of 

this height should be provided to the 

public at any hearing in order that 

public comment on this crucial aspect 

of the emission control plan may be 

properly analyzed. Under no 

circumstances should the 100-meter 

height be considered as a minimum 

permissible height by the EPA or by the 

companies involved for any stack or 

flaring system. 

Response: EPA does not restrict the 

physical height of a smoke stack. See 40 

CFR 51.118(a). However, we do restrict 

the credit a company receives for its 

stack height in the modeling used to 

determine whether a SIP will meet 

national standards for specific air 

pollutants. Id. The stack height credit is 

based on the greater of the following: (1) 

A height of 65 meters, (2) a height based 

on a formula that considers the 

surrounding buildings, or (3) a height 

based on technical modeling studies 

which show a certain height is 

necessary to avoid high levels of 

pollutants in the nearby area. See 40 

CFR 51.100(ii). 

EPA has rules that apply to tall stacks; 

otherwise, companies could avoid 

installing needed pollution control 

equipment. Industry could simply build 

higher stacks and emit into the air 

additional pollutant levels that would 

not violate local air quality standards, 

but could eventually affect the air 

quality of communities farther 

downwind. This is because the higher 

the stack height, the greater the 

dispersion of pollutants and the less 

likely they will reach the ground in the 


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vicinity of the stack. EPA does allow 

increases to stack height credits when 

the stacks meet the conditions noted 

above. 

EPA disapproved part of the Billings/ 

Laurel SO2 SIP because MSCC’s stack 

height credit did not meet the 

conditions noted above. EPA believes 

that the appropriate stack height credit 

for the MSCC SRU 100-meter stack is 65 

meters. The 65-meter stack height credit 

was used in the modeling for the FIP. 

We did not identify any other concerns 

with the stack height credit used for 

other sources in the SIP. 

(b) Comment (Citizen): Studies, 

including wind roses of the dispersal 

pattern of all stacks of 65 meters and 

higher should be provided to the public 

at a hearing of the final FIP, in order that 

the public comment on this crucial 

aspect of the emission control plan may 

be properly analyzed. 

Response: The CAA directs EPA to 

take public comment on proposed FIPs, 

not final FIPs. See CAA section 307(d). 

EPA’s modeling studies for the 

proposed FIP were contained in the 

docket for the proposed FIP and 

available for review during the comment 

period on the proposed FIP. 

Additionally, on July 13, 2007, the 

revised modeling files were indexed in 

the electronic docket contained on 

http://www.regulations.gov and a 

compact disk containing the modeling 

files was placed in the docket for this 

action. See reference document FFFFF. 

13. General Support 

(a) Comment (Citizen): The 

commenter wants to lend support to 

what EPA is trying to do here and the 

proposals that EPA is making, and he 

thinks it is very much on target and for 

his benefit, and he would hope the 

industries who are being regulated in 

this sense will find a way to make it 

worth their while to do it also. 

Response: We acknowledge receipt of 

the comment and the support for our 

proposal. 

(b) Comment (Citizen): Commenter 

encourages EPA to carry on the work we 

have been doing, to encourage 

movement in the positive direction of 

reducing emissions. 

Response: We acknowledge receipt of 

the comment and the support for our 

proposal. 

(c) Comment (Citizen): Commenter 

appreciates the changes that EPA is 

making and thinks the people in 

Billings deserve them. Commenter feels 

the industries need to step up to the 

plate and be responsible for their 

emissions. 

Response: We acknowledge receipt of 

the comment and the support for our 

proposal. 

14. SIP Escape Clause 

Comment (MSCC): The SIP contains 

an important ‘‘escape clause’’ by which 

there was a general agreement that if the 

State provided more favorable treatment 

to one facility, the same accommodation 

would be offered to the other facilities. 

The present proposed FIP which 

proposes to reduce MSCC’s stack height 

credit and drastically reduce MSCC’s 

emission limits will violate that clause. 

This unwarranted intrusion into a 

carefully-bargained agreement among 

multiple parties, violates both the letter 

and the spirit of the CAA. 

Response: We are not bound by the 

escape clause that the State approved; in 

fact, we disapproved this aspect of the 

SIP. See 67 FR 22168, May 2, 2002. 

Instead, we are obligated to correct the 

portions of the SIP we disapproved. We 

disapproved MSCC’s main stack 

emission limits because they were based 

on inappropriate stack height credit. 

The FIP establishes new limits for 

MSCC’s main stack that are consistent 

with our modeled attainment 

demonstration, based on a Good 

Engineering Practice (GEP) stack height 

credit of 65 meters. While it is not clear 

to us how this violates the Stateapproved escape clause, setting 

emission limits for MSCC’s main stack 

consistent with our stack height 

regulations and necessary to 

demonstrate attainment of the NAAQS 

does not violate the CAA. On the 

contrary, setting such limits is required 

by the CAA, regardless of the Stateapproved escape clause. 

G. MSCC Specific Issues 

1. Variable Emission Limit 

(a) Comment (MSCC): EPA offers 

surprisingly little discussion as to why 

a variable limit was not proposed for 

Montana Sulphur. EPA’s reasoning 

seems to ignore that MSCC has been 

operating under a variable emissions 

limit that has been modeled, monitored, 

and enforced for close to a decade. 

Response: EPA’s reasoning for not 

offering a variable limit is discussed in 

the July 12, 2006, proposal notice (see 

71 FR 39259, starting at 39268, col. 2) 

and reference document WW 

‘‘Technical Support Document’’

contained in EPA Docket No. EPA–R08–

OAR–2006–0098. Additionally, to our 

knowledge, the SIP limits for two 

sources in Billings (ExxonMobil and 

Montana Power) are the only instances 

in the United States where variable 

emission limits based on buoyancy flux 

have been adopted, approved, and 

implemented. The thousands of other 

emission limitations nationwide are 

based on a single fixed buoyancy flux 

value similar to what we proposed for 

MSCC. 

(b) Comment (MSCC): Complicated to 

Model. (i) MSCC agrees that it is more 

complicated to model a variable 

emission rate than a fixed emission rate. 

That alone is not sufficient reason to 

deny MSCC the variable emission rate. 

Also, much has changed since the 

original modeling effort. Computer 

speed, memory, data handling, and 

storage are all improved. 

Response: Modeling was one of the 

reasons we offered for not providing a 

variable emission limit; however, it was 

not the only reason. Although computer 

speed, data handling, and storage are 

improved since the MDEQ developed 

the Billings/Laurel SO2 SIP, there would 

still be a considerable effort on EPA’s 

part to model a variable emission limit 

for the SRU 100-meter stack. Therefore, 

we used EPA’s historical practice of 

selecting mean values of historical data. 

Individual stationary sources in SIP 

attainment demonstrations are typically 

modeled assuming a single 

representative value for the model input 

parameters that affect plume rise. Model 

input parameters that affect plume rise 

include stack gas temperature and 

volume flow, or buoyancy flux. If 

emissions are held constant, ground 

level concentrations would tend to 

decrease during periods with higher 

plume rise associated with elevated 

stack gas temperature and increased 

stack flow velocities. Conversely, 

ground level concentrations would tend 

to increase during periods with reduced 

stack gas temperatures and stack flow 

velocities. The State opted to set 

emission limitations based on variable 

buoyancy flux values for three of the 

sources. MDEQ identified a total of 11 

buoyancy flux modeling scenarios for 

MSCC, 12 for ExxonMobil, and 10 for 

the Corette Power Plant. Modeling all 

possible combinations of scenarios 

required the State to model a total of 

1,320 combinations for each year of 

meteorological data processed. EPA 

used a fixed buoyancy flux value for 

modeling MSCC and that reduced the 

number of potential modeling scenarios 

to 120. EPA reviewed the modeling 

results in the State’s attainment 

modeling to identify which scenarios (of 

the 120 possible scenarios) would 

produce the highest concentrations. 

Based on this selection process, EPA 

modeled approximately 50 scenarios in 

the FIP modeling, and we believe that 

these scenarios represent the limiting 


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(i.e. maximum predicted concentration) 

case. 

(ii) It is completely arbitrary to create, 

model, approve, monitor, and enforce 

variable limits at other Billings facilities 

but to deny the same courtesy for MSCC 

claiming that it is, in this case alone, too 

complicated a modeling effort. 

Response: Again, modeling was not 

the sole reason for not providing a 

variable emission limit for MSCC’s SRU 

100-meter stack. Although EPA 

approved the variable emission limits at 

other Billings facilities, we did so with 

reservations. (See our July 28, 1999, 

proposed rulemaking action on the 

Billings/Laurel SO2 SIP, 64 FR 40791, 

starting at 40794, col. 3, and our May 2, 

2002, final rulemaking action, 67 FR 

22168, starting at 22206, col. 2, for a full 

discussion of our concerns with the 

variable emission limit concept.) Since 

EPA is taking the lead in establishing 

emission limits for MSCC’s SRU 100- 

meter stack and will take the lead in 

enforcing the FIP, EPA has chosen not 

to model and provide a variable 

emission limit. We believe our exercise 

of discretion so as to simplify FIP 

development and enforcement is 

reasonable, particularly where the data 

indicate MSCC will be able to comply 

with a fixed emission limit without 

additional controls and where fixed 

limits are the norm in SIPs throughout 

the country. 

(c) Comment (MSCC): Complicated to 

Monitor. Buoyancy flux has been 

measured and reported to DEQ for a 

period of about eight years, with very 

high reliability. It is simply illogical to 

argue or imply that monitoring 

buoyancy flux is a task not worthy or 

too complicated in nature. One cannot 

deny the historical evidence that it has 

been measured successfully for many 

years and that it does not require any 

monitor instrumentation not already 

required to measure sulfur dioxide. 

Response: See response to comment 

II.G.1.(b)(ii), above. 

(d) Comment (MSCC): Complicated to 

Enforce. EPA’s reason for not proposing 

a variable limit for MSCC due to 

enforcement is puzzling. If EPA 

approved variable emission limits for 

other sources, even though the same 

enforcement concern exists, it should 

also be approved for MSCC. 

Response: The State developed the 

original SIP that allows variable 

emissions for several sources. The State 

takes the lead in enforcing the SIP, and 

EPA takes an oversight role. EPA 

approved portions of the SIP, including 

variable emission limits at two sources, 

and we did so with reservations. Since 

we would be taking the lead in 

enforcing the FIP, we have chosen not 

to place an increased burden on 

ourselves to enforce a variable limit. See 

also the response to comment II.G.1.(e), 

below. 

(e) Comment (MSCC): Variable Limit 

is Better Science. Though it involves 

incremental initial work, from a 

modeling perspective, the use of 

variable limits is better science. It 

replaces a false assumption in modeling 

(constant, average stack conditions 

under all operating scenarios) with 

factual information so that plume 

height, which is variable, can be more 

accurately represented. Plume height, 

just like mass emissions, is normally 

variable and is critical to calculation of 

downwind concentrations. 

Response: In addition to looking at air 

quality impacts of the FIP, we also need 

to assure that the FIP is enforceable. 

Although we may agree with the 

commenter that the variable emission 

limitation will result in fewer emissions 

when the buoyancy of the plume is 

lower, it will also result in higher 

emissions when the buoyancy of the 

plume is higher. Additionally, a variable 

emission limit is more difficult to 

enforce. Granted the same instruments 

would be used to determine compliance 

whether the emission limit is fixed or 

variable. However, in addition to 

confirming that the source is in 

compliance with a variable emission 

limit, agencies will also need to confirm 

that the variable emission limitation 

was determined correctly. Therefore, we 

believe that variable emission limits 

increase the workload and add a layer 

of complexity that is not found with 

fixed emission limitations. Because of 

this enforcement complexity, we do not 

agree with the commenter that variable 

emission limitations are a superior 

approach to setting emission 

limitations. 

(f) Comment (MSCC): Fixed Limit 

Compliance. Although MSCC has been 

able to meet the proposed FIP limit for 

several years, it must be noted that 

MSCC has not always been able to 

operate within such limits, and that 

MSCC was not operating its sulfur plant 

at maximum capacity during the time 

periods cited by EPA. The primary 

reason MSCC can operate under EPA’s 

proposed limit arises from MSCC’s 

voluntary installation of SuperClaus TM. 

The SuperClaus unit must be shut down 

periodically for repair. MSCC needs the 

variable limit to be in compliance when 

SuperClaus unit is shut down. MSCC 

should not be punished for its good 

behavior by requiring control 

technology and lower emissions than is 

necessary to maintain NAAQS. 

Response: EPA’s proposed FIP limit 

for MSCC’s SRU 100-meter stack was 

determined through modeling as the 

limit needed to assure attainment of the 

SO2 NAAQS. Since the NAAQS are 

health-based standards, as a general 

matter, SIPs/FIPs must assure 

attainment of the NAAQS on a 

continuous basis. 

We note that apparently MSCC was 

able to conduct maintenance on the 

SuperClaus unit in 2003, 2004, and 

2005 without exceeding the proposed 3- 

hour and 24-hour FIP SRU 100-meter 

limits. MSCC may be able to perform its 

maintenance on the SuperClaus unit 

when other process equipment at 

ExxonMobil is down for maintenance. 

Additionally, we understand that MSCC 

intends to install a second SuperClaus 

unit to provide redundancy to the 

existing SuperClaus equipment. 

Installation is expected to begin in the 

fourth quarter 2007, at the earliest 

(reference documents GGGGGG and 

BBBBBBB). Concerns about additional 

emissions during maintenance should 

be eliminated with the addition of a 

second SuperClaus unit. 

2. 100-Meter Stack Height Credit and 

Emission Limit 

(a) Comment: MSCC submitted 

summary comments regarding its 

position concerning good engineering 

practice stack height credit for the 100- 

meter SRU stack. MSCC noted that these 

comments had generally been submitted 

previously to both EPA and Montana. 

MSCC claimed that it has not received 

the proper stack height credit for the 

100-meter SRU stack in the proposed 

FIP. 

Response: EPA disapproved the 

State’s determination of stack height 

credit for MSCC’s 100-meter SRU stack 

on May 2, 2002 (67 FR 22168). In the 

May 2, 2002, notice, starting on page 

22209, we responded to all the stack 

height comments MSCC previously 

submitted. We hereby incorporate by 

reference our responses from that 

notice. We indicated in the May 2, 2002, 

notice that ‘‘[w]e considered the 

comments received and still believe we 

should finalize our proposed 

disapproval of the MSCC’s stack height 

credit and SRU 100-meter stack 

emission limitations. None of the 

adverse comments has convinced us 

that our interpretation of the CAA and 

our regulations is unreasonable or that 

we should change our proposed course 

of action.’’ See our May 2002 final 

action (67 FR 22168). EPA has 

determined that the GEP stack height 

credit for the 100-meter SRU stack is 65 

meters and has used that height in 

establishing the 100-meter SRU stack 

emission limit. Our stack height 

regulations, codified at 40 CFR 51.100 


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13See MSCC’s ‘‘Hydrogen Sulfide Fuel Gas 

Monitoring Plan,’’ dated September 2000, that 

fulfilled requirements of Montana Air Quality 

Operating Permit 2611–00, Appendix H. (See 

reference document IIIIII.) 

and 51.118, provide that the degree of 

emission limitation required for 

pollutant control under an applicable 

SIP shall not be affected by stack height 

in excess of GEP stack height. The 

central component of the regulations 

consists of definitions of the term ‘‘good 

engineering practice stack height.’’ GEP 

stack height is the greater of (1) 65 

meters (known as ‘‘de minimis’’ stack 

height), (2) the height calculated using 

a formula specified by regulations 

(‘‘formula height’’), or (3) the height 

demonstrated using fluid modeling or a 

field study (‘‘non-formula height’’ or 

‘‘above-formula height’’). See 40 CFR 

51.100(ii)(1)–(3). Prior to our SIP action, 

the State calculated the formula height 

for the SRU 100-meter stack to be 47.8 

meters (see reference documents 

VVVVVV and WWWWWW). Per our 

regulations, since this is lower than 65 

meters, GEP stack height is 65 meters. 

We have not received any new 

information to indicate formula height 

should be higher than 47.8 meters, nor 

have we received a valid demonstration 

for above-formula stack height credit. 

See our proposed and final actions on 

the Billings/Laurel SO2 SIP, 64 FR 

40791 (July 28, 1999) and 67 FR 22168 

(May 2, 2002), respectively. In light of 

our prior decision on the fluid modeling 

in the SIP action, and in the absence of 

a new, valid, GEP stack height 

demonstration, it would be 

inappropriate in this FIP for us to use 

a stack height value for MSCC that is 

inconsistent with our prior action. 

(b) Comment (YVAS): YVAS believes 

the annual emission limit of 9,088,000 

lbs of sulphur is too excessive because 

YVAS believes this ‘‘proposed’’

emission to be a major contribution to 

the total emissions of sulphur dioxide in 

the Billings/Laurel area and is, 

therefore, not acceptable. In addition, 

EPA states that: ‘‘We (EPA) are 

proposing fixed emission limits rather 

than variable emission limits on MSCC’s 

SRU 100 meter stack because they are 

less complicated to model monitor and 

enforce.’’ This proposal is inadequate 

and does not address the continuing 

high total SO2 emission limits you 

intend permitting MSCC to continue to 

release. 

Response: Stack emission limits are 

set to assure that the SO2 NAAQS are 

met. As seen in the SIP and FIP, there 

are 3-hour, 24-hour, and annual SO2

emission limits on most stacks. These 

emission limits assure that the 3-hour, 

24-hour, and annual SO2 NAAQS are 

attained and maintained. As indicated 

in the response to comment II.F.8., 

above, we cannot require states to adopt 

provisions that go beyond attaining and 

maintaining the NAAQS. The annual 

emission limit we proposed for the SRU 

100-meter stack, and that we are now 

promulgating in the FIP, assures that the 

annual SO2 NAAQS will be attained and 

maintained. Additionally, the 3-hour 

and 24-hour SO2 NAAQS are more 

controlling than the annual SO2

NAAQS. This means that more stringent 

emission limits must be placed on 

stacks to assure that the 3-hour and 24- 

hour SO2 NAAQS are attained and 

maintained than would be required to 

assure that the annual SO2 NAAQS are 

met. 

(c) Comment (Citizen): Commenter 

appreciates the logic of not allowing 

increases in stack height credit. 

Response: We acknowledge the 

support for our proposal. Also, please 

see our response to comment II.G.2.(a), 

above. 

