# Response to Request for Information Reasonable Progress For Montana Sulphur & Chemical Co

Pursuant to: Section 114(A) of the Federal Clean Air Act

[42 USC 7414(A)]

Prepared for: Montana Sulphur & Chemical Co

PO Box 31118 Billings, MT 59107

Prepared by: Montana Sulphur & Chemical Co

.

and

Bison Engineering, Inc. 1400 11 th 

### Avenue Helena, MT 59601 406-442-5768 www.bison-eng.com



### February 6, 2012Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response Page ii 

## TABLE OF CONTENTS

1.0 INTRODUCTION ......................................

................................................... ...... 1-1 1.1 Introduction ......................................

................................................... .... 1-1 1.2 Regulatory Summary ................................ .............................................. 1-4 1.3 Selection of Reasonable Progress .................. ........................................ 1-5 1.4 Historical Perspective of Emission Reductions at MS CC ........................ 1-7 1.5 Selection of Emitting Units ....................... ............................................. 1-11 1.6 Selection of Pollutants ........................... ............................................... 1-1 3 2.0 COSTS OF COMPLIANCE................................ ................................................ 2- 1 2.1 MSCC Facility Description ......................... ............................................. 2-1 2.2 Emitting Unit and Control Information ............. ........................................ 2-2 2.3 Particulate Matter ................................

................................................... . 2-3 2.4 Sulfur Dioxide ....................................

................................................... .. 2-4 2.4.1 Control Technologies Considered ................... ........................................ 2-4 2.4.2 Eliminating Technically Infeasible Options ........ ...................................... 2-9 2.4.3 Technically Feasible Options ...................... .......................................... 2-10 2.4.4 Cost-Effectiveness ................................ ................................................ 2- 12 2.5 Nitrogen Oxides ................................... ................................................. 2 -13 3.0 TIME NECESSARY FOR COMPLIANCE ..................... ..................................... 3-1 3.1 Time Necessary for Compliance ..................... ........................................ 3-1 3.1.1 Installation of SO 2 Controls ......................................... ............................ 3-1 4.0 ENERGY AND NON-AIR QUALITY IMPACTS ................ .................................. 4-1 4.1 Energy Impacts: SO 2 Controls ......................................... ...................... 4-1 4.2 Non-Air Quality Impacts: SO 2 Controls ......................................... ......... 4-2 5.0 REMAINING USEFUL LIFE OF THE AFFECTED SOURCE ...... ...................... 5-1 6.0 VISIBILITY MODELING RESULTS ....................... ............................................ 6-1 6.1 Visibility Modeling Results ....................... ............................................... 6-1 7.0 ECONOMIC RESULTS AND IMPACTS TO VISIBILITY ........ ........................... 7-1 8.0 SUMMARY ...........................................

................................................... .......... 8-1Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## 1.0 INTRODUCTION

1.1 Introduction

On January 6, 2012, Montana Sulphur & Chemical Comp any (MSCC) received a letter from the U.S. Environmental Protection Agency (EPA) requesting an analysis of control options for the Lockwood, Montana facility. The Jan uary letter invokes Section 114(a) of the Federal Clean Air Act. 1 The letter notes that in 2006, the Montana Departm ent of Environmental Quality (MDEQ) withdrew its developme nt of a state implementation plan (SIP) for regional haze under the Regional Haze Rul e (RHR). 2 EPA also stated in the January letter that: “ we believe that . . . emissions from . . . (MSCC) . . . warrant further analysis to determine whether additional controls s hould be considered .” 3 To that end, EPA requested that MSCC submit an analysis of contr ol options for the plant. 4

More specifically, the January letter asks that the analysis “ address the four factors included in 40 CFR §51.308(d)(1)(i)(A). ” These factors are summarized in the January 6 letter as:
(1) The costs of compliance, (2) The time necessary for compliance, (3) The energy and non-air quality impacts of compl iance, and (4) The remaining useful life of the potentially af fected sources.

This report and attached cover letter serve as MSCC ’s response to EPA’s information request.

The time allotted to conduct the requested analyses is extremely short. A few weeks are insufficient time to thoughtfully analyze equipment issues and control possibilities, much less for conducting an accurate analysis of costs o r construction schedules. We believe we have done our best to be responsive to EPA’s req uest, but caution the agency that much of the work is based on (optimistic) generic r eview reports or data. It represents our best effort at approximating a cost, impact or timeline given the extremely short period provided for response. We have sought data f rom manufacturers or designers of

1 The letter was dated December 30, 2011, by EPA. Th e letter itself was mailed on or after January 3 an d not received by MSCC until January 6, 2012. For pur poses of consistency, this letter will be reference d as the January 6, 2012, letter since that is the date on which MSCC first became aware of EPA’s request.

2 The RHR is a reference to the visibility protectio n program outlined in 40 CFR 51.308. The entire visibility program, including RHR, is found in 40 C FR 51, Subpart P.

3 We note that while EPA states they believe an anal ysis is warranted, there was no justification provi ded to reach that conclusion. Regardless, MSCC is provi ding this response in good faith. We note that the results of the investigations in this document prov ide substantial evidence that no additional emissio n reductions from MSCC are necessary to carry out the purposes of the RHR.

4 The January letter was not specific as to which em itting units were to be addressed in the analysis. Based on later discussions with EPA staff, we have presumed that the analysis is to be directed toward the emissions from the MSCC sulfur recovery plant ( at the main stack EU3) since it represents the larg est level of emissions (of those pollutants which could affect visibility) from the facility.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 1-2 possible equipment, but the timeline does not allow consideration of all processes or site-specific cost or reliability estimates. No ven dor or other source of information was able or willing to produce a quotation or performan ce guarantee, of course, in the short period allowed for response.

MSCC and Bison, until January 6, 2012, were reasona bly under the belief that the RHR program did not consider MSCC’s emissions as approp riate candidates for additional control under the reasonable progress (or any other ) criteria. First, MSCC’s emissions (historical and current actuals) have been addresse d and controlled by separate implementation plans, voluntary emission limitation s, voluntary actions undertaken by MSCC, and by subsequent federal implementation plan actions. The majority of these emission controlling items occurred between 1998 an d 2008.

Second, as a whole, Montana emission inventory data clearly shows substantial and adequate reductions in potential and actual sulfur dioxide and nitrogen oxide emissions in the period since 1980. These reductions have res ulted from voluntary source actions, implementation plans, major smelter and plant closu res, new plant constructions, and numerous consent decrees. As an example, annual SO 2 ambient concentrations in Billings have fallen over 95% since 1990. More nota bly, an 86% reduction in SO 2 concentrations has been realized since 2002 alone ( See Figure 1.1-1.).

Similarly, emissions in Billings have been reduced by approximately 75% since the early 1990s (See Figure 1.1-2). Emissions from MSCC have also dropped significantly during this same general period. MSCC emissions are found in Section 1.4 below.