3. 30-Meter Stack and Auxiliary Vent 

Stack 

(a) Comment (MSCC): Emissions 

monitoring for 30-meter Stack and 

Auxiliary Vent Stacks. EPA has 

proposed unnecessarily complex, 

redundant, and unneeded monitoring 

and reporting requirements for both the 

30-meter stack and the auxiliary vent 

stacks. The emissions from these units 

have minimal impact on model results. 

These predicted concentrations are less 

than 1% of the NAAQS. The emission 

limit applicable is miniscule in 

comparison with other uncertainties in 

the implementation plan. Emissions 

from these units, although authorized, 

are infrequent. Venting to the boiler 

stack is generally associated with events 

such as maintenance. For operational 

reliability and flexibility, MSCC needs 

to be able to vent these boilers locally. 

Monitoring these units is an expense 

and requirement that serves no real or 

useful purpose. Essentially the same 

information is already gathered under 

the State plan. 

Response: As we indicated in our July 

12, 2006, proposed FIP (71 FR 39259, 

39268), it is necessary for EPA to require 

methods to assure that the emission 

limits for the 30-meter stack and 

auxiliary vent stacks are met. However, 

since MSCC has already established a 

method to monitor these emissions 

using length-of-stain detector tubes (e.g., 

Dra ̈ger Tubes),13 and since length-ofstain detector tubes are widely-used and 

reliable, we have revised the FIP to 

make its requirements similar to those 

MSCC must already meet under the 

State’s operating permit. Specifically, 

we have revised the method by which 

MSCC shall determine the H2S content 

of the fuel burned. Our final FIP 

indicates that on a once-per-3-hour 

period frequency until no heater or 

boiler is exhausting to the 30-meter 

stack or an auxiliary vent stack, MSCC 

shall determine the H2S content of the 

fuel burned using length-of-stain 

detector tubes with the appropriate 

sample tube range pursuant to ASTM 

Method D4810–06, ‘‘Standard Test 

Method for Hydrogen Sulfide in Natural 

Gas Using Length-of-Stain Detector 

Tubes’’ (see reference document 

UUUUUU). The final FIP indicates that 

if the results exceed the tube’s range, 

another tube of a higher range must be 

used until results are in the tube’s range. 

(b) Comment (MSCC): Emission 

Limit—100 ppm H2S—A Redundant 

Limit. Having both a 12 lb/3-hour limit 

and 100 ppm H2S limit creates doublejeopardy. Both limits are for solely and 

exactly the same thing. If a particular 3- 

hour period were to indicate 120 ppm, 

it would be in violation of both limits. 

This could (and is very likely to) occur 

even if the units were not, in fact, 

operating anywhere near an actual 

emission rate of 12 lbs/3-hours. This 

result is overkill and is not appropriate 

or necessary for protection of the 

NAAQS. 

Response: In our FIP proposal, we 

were attempting to simplify the method 

to determine compliance with the mass 

emission limits. The assumption in the 

proposal was that if the H2S 

concentration was below 100 ppm H2S, 

then the source would be in compliance 

with the mass emission limits. We were 

not trying to create ‘‘double jeopardy’’

for MSCC. It appears that the 

commenter believes the 100 ppm H2S 

limit is too restrictive because the 

source could be in compliance with the 

mass emission limit but out of 

compliance with the ppm limit. 

In our final FIP we are keeping the 

simplified method to determine 

compliance with the mass emission 

limits. We believe determining direct 

compliance with the mass emission 

limits would either require additional 

monitoring equipment or methods and/ 

or would be unreliable due to potential 

variation in boiler use and venting 

practices. However, to address the 

commenter’s concern, we are increasing 

the H2S concentration limit to 160 ppm 

per 3-hour period. We are adding a 

calendar day H2S concentration limit of 

100 ppm. 

We selected the 160 ppm H2S per 3- 

hour period limit for the following 

reasons. First, as explained in greater 

detail below, this value will protect the 

3-hour SO2 NAAQS. Second, 160 ppm 


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of H2S per 3-hour period is the current 

NSPS limit for fuel gas combustion 

devices. EPA reported the following in 

its May 14, 2007, proposal to revise 

subpart J of the new source performance 

standards (NSPS), and to adopt new 

subpart Ja: 

after consideration of current operating 

practices, we concluded that amine 

scrubbing units are still the predominant 

technology for reduction of H2S in fuel gas 

(and SO2 emissions from subsequent fuel gas 

combustion). Considering the variability of 

the fuel gas streams from various refinery 

processing units, 160 ppmv also is still a 

realistic short term H2S concentration limit. 

However, one California Air Quality 

Management District rule sets a 40 ppmv H2S 

limit in fuel gas (averaged over 4 hours), and 

several refiners have reported that the typical 

fuel gas H2S concentrations (after scrubbing) 

are in the same range. 

(See 72 FR 27178, 27193.) Third, the 

State’s SIP indicates that MSCC shall 

burn only low sulfur fuel gas or natural 

gas in any unit being exhausted through 

the 30-meter stack (see MSCC’s exhibit 

A, reference document II). Low sulfur 

fuel gas is not defined in exhibit A. 

However, an MDEQ staff member 

indicated that the term ‘‘low sulfur fuel 

gas’’ in the SIP would be gas with an 

H2S concentration much lower than the 

NSPS subpart J limit of 160 ppm (see 

reference document GGGGGG). This 

suggests that MSCC should already be 

achieving a daily limit of 100 ppm. 

To test the use of a 160 ppm limit, we 

remodeled the area assuming the 

emissions were 1.01 g/s from the 30- 

meter stack and auxiliary vent stacks. 

We derived the higher emission value 

from the same assumptions and 

calculations expressed in our proposal, 

except we assumed a maximum H2S 

concentration of 160 ppm (see 71 FR 

39259, 39268, July 12, 2006). At the 

higher three hour emissions, the area 

would still show attainment of the 3- 

hour SO2 NAAQS. However, the area 

would not show attainment of the 24- 

hour SO2 NAAQS if all 3-hour periods 

in a calendar day were at the 160 ppm 

level. Therefore, we are revising the FIP 

to indicate that the H2S concentration in 

the fuel burned in the heaters and 

boilers, while any of the heaters and 

boilers are exhausting to the SRU 30- 

meter stack or auxiliary vents stacks, 

shall not exceed 160 ppm per 3-hour 

period and 100 ppm per calendar day. 

The mass emission limits remain the 

same as proposed. The revised modeling 

files are indexed in the electronic 

docket contained on http:// 

www.regulations.gov, and a compact 

disk containing the modeling files has 

been placed in the docket for this 

action. See reference document 

KKKKKK. 

(c) Comment (MSCC): Emission 

Limit—100 ppm H2S—Overly Stringent. 

The 100 ppm H2S limit, which is a 

surrogate for the pound/hour SO2 limit, 

is far too restrictive. EPA developed the 

100 ppm H2S limit based on conditions 

that have a miniscule probability of 

occurring. It has the effect of 

introducing a new, strict ‘‘performance 

standard’’ into the mix of limits, where 

such standard is not applicable. 

Response: See response to II.G.3.(b), 

above. Also, in order to protect the 

NAAQS, it is reasonable to consider 

potential worst-case conditions in 

setting emission limits and compliance 

determining methods. 

(d) Comment (MSCC): Monitoring 

Requirements. The requirement to 

monitor the auxiliary vent stacks has 

already been addressed through the 

State plan; there is no inadequacy or 

other basis to FIP this. The current 

system already periodically measures 

the H2S content in the fuel gas header 

for gas that is not natural gas, using a 

simple portable detector (nonelectronic) such as a Dra ̈ger tube or GasTec tube. The frequency of testing 

necessity was determined through the 

State’s plan and the frequency of such 

testing steps up in response to high 

measurements until the measurements 

have returned to low levels. The present 

plan also reasonably estimates the 

volume of gas used in each boiler to 

permit calculation of the SO2 emitted by 

each auxiliary vent when in use, and 

logs the venting location, as the State 

plan provides. 

Response: In large part, this comment 

appears to pertain to our disapproval of 

the relevant portion of the SIP. We note 

that we have not reopened our SIP 

action as part of this action and are not 

considering comments on that action 

here. To the extent the comment is 

relevant to our FIP action, see response 

to comment II.G.3.(b), above. As we 

explain there, the FIP retains the 

requirement that MSCC measure the 

H2S content of the fuel burned but 

increases the 3-hour concentration limit 

to 160 ppm. The FIP also allows MSCC 

to use length-of-stain detector tubes in 

lieu of portable analyzers. However, 

based on comments received, we are not 

convinced that MSCC’s current methods 

for determining direct compliance with 

the mass emission limits are sufficiently 

reliable or accurate for purposes of the 

FIP due to potential variation in boiler 

use and venting practices and lack of 

equipment to directly measure relevant 

parameters at or emissions from each 

boiler. We believe additional monitoring 

equipment would need to be installed, 

or additional monitoring would need to 

be performed, at greater expense to 

MSCC, to achieve adequate methods to 

determine direct compliance with the 

mass emission limits. The concentration 

limits we are imposing are reasonable, 

can be monitored at reasonable cost, and 

will ensure protection of the NAAQS. 

(e) Comment (MSCC): Monitoring 

Cost. EPA proposes imposing significant 

overly burdensome on-going costs to 

track a minuscule amount of potential 

or actual SO2 emissions. 

Response: As we indicate in response 

to comment II.G.3.(a), we have revised 

the FIP to allow MSCC to use the same 

devices to determine H2S concentrations 

in the gas going to the 30-meter stack 

and auxiliary vent stacks as MSCC is 

using to meet State requirements 

(length-of-stain detector tubes). While 

the frequency of monitoring may be 

somewhat different than the frequency 

under the State’s permit, the final FIP 

should not result in any substantial 

additional monitoring costs for the 30- 

meter stack and the auxiliary vent 

stacks, particularly since MSCC 

indicates emissions from these stacks 

are infrequent. 

H. ConocoPhillips Specific Issues 

SRU/ATS Stack and Jupiter Flare 

Comment (COPC): ConocoPhillips 

urges EPA to delete the proposed 

prohibition of simultaneous emissions 

from the SRU/ATS stack and the Jupiter 

flare even if the combined SO2

emissions are less than 25 lb/hr. This 

merely imposes a compliance risk and 

produces no environmental benefit. 

Logic does not dictate that because both 

sources were modeled as one point, that 

combined, simultaneous emissions from 

both are prohibited. Quite the contrary, 

having modeled both sources as one 

point supports and endorses the option 

of both sources being able to emit a 

combined total of the amount of SO2

which was modeled. 

Response: EPA agrees that it is not 

necessary to prohibit simultaneous 

emissions from both emission points. 

Attainment of the SO2 NAAQS would 

be assured so long as the combined 

emissions from both emission points do 

not exceed 75.0 pounds per 3-hour 

period. Since both emission points have 

methods for determining emissions, 

compliance with the emission limit 

would be assured. We are revising the 

regulatory text to eliminate the 

restriction on simultaneous emissions 

and any corresponding language. 

Additionally, in the final regulatory text 

we are clarifying the reporting 


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requirements to correspond to this 

change. 

I. ExxonMobil Specific Issues 

1. Coker CO Boiler 

Comment (ExxonMobil): The 

proposed FIP would require that the 

Coker CO Boiler stack CEMS operate at 

all times. This is unnecessary because 

the Coker Process gas is exhausted 

through the nearby Yellowstone Energy 

Limited Partnership Co-Generation 

facility. During those hours, Coker CO 

Boiler stack SO2 emissions are 

monitored by the existing fuel gas CEM 

for fuel gas combustion devices. The 

existing SO2 SIP requires that a SO2

CEMS be operated on the Coker CO 

Boiler stack during those few hours that 

the Coker Process Gas is exhausted 

through the Coker CO Boiler and stack. 

Given that a CEMS is already required 

for this source, nothing is served by 

requiring ExxonMobil to report the 

emissions and compliance assurance 

data for this source to both EPA and 

MDEQ. Nothing is served by requiring 

ExxonMobil to notify both EPA and 

MDEQ of required Relative Accuracy 

Test Audits (RATA). 

Response: It was not EPA’s intent to 

require that the Coker CO Boiler stack 

CEMS be operated at all times. Our 

intent was to clarify that the Coker CO 

Boiler CEMS already installed, in 

conjunction with the appropriate 

equations, must be used to determine 

compliance with the emission limits 

established in section 3(B)(1) of 

ExxonMobil’s 2000 exhibit. 

We are clarifying the FIP to indicate 

that the Coker CO Boiler CEMS only 

needs to be operating when 

ExxonMobil’s Coker unit is operating 

and Coker unit flue gases are exhausted 

through the Coker CO Boiler stack. We 

are also clarifying that whenever 

ExxonMobil’s Coker unit is operating 

and Coker unit flue gases are exhausted 

through the Coker CO Boiler stack, the 

CEMS shall immediately be operational. 

Also, with respect to the SO2 CEMS, we 

indicate that ExxonMobil shall perform 

a Cylinder Gas Audit (CGA) or Relative 

Accuracy Audit (RAA), which meets the 

requirements of 40 CFR part 60, 

Appendix F, within 8 hours of when the 

Coker unit flue gases begin exhausting 

through the Coker CO Boiler stack. 

Finally, for both the SO2 and flow 

CEMS, we indicate that ExxonMobil 

shall perform an annual RATA, on the 

CEMS. 

Because we will have primary 

responsibility to enforce the FIP, we 

have retained the requirements that 

ExxonMobil submit emissions and 

compliance assurance data to both EPA 

and MDEQ and notify EPA and MDEQ 

of RATAs. 

2. Tutwiler Analysis 

Comment (ExxonMobil): The 

proposed FIP would require that 

ExxonMobil measure the H2S 

concentration of the fuel gas once every 

three hours using the Tutwiler method 

contained in 40 CFR 60.648 any time 

the refinery fuel gas H2S CEMS 

measures a concentration of greater than 

1200 ppmv. The proposed once per 3- 

hour Tutwiler analysis is less protective 

than the existing requirement identified 

in the alternative monitoring plan 

(AMP) submitted to DEQ. The AMP 

requires measurement of the fuel gas 

H2S concentration with Dra ̈ger tubes on 

an hourly basis anytime the fuel gas H2S 

CEMS data are expected to be 

unavailable for any reason for more than 

one 3-hour block. 

Response: In our proposed FIP, EPA 

proposed a method for determining H2S 

concentrations when the range of the 

H2S CEMS is exceeded. ExxonMobil 

commented that they currently use 

another method for determining H2S 

concentrations when the H2S CEMS is 

not available. This other method has 

been identified in an AMP submitted to 

DEQ (reference document JJJJJJ). Since 

ExxonMobil already has procedures 

established for determining H2S 

concentrations when the H2S CEMS is 

not available, namely, the use of Dra ̈ger 

Tubes, a type of length-of-stain detector 

tube, and since length-of-stain detector 

tubes are widely-used and reliable, EPA 

is revising its FIP to incorporate the 

other method identified by ExxonMobil. 

Specifically, we are revising the FIP to 

indicate that when the H2S 

concentration in the refinery fuel gas 

exceeds 1200 ppmv as measured by the 

H2S CEMS, ExxonMobil shall measure 

the H2S concentration on an hourly 

basis using length-of-stain detector 

tubes pursuant to ASTM Method 

D4810–06, ‘‘Standard Test Method for 

Hydrogen Sulfide in Natural Gas Using 

Length-of-Stain Detector Tubes.’’ The 

length-of-stain detector tubes shall have 

the appropriate sample tube range. If the 

results exceed the tube’s range, another 

tube of a higher range must be used 

until results are in the tube’s range. The 

hourly length-of-stain detector tubes 

data will then be used to calculate SO2

emissions from refinery fuel gas 

combustion and to determine 

compliance with the emission limits in 

40 CFR 52.1392(f)(3)(i). 

3. ExxonMobil Emissions 

Comment (YVAS): The question must 

be asked that since ExxonMobil’s 

emissions are appreciably higher than 

its two closest competitors, that a 

significant lowering in total SO2

emissions in the Yellowstone Valley 

could be attained if ExxonMobil would 

be required to use that equipment under 

either Federal EPA standards or under 

the State of Montana emissions 

requirements as well. That there is no 

requirement to insist that ExxonMobil 

use equipment/refining processes that 

would lower its future SO2 emissions is 

a deplorable lack of public concern to 

YVAS’ best interests and should be 

publicly examined by the EPA. 

Response: EPA acknowledges this 

comment. See response to comment 

II.F.8., above. 

J. CHS Inc. Specific Issues 

Particulate Issues 

Comment (YVAS): YVAS is 

concerned that the Coker production 

unit at CHS Inc. will not have to provide 

a containment system shielding the 

nearby area from the effects of 

particulate pollution. This is a 

deplorable lack of proper protection of 

the public and, although addressing this 

particular issue was apparently not 

important to this FIP, since it was 

completely omitted from this FIP, either 

through oversight or deliberate 

omission, YVAS seeks a ruling from the 

EPA that could require CHS, Inc. to 

address this issue and provide relief to 

the public from this oversight. 

Response: EPA acknowledges the 

comment. However, the FIP addresses 

only the provisions of the SO2 SIP that 

we disapproved. Under CAA section 

110(c), EPA’s authority is to remedy the 

deficiencies we identified in the SO2

SIP. 

III. Summary of the Final Rules and 

Changes From the July 12, 2006, 

Proposal 

The following summarizes the final 

FIP and the major changes from our July 

12, 2006, FIP proposal. Generally, the 

reasons for the changes made in the 

final FIP appear in section II, above, 

‘‘Issues Raised by Commenters and 

EPA’s Response.’’ In some cases, the 

reasons appear below. We also describe 

some minor changes to the FIP in this 

section. 

A. Flare Requirements Applicable to All 

Sources 

Since the State’s attainment 

demonstration assumed that the main 

flares at each source were limited to 150 

pounds of SO2 per 3-hour period, and 

that the Jupiter Sulfur SRU flare would 

share an emission limit of 75 pounds of 

SO2 per 3-hour period with the Jupiter 


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14ATS stands for Ammonium Thiosulfate. 