### Figure 1.1-1: Billings Historical Ambient SO 2 

### ConcentrationsMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### Figure 1.1-2: Historical SO 2 

### Emissions

Third, discussions with the agency as late as the f ourth quarter of 2011 did not indicate a need for further information beyond that informal ly provided in those brief telephone discussions.

The Billings area reductions clearly exceed those a ttained nationally. For example, Figure 1.1-3 shows EPA-sourced data for SO 2 emissions since 1983, which show a decline of about 25% through 2002. 5

5 Issues in Political Economy, Vol. 13, August 2004, Ludwig, citing EPA data.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### Figure 1.1-3: National Historical SO 2 

### Emissions

The above graphic also shows that the reduction in emissions nationally have not kept pace with the reductions by MSCC and the Billings a rea in general. For Montana as a whole, major losses of industries in the state (e.g . smelters) have drastically reduced emissions since the creation of the national goals on visibility. Montana has clearly reduced industrial emissions disproportionately, an d any Montana plan should take this fact into account.

Despite the emissions discussion above, we understa nd, based from agency staff that EPA is pressed by a consent decree deadline of its own, 6 and believes it must act as quickly as possible. However, such constraint shoul d not justify any hasty or unsuitable conclusions.



### 1.2 Regulatory Summary

As this request for information arises from the RHR we find it useful and prudent to review our understanding of the nature and purpose of the visibility protection program in order to ascertain important criteria that will lead to the selection of specific Reasonable Progress requirements.
A visibility program aimed at attaining national vi sibility goals in mandatory Class I areas was authorized in Section 169A of the Clean Air Act . The national goals are to be attained by the year 2064, approximately 52 years f rom now. The rules which are to

6 Originally set for January, 2012, and then extende d to March, 2012, as described by discussions with the agency.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 1-5 implement this goal of protecting visibility are fo und at 40 CFR 51, Subpart P (subsections 300 through 309). A review of Subpart P indicates the purpose and goals of the program. The purposes of the program are out lined as follows:

“ The primary purposes of this subpart are . . .to as sure reasonable
progress

toward meeting the national goal of preventing any future, and remedying any existing, impairment of visibility in mandatory Class I Federal areas which impairment results from manmade air pollution;. . .” [40 CFR 51.300(a)].

The visibility program may then be thought of as th e implementation of two subprograms. One regards new source review (NSR, PSD, etc.) and the other addresses “regional haze.” Regional haze may further be broke n down into the best available retrofit technology (BART) program 7 and the Reasonable Progress program. The underlying reason stated for EPA’s January 6 letter to MSCC is to address the Reasonable Progress portion of visibility protectio n.

In that regard, the RHR [§308(d)] outlines what it refers to as: “the core requirements” for the implementation of the regional haze goals. More specifically, §308(d)(1) states:

“ For each mandatory Class I Federal area . . ., the State must establish goals . . . that provide for reasonable progress to wards achieving natural visibility conditions. The reasonable progress goals must provide for an improvement in visibility for the most impaired days. .” [ 40 CFR 51.308(d)(1)].

The rules go on to provide the states (EPA in this case) with a list of what must be considered in developing reasonable progress. Among these details are the “four factors” analysis that is outlined above in Section 1.1 and in the January 6 letter.



### 1.3 Selection of Reasonable Progress

For Montana, EPA is tasked to establish (a plan for ) Reasonable Progress in carrying out the visibility protection. Section 1.2 outlines the purpose of the program along with core elements. To that end, EPA states it has asked for “ an analysis of control options” which will, we assume, be evaluated by EPA for appl icability in establishing a set of specific reasonable Montana control strategies that create “reasonable progress” toward the 2064 goals.
The January 6 request for a review of “control opti ons” notwithstanding, it seems to us that the visibility program itself and the reasonab le progress portion of that program is clear as to intent. That is, the purpose of the pro gram is to protect visibility (by, over time, remedying, and preventing man-made impairment s) in mandatory Class I areas as to the effects of human activities. Reasonable Prog ress expresses the notion that states must have implementation plans to approach the nati onal goal by 2064 along a ‘glide-

7 Applicable to certain sources built between 1962 a nd 1976.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 1-6 path’ of improvements to visibility, with certain e xceptions. Based on the language contained in the rule, 8 it is also clear that any activity, remedy or cont rol (proposed or otherwise) that does not reasonably “improve visibi lity” in a mandatory Class I area is not a reasonable candidate for those “reasonable pr ogress” goals. 9

As a result, we believe an analysis that only consi ders one or more emission control options is not sufficient for inclusion into reason able progress mandates unless those emission controls are expected to improve actual vi sibility in a Class I area in a discernible manner. It is neither necessary nor app ropriate to include an emission control as part of a reasonable progress goal or pl an without reasonable expectation of a resulting improvement in regional haze arising fr om the application of the control (i.e., a discernible improvement in deciviews in a Class I area). (The deciview metric is briefly explained below.) 10

To that end, we have chosen to not only analyze var ious control “options” using the four factor test outlined in the January 6 letter, we ha ve also conducted a brief analysis of any modeled impacts this facility may have on the n earest mandatory Class I areas. This was accomplished to determine if either the cu rrent configuration or future control options would fulfill the underlying need of the pr ogram to “ provide for an improvement in visibility ” 11 at a mandatory Class I area.

We note that we have seen no measured evidence of a ny impact by MSCC’s operations on the visibility in any mandatory Class I airshed. We are peripherally aware that some efforts in the past decade have attempted to deline ate, via computer modeling assumptions, potential visibility impacts of select ed human emission sources at nearby mandatory Class I areas. For example, relative to t he BART program, analyses have been conducted for the PPL-Montana J.E. Corette coa l-fired plant that is a few miles from MSCC. (For reference, this coal-fired facility typically has higher emissions of SO 2 and NOx than MSCC). The results of that modeling in dicate a visibility impact of only about 0.7 deciviews (dv). This 0.7dv impact is less than that deemed as discernible.

The above notwithstanding, the visibility impact of MSCC as traditionally operated or as to any of the control options, via dispersion model ing presumptions, has been analyzed by Bison Engineering for inclusion in this reply. T he modeling and analysis results are

8 The language in 40 CFR 51.300(d)(1), among other e xamples, make it clear that these “reasonable progress” goals must indeed result in an actual imp rovement in visibility; not just a reduction in emi ssions. The language states: “The reasonable progress goal s must provide for an improvement in visibility. . .” [§300(d)(1)].

9 Ibid.

10 The definition of a deciview is as follows: Decivi ew haze index=10 ln e (b ext /10 Mm -1 ). This is taken from the definitions found in 40 CFR 51.301. There are, of course, numerous articles and explanations for t he deciview metric. One article may be found in the p ublication “IMPROVE,” Volume 2, No. 1, April 1993 which was written by Pitchford and Malm, 1993. From a non-mathematical point of view, the change in deciview of “1” is intended to represent a “just no ticeable change” (or sometimes referred to as ‘just discernible’) in visibility regardless of the basel ine visibility.

11 40 CFR 51.308(d)(1).Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 1-7 presented in subsequent sections of this document. The reader is referred to those sections for details on the analysis method and the results of those investigations.



### 1.4 Historical Perspective of Emission Reductions at MS CC

This response to EPA’s request would not be complet e without consideration of current and past emission reductions and controls that have occurred at MSCC. In the period since the authorizing legislation for the program w as passed (1977), 12 numerous changes have occurred (not only at MSCC, but many o ther nearby facilities as well). MSCC reasonably believes that it has made substanti al emission reductions from its facility, both as to “actual” and “potential” emiss ions. Any suggestion or conclusion that further reductions or controls are necessary and ap propriate for improvement to regional haze is not warranted. A short summary is in order.

MSCC was established in 1955 as a facility to captu re sulfur from fuel gases and acid gases. This sulfur was previously and traditionally burned as fuel without recovery resulting in tens of thousands of tons of sulfur di oxide emissions annually in the area. As a pioneer facility, MSCC’s plant operations also immediately reduced area emissions by tens of thousands of tons annually. MSCC’s facil ity also produces sulfur products, including fertilizer and soil-amending materials, w ith its sulfur recovery processes and clean fuel gases in its fuel gas scrubbing plant.

Fuel gases are scrubbed of hydrogen sulfide in an a mine unit. Cleaned fuel gases are returned to their owner for combustion or sale. The concentrated sulfur gases recovered are designated “acid gases.” Other acid gases are a lso received for processing and mingled with those recovered in the fuel gas scrubb er operation. The acid gases feed into the sulfur recovery equipment where they are r eacted with oxygen from the air in a thermal/catalytic system consisting of multiple rea ction furnaces/boilers and multiple catalytic reaction stages. The result of these proc esses is to produce elemental sulfur and water vapor, along with some side-reaction prod ucts. Elemental sulfur is separated from the gas stream by condensation in multiple sta ges. The use of such multiple stages allows the reversible “Claus” reaction to be driven toward completion. About 92% to 95% of the incoming sulfur in these particular g ases is recoverable in this manner. This is known as the modified “Claus/Chance” proces s. 13 14 Unrecovered sulfur and compounds from the plant were, in the 1950s and 196 0s, typically vented through the

12 The Visibility Protection program was originally c ontained in the Clean Air Act Amendments of 1977 in Section 169A.

13 MSCC also historically has processed acid gases to produce other products such as liquefied hydrogen sulfide. These materials were stored and shipped in large tonnages and used in numerous industries, including the nuclear power industry and the produc tion of “heavy water” for the US nuclear weapons industry. However, the national goal of reducing or eliminating domestic inventory of highly hazardous substances such as H 2 S has led to the cessation of sale of these materia ls by MSCC, which withdrew completely from supplying that market earlier in th is past decade.

14 AP-42 contains a description of this process. This information may be found at: http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13 .pdfMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 1-8 smoke stack, 15 as a semi-opaque plume consisting of sulfur aeroso l particulate, SO 2 , H 2 S, water vapor, carbon oxides and nitrogen, as was normal for the time period.

In anticipation of state regulation related to opac ity and visibility, these “tail gas” materials were next subjected to tail-gas oxidation or incineration. This tail-gas treatment process became established in its present form in about 1967 at MSCC. MSCC uses a selective oxidation catalyst in the pre sence of excess air and elevated temperature to convert particulate sulfur and reduc ed sulfur compounds in the tail-gas to sulfur dioxide gas which is both transparent and also (relatively) odorless.

In 1990, EPA contracted with E.H. Pechan and Associ ates to inventory both ‘actual’ and ‘potential-to-emit’ (PTE) SO 2 emissions in the Billings, Montana, area. This gov ernmentinitiated, -directed, and -funded study included em issions from MSCC as well as several other local industries. MSCC cooperated with Pechan in developing this inventory. Pechan concluded that as of 1989 for MSCC’s SRU, su lfur dioxide emissions were:

1989 Actuals: 3,450 tons/year Potential to Emit: 12,200 tons/year 16

By comparison, MSCC’s SRU actual emissions were 1,3 76 tons in 2010. Thus, actual emissions have dropped from the 1989 study period b y over 60%. Historical annual emissions are also shown as a graph later in this s ection.

In 1998, MSCC became subject to an annual emission limitation of SO 2 at its main stack of 4,544 tons per year. 17 Thus, “potential to emit” dropped by 73% from 1989 potential to emit values. In December of that same year, MSCC voluntarily installed a SuperClaus TM unit at the facility to assist in meeting shorter- term emission limitations, also established in 1998. This unit processes tail gas from the Claus plant and significantly reduced actual emissions. The unit, i n effect, is an additional emissions control device for the facility.

It is interesting to note that while MSCC’s allowab le emissions were 4,544 tons per year in1998, its actual emissions the prior year were 4, 058. 18 In 1999, the first full year of SuperClausTM operation, MSCC’s actual emissions were reduced to 1,137 tons/year, a 72% reduction. A graphical representation of annual emissions is found later in this section.

15 These emissions were routinely emitted through the 100-foot stack (EU4) during this period.

16 These values represent the SRU unit only. Actual a nd PTE emissions from the boilers and flares were (and continue to be) much less than the SRU. As an example, PTE emissions from the boilers were, at the time of the Pechan report, 18 tons/year while t he flares were 271 tons/year.

17 This was the “Stipulation” limit adopted by the Mo ntana Board of Environmental Review in 1998. EPA eventually adopted the same limit in their FIP whic h is found in 40 CFR 52.1392(g).

18 The emissions for 1998 were 3,626 tons per year. H owever, 1986 includes partial operation of the new SuperClaus TM unit. The first full year of operation of the Supe rClaus TM yielded in a 69% reduction in emissions from the 1998 year.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 1-9 In May 2002, EPA found the 1998 SIP revision limita tions “inadequate” to protect NAAQS under modeling criteria. 19 EPA then empowered itself to impose additional restrictions on MSCC. Those restrictions became ‘fi nal’ on April 21, 2008 (73 FR 21418) in 40 CFR 52.1392. 20

Like all processes, SuperClaus TM processing must occasionally be interrupted, for example, for repairs and catalyst work. In such cas es MSCC’s emissions would again necessarily return to pre-1998 levels, if processin g normal loads. In 2007 MSCC undertook to increase the on-line reliability of Su perClaus TM processing by installing a second SuperClaus TM unit in parallel with the 1998 unit. 21 This provides a great level of redundancy for enhanced SuperClaus TM processing, so that sulfur and fuel gas processing can continue during periods of repair an d maintenance on either (but not both) of the SuperClaus TM process trains.