Sulfur SRU/ATS 14 stack, we proposed 

flare emission limits that reflected the 

State’s assumption that emissions from 

these points would not exceed these 

levels. While we proposed that 150 

pounds of SO2 per 3-hour period be the 

limit for the main flares, we also 

solicited input on whether we should 

instead limit the main flares to 500 

pounds of SO2 per calendar day. The 

final FIP requires that the main flares at 

each source be limited to 150 pounds of 

SO2 per 3-hour period and that the 

Jupiter Sulfur flare share an emission 

limit of 75 pounds of SO2 per 3-hour 

period with the Jupiter Sulfur SRU/ATS 

stack. 

We also proposed that the flare limits 

would apply at all times without 

exception. We also solicited comment 

on whether it would be appropriate to 

include in our final FIP the ability to 

assert an affirmative defense to penalties 

only (not injunctive relief) for violations 

of the flare limits. Under the final FIP, 

flare limits apply at all times. However, 

we have changed the proposed rule to 

provide the ability for sources to assert 

an affirmative defense to penalties only 

(not injunctive relief) for violations of 

the flare limits. The affirmative defense 

provision includes notification 

requirements that are distinct from the 

FIP’s quarterly reporting requirements. 

We proposed that compliance with 

the flare emission limits would be 

determined by continuous measurement 

of the total sulfur concentration and 

volumetric flow rate of the gas stream to 

the flare(s), followed by calculation, 

using appropriate equations, of SO2

emitted per 3-hour period. 

We proposed that sources install, 

calibrate, maintain, and operate a 

continuous flow monitoring system 

capable of measuring the total 

volumetric flow of the gas stream 

combusted in a flare in accordance with 

the specifications described below. We 

indicated that the flow monitoring 

system could require one or more flow 

monitoring devices or flow 

measurements at one or more header 

locations if one monitor could not 

measure all of the volumetric flow to a 

flare. 

We proposed the following 

volumetric flow monitoring 

specifications: 

(1) The minimum detectible velocity 

of the flow monitoring device(s) would 

be 0.1 feet per second (fps); 

(2) The device(s) would continuously 

measure the range of flow rates 

corresponding to velocities from 0.5 to 

275 fps and have a manufacturer’s 

specified accuracy of ± 5% over the 

range of 1 to 275 fps; 

(3) For correcting flow rate to 

standard conditions (defined as 68°F 

and 760 millimeters of mercury 

(mmHg)), temperature and pressure 

would be monitored continuously; 

(4) The temperature and pressure 

would be monitored in the same 

location as the flow monitoring 

device(s) and be calibrated to meet 

accuracy specifications as follows: 

Temperature would be calibrated 

annually to within ± 2.0% at absolute 

temperature and the pressure monitor 

would be calibrated annually to within 

± 5.0 mmHg; 

(5) Flow monitoring device(s) would 

be calibrated prior to installation to 

demonstrate accuracy to within 5.0% at 

flow rates equivalent to 30%, 60%, and 

90% of monitor full scale; and 

(6) After installation, the flow 

monitoring devices would be calibrated 

annually according to manufacturer’s 

specifications. 

The final FIP flow monitoring 

provisions are the same as proposed 

except that we are revising the following 

provisions: 

(1) With respect to the accuracy of the 

flow monitor, the final FIP indicates 

that the device(s) shall continuously 

measure the range of flow rates 

corresponding to velocities from 0.5 to 

275 fps and have a manufacturer’s 

specified accuracy of ± 5% of the 

measured flow over the range of 1 to 275 

fps and ± 20% of the measured flow 

over the range of 0.1 to 1.0 fps. 

(2) With respect to measurement of 

volumetric flow rate, the final FIP 

indicates that volumetric flow rate shall 

be measured on an actual wet basis and 

converted to standard conditions, and 

reported in SCFH. 

(3) With respect to temperature and 

pressure monitors, the final FIP 

indicates that temperature and pressure 

monitors should be calibrated prior to 

installation according to manufacturer’s 

specifications. We inadvertently omitted 

this requirement in our proposal. 

We proposed that in cases where the 

flow to the flare exceeds the range of the 

monitor, other methods could be used to 

determine the volumetric flow rate. In 

the final FIP, we have clarified this 

provision to read that in cases when the 

volumetric flow monitor is not working 

or where the flow exceeds the range of 

the monitor, methods established in the 

flare monitoring plan required by the 

FIP shall be used to determine the 

volumetric flow rate to the flare, which 

shall then be used to calculate SO2

emissions. Additionally, we have 

revised the quarterly reporting 

requirements to be consistent with these 

changes. The final FIP now indicates 

that in quarterly reports, sources shall 

indicate the date and time when a 

monitor is not working or the range is 

exceeded, and the other methods used 

to determine flare emissions. We have 

made these revisions to the final FIP so 

that these provisions are consistent with 

what we require in the flare monitoring 

plan. 

The final FIP also adds the ability for 

sources to use means other than the 

flow monitor to determine that the flare 

is not operating when the flow monitor 

registers low flow. Specifically, the final 

FIP allows sources to use devices that 

monitor the integrity of the flare water 

seal. If these devices indicate that no 

flow is going to the flare, yet the flow 

monitor indicates there is flow, the 

presumption will be that no flow is 

going to the flare. We have also revised 

the flare monitoring plan and reporting 

requirements to recognize the use of, 

and require reporting on, these other 

flare flow devices. 

We proposed that sources install, 

calibrate, maintain, and operate an online analyzer system capable of 

continuously determining the total 

sulfur concentration of the gas stream 

sent to a flare. We proposed that the 

continuous monitoring occur at a 

location or locations that are 

representative of the gas combusted in 

the flare and be capable of measuring 

the expected range of total sulfur in the 

gas stream to the flare. We proposed that 

the total sulfur analyzer be installed, 

certified (on a concentration basis), and 

operated in accordance with 40 CFR 

part 60, Appendix B, Performance 

Specification 5, and be subject to and 

meet the quality assurance and quality 

control requirements (on a 

concentration basis) of 40 CFR part 60, 

Appendix F. Additionally, we proposed 

that sources notify EPA in writing of 

each Relative Accuracy Test Audit 

(RATA) a minimum of 25 working days 

prior to the actual testing. In the final 

FIP, we are retaining the above 

provisions, but are allowing the use of 

other methods to determine total sulfur 

concentration. See discussion below. 

The final FIP also clarifies that the total 

sulfur concentration monitor should 

measure in the range of concentrations 

that are normally present in the gas 

stream to the flare. 

In the final FIP, we are adding 

provisions that indicate that, in cases 

when the total sulfur analyzer is not 

working or where the concentration of 

the total sulfur exceeds the range of the 

monitor, methods established in the 

flare monitoring plan required by the 

FIP shall be used to determine the total 

sulfur concentrations, which shall than 


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15Note that the SRU/ATS stack has an SO2 CEMS 

and flow monitor to determine compliance when 

emissions are vented through that stack. 

be used to calculate SO2 emissions. 

Additionally, the final FIP indicates that 

in quarterly reports, sources shall 

indicate the date and time when a 

monitor is not working, or the range is 

exceeded, and the other methods used 

to determine flare emissions. We have 

made this addition to the FIP so that 

these provisions are consistent with 

what we require in the flare monitoring 

plan. 

In lieu of continuous total sulfur 

concentration analyzers, the final FIP 

allows sources to determine the total 

sulfur concentration through grab or 

integrated sampling. If a source chooses 

to use one of these methods, the final 

FIP provides a trigger by which sources 

must begin the sampling and indicates 

the analytical methods to be used to 

determine the total sulfur concentration 

in the sample. The final FIP also 

provides that in cases where a grab or 

integrated sample is not obtained or 

analyzed, methods established in the 

flare monitoring plan required by the 

FIP shall be used to determine total 

sulfur concentrations, which will then 

be used to calculate SO2 emissions. The 

flare monitoring plan and reporting 

requirements have also been revised to 

recognize the potential use of grab or 

integrated sampling. 

We proposed that within 180 days 

after receiving EPA approval of the flare 

monitoring plan, sources install and 

calibrate, and thereafter calibrate, 

maintain, and operate continuous flow 

monitors and total sulfur concentration 

analyzers. The final FIP has been 

revised to allow sources 365 days after 

receiving EPA approval of the flare 

monitoring plan to install and calibrate, 

and thereafter calibrate, maintain, and 

operate the continuous volumetric flow 

monitors and to start determining total 

sulfur concentrations of the gas stream 

by either continuous total sulfur 

concentration analyzers or grab or 

integrated sampling monitoring. 

We proposed that each facility submit 

a flare monitoring plan including, 

among other things, information 

regarding pilot and purge gas at each 

flare and how the concentration and 

volumetric flow monitors would 

analyze the pilot and purge gases. The 

final FIP indicates that if the facility 

certifies that only natural gas or an inert 

gas is used as pilot and/or purge gas, 

monitoring the stream(s) consisting of 

only natural gas or inert gas is not 

required. However, if natural gas or 

inert gas is not used for pilot and/or 

purge gas, then the source must measure 

the flow and H2S concentration of the 

gas streams that do not consist of only 

natural gas or inert gas or use other 

methods approved by EPA in the flare 

monitoring plan to estimate flow and 

H2S concentration. Pilot and purge gas 

SO2 emissions will then be calculated 

and added to the other SO2 emissions 

from the flare to determine compliance 

with the SO2 flare emission limits. We 

have revised the reporting requirements 

accordingly to require sources to either: 

(1) Certify in the quarterly reports if 

pilot and/or purge gas is not monitored 

because only natural gas or inert gas is 

used as the pilot and/or purge gas; or (2) 

report flow, H2S concentration of, and 

SO2 emissions from, the pilot and/or 

purge gas. 

We also added provisions that 

indicate that in cases when any pilot or 

purge gas flow monitor or H2S analyzer 

is not working, or where the flow or 

concentration of the H2S exceeds the 

range of the monitor or analyzer, 

methods established in the flare 

monitoring plan required by the FIP 

shall be used to determine the pilot and 

purge gas flow and/or H2S 

concentrations, which shall then be 

used to calculate SO2 emissions. The 

FIP indicates that in quarterly reports, 

sources shall indicate the date and time 

when a monitor or analyzer is not 

working, or the range is exceeded, and 

the other methods used to determine 

flare emissions. 

The flare monitoring plan 

requirements have been revised to be 

consistent with the pilot and purge gas 

provisions described above. 

We have added definitions of Aliquot, 

Integrated sampling, Pilot gas, and 

Purge gas to clarify the FIP’s flare 

monitoring requirements. Finally, we 

proposed quarterly reporting 

requirements similar to the reporting 

requirements contained in the Billings/ 

Laurel SO2 SIP and those contained in 

40 CFR 60.7(c). We added to the 

reporting requirements as necessary to 

address the changes to other 

requirements. 

B. CHS Inc. 

1. Flare Requirements 

We proposed that CHS Inc.’s flare be 

limited to 150 pounds of SO2 per 3-hour 

period and that compliance with the 

limit be determined as discussed above. 

The final FIP is the same as proposed 

except for the flare monitoring changes 

applicable to all sources mentioned 

above. 

2. Combustion Sources Emission Limits 

We proposed a prohibition in the FIP 

on the burning of SWS overheads in the 

main crude heater. We proposed that 

compliance with the prohibition to not 

burn SWS overheads in the main crude 

heater be determined by CHS Inc. 

installing a chain and lock on the valve 

that supplies sour water stripper 

overheads from the ‘‘old’’ SWS to the 

main crude heater to insure that the 

valve could not be opened. The 

proposed FIP also required CHS Inc. to 

maintain the chain and lock in place, 

keep the valve closed at all times, and 

log and report any noncompliance with 

this provision. The final FIP is the same 

as proposed. 

C. ConocoPhillips 

Flare Requirements 

We proposed that ConocoPhillips’s 

main flare be limited to 150 pounds of 

SO2 per 3-hour period and that 

compliance with the limit be 

determined as discussed above. We also 

proposed that at any one time, 

ConocoPhillips could only use either 

the north or south main flare. The final 

FIP is the same as proposed except for 

the flare monitoring changes applicable 

to all sources mentioned above. 

We proposed an emission limit of 75 

pounds of SO2 per 3-hour period for the 

Jupiter Sulfur SRU flare and SRU/ATS 

stack and that emissions could only be 

vented from the SRU flare when 

emissions were not being vented from 

the SRU/ATS stack. We proposed that 

compliance with the SRU flare emission 

limit, when Jupiter Sulfur vented 

emissions to the SRU flare rather than 

the SRU/ATS stack, be determined by 

measuring the total sulfur concentration 

and volumetric flow rate of the gas 

stream to the flare.15 Our final FIP is the 

same as proposed except that we have 

removed the restriction that emissions 

could only be vented from the SRU flare 

when emissions were not being vented 

from the SRU/ATS stack. Our final FIP 

indicates that compliance with the 

combined emission limit be determined 

by summing the emissions from the 

Jupiter Sulfur SRU flare and SRU/ATS 

stack. 

D. ExxonMobil 

1. Flare Requirements 

We proposed that ExxonMobil’s 

primary process and turnaround flares 

be limited to 150 pounds of SO2 per 3- 

hour period and that compliance with 

the limit be determined as discussed 

above. Our proposal indicated that we 

understood that the turnaround flare is 

only used about 30–40 days every 5 to 

6 years and is not normally operating. 

Therefore, we proposed to establish one 

combined emission limit for the primary 

process and turnaround flares. Our 


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16See section 6(B)(3) of CHS Inc.’s 1998 exhibit. 

(See reference document DD for a copy of the 

exhibit.) 

17See 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.) 

18See section 3(B)(1) of ExxonMobil’s 2000. (See 

reference document HH for a copy of the exhibit.) 

19See sections 2(A)(1), (8), (11)(a), and (16) of 

ExxonMobil’s 1998 exhibit. (See reference 

document GG for a copy of the exhibit.) 

assumption was that the flow and 

concentration monitoring devices 

installed to measure the gas stream to 

the primary process flare would also be 

able to measure the gas stream to the 

turnaround flare. However, we 

indicated that if that was not the case, 

ExxonMobil could propose another 

method to determine emissions from the 

turnaround flare. The final FIP is the 

same as proposed except for the flare 

monitoring changes applicable to all 

sources mentioned above. 

2. Compliance Monitoring of Refinery 

Fuel Gas Combustion Emission Limits 

We proposed a method for measuring 

the H2S concentrations in the refinery 

fuel gas when the H2S concentrations in 

the refinery fuel gas exceed the range of 

the H2S CEMS. The method we 

proposed is identical to the method 

included in CHS Inc.’s 1998 exhibit.16

Specifically, we proposed that within 

four hours of the initial determination 

that the H2S concentrations in the 

refinery fuel gas stream exceed the 

upper range of the H2S CEMS, 

ExxonMobil would have to initiate 

sampling of the refinery fuel gas stream 

at the fuel header on a once-per-3-hourperiod frequency using the Tutwiler 

method in 40 CFR 60.648. The Tutwiler 

method determines the H2S 

concentration in the refinery fuel gas. 

We also proposed that the Tutwilerderived H2S refinery fuel gas 

concentration be used in calculations to 

determine the hourly, 3-hour, and 24- 

hour SO2 emission rates, in pounds, 

from refinery fuel gas combustion. 

These emission rates would then be 

used to determine compliance with the 

refinery fuel gas combustion emission 

limits in ExxonMobil’s 1998 and 2000 

exhibits when the H2S concentrations in 

the refinery fuel gas stream exceeded 

the upper range of the H2S CEMS.17

In our final FIP we have revised the 

method by which ExxonMobil shall 

obtain the H2S concentration of the 

refinery fuel gas when the H2S 

concentrations in the refinery fuel gas 

exceed the range of the H2S CEMS. 

Specifically, our final FIP indicates that 

within four hours after the H2S CEMS 

measures an H2S concentration in the 

fuel gas stream greater than 1200 ppmv, 

ExxonMobil shall initiate sampling of 

the fuel gas stream at the fuel header on 

a once-per-hour-period frequency using 

length-of-stain detector tubes with the 

appropriate sample tube range. If the 

results exceed the tube’s range, another 

tube of a higher range must be used 

until results are in the tube’s range. 

ExxonMobil shall continue to use the 

length-of-stain detector tube method at 

this frequency until the H2S CEMS 

measures an H2S concentration in the 

fuel gas stream equal to or less than 

1200 ppmv continuously over a 3-hour 

period. We also revised the equation 

used to calculate the SO2 emissions 

because of the change in the H2S 

analysis method. 

We proposed reporting requirements 

similar to the requirements adopted by 

the State for CHS Inc. and those 

contained in 40 CFR 60.7(c). We added 

a provision that requires ExxonMobil to 

report information for periods when the 

range of the refinery fuel gas CEMS is 

exceeded. 

3. Compliance Monitoring of Coker CO 

Boiler Emission Limits 

We proposed that existing SO2 and 

flow CEMS, in conjunction with the 

appropriate calculations mentioned 

below, be used to determine compliance 

with the emission limits established in 

section 3(B)(1) of ExxonMobil’s 2000 

exhibit. Specifically, we proposed that 

at all times ExxonMobil operate and 

maintain CEMS to measure SO2

concentrations from the Coker CO Boiler 

stack and a continuous stack flow rate 

monitor to measure stack gas flow rates 

from the Coker CO Boiler stack. We 

proposed that the SO2 and flow rate 

CEMS meet the CEM Performance 

Specifications contained in sections 

6(C) and (D), respectively, of 

ExxonMobil’s 1998 exhibit, except that 

ExxonMobil would have to notify EPA 

in writing of each annual RATA a 

minimum of 25 working days prior to 

actual testing. 

Our final FIP is the same as proposed 

except that we have deleted the 

requirement that the flow and SO2

CEMS be operated at all times and 

added the requirement that whenever 

ExxonMobil’s Coker unit is operating 

and Coker unit flue gases are exhausted 

through the Coker CO Boiler stack, the 

flow and SO2 CEMS shall be 

immediately operational. We have also 

clarified that ExxonMobil shall meet the 

specifications contained in section 6(C) 

of ExxonMobil’s 1998 exhibit, except 

that ExxonMobil shall perform a 

Cylinder Gas Audit (CGA) or Relative 

Accuracy Audit (RAA) which meets the 

requirements of 40 CFR part 60, 

Appendix F, within eight hours of when 

the Coker unit flue gases begin 

exhausting through the Coker CO Boiler 

stack and that ExxonMobil shall 

perform an annual RATA on the flow 

and SO2 CEMS. 

We proposed that compliance with 

ExxonMobil’s Coker CO Boiler emission 

limits 18 be determined using the data 

from the CEMS mentioned above and in 

accordance with the appropriate 

calculations described in ExxonMobil’s 

1998 exhibit.19 We also proposed 

reporting requirements similar to the 

requirements adopted in the Billings/ 

Laurel SO2 SIP and those contained in 

40 CFR 60.7(c). Our final FIP is the same 

as proposed, except as noted above. 

E. Montana Sulphur & Chemical 

Company (MSCC) 

1. Flare Requirements 

We proposed that MSCC’s 80-foot 

west flare, 125-foot east flare, and 100- 

meter flare be limited to 150 pounds of 

SO2 per 3-hour period combined total 

and that compliance with the limit be 

determined as discussed above. Our 

final FIP is the same as proposed except 

for the flare monitoring changes 

applicable to all sources mentioned 

above. 

2. SRU 100-Meter Stack 

We proposed the following emission 

limits for the SRU 100-meter stack: 

Emissions of SO2 not to exceed (a) 

3,003.1 pounds per 3-hour period, (b) 

24,025.0 pounds per calendar day, and 

(c) 9,088,000.0 pounds per calendar 

year. Our final FIP is the same as 

proposed except that the 3-hour and 

calendar day emission limits have been 

slightly reduced due to minor 

corrections in the modeling. The final 

FIP emission limits for the SRU 100- 

meter stack are as follows: Emissions of 

SO2 shall not exceed (a) 2981.7 pounds 

per 3-hour period, (b) 23,853.6 pounds 

per calendar day, and (c) 9,088,000.0 

pounds per calendar year 

We proposed that compliance with 

the above emission limits be determined 

according to the methods established in 

MSCC’s 1998 exhibit. Finally, we 

proposed quarterly reporting 

requirements similar to the reporting 

requirements contained in the Billings/ 

Laurel SO2 SIP and those contained in 

40 CFR 60.7(c). Our final FIP is the same 

as proposed, except as noted above. 

3. SRU 30-Meter Stack 

We proposed the following mass 

emission limits for the 30-meter stack: 

Emissions of SO2 not to exceed: (a) 12.0 

pounds per 3-hour period, (b) 96.0 


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pounds per calendar day, and (c) 35,040 

pounds per calendar year. The mass 

emission limits remain the same as 

proposed. 

We proposed that H2S concentrations 

in the fuel burned in the boilers and 

heaters, while any boiler or heater was 

exhausting through the SRU 30-meter 

stack, be limited to 100 ppm of H2S or 

less, averaged over a 3-hour period. 

While we proposed the foregoing 

approach for determining compliance 

with the SRU 30-meter stack emission 

limits, we also solicited input on 

whether we should promulgate a 

different compliance determining 

method. 

In our final FIP, we are keeping the 

simplified method to determine 

compliance with mass emission limits. 

However, we are increasing the H2S 

concentration limit to 160 ppm/3-hour 

period and adding a calendar day H2S 

concentration limit of 100 ppm. 

We proposed that the H2S 

concentration in the fuel be measured 

using a portable H2S monitor. In our 

final FIP, we have revised the method 

by which MSCC shall determine the H2S 

content of the fuel burned. Specifically, 

our final FIP indicates that MSCC shall 

determine the H2S content of the fuel 

burned using length-of-stain detector 

tubes with the appropriate sample tube 

range. The final FIP indicates that if the 

results exceed the tube’s range, another 

tube of a higher range must be used 

until results are in the tube’s range. 

Finally, we proposed quarterly 

reporting requirements. The quarterly 

reporting requirements are similar to the 

reporting requirements contained in the 

Billings/Laurel SO2 SIP and those 

contained in 40 CFR 60.7(c). Our final 

FIP is the same as proposed, except as 

needed to address the changes noted 

above. 

4. Combined SO2 Emission Limit From 

the Auxiliary Vent Stacks 

We proposed the following mass 

emission limits for the auxiliary vent 

stacks: emissions of SO2 not to exceed: 

(a) 12.0 pounds per 3-hour period, (b) 

96.0 pounds per calendar day, and (c) 

35,040 pounds per calendar year. The 

mass emission limits remain the same as 

proposed. In our proposal, we indicated 

that the issues associated with 

monitoring compliance with these 

limits were essentially the same as those 

associated with monitoring compliance 

with the SRU 30-meter stack emission 

limits. Thus, we proposed the same 

approach for monitoring compliance 

with these emission limits as we 

describe in section III.E.3, above. 

Similarly, we solicited input on whether 

we should promulgate a different 

compliance determining method. 

In our final FIP, we are keeping the 

simplified method to determine 

compliance with mass emission limits. 

However, we are increasing the H2S 

concentration limit to 160 ppm/3-hour 

period and adding a calendar day H2S 

concentration limit of 100 ppm. 

We proposed that the H2S 

concentration in the fuel be measured 

using a portable H2S monitor. In our 

final FIP we have revised the method by 

which MSCC shall determine the H2S 

content of the fuel burned. Specifically, 

our final FIP indicates that MSCC shall 

determine the H2S content of the fuel 

burned using length-of-stain detector 

tubes with the appropriate sample tube 

range. The final FIP indicates that if the 

results exceed the tube’s range, another 

tube of a higher range must be used 

until results are in the tube’s range. 

Finally, we proposed quarterly 

reporting requirements similar to 

reporting requirements contained in the 

Billings/Laurel SO2 SIP and those 

contained in 40 CFR 60.7(c). Our final 

FIP is the same as proposed, except as 

noted above. 

F. Modeling To Support Emission Limits 

Our proposal discussed the modeling 

conducted to support the emission 

limits proposed for MSCC’s SRU 100- 

meter stack. EPA received comments 

regarding our modeling files that 

identified the need for minor technical 

corrections to those files. In response to 

several of these comments, EPA has 

revised its modeling files, as necessary, 

to omit extraneous information, add 

information that was inadvertently 

omitted, make minor corrections, or 

otherwise clarify the files. EPA does not 

consider any of the revisions to be 

significant. The only change with any 

substantive impact—the correction to 

the coordinates for MSCC described 

below—results in a very slight decrease 

in our proposed emission limit for 

MSCC’s 100-meter stack from 126.13 g/ 

second to125.23 g/second, less than a 1 

percent change. The specific changes 

EPA has made are as follows: 

(1) A commenter recommended that 

the modeling files contain a more 

complete description of the naming 

convention and purpose behind each 

modeling effort. 

EPA changes: To improve 

documentation, some extraneous 

modeling files have been removed and 

a text file added to explain the naming 

conventions. The naming conventions, 

typically used by modelers, help define 

the purpose behind each modeling 

effort. 

(2) One commenter indicated that 

only proper geographical coordinates 

should be used as inputs to the 

dispersion modeling. Commenters 

indicated that the location of the small 

boiler stacks at MSCC that were 

modeled as volume sources was 

incorrect. 

EPA changes: We have corrected the 

incorrect source coordinate for MSCC’s 

boiler stacks in the modeling files. 

(3) One commenter indicated that 

three source input files were not 

included in reference document EEE. 

EPA change: We have added the three 

source input files to the compact disk 

containing the modeling files. 

(4) One commenter indicated that a 

source input file (ref-5t.sri) was 

included in reference document EEE but 

did not appear to be used in any input 

and output files. 

EPA change: This was a test file that 

we inadvertently included and have 

now deleted. 

On July 13, 2007, the revised 

modeling files were indexed in the 

electronic docket contained on http:// 

www.regulations.gov and a compact 

disk containing the modeling files was 

placed in the docket for this action. See 

reference document FFFFF. 

Also, as noted above, with respect to 

the 30-meter stack and auxiliary vent 

stacks, we are keeping the simplified 

method to determine compliance with 

the mass emission limits. However, we 

are increasing the H2S concentration 

limit to 160 ppm/3-hour period and 

adding a calendar day H2S 

concentration limit of 100 ppm. The 

mass emission limits remain the same as 

proposed. 

We remodeled the area assuming the 

emissions were 1.01 g/s from the 30- 

meter stack and auxiliary vent stacks. 

We derived the higher emission value 

from the same assumptions and 

calculations expressed in our proposal, 

except we assumed a maximum H2S 

concentration of 160 ppm (see 71 FR 

39259, 39268, July 12, 2006). At the 

higher 3-hour emissions, the area would 

still show attainment of the 3-hour SO2

NAAQS. However, the area would not 

show attainment of the 24-hour SO2

NAAQS if all 8 3-hour periods in a 

calendar day were at the 160 ppm level. 

Therefore, we are revising the FIP to 

indicate that the H2S concentration in 

the fuel burned in the heaters and 

boilers, while any of the heaters and 

boilers are exhausting to the SRU 30- 

meter stack or auxiliary vents stacks, 

shall not exceed 160 ppm per 3-hour 

period and 100 ppm per calendar day. 

The revised modeling files are indexed 

in the electronic docket contained on 

http://www.regulations.gov, and a 


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compact disk containing the modeling 

files was placed in the docket for this 

action. See reference document 

KKKKKK. 

IV. Statutory and Executive Order 

Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review 

Under Executive Order 12866, 58 FR 

51735 (October 4, 1993), all ‘‘regulatory 

actions’’ that are ‘‘significant’’ are 

subject to Office of Management and 

Budget (OMB) review and the 

requirements of the Executive Order. A 

‘‘regulatory action’’ is defined as ‘‘any 

substantive action by an agency 

(normally published in the Federal 

Register) that promulgates or is 

expected to result in the promulgation 

of a final rule or regulation, including 

* * * notices of proposed rulemaking.’’

A ‘‘regulation or rule’’ is defined as ‘‘an 

agency statement of general 

applicability and future effect, * * * ’’

The FIP is not subject to OMB review 

under E.O. 12866 because it applies to 

only four specifically named facilities, 

with requirements unique to each 

facility, and is, therefore, not a rule of 

general applicability. Thus, it is not a 

‘‘regulatory action’’ under E.O. 12866 

and was not submitted to OMB for 

review. 

B. Paperwork Reduction Act 

This action does not impose an 

information collection burden under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. Burden is 

defined at 5 CFR 1320.3(b). Under the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq., OMB must approve all 

‘‘collections of information’’ by EPA. 

The Act defines ‘‘collection of 

information’’ as a requirement for 

‘‘answers to * * * identical reporting or 

recordkeeping requirements imposed on 

ten or more persons * * * ’’ 4 U.S.C. 

3502(3)(A). Because the FIP only applies 

to four companies, the Paperwork 

Reduction Act does not apply. 

C. Regulatory Flexibility Act 

Under the Regulatory Flexibility Act 

(RFA), 5 U.S.C. section 601 et seq., EPA 

generally must prepare a regulatory 

flexibility analysis of any rule subject to 

notice and comment rulemaking 

requirements unless EPA certifies that 

the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small not-forprofit enterprises, and small 

governmental jurisdictions. 5 U.S.C. 

603, 604, and 605(b). 

This FIP will not have a significant 

economic impact on a substantial 

number of small entities because this 

FIP applies to only four sources (CHS 

Inc., ConocoPhillips, ExxonMobil and 

MSCC) in the Billings/Laurel, Montana 

area. Therefore, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995, Public Law 04 4, 

establishes requirements for Federal 

agencies to assess the effects of their 

regulatory actions on State, local, and 

tribal governments and the private 

sector. Under section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost benefit 

analysis, for proposed rules and for final 

rules with ‘‘Federal mandates’’ that may 

result in the expenditure by State, local, 

and tribal governments, in the aggregate, 

or by the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most cost 

effective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 do not apply when they are 

inconsistent with applicable law. 

Moreover, section 205 allows EPA to 

adopt an alternative other than the least 

costly, most cost-effective or least 

burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that might 

significantly or uniquely affect small 

governments, including tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that this rule 

does not contain a Federal mandate that 

may result in the expenditure of $100 

million for State, local and tribal 

governments, in the aggregate, or the 

private sector in any one year. The FIP 

does not impose any enforceable duties 

on state, local, or tribal governments. 

Although the FIP would impose 

enforceable duties on entities in the 

private sector, the costs are expected to 

be less than $100 million in any one 

year. Thus, today’s rule is not subject to 

the requirements of 202 and 205 of the 

UMRA. 

EPA has determined that this rule 

contains no regulatory requirements that 

might significantly or uniquely affect 

small governments, because it imposes 

no requirements on small governments. 

Nor will the rule impact small 

governments in any significant or 

unique way. Thus, today’s rule is not 

subject to the requirements of section 

203 of the UMRA. 

E. Executive Order 13132, Federalism 

Executive Order, 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’

The final rule does not have 

federalism implications. It will not have 

substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This rule 

establishes standards appropriate for 

four companies in the Billings/Laurel, 

Montana area, and, thus, does not 

directly affect any State or local 

government. It does not alter the 

relationship or the distribution of power 

and responsibilities established by the 

Clean Air Act. Thus, Executive Order 

13132 does not apply to this rule. 

F. Executive Order 13175, Coordination 

With Indian Tribal Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This final rule does not 

have tribal implications, as specified in 

Executive Order 13175. It will not have 

substantial, direct effects on tribal 

governments, on the relationship 

between the Federal government and 

Indian tribes, or on the distribution of 

power and responsibilities between the 


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Federal government and Indian tribes as 

specified in Executive Order 13175. 

This Action does not involve or impose 

any requirements that affect Indian 

Tribes. Thus, Executive Order 13175 

does not apply to this rule. 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: ‘‘Protection of 

Children from Environmental Health 

Risks and Safety Risks’’ (62 FR 19885, 

April 23, 1997), applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866, and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. 

This FIP is not subject to the 

Executive Order because it is not 

economically significant as defined in 

Executive Order 12866. Further, EPA 

interprets Executive Order 13045 as 

applying only to those regulatory 

actions that are based on health or safety 

risks, such that the analysis required 

under section 5–501 of the Order has 

the potential to influence the regulation. 

This FIP is not subject to Executive 

Order 13045 because it implements a 

previously promulgated health and 

safety-based Federal standard. 

H. Executive Order 13211, Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not subject to Executive 

Order 13211, ‘‘Actions Concerning 

Regulations That Significantly Affect 

Energy Supply, Distribution, or Use’’ (66 

FR 28355, May 22, 2001) because it is 

not a significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act 

As noted in the proposed rule, 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995, Public Law No. 

104–113 (15 U.S.C. 272 note), directs 

EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards (VCS) are technical standards 

(e.g., materials specifications, test 

methods, sampling procedures, business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. The NTTAA directs EPA to 

provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary standards. 

This rulemaking involves technical 

standards. We have identified three VCS 

that can be used in lieu of EPA methods. 

The American Society for Testing and 

Materials (ASTM) Methods D4468–85 

(Reapproved 2000) and D5504–01 

(Reapproved 2006) are acceptable 

methods for determining total sulfur 

concentrations in the gas streams going 

to facility flares in lieu of using a 

continuous total sulfur analyzer in 

accordance with 40 CFR part 60, 

Appendix B, Performance Specification 

5. ASTM Method D4810–06 is an 

acceptable method for determining the 

hydrogen sulfide concentration in 

ExxonMobil’s refinery fuel gas in lieu of 

using the Tutwiler method described in 

40 CFR 60.648. We are incorporating 

these methods by reference in 40 CFR 

52.1392(j). 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this final 

rule will not have disproportionately 

high and adverse human health or 

environmental effects on minority or 

low-income populations because it 

increases the level of environmental 

protection for all affected populations 

without having any disproportionately 

high and adverse human health or 

environmental effects on any 

population, including any minority or 

low-income population. This final rule 

establishes emission limits and 

compliance determining methods at 

four sources in the Billings/Laurel, 

Montana area to assure that the SO2

NAAQS are met. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. section 801 et seq., as added by 

the Small Business Regulatory 

Enforcement Fairness Act of 1996, 

generally provides that before a rule 

may take effect, the agency 

promulgating the rule must submit a 

rule report, which includes a copy of 

the rule, to each House of the Congress 

and to the Comptroller General of the 

United States. Section 804 exempts from 

section 801 the following types of rules: 

(1) Rules of particular applicability; (2) 

rules relating to agency management or 

personnel; and (3) rules of agency 

organization, procedure, or practice that 

do not substantially affect the rights or 

obligations of non-agency parties. 5 

U.S.C. 804(3). EPA is not required to 

submit a rule report regarding today’s 

action under section 801 because this is 

a rule of particular applicability; it only 

applies to four specifically named 

sources, with requirements unique to 

each facility. 

L. Petitions for Judicial Review 

Under section 307(b)(1) of the Clean 

Air Act, petitions for judicial review of 

this action must be filed in the United 

States Court of Appeals for the 

appropriate circuit by June 20, 2008. 

Filing a petition for reconsideration by 

the Administrator of this final rule does 

not affect the finality of this rule for the 

purposes of judicial review nor does it 

extend the time within which a petition 

for judicial review may be filed, and 

shall not postpone the effectiveness of 

such rule or action. This action may not 

be challenged later in proceedings to 

enforce its requirements. (See CAA 

section 307(b)(2).) 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements, Sulfur oxides. 

Dated: March 28, 2008. 

Stephen L. Johnson, 

Administrator. 

■ For reasons stated in the preamble, 40 

CFR part 52 is 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 amended by adding 

§ 52.1392 to read as follows: 

§ 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 


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event of a change in ownership or 

operation, of the following facilities in 

the Billings/Laurel, Montana area: CHS 

Inc. Petroleum Refinery, Laurel 

Refinery, 803 Highway 212 South, 

Laurel, MT; ConocoPhillips Petroleum 

Refinery, Billings Refinery, 401 South 

23rd St., Billings, MT; ExxonMobil 

Petroleum Refinery, 700 Exxon Road, 

Billings, MT; and Montana Sulphur & 

Chemical Company, 627 Exxon Road, 

Billings, MT. 

(b) Scope. The facilities listed in 

paragraph (a) of this section are also 

subject to the Billings/Laurel SO2 SIP, as 

approved at 40 CFR 52.1370(c)(46) and 

(52). In cases where the provisions of 

this FIP address emissions activities 

differently or establish a different 

requirement than the provisions of the 

approved SIP, the provisions of this FIP 

take precedence. 

(c) Definitions. For the purpose of this 

section, we are defining certain words 

or initials as described in this 

paragraph. Terms not defined below 

that are defined in the Clean Air Act or 

regulations implementing the Clean Air 

Act, shall have the meaning set forth in 

the Clean Air Act or such regulations. 