Shortly thereafter, MSCC also ramped up the reliabi lity of incinerator processing for opacity control, with a second selective oxidation incinerator operating in parallel with the 1967 unit. 22 This provides a great level of redundancy for this processing, so that sulfur and fuel gas processing can continue, with i ncineration, even during periods of repair and maintenance on either (but not both) inc ineration trains.

In 2008, as part of the FIP, 23 MSCC’s flare emissions during startup, shutdown, a nd malfunction (SSM) events also became regulated and limited to 150 pounds per 3-hour period (this is equivalent to 219 tons/year). This enforceable limitation represented a substantial reduction from the prior emissions pres ented in the EPA PECHAN study. 24 Actual emissions since the FIP was promulgated, inc luding SSM emissions, were:
2009: 0.2 tons/year 2010: 6.5 tons/year

To aid the reader in understanding the depth of the changes in emissions from the Billings area and MSCC in particular, the following figure shows historical emissions from the industrial facilities.

19 May 2, 2002, at 67 FR 22168.

20 This became EPA’s final action regarding the Monta na FIP for Billings-Laurel area SO 2
. 21 Montana DEQ approved the installation of the secon d SuperClaus TM unit (and a redundant selective oxidizer incinerator) on March 1, 2007.

22 Ibid.

23 40 CFR 52.1392(g).

24 “ Development of a Sulfur Dioxide Emissions Inventory for Billings and Laurel, Montana – Volume 6 – Montana Sulphur & Chemical Company Sulfur Recovery Plant ,” EPA Contract 68-02-4400, EPA Region VIII.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### Figure 1.4-1: MSCC Historical Emissions

If, solely for purposes of argument, MSCC’s relativ ely small past emissions of 3,500+ tons per year are deemed to have created a signific ant (discernible) visibility impact on a mandatory Class I area, the plant changes and con trol options outlined above clearly have led to a large reduction in those emissions. B y inference, if the prior emissions are deemed significant to visibility, then those same e mission reductions might necessarily be deemed to represent reasonable progress toward a goal for the year 2064 established by 40 CFR 51.308(d)(1)(i)(B). That woul d be so if these prior MSCC emissions were known to be creating a significant i mpact on visibility. If, on the other hand, there is no data and no finding that MSCC’s p ast emissions were creating significant visibility impact, then the reductions made since 1998 [SIP and second SuperClaus TM (2006)] could not have amounted to reasonable prog ress toward the national visibility goal and, of course, any furthe r future reductions, control options, or changes also could not amount to reasonable progres s toward natural visibility in a Class I area.

A modeling study, summarized in Appendix B, address es this question more directly. The modeling supports a conclusion that MSCC’s pres ent emissions, and even MSCC’s past emissions rates which were significantly highe r, were and are not significantly impacting regional haze visibility in Class I areas . Accordingly, any further “control option” considered herein also cannot significantly impact visibility improvements or be justified as reasonable progress.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### 1.5 Selection of Emitting Units

On January 13, 2012, Hal Robbins of Bison Engineeri ng, Inc. (Bison) called Vanessa Hinkle, EPA Region 8, at the request of MSCC manage ment, to discuss and clarify various requirements in the January 6 letter. Durin g the discussion, it was clarified that the sulfur recovery process, which vents through th e main 100m stack (EU3), would be the emitting unit subject to analysis. This process an d its related stack is the preponderant source of SO 2 from the facility. All other emitting units at MSC C constitute a tiny fraction of potential visibility-related pol lutants (see discussion below for the selection of pollutants for further analysis) relat ing to SO 2 , NOx and particulate matter.

In order to lend some specifics to the justificatio n of only selecting the SRU, the following discussion is offered.

MSCC’s operating permit (OP211-04) lists 25 emittin g units. A cursory review indicates that most of the units do not warrant further atten tion. Those units include:Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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Unit Name Comment

EU1 Monaca – Sulfur Vaporization

Heater This is a small natural gas-fired unit. It has not operated for many years. It is rated at less than 5 mmBtu/hr.

EU2 Monaca – Steam Methane

Superheater Same comment as above.

EU3 100 Meter SRU Stack This is the primary stack through which the SRU equipment (including the incinerators) vents. The SRU itself will be the subject of this Reasonable Progress analysis.

EU4 30 Meter Stack This is a stack and is not, by itself, the subject of an analysis.

EU5 Railroad Boiler This is an older primarily gas-fired boiler. It has a small capacity and has not operated for many years. The function of the unit was effectively replaced by the 17 MMBTU/hr boiler (EU10).

EU6 through EU9 H-1 through H1-2 Boilers These multipurpose boilers are almost exclusively used as an integral part of the Claus plant (SRU). These emissions will be analyzed as part of the SRU analysis to follow. They occasionally may vent separately as a small capacity gas-fired boiler, but this is not a common event, and emissions from such gas-firing are de minimis

in any event.

EU10 17 MMBTU/hr Boiler This is a gas-fired boiler. It combusts natural gas or sweetened refinery fuel gas. Its SO 2 emissions are minimal.

EU11 through EU14 Flares These flares are operated intermittently. In addition they have been the subject of extensive federal and state regulation since 1998.

EU15 Hydrogen Plant This is a natural gas or sweetened refinery fuel gas-fired device of small potential emissions. It is not in

use.

EU16 through EU25 These sources include H 2 S compression, molten sulfur storage and load-out, sulfur handling, valves and pumps, and fugitive emissions (access roads). These units do not emit significant quantities of SO 2 and/or do not or have not operated for some time.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 1-13 As a result of a review of the table above, the emi ssions information for these units, and the January 13 discussion with EPA staff, only the SRU equipment is a candidate for a Reasonable Progress analysis. The other units are n ot considered since they emit only minimal quantities of SO 2 and NOx (primarily as a result of the combustion o f natural gas or sweetened refinery fuel gas). Absent evidenc e to the contrary, it is reasonable to conclude that small emissions units cannot reasonab ly impact regional haze at distant areas, and control options, if any, for such source s cannot reasonably contribute to “reasonable progress” toward any mandatory Class I visibility goal.



### 1.6 Selection of Pollutants

During the January 13, 2012, phone call with EPA, i t was also clarified that only sulfur dioxide (as to this source) would likely bear any p otential relationship as to Reasonable Progress. The other potential visibility-affecting pollutants are small in volume at MSCC and in general those pollutants do not relate to th e SRU. However, it was agreed to provide some justification to that conclusion for t he record.

To begin, one must first identify which pollutants typically are believed by EPA to participate in the degradation of visibility (regio nal haze) when arising from sources far removed from the mandatory Class I area of interest

. The January 6 letter suggests that we (MSCC) refer to the Best Available Retrofit Technology (BART) Guidelines which are found in 40 CFR 51, Appendix Y. A review of the Guideline yields the following comment.