(1) Aliquot means a fractional part of 

a sample that is an exact divisor of the 

whole sample. 

(2) Annual Emissions means the 

amount of SO2 emitted in a calendar 

year, expressed in pounds per year 

rounded to the nearest pound, where: 

Annual emissions = S Daily emissions 

within the calendar year. 

(3) Calendar Day means a 24-hour 

period starting at 12 midnight and 

ending at 12 midnight, 24 hours later. 

(4) Clock Hour means a twenty-fourth 

(1⁄24) of a calendar day; specifically any 

of the standard 60-minute periods in a 

day that are identified and separated on 

a clock by the whole numbers one (1) 

through 12. 

(5) Continuous Emission Monitoring 

System or CEMS means all continuous 

concentration and volumetric flow rate 

monitors, associated data acquisition 

equipment, and all other equipment 

necessary to meet the requirements of 

this section for continuous monitoring. 

(6) Daily Emissions means the amount 

of SO2 emitted in a calendar day, 

expressed in pounds per day rounded to 

the nearest tenth (1⁄10) of a pound, 

where: 

Daily emissions = S 3-hour emissions 

within a calendar day. 

(7) EPA means the United States 

Environmental Protection Agency. 

(8) Exhibit means for a given facility 

named in paragraph (a) of this section, 

exhibit A to the stipulation of the 

Montana Department of Environmental 

Quality and that facility, adopted by the 

Montana Board of Environmental 

Review on either June 12, 1998, or 

March 17, 2000. 

(9) 1998 Exhibit means for a given 

facility named in paragraph (a) of this 

section, the exhibit adopted by the 

Montana Board of Environmental 

Review on June 12, 1998. 

(10) 2000 Exhibit means for a given 

facility named in paragraph (a) of this 

section, the exhibit adopted by the 

Montana Board of Environmental 

Review on March 17, 2000. 

(11) Flare means a combustion device 

that uses an open flame to burn 

combustible gases with combustion air 

provided by uncontrolled ambient air 

around the flame. This term includes 

both ground and elevated flares. 

(12) The initials Hg mean mercury. 

(13) Hourly means or refers to each 

clock hour in a calendar day. 

(14) Hourly Average means an 

arithmetic average of all valid and 

complete 15-minute data blocks in a 

clock hour. Four (4) valid and complete 

15-minute data blocks are required to 

determine an hourly average for each 

CEMS per clock hour. 

Exclusive of the above definition, an 

hourly CEMS average may be 

determined with two (2) valid and 

complete 15-minute data blocks, for two 

(2) of the 24 hours in any calendar day. 

A complete 15-minute data block for 

each CEMS shall have a minimum of 

one (1) data point value; however, each 

CEMS shall be operated such that all 

valid data points acquired in any 15- 

minute block shall be used to determine 

the 15-minute block’s reported 

concentration and flow rate. 

(15) Hourly Emissions means the 

pounds per clock hour of SO2 emissions 

from a source (including, but not 

limited to, a flare, stack, fuel oil system, 

sour water system, or fuel gas system) 

determined using hourly averages and 

rounded to the nearest tenth (1⁄10) of a 

pound. 

(16) The initials H2S mean hydrogen 

sulfide. 

(17) Integrated sampling means an 

automated method of obtaining a 

sample from the gas stream to the flare 

that produces a composite sample of 

individual aliquots taken over time. 

(18) The initials MBER mean the 

Montana Board of Environmental 

Review. 

(19) The initials MDEQ mean the 

Montana Department of Environmental 

Quality. 

(20) The initials mm mean 

millimeters. 

(21) The initials MSCC mean the 

Montana Sulphur & Chemical Company. 

(22) Pilot gas means the gas used to 

maintain the presence of a flame for 

ignition of gases routed to a flare. 

(23) Purge gas means a continuous gas 

stream introduced into a flare header, 

flare stack, and/or flare tip for the 

purpose of maintaining a positive flow 

that prevents the formation of an 

explosive mixture due to ambient air 

ingress. 

(24) The initials ppm mean parts per 

million. 

(25) The initials SCFH mean standard 

cubic feet per hour. 

(26) The initials SCFM mean standard 

cubic feet per minute. 

(27) Standard Conditions means (a) 20 

°C (293.2 °K, 527.7 °R, or 68.0 °F) and 

one (1) atmosphere pressure (29.92 

inches Hg or 760 mm Hg) for stack and 

flare gas emission calculations, and (b) 

15.6 °C (288.7 °K, 520.0 °R, or 60.3 °F) 

and one (1) atmosphere pressure (29.92 

inches Hg or 760 mm Hg) for refinery 

fuel gas emission calculations. 

(28) The initials SO2 mean sulfur 

dioxide. 

(29) The initials SWS mean sour water 

stripper. 

(30) The term 3-hour emissions means 

the amount of SO2 emitted in each of 

the eight (8) non-overlapping 3-hour 

periods in a calendar day, expressed in 

pounds and rounded to the nearest 

tenth (1⁄10) of a pound, where: 

3 hour emissions = Σ Hourly emissions 

within the 3-hour period. 

(31) The term 3-hour period means 

any of the eight (8) non-overlapping 3- 

hour periods in a calendar day: 

Midnight to 3 a.m., 3 a.m. to 6 a.m., 6 

a.m. to 9 a.m., 9 a.m. to noon, noon to 

3 p.m., 3 p.m. to 6 p.m., 6 p.m. to 9 

p.m., 9 p.m. to midnight. 

(32) Turnaround means a planned 

activity involving shutdown and startup 

of one or several process units for the 

purpose of performing periodic 

maintenance, repair, replacement of 

equipment, or installation of new 

equipment. 

(33) Valid means data that are 

obtained from a monitor or meter 

serving as a component of a CEMS 

which meets the applicable 

specifications, operating requirements, 

and quality assurance and control 

requirements of section 6 of 

ConocoPhillips’, CHS Inc.’s, 

ExxonMobil’s, and MSCC’s 1998 

exhibits, respectively, and this section. 

(d) CHS Inc. emission limits and 

compliance determining methods. 

(1) Introduction. The provisions for 

CHS Inc. cover the following units: 

(i) The flare. 

(ii) Combustion sources, which 

consist of those sources identified in the 


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combustion sources emission limit in 

section 3(A)(1)(d) of CHS Inc.’s 1998 

exhibit. 

(2) Flare requirements. 

(i) Emission limit. The total emissions 

of SO2 from the flare shall not exceed 

150.0 pounds per 3-hour period. 

(ii) Compliance determining method. 

Compliance with the emission limit in 

paragraph (d)(2)(i) of this section shall 

be determined in accordance with 

paragraph (h) of this section. 

(3) Combustion sources. 

(i) Restrictions. Sour water stripper 

overheads (ammonia (NH3) and H2S 

gases removed from the sour water in 

the sour water stripper) shall not be 

burned in the main crude heater. At all 

times, CHS Inc. shall keep a chain and 

lock on the valve that supplies sour 

water stripper overheads from the old 

sour water stripper to the main crude 

heater and shall keep such valve closed. 

(ii) Compliance determining method. 

CHS Inc. shall log and report any 

noncompliance with the requirements 

of paragraph (d)(3)(i) of this section. 

(4) Data reporting requirements. 

(i) CHS Inc. shall submit quarterly 

reports beginning with the first calendar 

quarter following May 21, 2008. The 

quarterly reports shall be submitted 

within 30 days of the end of each 

calendar quarter. The quarterly reports 

shall be submitted to EPA at the 

following address: Air Program Contact, 

EPA Montana Operations Office, 

Federal Building, 10 West 15th Street, 

Suite 3200, Helena, MT 59626. 

The quarterly report shall be certified 

for accuracy in writing by a responsible 

CHS Inc. official. The quarterly report 

shall consist of both a comprehensive 

electronic-magnetic report and a written 

hard copy data summary report. 

(ii) The electronic report shall be on 

magnetic or optical media, and such 

submittal shall follow the reporting 

format of electronic data being 

submitted to the MDEQ. EPA may 

modify the reporting format delineated 

in this section, and, thereafter, CHS Inc. 

shall follow the revised format. In 

addition to submitting the electronic 

quarterly reports to EPA, CHS Inc. shall 

also record, organize, and archive for at 

least five (5) years the same data, and 

upon request by EPA, CHS Inc. shall 

provide EPA with any data archived in 

accordance with this provision. The 

electronic report shall contain the 

following: 

(A) Hourly average total sulfur 

concentrations as H2S or SO2 in ppm in 

the gas stream to the flare; 

(B) Hourly average H2S concentrations 

of the flare pilot and purge gases in 

ppm; 

(C) Hourly average volumetric flow 

rates in SCFH of the gas stream to the 

flare; 

(D) Hourly average volumetric flow 

rates in SCFH of the flare pilot and 

purge gases; 

(E) Hourly average temperature (in °F) 

and pressure (in mm or inches of Hg) of 

the gas stream to the flare; 

(F) Hourly emissions from the flare in 

pounds per clock hour; and 

(G) Daily calibration data for all flare, 

pilot gas, and purge gas CEMS. 

(iii) The quarterly written report shall 

contain the following information: 

(A) The 3-hour emissions in pounds 

per 3-hour period from each flare; 

(B) Periods in which only natural gas 

or an inert gas was used as flare pilot 

gas or purge gas or both; 

(C) The results of all quarterly 

Cylinder Gas Audits (CGA), Relative 

Accuracy Audits (RAA), and annual 

Relative Accuracy Test Audits (RATA) 

for all total sulfur analyzer(s) and H2S 

analyzer(s), and the results of all annual 

calibrations and verifications for the 

volumetric flow, temperature, and 

pressure monitors; 

(D) For all periods of flare volumetric 

flow rate monitoring system or total 

sulfur analyzer system downtime, flare 

pilot gas or purge gas volumetric flow or 

H2S analyzer system downtime, or 

failure to obtain or analyze a grab or 

integrated sample, the written report 

shall identify: 

(1) Dates and times of downtime or 

failure; 

(2) Reasons for downtime or failure; 

(3) Corrective actions taken to 

mitigate downtime or failure; and 

(4) The other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, used to determine flare 

emissions; 

(E) For all periods that the range of 

the flare or any pilot or purge gas 

volumetric flow rate monitor(s), any 

flare total sulfur analyzer(s), or any pilot 

or purge gas H2S analyzer(s) is 

exceeded, the written report shall 

identify: 

(1) Date and time when the range of 

the volumetric flow monitor(s), total 

sulfur analyzer(s), or H2S analyzer(s) 

was exceeded; and 

(2) The other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, used to determine flare 

emissions; 

(F) For all periods that the flare 

volumetric flow monitor or monitors are 

recording flow, yet any Flare Water Seal 

Monitoring Device indicates there is no 

flow, the written report shall identify: 

(1) Date, time, and duration when the 

flare volumetric flow monitor(s) 

recorded flow, yet any Flare Water Seal 

Monitoring Device indicated there was 

no flow; 

(G) For each 3-hour period in which 

the flare emission limit is exceeded, the 

written report shall identify: 

(1) The date, start time, and end time 

of the excess emissions; 

(2) Total hours of operation with 

excess emissions, the hourly emissions, 

and the 3-hour emissions; 

(3) All information regarding reasons 

for operating with excess emissions; and 

(4) Corrective actions taken to 

mitigate excess emissions; 

(H) The date and time of any 

noncompliance with the requirements 

of paragraph (d)(3)(i) of this section; and 

(I) When no excess emissions have 

occurred or the continuous monitoring 

system(s) or manual system(s) have not 

been inoperative, repaired, or adjusted, 

such information shall be stated in the 

report. 

(e) ConocoPhillips emission limits 

and compliance determining methods. 

(1) Introduction. The provisions for 

ConocoPhillips cover the following 

units: 

(i) The main flare, which consists of 

two flares—the north flare and the south 

flare—that are operated on alternating 

schedules. These flares are referred to 

herein as the north main flare and south 

main flare, or generically as the main 

flare. 

(ii) The Jupiter Sulfur SRU flare, 

which is the flare at Jupiter Sulfur, 

ConocoPhillips’ sulfur recovery unit. 

(2) Flare requirements. 

(i) Emission limits. 

(A) Combined emissions of SO2 from 

the main flare (which can be emitted 

from either the north or south main 

flare, but not both at the same time) 

shall not exceed 150.0 pounds per 3- 

hour period. 

(B) Emissions of SO2 from the Jupiter 

Sulfur SRU flare and the Jupiter Sulfur 

SRU/ATS stack (also referred to as the 

Jupiter Sulfur SRU stack) shall not 

exceed 75.0 pounds per 3-hour period, 

600.0 pounds per calendar day, and 

219,000 pounds per calendar year. 

(ii) Compliance determining method. 

(A) Compliance with the emission 

limit in paragraph (e)(2)(i)(A) of this 

section shall be determined in 

accordance with paragraph (h) of this 

section. In the event that a single 

monitoring location cannot be used for 

both the north and south main flare, 

ConocoPhillips shall monitor the flow 

and measure the total sulfur 

concentration at more than one location 

in order to determine compliance with 

the main flare emission limit. 

ConocoPhillips shall log and report any 

instances when emissions are vented 


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from the north main flare and south 

main flare simultaneously. 

(B) Compliance with the emission 

limits and requirements in paragraph 

(e)(2)(i)(B) of this section shall be 

determined by summing the emissions 

from the Jupiter Sulfur SRU flare and 

SRU/ATS stack. Emissions from the 

Jupiter Sulfur SRU flare shall be 

determined in accordance with 

paragraph (h) of this section and the 

emissions from the Jupiter Sulfur SRU/ 

ATS stack shall be determined pursuant 

to ConocoPhillips’ 1998 exhibit (see 

section 4(A) of the exhibit). 

(3) Data reporting requirements. 

(i) ConocoPhillips shall submit 

quarterly reports on a calendar year 

basis, beginning with the first calendar 

quarter following May 21, 2008. The 

quarterly reports shall be submitted 

within 30 days of the end of each 

calendar quarter. The quarterly reports 

shall be submitted to EPA at the 

following address: Air Program Contact, 

EPA Montana Operations Office, 

Federal Building, 10 West 15th Street, 

Suite 3200, Helena, MT 59626. 

The quarterly report shall be certified 

for accuracy in writing by a responsible 

ConocoPhillips official. The quarterly 

report shall consist of both a 

comprehensive electronic-magnetic 

report and a written hard copy data 

summary report. 

(ii) The electronic report shall be on 

magnetic or optical media, and such 

submittal shall follow the reporting 

format of electronic data being 

submitted to the MDEQ. EPA may 

modify the reporting format delineated 

in this section, and, thereafter, 

ConocoPhillips shall follow the revised 

format. In addition to submitting the 

electronic quarterly reports to EPA, 

ConocoPhillips shall also record, 

organize, and archive for at least five (5) 

years the same data, and upon request 

by EPA, ConocoPhillips shall provide 

EPA with any data archived in 

accordance with this provision. The 

electronic report shall contain the 

following: 

(A) Hourly average total sulfur 

concentrations as H2S or SO2 in ppm in 

the gas stream to the ConocoPhillips 

main flare and Jupiter Sulfur SRU flare; 

(B) Hourly average H2S concentrations 

of the ConocoPhillips main flare and 

Jupiter Sulfur SRU flare pilot and purge 

gases in ppm; 

(C) Hourly average volumetric flow 

rates in SCFH of the gas streams to the 

ConocoPhillips main flare and Jupiter 

Sulfur SRU flare; 

(D) Hourly average volumetric flow 

rates in SCFH of the ConocoPhillips 

main flare and Jupiter Sulfur SRU flare 

pilot and purge gases; 

(E) Hourly average temperature (in °F) 

and pressure (in mm or inches of Hg) of 

the gas streams to the ConocoPhillips 

main flare and Jupiter Sulfur SRU flare; 

(F) Hourly emissions in pounds per 

clock hour from the ConocoPhillips 

main flare and Jupiter Sulfur SRU flare; 

and 

(G) Daily calibration data for all flare, 

pilot gas, and purge gas CEMS. 

(iii) The quarterly written report shall 

contain the following information: 

(A) The 3-hour emissions in pounds 

per 3-hour period from the 

ConocoPhillips main flare and the sum 

of the combined 3-hour emissions from 

the Jupiter Sulfur SRU/ATS stack and 

Jupiter Sulfur SRU flare in pounds per 

3-hour period; 

(B) Periods in which only natural gas 

or an inert gas was used as flare pilot 

gas or purge gas or both; 

(C) The results of all quarterly 

Cylinder Gas Audits (CGA), Relative 

Accuracy Audits (RAA), and annual 

Relative Accuracy Test Audits (RATA) 

for all total sulfur analyzer(s) and H2S 

analyzer(s), and the results of all annual 

calibrations and verifications for the 

volumetric flow, temperature, and 

pressure monitors; 

(D) For all periods of flare volumetric 

flow rate monitoring system or total 

sulfur analyzer system downtime, flare 

pilot gas or purge gas volumetric flow or 

H2S analyzer system downtime, or 

failure to obtain or analyze a grab or 

integrated sample, the written report 

shall identify: 

(1) Dates and times of downtime or 

failure; 

(2) Reasons for downtime or failure; 

(3) Corrective actions taken to 

mitigate downtime or failure; and 

(4) The other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, used to determine flare 

emissions; 

(E) For all periods that the range of 

the flare or any pilot or purge gas 

volumetric flow rate monitor(s), any 

flare total sulfur analyzer(s), or any pilot 

or purge gas H2S analyzer(s) is 

exceeded, the written report shall 

identify: 

(1) Date and time when the range of 

the volumetric flow monitor(s), total 

sulfur analyzer(s), or H2S analyzer(s) 

was exceeded, and 

(2) The other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, used to determine flare 

emissions; 

(F) For all periods that the flare 

volumetric flow monitor or monitors are 

recording flow, yet any Flare Water Seal 

Monitoring Device indicates there is no 

flow, the written report shall identify: 

(1) Date, time, and duration when the 

flare volumetric flow monitor(s) 

recorded flow, yet any Flare Water Seal 

Monitoring Device indicated there was 

no flow; 

(G) Identification of dates, times, and 

duration of any instances when 

emissions were vented from the north 

and south main flares simultaneously; 

(H) For each 3-hour period in which 

a flare emission limit is exceeded, the 

written report shall identify: 

(1) The date, start time, and end time 

of the excess emissions; 

(2) Total hours of operation with 

excess emissions, the hourly emissions, 

and the 3-hour emissions; 

(3) All information regarding reasons 

for operating with excess emissions; and 

(4) Corrective actions taken to 

mitigate excess emissions; and 

(I) When no excess emissions have 

occurred or the continuous monitoring 

system(s) or manual system(s) have not 

been inoperative, repaired, or adjusted, 

such information shall be stated in the 

report. 

(f) ExxonMobil emission limits and 

compliance determining methods. 

(1) Introduction. The provisions for 

ExxonMobil cover the following units: 

(i) The Primary process flare and the 

Turnaround flare. The Primary process 

flare is the flare normally used by 

ExxonMobil. The Turnaround flare is 

the flare ExxonMobil uses for about 30 

to 40 days every 5 to 6 years when the 

facility’s major SO2 source, the fluid 

catalytic cracking unit, is not normally 

operating. 

(ii) The following refinery fuel gas 

combustion units: The FCC CO Boiler, 

F–2 crude/vacuum heater, F–3 unit, F–

3X unit, F–5 unit, F–700 unit, F–201 

unit, F–202 unit, F–402 unit, F–551 

unit, F–651 unit, standby boiler house 

(B–8 boiler), and Coker CO Boiler (only 

when the Yellowstone Energy Limited 

Partnership (YELP) facility is receiving 

ExxonMobil Coker unit flue gas or 

whenever the ExxonMobil Coker is not 

operating). 

(iii) Coker CO Boiler stack. 

(2) Flare requirements. 

(i) Emission limit. The total combined 

emissions of SO2 from the Primary 

process and Turnaround refinery flares 

shall not exceed 150.0 pounds per 3- 

hour period. 

(ii) Compliance determining method. 

Compliance with the emission limit in 

paragraph (f)(2)(i) of this section shall be 

determined in accordance with 

paragraph (h) of this section. If 

volumetric flow monitoring device(s) 

installed and concentration monitoring 

methods used to measure the gas stream 


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to the Primary Process flare cannot 

measure the gas stream to the 

Turnaround flare, ExxonMobil may 

apply to EPA for alternative measures to 

determine the volumetric flow rate and 

total sulfur concentration of the gas 

stream to the Turnaround flare. Before 

EPA will approve such alternative 

measures, ExxonMobil must agree that 

the Turnaround flare will be used only 

during refinery turnarounds of limited 

duration and frequency—no more than 

60 days once every five (5) years—

which restriction shall be considered an 

enforceable part of this FIP. Such 

alternative measures may consist of 

reliable flow estimation parameters to 

estimate volumetric flow rate and 

manual sampling of the gas stream to 

the flare to determine total sulfur 

concentrations, or such other measures 

that EPA finds will provide accurate 

estimations of SO2 emissions from the 

Turnaround flare. 

(3) Refinery fuel gas combustion 

requirements. 

(i) Emission limits. The applicable 

emission limits are contained in section 

3(A)(1) of ExxonMobil’s 2000 exhibit 

and section 3(B)(2) of ExxonMobil’s 

1998 exhibit. 

(ii) Compliance determining method. 

For the limits referenced in paragraph 

(f)(3)(i) of this section, the compliance 

determining methods specified in 

section 4(B) of ExxonMobil’s 1998 

exhibit shall be followed except when 

the H2S concentration in the refinery 

fuel gas stream exceeds 1200 ppmv as 

measured by the H2S CEMS required by 

section 6(B)(3) of ExxonMobil’s 1998 

exhibit (the H2S CEMS.) When such 

value is exceeded, the following 

compliance monitoring method shall be 

employed: 

(A) ExxonMobil shall measure the 

H2S concentration in the refinery fuel 

gas according to the procedures in 

paragraph (f)(3)(ii)(B) of this section and 

calculate the emissions according to the 

equations in paragraph (f)(3)(ii)(C) of 

this section. 

(B) Within four (4) hours after the H2S 

CEMS measures an H2S concentration in 

the refinery fuel gas stream greater than 

1200 ppmv, ExxonMobil shall initiate 

sampling of the refinery fuel gas stream 

at the fuel header on a once-per-hour 

frequency using length-of-stain detector 

tubes pursuant to ASTM Method 

D4810–06, ‘‘Standard Test Method for 

Hydrogen Sulfide in Natural Gas Using 

Length-of-Stain Detector Tubes’’

(incorporated by reference, see 

paragraph (j) of this section) with the 

appropriate sample tube range. If the 

results exceed the tube’s range, another 

tube of a higher range must be used 

until results are in the tube’s range. 

ExxonMobil shall continue to use the 

length-of-stain detector tube method at 

this frequency until the H2S CEMS 

measures an H2S concentration in the 

refinery fuel gas stream equal to or less 

than 1200 ppmv continuously over a 3- 

hour period. 

(C) When the length-of-stain detector 

tube method is required, SO2 emissions 

from refinery fuel gas combustion shall 

be calculated as follows: the Hourly 

emissions shall be calculated using 

equation 1, 3-hour emissions shall be 

calculated using equation 2, and the 

Daily emissions shall be calculated 

using equation 3. 

Equation 1: EH = K * CH * QH

Where: 

EH = Refinery fuel gas combustion hourly 

emissions in pounds per hour, rounded 

to the nearest tenth of a pound; 

K= 1.688 × 10-7 in (pounds/standard cubic 

feet (SCF))/parts per million (ppm); 

CH = Hourly refinery fuel gas H2S 

concentration in ppm determined by the 

length-of-stain detector tube method as 

required by paragraph (f)(3)(ii)(B) of this 

section; and 

QH = actual fuel gas firing rate in standard 

cubic feet per hour (SCFH), as measured 

by the monitor required by section 

6(B)(8) of ExxonMobil’s 1998 exhibit. 

Equation 2: (Refinery fuel gas 

combustion 3-hour emissions) = Σ 

(Hourly emissions within the 3- 

hour period as determined by 

equation 1). 

Equation 3: (Refinery fuel gas 

combustion daily emissions) = Σ (3- 

hour emissions within the day as 

determined by equation 2). 

(4) Coker CO Boiler stack 

requirements. 

(i) Emission limits. When 

ExxonMobil’s Coker unit is operating 

and Coker unit flue gases are burned in 

the Coker CO Boiler, the applicable 

emission limits are contained in section 

3(B)(1) of ExxonMobil’s 2000 exhibit. 

(ii) Compliance determining method. 

(A) Compliance with the emission 

limits referenced in paragraph (f)(4)(i) of 

this section shall be determined by 

measuring the SO2 concentration and 

flow rate in the Coker CO Boiler stack 

according to the procedures in 

paragraphs (f)(4)(ii)(B) and (C) of this 

section and calculating emissions 

according to the equations in paragraph 

(f)(4)(ii)(D) of this section. 

(B) Beginning on May 21, 2008, 

ExxonMobil shall operate and maintain 

a CEMS to measure sulfur dioxide 

concentrations in the Coker CO Boiler 

stack. Whenever ExxonMobil’s Coker 

unit is operating and Coker unit flue 

gases are exhausted through the Coker 

CO Boiler stack, the CEMS shall be 

operational and shall achieve a temporal 

sampling resolution of at least one (1) 

concentration measurement per minute, 

meet the requirements expressed in the 

definition of ‘‘hourly average’’ in 

paragraph (c)(14) of this section, and 

meet the CEMS Performance 

Specifications contained in section 6(C) 

of ExxonMobil’s 1998 exhibit, except 

that ExxonMobil shall perform a 

Cylinder Gas Audit (CGA) or Relative 

Accuracy Audit (RAA) which meets the 

requirements of 40 CFR part 60, 

Appendix F, within eight (8) hours of 

when the Coker unit flue gases begin 

exhausting through the Coker CO Boiler 

stack. ExxonMobil shall perform an 

annual Relative Accuracy Test Audit 

(RATA) on the CEMS and notify EPA in 

writing of each annual RATA a 

minimum of 25 working days prior to 

actual testing. 

(C) Beginning on May 21, 2008, 

ExxonMobil shall operate and maintain 

a continuous stack flow rate monitor to 

measure the stack gas flow rates in the 

Coker CO Boiler stack. Whenever 

ExxonMobil’s Coker unit is operating 

and Coker unit flue gases are exhausted 

through the Coker CO Boiler stack, this 

CEMS shall be operational and shall 

achieve a temporal sampling resolution 

of at least one (1) flow rate measurement 

per minute, meet the requirements 

expressed in the definition of ‘‘hourly 

average’’ in paragraph (c)(14) of this 

section, and meet the Stack Gas Flow 

Rate Monitor Performance 

Specifications of section 6(D) of 

ExxonMobil’s 1998 exhibit, except that 

ExxonMobil shall perform an annual 

Relative Accuracy Test Audit (RATA) 

on the CEMS and notify EPA in writing 

of each annual RATA a minimum of 25 

working days prior to actual testing. 

(D) SO2 emissions from the Coker CO 

Boiler stack shall be determined in 

accordance with the equations in 

sections 2(A)(1), (8), (11)(a), and (16) of 

ExxonMobil’s 1998 exhibit. 

(5) Data reporting requirements. 

(i) ExxonMobil shall submit quarterly 

reports beginning with the first calendar 

quarter following May 21, 2008. The 

quarterly reports shall be submitted 

within 30 days of the end of each 

calendar quarter. The quarterly reports 

shall be submitted to EPA at the 

following address: Air Program Contact, 

EPA Montana Operations Office, 

Federal Building, 10 West 15th Street, 

Suite 3200, Helena, MT 59626. 

The quarterly report shall be certified 

for accuracy in writing by a responsible 

ExxonMobil official. The quarterly 

report shall consist of both a 

comprehensive electronic-magnetic 

report and a written hard copy data 

summary report. 


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(ii) The electronic report shall be on 

magnetic or optical media, and such 

submittal shall follow the reporting 

format of electronic data being 

submitted to the MDEQ. EPA may 

modify the reporting format delineated 

in this section, and, thereafter, 

ExxonMobil shall follow the revised 

format. In addition to submitting the 

electronic quarterly reports to EPA, 

ExxonMobil shall also record, organize, 

and archive for at least five (5) years the 

same data, and upon request by EPA, 

ExxonMobil shall provide EPA with any 

data archived in accordance with this 

provision. The electronic report shall 

contain the following: 

(A) Hourly average total sulfur 

concentrations as H2S or SO2 in ppm in 

the gas stream to the flare(s); 

(B) Hourly average H2S concentrations 

of the flare pilot and purge gases in 

ppm; 

(C) Hourly average SO2 concentrations 

in ppm from the Coker CO Boiler stack; 

(D) Hourly average volumetric flow 

rates in SCFH of the flare pilot and 

purge gases; 

(E) Hourly average volumetric flow 

rates in SCFH in the gas stream to the 

flare(s) and in the Coker CO Boiler 

stack; 

(F) Hourly average H2S concentrations 

in ppm from the refinery fuel gas 

system; 

(G) Hourly average refinery fuel gas 

combustion units’ actual fuel firing rate 

in SCFH; 

(H) Hourly average temperature (in °F) 

and pressure (in mm or inches of Hg) of 

the gas stream to the flare(s); 

(I) Hourly emissions in pounds per 

clock hour from the flare(s), Coker CO 

Boiler stack, and refinery fuel gas 

combustion system; and 

(J) Daily calibration data for the CEMS 

described in paragraphs (f)(2)(ii), 

(f)(3)(ii) and (f)(4)(ii) of this section. 

(iii) The quarterly written report shall 

contain the following information: 

(A) The 3-hour emissions in pounds 

per 3-hour period from the flare(s), 

Coker CO Boiler stack, and refinery fuel 

gas combustion system; 

(B) Periods in which only natural gas 

or an inert gas was used as flare pilot 

gas or purge gas or both; 

(C) Daily emissions in pounds per 

calendar day from the Coker CO Boiler 

stack and refinery fuel gas combustion 

system; 

(D) The results of all quarterly or 

other Cylinder Gas Audits (CGA), 

Relative Accuracy Audits (RAA), and 

annual Relative Accuracy Test Audits 

(RATA) for the CEMS described in 

paragraphs (f)(2)(ii) (flare total sulfur 

analyzer(s); pilot gas or purge gas H2S 

analyzer(s)), (f)(3)(ii), and (f)(4)(ii) of 

this section, and the results of all annual 

calibrations and verifications for the 

volumetric flow, temperature, and 

pressure monitors; 

(E) For all periods of flare volumetric 

flow rate monitoring system or total 

sulfur analyzer system downtime, Coker 

CO Boiler stack CEMS downtime, 

refinery fuel gas combustion system 

CEMS downtime, flare pilot gas or purge 

gas volumetric flow or H2S analyzer 

system downtime, or failure to obtain or 

analyze a grab or integrated sample, the 

written report shall identify: 

(1) Dates and times of downtime or 

failure; 

(2) Reasons for downtime or failure; 

(3) Corrective actions taken to 

mitigate downtime or failure; and 

(4) The other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, used to determine flare 

emissions; 

(F) For all periods that the range of 

the flare or any pilot or purge gas 

volumetric flow rate monitor(s), any 

flare total sulfur analyzer(s), or any pilot 

or purge gas H2S analyzer(s) is 

exceeded, the written report shall 

identify: 

(1) Date and time when the range of 

the volumetric flow monitor(s), total 

sulfur analyzer(s), or H2S analyzer(s) 

was exceeded, and 

(2) The other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, used to determine flare 

emissions; 

(G) For all periods that the range of 

the refinery fuel gas CEMS is exceeded, 

the written report shall identify: 

(1) Date, time, and duration when the 

range of the refinery fuel gas CEMS was 

exceeded; 

(H) For all periods that the flare 

volumetric flow monitor or monitors are 

recording flow, yet any Flare Water Seal 

Monitoring Device indicates there is no 

flow, the written report shall identify: 

(1) Date, time, and duration when the 

flare volumetric flow monitor(s) 

recorded flow, yet any Flare Water Seal 

Monitoring Device indicated there was 

no flow; 

(I) For each 3-hour period and 

calendar day in which the flare 

emission limits, the Coker CO Boiler 

stack emission limits, or the fuel gas 

combustion system emission limits are 

exceeded, the written report shall 

identify: 

(1) The date, start time, and end time 

of the excess emissions; 

(2) Total hours of operation with 

excess emissions, the hourly emissions, 

the 3-hour emissions, and the daily 

emissions; 

(3) All information regarding reasons 

for operating with excess emissions; and 

(4) Corrective actions taken to 

mitigate excess emissions; and 

(J) When no excess emissions have 

occurred or the continuous monitoring 

system(s) or manual system(s) have not 

been inoperative, repaired, or adjusted, 

such information shall be stated in the 

report. 

(g) Montana Sulphur & Chemical 

Company (MSCC) emission limits and 

compliance determining methods. 

(1) Introduction. The provisions for 

MSCC cover the following units: 

(i) The flares, which consist of the 80- 

foot west flare, 125-foot east flare, and 

100-meter flare. 

(ii) The SRU 100-meter stack. 

(iii) The auxiliary vent stacks and the 

units that can exhaust through the 

auxiliary vent stacks, which consist of 

the Railroad Boiler, the H–1 Unit, the 

H1–A unit, the H1–1 unit and the H1–

2 unit. 

(iv) The SRU 30-meter stack and the 

units that can exhaust through the SRU 

30-meter stack. The units that can 

exhaust through the SRU 30-meter stack 

are identified in section 3(A)(2)(d) and 

(e) of MSCC’s 1998 exhibit. 

(2) Flare requirements. 

(i) Emission limit. Total combined 

emissions of SO2 from the 80-foot west 

flare, 125-foot east flare, and 100-meter 

flare shall not exceed 150.0 pounds per 

3-hour period. 

(ii) Compliance determining method. 

Compliance with the emission limit in 

paragraph (g)(2)(i) of this section shall 

be determined in accordance with 

paragraph (h) of this section. In the 

event MSCC cannot monitor all three 

flares from a single location, MSCC shall 

establish multiple monitoring locations. 

(3) SRU 100-meter stack 

requirements. 

(i) Emission limits. Emissions of SO2

from the SRU 100-meter stack shall not 

exceed: 

(A) 2,981.7 pounds per 3-hour period; 

(B) 23,853.6 pounds per calendar day; 

and 

(C) 9,088,000 pounds per calendar 

year. 

(ii) Compliance determining method. 

(A) Compliance with the emission 

limits contained in paragraph (g)(3)(i) of 

this section shall be determined by the 

CEMS and emission testing methods 

required by sections 6(B)(1) and (2) and 

section 5, respectively, of MSCC’s 1998 

exhibit. 

(B) MSCC shall notify EPA in writing 

of each annual source test a minimum 

of 25 working days prior to actual 

testing. 

(C) The CEMS referenced in 

paragraph (g)(3)(ii)(A) of this section 


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shall achieve a temporal sampling 

resolution of at least one (1) 

concentration and flow rate 

measurement per minute, meet the 

requirements expressed in the definition 

of ‘‘hourly average’’ in paragraph (c)(14) 

of this section, and meet the ‘‘CEM 

Performance Specifications’’ in sections 

6(C) and (D) of MSCC’s 1998 exhibit, 

except that MSCC shall also notify EPA 

in writing of each annual Relative 

Accuracy Test Audit at least 25 working 

days prior to actual testing. 

(4) Auxiliary vent stacks. 

(i) Emission limits. 

(A) Total combined emissions of SO2

from the auxiliary vent stacks shall not 

exceed 12.0 pounds per 3-hour period; 

(B) Total combined emissions of SO2

from the auxiliary vent stacks shall not 

exceed 96.0 pounds per calendar day; 

(C) Total combined emissions of SO2

from the auxiliary vent stacks shall not 

exceed 35,040 pounds per calendar 

year; and 

(D) The H2S concentration in the fuel 

burned in the Railroad Boiler, the H–1 

Unit, the H1–A unit, the H1–1 unit, and 

the H1–2 unit, while any of these units 

is exhausting to the auxiliary vent 

stacks, shall not exceed 160 ppm per 3- 

hour period and 100 ppm per calendar 

day. 

(ii) Compliance determining method. 

(A) Compliance with the emission 

limits in paragraph (g)(4)(i) of this 

section shall be determined by 

measuring the H2S concentration of the 

fuel burned in the Railroad Boiler, the 

H–1 Unit, the H1–A unit, the H1–1 unit, 

and the H1–2 unit (when fuel other than 

natural gas is burned in one or more of 

these units) according to the procedures 

in paragraph (g)(4)(ii)(C) of this section. 