**What pollutants should I address? Visibility-impairing pollutants include the followi**  **ng: (1) Sulfur dioxide (SO2),**  **(2) Nitrogen oxides (NOX), and (3) Particulate matter.**  **25**

Using this guideline, then the pollutants of intere st will be SO 2 , NOx and particulate matter (PM). From this we must now deduce which of these visibility pollutants should be the subject of further investigation in Section 2 below.

To make the analysis more complete, a table has bee n prepared which compares (recent) emissions from not only the SRU stack, but some of the other (smaller) emitting units of the three pollutants above. The emissions are presented based on the actual emissions from calendar year 2010. This year was ch osen since it is the most recent year with complete inventory data. Calendar years b efore 2010 are similar in nature. Those prior year values would not lead to a differe nt conclusion regarding which units or pollutants to select for analysis.

25 This language is taken from Page 598 of the July 1, 2010 version of the CFR found in: http://edocket.access.gpo.gov/cfr_2010/julqtr/pdf/4 0cfr51AppY.pdfMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### Figure 1.6-1: 2010 Actual Emissions (Tons/year)

Emitting Unit Description SO 2 NOx PM 10

EU1 Monaca – Sulfur Vaporization Heater 0 0 0

EU2 Monaca – Steam Methane

Superheater 0 0 0

EU3 100 Meter SRU Stack 1,376 3 1

EU4 30 Meter Stack 0 0 0

EU5 Railroad Boiler 0 0 0

EU10 17 MMBTU/hr Boiler < 1 1 < 1

EU12 – 14 Flares (all) 6 < 1 < 1

EU15 Hydrogen Plant 0 0

The results shown above indicate that the amount of NOx and PM 10 emitted from the facility is small, that it is small relative to SO 2 , and that SO 2 is “major” only as to the SRU main stack EU3. As a result, no control technol ogy analyses will be made for these pollutants, or for emission units other than EU3. T he remainder of this document will address SO 2 from the SRU.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## 2.0 COSTS OF COMPLIANCE

This section of the RHR Section 114 response will d escribe some estimated “costs of compliance,” presumably to meet the reasonable prog ress goals and strategies of the RHR. EPA has requested that MSCC provide the “cost s of compliance.” 26 The term “costs of compliance” is vague in the regulation si nce it is not clear what standard of compliance is to be met in which a particular cost must be incurred.

For example, a hypothetical facility may need to me et an applicable NSPS emission limit. 27 From such a limit, one may begin to determine and then analyze what equipment and operating parameters may be necessary to meet t he limit for the hypothetical plant. As a result, the “cost of compliance” may ultimatel y be ascertained. Since there is no particular numerical emission value to be met under this program, or under the reasonable progress criteria, the “costs of complia nce” are undefined and such costs cannot be determined by MSCC or any other person.

Nonetheless, we have interpreted this request for c ontrol option analysis to be a review of some “available” (additional) controls known to MSCC that could further reduce SO 2 emissions. As noted elsewhere in this document, it is assumed that such reduction has a cause/effect relationship to regional haze at man datory Class 1 areas. Based on the January 13 conversation with EPA, we have surmised that SCOT-type processing in particular was to be considered.



### 2.1 MSCC Facility Description

Before discussing control options, it is appropriat e to provide the reader with a brief description of MSCC’s facility and the current emis sion control system.

As discussed above, the MSCC facility has been in e xistence at its Billings-area location since 1955. The facility processes various hydrogen sulfide-laden streams from a nearby refinery. The facility is able to take raw ( sour) refinery fuel gas and clean the gas of most of the sulfur compounds creating a ‘sweeten ed’ fuel gas for the refinery. In addition to the fuel gas, MSCC processes other sulf ur-bearing streams (sour water stripper overhead, acid gases, and recovered flare gases, for example) from the refinery.

MSCC then takes these (recovered) sulfur compounds and/or streams and creates primarily elemental sulfur. The small fraction of u nrecoverable sulfur is vented to the 100 meter stack (in almost all cases) as SO 2 . As discussed above, these emissions of SO 2 are presently limited under the FIP to 2,983 pound s per three-hours which, after 2008, results in an effective annual limitation of no more than 4,355 tons per year. Prior permit limits (post-1998) were set at 4,544 tons pe r year. As indicated in the E.H.

26 This term is found in 40 CFR 51.308(d)(i)(A).

27 This discussion is purely hypothetical for purpose s of making a point. There is no NSPS limit that is applicable to this facility for a number of reasons . In addition, the sulfur recovery operation at MSC C predates the NSR regulations as well as BART.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-2 Pechan (1989) study, permissible emissions (not act ual) at 1989-1990 were about 12,200 tons per year. Significant progress has ther efore been made in reducing permissible emissions since 1990.

The basic form of the sulfur dioxide control system at the sulfur recovery plant may be thought of as three components:
a) Claus,
b) SuperClaus TM , and
c) Tailgas oxidizer.

The Claus process is the first step and is responsi ble for the vast majority of sulfur recovery and collection. The SuperClaus TM is an additional device 28 that further removes primarily H 2 S and sulfur mist from the stream. Finally, the tai lgas oxidizer converts the few remaining sulfur compounds (such a s H 2 S and other reduced compounds) and remaining sulfur vapors to SO 2 prior to being exited from the stack.

Section 1.4 provides more complete description and history of the facility. The reader is referred to that section for further discussion.



### 2.2 Emitting Unit and Control Information

Emissions from the sulfur recovery process and othe r sources are vented to atmosphere using the 100-meter stack. The stack han dles emissions from the sulfur recovery plant (including the Claus plant, SuperCla us TM and incinerator units) and may also handle minor gas combustion emissions from sev eral small gas-fired boilers such as the 17-mmBtu/hour boiler (EU10) and the H-boiler s.

The sulfur recovery process is a combination of equ ipment including but not limited to four “H” boiler units, 29 five Claus Sulfur Reactor systems including their associated multi-fuel process re-heaters, process gas coolers, barometric seal legs, which normally vent ultimately to the associated tail gas oxidatio n heaters and oxidation reactor equipment with optional waste heat recovery. Both t he original and the newer redundant tail gas oxidizer (incinerator) permissibly may ope rate either catalytically or noncatalytically. The five Claus reactors are generall y configured in a three-stage operation, but were designed for and may be configured in two- stage operation; for example, during reactor maintenance, and are designed to ope rate as a combined single train or as dual parallel trains by means of by-pass ducting and alternative ducting to allow maintenance and operational flexibility over a wide range of operating loads. At reduced loads, the unit has also been configured as a four- stage Claus plant. Individual reactors and the associated stage equipment may be taken on or off line to allow repairs/maintenance on each stage while operations of the Claus process then resume while the equipment is isolated. This is normally accomplished by brief shutdowns to

28 There are two redundant (parallel) SuperClaus TM units.

29 The H-Boiler units are small reaction boilers that are, in most circumstances, an integral part of th e “Claus” operation, but which may also be used as fu el gas-fired steam generators.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-3 swing blinds on alternative duct routes. Feed gas is flared as necessary during these brief and infrequent shutdowns.