(B) Beginning June 20, 2008, MSCC 

shall maintain logs of: 

(1) The dates and time periods that 

emissions are exhausted through the 

auxiliary vent stacks, 

(2) The heaters and boilers that are 

exhausting to the auxiliary vent stacks 

during such time periods, and 

(3) The type of fuel burned in the 

heaters and boilers during such time 

periods. 

(C) Beginning June 20, 2008, MSCC 

shall measure the H2S content of the 

fuel burned when fuel other than 

natural gas is burned in a heater or 

boiler that is exhausting to an auxiliary 

vent stack. MSCC shall begin measuring 

the H2S content of the fuel at the fuel 

header within one (1) hour from when 

a heater or boiler begins exhausting to 

an auxiliary vent stack and on a onceper-3-hour period frequency until no 

heater or boiler is exhausting to an 

auxiliary vent stack. To determine the 

H2S content of the fuel burned, MSCC 

shall use length-of-stain detector tubes 

pursuant to ASTM Method D4810–06, 

‘‘Standard Test Method for Hydrogen 

Sulfide in Natural Gas Using Length-ofStain Detector Tubes’’ (incorporated by 

reference, see paragraph (j) of this 

section) with the appropriate sample 

tube range. If the results exceed the 

tube’s range, another tube of a higher 

range must be used until results are in 

the tube’s range. 

(5) SRU 30-meter stack. 

(i) Emission limits. 

(A) Emissions of SO2 from the SRU 

30-meter stack shall not exceed 12.0 

pounds per 3-hour period; 

(B) Emissions of SO2 from the SRU 

30-meter stack shall not exceed 96.0 

pounds per calendar day; 

(C) Emissions of SO2 from the SRU 

30-meter stack shall not exceed 35,040 

pounds per calendar year; and 

(D) The H2S concentration in the fuel 

burned in the heaters and boilers 

described in paragraph (g)(1)(iv) of this 

section, while any of these units is 

exhausting to the SRU 30-meter stack, 

shall not exceed 160 ppm per 3-hour 

period and 100 ppm per calendar day. 

(ii) Compliance determining method. 

(A) Compliance with the emission 

limits in paragraph (g)(5)(i) of this 

section shall be determined by 

measuring the H2S concentration of the 

fuel burned in the heaters and boilers 

described in paragraph (g)(1)(iv) of this 

section (when fuel other than natural 

gas is burned in one or more of these 

heaters or boilers) according to the 

procedures in paragraph (g)(5)(ii)(C) of 

this section. 

(B) Beginning June 20, 2008, MSCC 

shall maintain logs of: 

(1) The dates and time periods that 

emissions are exhausted through the 

SRU 30-meter stack, 

(2) The heaters and boilers that are 

exhausting to the SRU 30-meter stack 

during such time periods, and 

(3) The type of fuel burned in the 

heaters and boilers during such time 

periods. 

(C) Beginning June 20, 2008, MSCC 

shall measure the H2S content of the 

fuel burned when fuel other than 

natural gas is burned in a heater or 

boiler that is exhausting to the SRU 30- 

meter stack. MSCC shall begin 

measuring the H2S content of the fuel at 

the fuel header within one (1) hour from 

when any heater or boiler begins 

exhausting to the SRU 30-meter stack 

and on a once-per-3-hour period 

frequency until no heater or boiler is 

exhausting to the SRU 30-meter stack. 

To determine the H2S content of the fuel 

burned, MSCC shall use length-of-stain 

detector tubes pursuant to ASTM 

Method D4810–06, ‘‘Standard Test 

Method for Hydrogen Sulfide in Natural 

Gas Using Length-of-Stain Detector 

Tubes’’ (incorporated by reference, see 

paragraph (j) of this section) with the 

appropriate sample tube range. If the 

results exceed the tube’s range, another 

tube of a higher range must be used 

until results are in the tube’s range. 

(6) Data reporting requirements: 

(i) MSCC shall submit quarterly 

reports beginning with the first calendar 

quarter following May 21, 2008. The 

quarterly reports shall be submitted 

within 30 days of the end of each 

calendar quarter. The quarterly reports 

shall be submitted to EPA at the 

following address: Air Program Contact, 

EPA Montana Operations Office, 

Federal Building, 10 West 15th Street, 

Suite 3200, Helena, MT 59626. 

The quarterly report shall be certified 

for accuracy in writing by a responsible 

MSCC official. The quarterly report 

shall consist of both a comprehensive 

electronic-magnetic report and a written 

hard copy data summary report. 

(ii) The electronic report shall be on 

magnetic or optical media, and such 

submittal shall follow the reporting 

format of electronic data being 

submitted to the MDEQ. EPA may 

modify the reporting format delineated 

in this section, and, thereafter, MSCC 

shall follow the revised format. In 

addition to submitting the electronic 

quarterly reports to EPA, MSCC shall 

also record, organize, and archive for at 

least five (5) years the same data, and 

upon request by EPA, MSCC shall 

provide EPA with any data archived in 

accordance with this provision. The 

electronic report shall contain the 

following: 

(A) Hourly average total sulfur 

concentrations as H2S or SO2 in ppm, in 

the gas stream to the flare(s); 

(B) Hourly average H2S concentrations 

of the flare pilot and purge gases in 

ppm; 

(C) Hourly average SO2 concentrations 

in ppm from the SRU 100-meter stack; 

(D) Hourly average volumetric flow 

rates in SCFH in the gas stream to the 

flare(s) and in the SRU 100-meter stack; 

(E) Hourly average volumetric flow 

rates in SCFH of the flare pilot and 

purge gases; 

(F) Hourly average temperature (in (F) 

and pressure (in mm or inches of Hg) in 

the gas stream to the flare(s); 

(G) Hourly emissions in pounds per 

clock hour from the flare(s) and SRU 

100-meter stack; 

(H) Daily calibration data for all flare 

CEMS, all pilot gas and purge gas 

CEMS, and the SRU 100-meter stack 

CEMS; 

(iii) The quarterly written report shall 

contain the following information: 


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(A) The 3-hour emissions in pounds 

per 3-hour period from the flare(s) and 

SRU 100-meter stack, and 3-hour H2S 

concentrations in the fuel burned in the 

heaters and boilers described in 

paragraphs (g)(1)(iii) and (iv) of this 

section while any of these units is 

exhausting to the SRU 30-meter stack or 

auxiliary vent stacks and burning fuel 

other than natural gas; 

(B) Periods in which only natural gas 

or an inert gas was used as flare pilot 

gas or purge gas or both; 

(C) Daily emissions in pounds per 

calendar day from the SRU 100-meter 

stack; 

(D) Annual emissions of SO2 in 

pounds per calendar year from the SRU 

100-meter stack; 

(E) The results of all quarterly 

Cylinder Gas Audits (CGA), Relative 

Accuracy Audits (RAA) and annual 

Relative Accuracy Test Audits (RATA) 

for all total sulfur analyzer(s), all H2S 

analyzer(s), and the SRU 100-meter 

stack CEMS, and the results of all 

annual calibrations and verifications for 

the volumetric flow, temperature, and 

pressure monitors; 

(F) For all periods of flare volumetric 

flow rate monitoring system or total 

sulfur analyzer system downtime, SRU 

100-meter CEMS downtime, flare pilot 

gas or purge gas volumetric flow or H2S 

analyzer system downtime, failure to 

obtain or analyze a grab or integrated 

sample, or failure to obtain an H2S 

concentration sample as required by 

paragraphs (g)(4)(ii)(C) and (g)(5)(ii)(C) 

of this section, the written report shall 

identify: 

(1) Dates and times of downtime or 

failure; 

(2) Reasons for downtime or failure; 

(3) Corrective actions taken to 

mitigate downtime or failure; and 

(4) The other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, used to determine flare 

emissions; 

(G) For all periods that the range of 

the flare or any pilot or purge gas 

volumetric flow rate monitor(s), any 

flare total sulfur analyzer(s), or any pilot 

or purge gas H2S analyzer(s), is 

exceeded, the written report shall 

identify: 

(1) Date and time when the range of 

the volumetric flow monitor(s), total 

sulfur analyzer(s), or H2S analyzer(s) 

was exceeded; and 

(2) The other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, used to determine flare 

emissions; 

(H) For all periods that the flare 

volumetric flow monitor or monitors are 

recording flow, yet any Flare Water Seal 

Monitoring Device indicates there is no 

flow, the written report shall identify: 

(1) Date, time, and duration when the 

flare volumetric flow monitor(s) 

recorded flow, yet any Flare Water Seal 

Monitoring Device indicated there was 

no flow; 

(I) For each 3-hour period and 

calendar day in which the flare 

emission limit, the SRU 100-meter stack 

emission limits, the SRU 30-meter stack 

emission limits, or auxiliary vent stack 

emission limits are exceeded, the 

written report shall identify: 

(1) The date, start time, and end time 

of the excess emissions; 

(2) Total hours of operation with 

excess emissions, the hourly emissions, 

the 3-hour emissions, and the daily 

emissions; 

(3) All information regarding reasons 

for operating with excess emissions; and 

(4) Corrective actions taken to 

mitigate excess emissions; 

(J) For instances in which emissions 

are exhausted through the auxiliary vent 

stacks or 30-meter stack, the quarterly 

written report shall identify: 

(1) The dates and time periods that 

emissions were exhausted through the 

auxiliary vent stacks or the 30-meter 

stack; 

(2) The heaters and boilers that were 

exhausting to the auxiliary vent stacks 

or 30-meter stack during such time 

periods; and 

(3) The type of fuel burned in the 

heaters and boilers during such time 

periods; and 

(K) When no excess emissions have 

occurred or the continuous monitoring 

system(s) or manual system(s) have not 

been inoperative, repaired, or adjusted, 

such information shall be stated in the 

report. 

(h) Flare compliance determining 

method. 

(1) Compliance with the emission 

limits in paragraphs (d)(2)(i), (e)(2)(i), 

(f)(2)(i) and (g)(2)(i) of this section shall 

be determined by measuring the total 

sulfur concentration and volumetric 

flow rate of the gas stream to the flare(s) 

(corrected to one (1) atmosphere 

pressure and 68° F) and using the 

methods contained in the flare 

monitoring plan required by paragraph 

(h)(5) of this section. The volumetric 

flow rate of the gas stream to the flare(s) 

shall be determined in accordance with 

the requirements in paragraph (h)(2) of 

this section and the total sulfur 

concentration of the gas stream to the 

flare(s) shall be determined in 

accordance with paragraph (h)(3) of this 

section. 

(2) Flare flow monitoring: 

(i) Within 365 days after receiving 

EPA approval of the flare monitoring 

plan required by paragraph (h)(5) of this 

section, each facility named in 

paragraph (a) of this section shall install 

and calibrate, and, thereafter, calibrate, 

maintain and operate, a continuous flow 

monitoring system capable of measuring 

the volumetric flow of the gas stream to 

the flare(s) in accordance with the 

specifications contained in paragraphs 

(h)(2)(iii) through (vi) of this section. 

The flow monitoring system shall 

require more than one flow monitoring 

device or flow measurements at more 

than one location if one monitor cannot 

measure the total volumetric flow to 

each flare. 

(ii) Volumetric flow monitors meeting 

the proposed volumetric flow 

monitoring specifications below should 

be able to measure the majority of 

volumetric flow in the gas streams to the 

flare. However, in rare events (e.g., 

upset conditions) the flow to the flare 

may exceed the range of the monitor. In 

such cases, or when the volumetric flow 

monitor or monitors are not working, 

other methods approved by EPA in the 

flare monitoring plan required by 

paragraph (h)(5) of this section shall be 

used to determine the volumetric flow 

rate to the flare, which shall then be 

used to calculate SO2 emissions. In 

quarterly reports, sources shall indicate 

when these other methods are used. 

(iii) The flare gas stream volumetric 

flow rate shall be measured on an actual 

wet basis, converted to Standard 

Conditions, and reported in SCFH. The 

minimum detectable velocity of the flow 

monitoring device(s) shall be 0.1 feet 

per second (fps). The flow monitoring 

device(s) shall continuously measure 

the range of flow rates corresponding to 

velocities from 0.5 to 275 fps and have 

a manufacturer’s specified accuracy of 

±5% of the measured flow over the 

range of 1.0 to 275 fps and ±20% of the 

measured flow over the range of 0.1 to 

1.0 fps. The volumetric flow monitor(s) 

shall feature automated daily 

calibrations at low and high ranges. The 

volumetric flow monitor(s) shall be 

calibrated annually according to 

manufacturer’s specifications. 

(iv) For correcting flow rate to 

standard conditions (defined as 68°F 

and 760 mm, or 29.92 inches, of Hg), 

temperature and pressure shall be 

monitored continuously. Temperature 

and pressure shall be monitored in the 

same location as volumetric flow, and 

the temperature and pressure monitors 

shall be calibrated prior to installation 

according to manufacturer’s 

specifications and, thereafter, annually 

to meet accuracy specifications as 

follows: The temperature monitor shall 


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be calibrated to within ± 2.0% at 

absolute temperature and the pressure 

monitor shall be calibrated to within ± 

5.0 mmHg; 

(v) The flow monitoring device(s) 

shall be calibrated prior to installation 

to demonstrate accuracy of the 

measured flow to within 5.0% at flow 

rates equivalent to 30%, 60%, and 90% 

of monitor full scale. 

(vi) Each volumetric flow device shall 

achieve a temporal sampling resolution 

of at least one (1) flow rate measurement 

per minute, meet the requirements 

expressed in the definition of ‘‘hourly 

average’’ in paragraph (c)(14) of this 

section, and be installed in a manner 

and at a location that will allow for 

accurate measurements of the total 

volume of the gas stream going to each 

flare. Each temperature and pressure 

monitoring device shall achieve a 

temporal sampling resolution of at least 

one (1) measurement per minute, meet 

the requirements expressed in the 

definition of ‘‘hourly average’’ in 

paragraph (c)(14) of this section, and be 

installed in a manner that will allow for 

accurate measurements. 

(vii) In addition to the continuous 

flow monitors, facilities may use flare 

water seal monitoring devices to 

determine whether there is flow going to 

the flare. If used, owners or operators 

shall install, calibrate, operate, and 

maintain these devices according to 

manufacturer’s specifications. The 

devices shall include a continuous 

monitoring system that: 

(A) Monitors the status of the water 

seal to indicate when flow is going to 

the flare; 

(B) Automatically records the time 

and duration when flow is going to the 

flare; and 

(C) Verifies that the physical seal has 

been restored after flow has been sent to 

the flare. 

If the water seal monitoring devices 

indicate that there is no flow going to 

the flare, yet the continuous flow 

monitor is indicating flow, the 

presumption will be that no flow is 

going to the flare. 

(viii) Each facility named in 

paragraph (a) of this section, that does 

not certify that only natural gas or an 

inert gas is used for both the pilot gas 

and purge gas, shall determine the 

volumetric flow of each pilot gas and 

purge gas stream for which natural gas 

or inert gas is not used by one of the 

following methods: 

(A) Measure the volumetric flow of 

the gas using continuous flow 

monitoring devices on an actual wet 

basis, converted to Standard Conditions, 

and reported in SCFH. Each flow 

monitoring device shall achieve a 

temporal sampling resolution of at least 

one (1) flow rate measurement per 

minute, meet the requirements 

expressed in the definition of ‘‘hourly 

average’’ in paragraph (c)(14) of this 

section, and be installed in a manner 

and at a location that will allow for 

accurate measurements of the total 

volume of the gas. Gas flow rate monitor 

accuracy determinations shall be 

required at least once every 48 months 

or more frequently at routine refinery 

turn-around. In cases when the flow 

monitoring device or devices are not 

working or the range of the monitoring 

device(s) is exceeded, other methods 

approved by EPA in the flare monitoring 

plan required by paragraph (h)(5) of this 

section shall be used to determine 

volumetric flow of the gas which shall 

then be used to calculate SO2 emissions. 

In quarterly reports, sources shall 

indicate when other methods are used; 

or 

(B) Use parameters and methods 

approved by EPA in the flare monitoring 

plan required by paragraph (h)(5) of this 

section to calculate the volumetric flows 

of the gas, in SCFH. 

(3) Flare concentration monitoring: 

(i) Within 365 days after receiving 

EPA approval of the flare monitoring 

plan required by paragraph (h)(5) of this 

section, each facility named in 

paragraph (a) of this section shall 

determine the total sulfur concentration 

of the gas stream to the flare(s) using 

either continuous total sulfur analyzers 

or grab or integrated sampling with lab 

analysis, as described in the following 

paragraphs: 

(A) Continuous total sulfur 

concentration monitoring. If a facility 

chooses to use continuous total sulfur 

concentration monitoring, the following 

requirements apply: 

(1 ) The facility shall install and 

calibrate, and, thereafter, calibrate, 

maintain and operate, a continuous total 

sulfur concentration monitoring system 

capable of measuring the total sulfur 

concentration of the gas stream to each 

flare. Continuous monitoring shall occur 

at a location or locations that are 

representative of the gas combusted in 

the flare and be capable of measuring 

the normally expected range of total 

sulfur in the gas stream to the flare. The 

concentration monitoring system shall 

require more than one concentration 

monitoring device or concentration 

measurements at more than one location 

if one monitor cannot measure the total 

sulfur concentration to each flare. Total 

sulfur concentration shall be reported as 

H2S or SO2 in ppm. In cases when the 

total sulfur analyzer or analyzers are not 

working or the concentration of the total 

sulfur exceeds the range of the 

analyzer(s), other methods, approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section, shall be used to determine total 

sulfur concentrations, which shall then 

be used to calculate SO2 emissions. In 

quarterly reports, sources shall indicate 

when these other methods are used. 

(2 ) The total sulfur analyzer(s) shall 

achieve a temporal sampling resolution 

of at least one (1) concentration 

measurement per 15 minutes, meet the 

requirements expressed in the definition 

of ‘‘hourly average’’ in paragraph (c)(14) 

of this section, be installed, certified (on 

a concentration basis), and operated in 

accordance with 40 CFR part 60, 

Appendix B, Performance Specification 

5, and be subject to and meet the quality 

assurance and quality control 

requirements (on a concentration basis) 

of 40 CFR part 60, Appendix F. 