Claus process reheaters are dual-fueled, meaning th at the re-heat energy is provided by either low sulfur fuel gas or process acid gas. Normally these are fired by process acid gases; the reheater gases join the main Claus process gases at each stage for further processing.

The Claus process is capable of converting hydrogen sulfide-rich gases into elemental sulfur by means of partial oxidation and catalytic oxidation-reduction of sulfur dioxide and hydrogen sulfide. The process also is capable of converting other sulfur-containing materials (e.g., carbonyl sulfide, carbon disulfide , mercaptans, sulfuric acid, and others) to elemental sulfur in conjunction with hydrogen su lfide-rich feed gases. It is capable of handling small concentrations of volatile ammonia c ompounds in the acid gas feed.

The Claus process is enclosed and pressurized to mi nimize fugitive emissions and vents presently to the 100-meter stack. Historical ly, it vented to a 30-meter stack along with the above-mentioned H units. The Claus proces s is rated at 252 long tons (2240 pounds = 1 long ton) per day of elemental sulfur pr oduction. 30



### 2.3 Particulate Matter

Particulate matter generated by the Sulphur Recover Equipment and emitted from the 100m stack is minimal. Below is a summary of MSCC’s PM and PM 10 emissions inventory 31 from 2009 and 2010:



### Table 2.2-1: 2008–2009 PM and PM 10 

### Emission Rates

Year PM (tpy) PM 10 (tpy)

2009 1.15 1.15

2010 1.07 0.83

Based on experience, conducting a cost analysis for additional controls to an emitting unit with such low emissions would show that adding particulate control would be prohibitively expensive with no discernible improve ment to visibility impacts. Therefore, we conclude that PM is being controlled to a level that satisfies the RP goals of the RHR and no further cost analysis is warranted. Please s ee the Visibility Modeling Results in Section 6.0 of this report which support this concl usion.

30 “ Development of a Sulfur Dioxide Emissions Inventory for Billings and Laurel, Montana – Volume 6 – Montana Sulphur & Chemical Company Sulfur Recovery Plant ,” EPA Contract 68-02-4400, EPA Region VIII.

31 Emissions estimates from Montana Department of Env ironmental Quality annual emission inventories.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-4 

### 2.4 Sulfur Dioxide

Several techniques can, in theory, be used to gener ally reduce SO 2 emissions from SRUs. SO 2 control options typically can include traditional post-combustion controls (e.g., wet scrubbers, dry scrubbers, etc.), tail ga s treating units (TGTU) such as the Shell Claus Off-gas Treating Process (SCOTTM) which rely on reduction, or TGTUs such as SuperClausTM or Wellman Lord relying on oxidation, and/or exten ding the Claus reaction into a lower temperature liquid phase (dis cussed below).

MSCC currently controls SO 2 emissions using the Claus and SuperClausTM processe s (see Section 1), and controls odors and opacity via incineration.

2.4.1 

### Control Technologies Considered

AP-42 Chapter 8.13 Sulfur Recovery identifies two g eneral types of control technologies to reduce SO 2 emissions from Claus Plants 32 : 1. Extend the Claus reaction into a lower temperatu re liquid phase 2. Tail Gas “Scrubbing”

The third listed technology at AP-42, incineration, is not discussed further because it is used to reduce H 2 S emissions and visible emissions in the tail gas b y converting these to SO 2 . Hence, this technology does not reduce SO 2 emissions as part of this analysis.

SuperClaus TM technology does not extend the Claus reaction at l ower temperature, instead reaching a similar product result by means of “selective catalytic oxidation of H 2 S.” The net result is production of sulfur and wate r vapor from H 2 S, just as with the forward direction of the Claus reaction. The select ive oxidation reaction is relatively irreversible compared to the Claus reaction, which is highly reversible at process temperatures. SuperClaus TM technology is reported to result in up to to ~99% overall recovery when used after a typical three-stage or f our-stage Claus system, 33 with somewhat lesser recoveries expected following short er or atypical Claus configurations.

SuperClausTM technology was selected by MSCC in 1997 as the most appropriate retrofit technology for this pioneer 34 facility. As seen from Figure 1.4-1, the results w ere a substantial reduction in annual facility SO 2 emissions following application of SuperClausTM processing. SuperClausTM is is widely us ed, and well recognized technology, worldwide.
Extend the Claus Reaction into a Lower Temperature Liquid Phase

This technique reduces sulfur dioxide emissions by lowering the temperature in downstream Claus catalytic stages and extending the Claus reaction. Five common

32 AP-42 Chapter 8.13 Sulfur Recovery also identified incineration as an H 2 S control technology. http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13 .pdf

33 Jacobs Comprimo Sulfur Solutions. Link: http://www .jacobs.com/products.aspx?id=6292

34 MSCC believes this facility to be the longest cont inuously running sulfur recovery plant in North America, if not the world, at this time.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-5 processes that extend the Claus reaction include Su lfreen®, BSR/selectox, Cold Bed Absorption, Maxisulf, and the IFP-1 process. These processes are variously reported (but not guaranteed) to result in 98 35 to 99.5 36 percent sulfur recovery when used after a typical two- or three-stage Claus SRU. AP-42 Chapte r 8.13 Sulfur Recovery reports, “All of these processes give overall sulfur recoveries o f 98 to 99 percent when installed downstream of a typical two- or three-stage Claus s ulfur recovery unit, and therefore emit lower sulfur emissions [than normal Claus].” 37 As such, we conclude they have potential recoveries similar to those being attaine d or attainable, on similar typical plants, using SuperClaus TM technology. As noted, SuperClausTM is employed as a retrofit technology at MSCC since 1998.

Tail Gas Scrubbing

Two types of tail gas scrubber technologies are pre dominant at Claus SRUs: oxidation and reduction tail gas scrubbers.

Oxidation tail gas scrubbers remove SO 2 from the post-incinerator flue gas. SO 2 is concentrated and recycled back into the Claus SRU w here it is converted to elemental sulfur. The Wellman-Lord scrubber system is the typ ically cited oxidation tail gas scrubber on Claus SRUs. 38 These systems, however, appear to be rarely, if ev er, in use on SRUs in the United States.

The Wellman-Lord (W-L) scrubber uses sodium sulfite (Na 2 SO 3 ) and sodium bisulfite (NaHSO 3 ) to react with SO 2 gas from the Claus incinerator to from bisulfite. The incinerator gases must be cooled and quenched befor e scrubbing, subjected to misting after scrubbing, and reheated afterwards. The bisul fite solution is regenerated to sodium sulfite in a steam-energized evaporator. The concen trated wet SO 2 gas stream from the evaporator is partially condensed and some of the l iquid water is used to dissolve sulfite crystals. The remaining enriched SO 2 gas stream is recycled back to the Claus plant and used to recover additional sulfur by reaction w ith the incoming hydrogen sulfide.

Claimed advantages of the W-L process include that it does not typically result in scaling or plugging and that it produces sulfur for incremental sales. Disadvantages include higher operating costs, sensitivity to comp onents in the gas (particulates, HCl, and SO 3 ), metals attrition, and the requirement of a purge system to remove solids and chlorides. 39 Excess acid water must also be disposed of. W-L sc rubber systems are

35 AP-42 Chapter 8.13 Sulfur Recovery also identified incineration as an H 2 S control technology. http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13 .pdf

36 Concawe Cost and Cost-Effectiveness Assessment of Abatement Technology/Techniques For Refineries. http://www.citepa.org/forums/egtei/5-Wh ite-refineries.pdf

37 AP-42 Chapter 8.13 Sulfur Recovery also identified incineration as an H 2 S control technology. http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13 .pdf
38 Another might be “ClausMasterTM” which is based on different chemistry.

39 Estimating Costs of Air Pollution Control , 1990, William M. Vatavuk, p 197.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-6 complex and can also require significant area to co nstruct, especially in retrofit applications. 40

The reduction scrubber processes first require a hydrogenation step to convert sulf ur, SO 2 , and reduced compounds in the tailgas to H 2 S. The tail gas must be pre-heated to reaction temperature, which varies with the catalys t employed. Preheat consumes fuel or steam energy. All sulfur compounds in the SRU ta ilgas besides H 2 S (e.g., SO 2 , COS, CS 2 , and elemental sulfur) are reduced to H 2 S in this step by using a catalyst and a reducing gas, such as hydrogen or water-gas.
The hot reduced tailgas is then cooled and quenched , removing a sour water waste, and gaseous moist H 2 S is then sent to the scrubber for contact with a s elective amine. The amine must reject carbon dioxide effectively. H 2 S is removed from the gas by amine equipment for regeneration in a separate rege neration stage, where the H 2 S gas is then cooled and processed (again) in the Claus p rocess. The produced sour water (which necessarily arises from cooling the Claus ta il-gas below its dew point for wet scrubbing) must also be processed in separate units , requiring substantial energy and capital. The cooled, scrubbed tail gas is typically reheated again and incinerated before discharge. Variants on this processing scheme are b elieved to be the most typically used in U.S. refinery sulfur plants built since 197 6.

Other traditional flue gas desulfurization (FGD) te chnologies were considered as part of this analysis. For a variety of reasons, these do n ot appear to be applied to sulfur recovery plants. These technologies include:

• Wet lime scrubbers,

• Wet limestone scrubbers,

• Dual alkali wet scrubbers,

• Spray dry absorbers,

• Dry sorbent injection,

• Circulating dry scrubber.

Wet Lime Scrubber

The wet lime scrubbing process uses alkaline slurry made by adding lime (CaO) to water. The lime must be produced in a fired kiln ei ther on or off site, from limestone. The alkaline slurry is sprayed into the exhaust stream and reacts with the SO 2 in the flue gas. Insoluble calcium sulfite (CaSO 3 ) and calcium sulfate (CaSO 4 ) salts are formed in

40 Summary Report, Sulfur Oxides Control Technology Se ries: Flue Gas Desulfurization; Wellman-Lord Process. EPA National Service Center for Environmental Publi cations, http://nepis.epa.gov/Exe/ZyNET.exe/30004EB1.TXT?ZyA ctionD=ZyDocument&Client=EPA&Index=1976 +Thru+1980&Docs=&Query=&Time=&EndTime=&SearchMethod =1&TocRestrict=n&Toc=&TocEntry=&Q Field=&QFieldYear=&QFieldMonth=&QFieldDay=&IntQFiel dOp=0&ExtQFieldOp=0&XmlQuery=&File=D %3A\zyfiles\Index%20Data\76thru80\Txt\00000001\3000 4EB1.txt&User=ANONYMOUS&Password=anon ymous&SortMethod=h|- &MaximumDocuments=1&FuzzyDegree=0&ImageQuality=r75g 8/r75g8/x150y150g16/i425&Display=p|f& DefSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&B ackDesc=Results%20page&MaximumPag es=1&ZyEntry=1&SeekPage=x&ZyPURLMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-7 the chemical reaction that occurs in the scrubber. The salts are removed as a solid waste by-product. The waste by-product is mainly Ca SO 3 , which is difficult to dewater. Solid waste by-products from wet lime scrubbing are typically managed in dewatering ponds and landfills. A review of the RBLC database has found wet lime scrubbers are commonly used in large industrial and utility boile r applications and not on SRUs.

Wet Limestone Scrubber

Wet limestone scrubbers are very similar to wet lim e scrubbers. However, the use of limestone (CaCO 3 ) instead of prepared lime requires different feed preparation equipment and a higher liquid-to-gas ratio. The hig her liquid-to-gas ratio typically requires a larger absorbing unit. The limestone slu rry process also requires a ball mill to crush the limestone feed.

Wet lime/limestone scrubbers can achieve SO 2 control efficiencies of approximately 95% or greater. The actual control efficiency of a wet lime/limestone FGD system depends on several factors, including the uncontrol led SO 2 concentration entering the scrubber: The higher the uncontrolled concentration , the higher the efficiency. Similar to wet lime scrubbers, wet limestone scrubbers generat e sludge that creates material handling and disposal issues. A review of the RBLC database has found wet limestone scrubbers are commonly used in large industrial and utility boiler applications and not on SRUs.

Dual Alkali Wet Scrubber

Dual-alkali scrubbers use a sodium-based alkali sol ution to remove SO 2 from the combustion exhaust gas. The process uses both sodiu m-based and calcium-based compounds. The sodium-based reagents absorb SO 2 from the exhaust gas, and the calcium-based solution (lime or limestone) regenera tes the spent liquor. Calcium sulfites and sulfates are precipitated and discarded as slud ge, and the regenerated alkaline sodium solution is returned to the absorber loop.

The dual-alkali process requires lower liquid-to-ga s ratios than scrubbing with lime or limestone. The reduced liquid-to-gas ratios general ly mean smaller scrubber units; however, additional regeneration and sludge process ing equipment is necessary.

A sodium-based scrubbing solution, typically consis ting of a mixture of sodium hydroxide, sodium carbonate, and sodium sulfite, is an efficient SO 2 control reagent. However, the process generates sludge that creates material handling and disposal issues. The control efficiency is similar to the we t lime/limestone scrubbers at approximately 95% or greater. Once again, control e fficiencies are highly dependent upon the uncontrolled SO 2 concentration entering the scrubber. A review of t he RBLC database has found dual-alkali scrubbers are common ly used in large industrial and utility boiler applications and not on SRUs.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-8 Spray Dry Absorber

The typical spray dry absorber (SDA) uses lime slur ry and water injected into a tower to remove SO 2 from the combustion gases. The towers must be desi gned to provide adequate contact and residence time between the exh aust gas and the slurry in order to produce a relatively dry by-product. The process eq uipment associated with an SDA typically includes an alkaline storage tank, mixing and feed tanks, atomizer, spray chamber, particulate control device, and recycle sy stem. The recycle system collects solid reaction products and recycles them back to t he spray dryer feed system to reduce alkaline sorbent use.