(3) Each affected facility named in 

paragraph (a) of this section shall notify 

the Air Program Contact at EPA’s 

Montana Operations Office, Federal 

Building, 10 West 15th Street, Suite 

3200, Helena, MT 59626, in writing of 

each Relative Accuracy Test Audit a 

minimum of 25 working days prior to 

the actual testing. 

(B) Grab or integrated total sulfur 

concentration monitoring: If a facility 

chooses grab or integrated sampling 

instead of continuous total sulfur 

concentration monitoring, the facility 

shall comply with the methods 

specified in either paragraph 

(h)(3)(i)(B)(1) (‘‘Grab Sampling’’) or 

(h)(3)(B)(i)(B)(2 ) (‘‘Integrated 

Sampling’’), and the requirements of 

paragraphs (h)(3)(i)(B)(3) (‘‘Sample 

Analysis’’), (h)(3)(i)(B)(4) 

(‘‘Exemptions’’), and (h)(3)(i)(B)(5) 

(‘‘Missing or Unanalyzed Sample’’) of 

this section, as follows: 

(1) Grab Sampling. Each facility that 

chooses to use grab sampling shall meet 

the following requirements: if the flow 

rate of the gas stream to the flare in any 

consecutive 15-minute period 

continuously exceeds 0.5 feet per 

second (fps) and the water seal 

monitoring device, if any, indicates that 

flow is going to the flare, a grab sample 

shall be collected within 15 minutes. 

The grab sample shall be collected at a 

location that is representative of the gas 

combusted in the flare. Thereafter, the 

sampling frequency shall be one (1) grab 

sample every three (3) hours, which 

shall continue until the velocity of the 

gas stream going to the flare in any 

consecutive 15-minute period is 

continuously 0.5 fps or less. Samples 

shall be analyzed according to 

paragraph (h)(3)(i)(B)(3) of this section. 

The requirements of this paragraph 

(h)(3)(i)(B)(1) shall apply to each flare at 


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a facility for which the sampling 

threshold is exceeded. 

(2) Integrated Sampling. Each facility 

that chooses to use integrated sampling 

shall meet the following requirements: if 

the flow rate of the gas stream to the 

flare in any consecutive 15-minute 

period continuously exceeds 0.5 feet per 

second (fps) and the water seal 

monitoring device, if any, indicates that 

flow is going to the flare, a sample shall 

be collected within 15 minutes. The 

sample shall be collected at a location 

that is representative of the gas 

combusted in the flare. The sampling 

frequency, thereafter, shall be a 

minimum of one (1) aliquot for each 15- 

minute period until the sample 

container is full, or until the end of a 3- 

hour period is reached, whichever 

comes sooner. Within 30 minutes 

thereafter, a new sample container shall 

be placed in service, and sampling on 

this frequency, and in this manner, shall 

continue until the velocity of the gas 

stream going to the flare in any 

consecutive 15-minute period is 

continuously 0.5 fps or less. Samples 

shall be analyzed according to 

paragraph (h)(3)(i)(B)(3) of this section. 

The requirements of this paragraph 

(h)(3)(i)(B)(2) shall apply to each flare at 

a facility for which the sampling 

threshold is exceeded. 

(3) Samples shall be analyzed using 

ASTM Method D4468–85 (Reapproved 

2000) ‘‘Standard Test Method for Total 

Sulfur in Gaseous Fuels by 

Hydrogenolysis and Rateometric 

Colorimetry,’’ (incorporated by 

reference, see paragraph (j) of this 

section) ASTM Method D5504–01 

(Reapproved 2006) ‘‘Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Chemiluminescence,’’ (incorporated by 

reference, see paragraph (j) of this 

section) or 40 CFR part 60, Appendix 

A–5, Method 15A ‘‘Determination of 

Total Reduced Sulfur Emissions From 

the Sulfur Recovery Plants in Petroleum 

Refineries.’’ Total sulfur concentration 

shall be reported as H2S or SO2 in ppm. 

(4) Exemptions. For facilities using a 

sampling method specified in either 

paragraph (h)(3)(i)(B)(1) (‘‘Grab 

Sampling’’) or (h)(3)(i)(B)(2) (‘‘Integrated 

Sampling’’) of this section, obtaining a 

sample is not required if flaring is a 

result of a catastrophic or other unusual 

event, including a major fire or an 

explosion at the facility, such that 

collecting a sample at the EPA-approved 

location during the relevant period is 

infeasible or constitutes a safety hazard, 

provided that the owner or operator 

shall collect a sample at an alternative 

location if feasible, safe, and 

representative of the flaring event. The 

owner or operator shall demonstrate to 

EPA that it was infeasible or unsafe to 

collect a sample or to collect a sample 

at the sampling location approved by 

EPA in the flare monitoring plan 

required by paragraph (h)(5) of this 

section. The owner or operator shall 

also demonstrate to EPA that any 

sample collected at an alternative 

location is representative of the flaring 

incident. If a facility experiences 

ongoing difficulties collecting grab or 

integrated samples in accordance with 

its flare monitoring plan approved by 

EPA pursuant to paragraph (h)(5) of this 

section, EPA may require the facility to 

revise its flare monitoring plan and use 

continuous total sulfur concentration 

monitoring as described in paragraph 

(h)(3)(i)(A) of this section or other 

reliable method to determine total sulfur 

concentrations of the gas stream to the 

flare. 

(5) Missing or Unanalyzed Samples. 

For facilities using a sampling method 

specified in either paragraph 

(h)(3)(i)(B)(1) (‘‘Grab Sampling’’) or 

(h)(3)(i)(B)(2) (‘‘Integrated Sampling’’) of 

this section, if a required sample is not 

obtained or analyzed for any reason, 

other methods approved by EPA in the 

flare monitoring plan required by 

paragraph (h)(5) of this section shall be 

used to determine total sulfur 

concentrations, which shall then be 

used to calculate SO2 emissions. In 

quarterly reports, sources shall indicate 

when these other methods are used. 

(6) Reporting. For facilities using a 

sampling method specified in either 

paragraph (h)(3)(i)(B)(1 ) (‘‘Grab 

Sampling’’) or (h)(3)(i)(B)(2 ) 

(‘‘Integrated Sampling’’) of this section, 

since normally only one (1) sample per 

flare will be analyzed for a 3-hour 

period, the total sulfur concentration of 

a sample obtained during a given 3-hour 

period shall be substituted for each hour 

of such 3-hour period. If integrated 

sampling for a flare produces more than 

one (1) sample container during a 3- 

hour period, and the gas in each 

container is analyzed separately, the 

concentrations for the containers shall 

be averaged. For that flare, the resulting 

average shall be substituted for each 

hour of the 3-hour period during which 

the sampling occurred. The substituted 

hourly total sulfur concentrations 

determined per this paragraph shall be 

used to determine hourly emissions 

from the flare. 

(ii) Each facility named in paragraph 

(a) of this section that does not certify 

that only natural gas or an inert gas is 

used for both the pilot gas and purge gas 

shall determine the H2S concentration 

of each pilot gas and purge gas stream 

for which natural gas or inert gas is not 

used by one of the following methods: 

(A) Measure the H2S concentration of 

the gas by continuous H2S analyzer. The 

H2S concentration analyzer(s) shall 

achieve a temporal sampling resolution 

of at least one (1) concentration 

measurement per three (3) minutes, 

meet the requirements expressed in the 

definition of ‘‘hourly average’’ in 

paragraph (c)(14) of this section, be 

installed, certified (on a concentration 

basis), and operated in accordance with 

40 CFR part 60, Appendix B, 

Performance Specification 2, and be 

subject to and meet the quality 

assurance and quality control 

requirements (on a concentration basis) 

of 40 CFR part 60, Appendix F. In cases 

where the H2S analyzer or analyzers are 

not working or the H2S concentration 

exceeds the range of the analyzer(s), 

other methods approved by EPA in the 

flare monitoring plan required by 

paragraph (h)(5) of this section shall be 

used to determine the H2S concentration 

of the gas, which shall then be used to 

calculate SO2 emissions. In quarterly 

reports, sources shall indicate when 

other methods are used; or 

(B) Use methods approved by EPA as 

part of the facility’s flare monitoring 

plan required by paragraph (h)(5) of this 

section to estimate the H2S 

concentration of the gas. 

(4) Calculation of SO2 emissions from 

flares. Methods for calculating hourly 

and 3-hour SO2 emissions from flares 

shall be submitted to EPA as part of the 

flare monitoring plan required by 

paragraph (h)(5) of this section. 

Following approval by EPA, such 

methods shall be followed for 

calculating hourly and 3-hour SO2

emissions from a facility’s flare(s). 

(5) By October 20, 2008, each facility 

named in paragraph (a) of this section 

shall submit a flare monitoring plan. 

Each flare monitoring plan shall 

include, at a minimum, the following: 

(i) A facility plot plan showing the 

location of each flare in relation to the 

general plant layout; 

(ii) Drawing(s) with dimensions, 

preferably to scale, and an as-built 

process flow diagram of the flare(s) 

identifying major components, such as 

flare header, flare stack, flare tip(s) or 

burner(s), purge gas system, pilot gas 

system, water seal, knockout drum, and 

molecular seal; 

(iii) A representative flow diagram 

showing the interconnections of the 

flare system(s) with vapor recovery 

system(s), process units, and other 

equipment as applicable; 

(iv) A complete description of the gas 

flaring process for an integrated gas 


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flaring system that describes the method 

of operation of the flares; 

(v) A complete description of the 

vapor recovery system(s) which have 

interconnection to a flare, such as 

compressor description(s); design 

capacities of each compressor and the 

vapor recovery system; and the method 

currently used to determine and record 

the amount of vapors recovered; 

(vi) A complete description of the 

proposed method to monitor, determine, 

and record the total volume and total 

sulfur concentration of gases combusted 

in the flare, including drawing(s) with 

dimensions, preferably to scale, 

showing the following information for 

the proposed flare gas stream 

monitoring systems: 

(A) The locations to be used for all 

monitoring and sampling, including, but 

not limited to: Flare flow monitors, total 

sulfur analyzers, concentration 

integrated sampling, concentration grab 

sampling, water seal monitoring 

devices, pilot and purge gas flow 

monitors, and pilot and purge gas 

concentration monitors; 

(vii) A description of the method(s) 

used to determine, and reasoning 

behind, all monitoring and sampling 

locations; 

(viii) The following information 

regarding pilot gas and purge gas for 

each flare: 

(A) Type(s) of gas used; 

(B) A complete description of the 

monitor(s) to be used, or the other 

parameters that will be used and 

monitored, to determine volumetric 

flows of the pilot gas and purge gas 

streams for which natural gas or inert 

gas is not used; and 

(C) A complete description of the 

analyzer(s) to be used to determine, or 

other methods that will be used to 

estimate, the H2S concentrations in the 

pilot gas and purge gas streams for 

which natural gas or inert gas is not 

used; 

(ix) A detailed description of 

manufacturer’s specifications, 

including, but not limited to, make, 

model, type, range, precision, accuracy, 

calibration, maintenance, quality 

assurance procedure, and any other 

relevant specifications and information 

referenced in paragraphs (h)(2) and (3) 

of this section for all existing and 

proposed flow monitoring devices and 

total sulfur analyzers; 

(x) The following information if grab 

or integrated sampling is used: 

(A) A complete description of 

proposed analytical and sampling 

methods if grab or integrated sampling 

methods will be used for determining 

the total sulfur concentration of the gas 

stream going to the flare; 

(B) A detailed description of 

manufacturer’s specifications, 

including, but not limited to, make, 

model, type, maintenance, and quality 

assurance procedures for the integrated 

sampling device, if used; and 

(C) A complete description of the 

proposed method to alert personnel 

designated to collect samples that the 

trigger for collecting a sample has 

occurred; 

(xi) A complete description of the 

methods to be used to estimate flare 

emissions when any flare, pilot gas, or 

purge gas volumetric flow monitoring 

devices, total sulfur analyzers, or grab or 

integrated sampling methods, or pilot 

gas or purge gas H2S analyzers are not 

working or available, or the operating 

range of the monitors or analyzers is 

exceeded; 

(xii) A complete description of the 

proposed data recording, collection, and 

management system and any other 

relevant specifications and information 

referenced in paragraphs (h)(2) and (3) 

of this section for each flare monitoring 

system; 

(xiii) The following information for 

each flare using a water seal monitoring 

device: 

(A) A detailed description of 

manufacturer’s specifications, 

including, but not limited to, make, 

model, type, maintenance, and quality 

assurance procedures; 

(B) A complete description of the 

proposed methods to determine that the 

water seal is no longer intact and flow 

is going to the flare, and the data used 

to establish, and reasoning behind, these 

methods; 

(xiv) A schedule for the installation 

and operation of each flare monitoring 

system consistent with the deadline in 

paragraphs (h)(2) and (h)(3) of this 

section; and 

(xv) A complete description of the 

methods to be used for calculating 

hourly and 3-hour SO2 emissions from 

flares. 

(6) Thirty (30) days prior to installing 

any continuous monitor or integrated 

sampler pursuant to paragraphs (h)(2) 

and (3) of this section, each facility 

named in paragraph (a) of this section 

shall submit for EPA review a quality 

assurance/quality control (QA/QC) plan 

for each monitor or sampler being 

installed. 

(i) Affirmative defense provisions for 

exceedances of flare emission limits 

during malfunctions, startups, and 

shutdowns. 

(1) In response to an action to enforce 

the emission limits in paragraphs 

(d)(2)(i), (e)(2)(i), (f)(2)(i), and (g)(2)(i) of 

this section, owners and/or operators of 

the facilities named in paragraph (a) of 

this section may assert an affirmative 

defense to a claim for civil penalties for 

exceedances of such limits during 

periods of malfunction, startup, or 

shutdown. To establish the affirmative 

defense and to be relieved of a civil 

penalty in any action to enforce such a 

limit, the owner or operator of the 

facility must meet the notification 

requirements of paragraph (i)(2) of this 

section in a timely manner and prove by 

a preponderance of evidence that: 

(i) For claims of malfunction: 

(A) The excess emissions were caused 

by a sudden, unavoidable breakdown of 

equipment, or a sudden, unavoidable 

failure of a process to operate in the 

normal or usual manner, beyond the 

control of the owner or operator; 

(B) The excess emissions: 

(1) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(2) Could not have been avoided by 

better operation and maintenance 

practices; 

(C) Repairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded. Off-shift and overtime 

labor were used, to the extent 

practicable; 

(D) The amount and duration of the 

excess emissions (including any bypass) 

were minimized to the maximum extent 

practicable during periods of such 

emissions; 

(ii) For claims of startup or shutdown: 

(A) All or a portion of the facility was 

in startup or shutdown mode, resulting 

in the need to route gases to the flare; 

(B) The periods of excess emissions 

that occurred during startup and 

shutdown were short and infrequent 

and could not have been prevented 

through careful planning and design or 

better operation and maintenance 

practices; and 

(C) The frequency and duration of 

operation in startup or shutdown mode 

were minimized to the maximum extent 

practicable; 

(iii) For claims of malfunction, 

startup, or shutdown: 

(A) If the excess emissions resulted 

from a bypass of control equipment or 

a process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; 

(B) All possible steps were taken to 

minimize the impact of the excess 

emissions on ambient air quality; 

(C) All emissions monitoring systems 

were kept in operation if at all possible; 

(D) The owner or operator’s actions in 

response to the excess emissions were 

documented by properly signed, 

contemporaneous operating logs; 


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Federal Register / Vol. 73, No. 77 / Monday, April 21, 2008 / Rules and Regulations 21465 

(E) The excess emissions were not 

part of a recurring pattern indicative of 

inadequate design, operation, or 

maintenance; 

(F) At all times, the facility was 

operated in a manner consistent with 

good practices for minimizing 

emissions; and 

(G) During the period of excess 

emissions, there were no exceedances of 

the SO2 NAAQS that could be attributed 

to the emitting source. 

(2) Notification. The owner or 

operator of the facility experiencing an 

exceedance of its flare emission limit(s) 

during startup, shutdown, or 

malfunction shall notify EPA verbally as 

soon as possible, but no later than noon 

of EPA’s next working day, and shall 

submit written notification to EPA 

within 30 days of the initial occurrence 

of the exceedance. The written 

notification shall explain whether and 

how the elements set forth in paragraph 

(i)(1) of this section were met, and 

include all supporting documentation. 

(3) Injunctive relief. The Affirmative 

Defense Provisions contained in 

paragraph (i)(1) of this section shall not 

be available to claims for injunctive 

relief. 

(j) Incorporation by reference. (1) The 

materials listed in this paragraph are 

incorporated by reference in the 

corresponding paragraphs noted. These 

incorporations by reference are 

approved by the Director of the Federal 

Register in accordance with 5 U.S.C. 

552(a) and 1 CFR part 51. These 

materials are incorporated as they exist 

on the date of the approval, and notice 

of any change in these materials will be 

published in the Federal Register. The 

materials are available for purchase at 

the corresponding address noted below, 

and all are available for inspection at 

the National Archives and Records 

Administration (NARA) and at the Air 

Program, EPA, Region 8, 1595 Wynkoop 

Street, Denver, CO. For information on 

the availability of this material at 

NARA, call 202–741–6030, or go to: 

http://www.archives.gov/ 

federal_register/ 

code_of_federal_regulations/ 

ibr_locations.html. 

(2) The following materials are 

available for purchase from the 

following address: American Society for 

Testing and Materials (ASTM), 100 Barr 

Harbor Drive, Post Office Box C700, 

West Conshohocken, PA 19428–2959, 

www.astm.org, or by calling (610) 832–

9585. 

(i) ASTM Method D4468–85 

(Reapproved 2000), Standard Test 

Method for Total Sulfur in Gaseous 

Fuels by Hydrogenolysis and 

Rateometric Colorimetry, IBR approved 

for paragraph (h)(3)(i)(B)(3) of this 

section. 

(ii) ASTM Method D4810–06, 

Standard Test Method for Hydrogen 

Sulfide in Natural Gas Using Length-ofStain Detector Tubes, IBR approved for 

paragraphs (f)(3)(ii)(B), (g)(4)(ii)(C), and 

(g)(5)(ii)(C) of this section. 

(ii) ASTM Method D5504–01 

(Reapproved 2006), Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography IBR 

approved for paragraph (h)(3)(i)(B)(3) of 

this section. 

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

BILLING CODE 6560–50–P 


jlentini on PROD1PC65 with RULES2