SDAs are the commonly used dry scrubbing method in large industrial and utility boiler applications and not on SRUs. SDAs have demonstrate d the ability to achieve greater than 95% SO 2 reduction. Once again, control efficiencies are hi ghly dependent upon the uncontrolled SO 2 concentration entering the scrubber, and fall off as the incoming concentration falls off.

Dry Sorbent Injection

Dry sorbent injection involves the injection of pow dered or hydrated sorbent (typically alkaline) directly into the flue gas exhaust stream . Dry sorbent injection systems are simple systems, and generally require a sorbent sto rage tank, feeding mechanism, transfer line and blower, and injection device. The dry sorbent is typically injected countercurrent to the gas flow through a venturi or ifice. An expansion chamber is often located downstream of the injection point to increa se residence time and contact efficiency. Particulates generated in the reaction are controlled in a downstream particulate control device.

SO 2 control efficiencies for dry sorbent injection sys tems are approximately 50%, but if the sorbent is hydrated lime, then 80% or greater r emoval can be achieved. These systems are commonly called lime spray dryers. Once again, control efficiencies are highly dependent upon the uncontrolled SO 2 concentration entering the scrubber.

Circulating Dry Scrubber

A third type of dry scrubbing system, the circulati ng dry scrubber (CDS), uses a circulating fluidized bed of dry hydrated lime reag ent to remove SO 2 . Flue gas passes through a venturi at the base of a vertical reactor tower and is humidified by a water mist. The humidified flue gas then enters a fluidi zed bed of powdered hydrated lime where SO 2 is removed. The dry by-product produced by this s ystem is routed with the flue gas to a particulate removal system.

Material must be purged from the system continuousl y and replaced. The solid waste must be landfilled in accordance with regulations a nd with the consent of the landfill owners. Approximately 2.5 pounds of waste are gener ated for each pound of SO 2 removed. 41

41 Based on lime to sulfur stoichiometric ratio of 1. 4:1 and 80% removal efficiency.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-9 2.4.2 

### Eliminating Technically Infeasible Options

CDS systems result in high particulate loading to a unit’s downstream particulate control device. Because of the high particulate loading, th e pressure drop across a fabric filter would be unacceptable; therefore, electrostatic pre cipitators (ESP) are generally used for particulate control in power plant applications . Based on limited technical data from non-comparable applications and engineering judgmen t, it has been determined that CDS is not technically feasible. Therefore, CDS wil l not be evaluated further.

SDA and DSI are not typically used at Claus SRUs. T he EPA factsheet for these technologies also indicates that they cannot be use d for waste gas SO 2 concentrations greater than 2,000 ppm. 42 Due to these reasons, these technologies were not evaluated further.

The MSCC facility has a very limited area to instal l additional SO 2 controls or to manage waste materials (see Figure 2.3-1). The wet FGD scr ubber systems with the higher water requirements (Wet Lime Scrubber, Wet Limeston e Scrubber, Dual Alkali Wet Scrubber) would require an on-site dewatering pond and landfill to process and dispose of scrubber sludge. Similarly, the Wellman-Lord scr ubber also has significant space requirements, especially in a retrofit situation 43 as well as a “purge stream” requiring disposal. Due to MSCC’s limited space, its proximit y to the Yellowstone River and a shallow aquifer, and due to limited water availabil ity and lack of disposal infrastructure for these controls, these technologies are consider ed technically infeasible and will not be evaluated further.

42 Air Pollution Control Technology Fact Sheet, Flue Gas Desulfurization (FGD) – Wet, Spray Dry, and Dry Scrubbers, http://www.epa.gov/ttncatc1/dir1/ffd g.pdf

43 Summary Report, Sulfur Oxides Control Technology Se ries: Flue Gas Desulfurization; Wellman-Lord Process. EPA National Service Center for Environmental Publi cations, http://nepis.epa.gov/Exe/ZyNET.exe/30004EB1.TXT?ZyA ctionD=ZyDocument&Client=EPA&Index=1976 +Thru+1980&Docs=&Query=&Time=&EndTime=&SearchMethod =1&TocRestrict=n&Toc=&TocEntry=&Q Field=&QFieldYear=&QFieldMonth=&QFieldDay=&IntQFiel dOp=0&ExtQFieldOp=0&XmlQuery=&File=D %3A\zyfiles\Index%20Data\76thru80\Txt\00000001\3000 4EB1.txt&User=ANONYMOUS&Password=anon ymous&SortMethod=h|- &MaximumDocuments=1&FuzzyDegree=0&ImageQuality=r75g 8/r75g8/x150y150g16/i425&Display=p|f& DefSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&B ackDesc=Results%20page&MaximumPag es=1&ZyEntry=1&SeekPage=x&ZyPURLMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-10 

### Figure 2.3-1: Approximate MSCC Leased Property Boun dary and Yellowstone River

2.4.3 

### Technically Feasible Options

Technologies proven effective at Claus plants and w hich require low amounts of water and installation space were evaluated. The two tech nically feasible alternative control approaches for the MSCC facility were determined to be:Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-11 • Extending the Claus reaction into a lower temperat ure liquid phase (ECLT) (or equivalent)

• Reduction Tail Gas Scrubbing (RTGS)

ECLT 44 and RTGS 45 include several potentially feasible technologies. Due to the extremely limited timeframe to adequately respond, Sulfreen® and SCOT were chosen as representative average cases of ECLT and RTGS, r espectively. These technologies were selected due to the availability of some cost information provided by contacted vendors, information available on the web, and thei r commercial availability.

2.4.3.1 Sulfreen®

In the Sulfreen® process, the Claus reaction is ext ended at low temperatures (260 to 300oF) to recover SO 2 and H 2 S in the tail gas. Tail gas passes through one of t hree reactors on line at a given time. Two reactors are on either heating or cooling cycles while the third is on the gas stream. Gas flow is s witched from the reactors and is determined by the sulfur-holding capacity of each c atalyst bed in the reactors. Sulfur is vaporized by using inert gas from a blower, resulti ng in the regeneration of the catalyst bed. The inert gas is then cooled in a condenser, w here the liquid sulfur is removed. The hot regenerated catalyst bed must be cooled bef ore going back on the gas stream. Sulfreen® systems reportedly can achieve 98% 46 to 99.5% 47 sulfur recovery efficiency. AP-42 Chapter 8.13 Sulfur Recovery suggests the upp er range is about 99%. Bison and MSCC believe the higher end of this recovery pe rcentage to be theoretically possible, but unlikely achievable at the MSCC facil ity. These are substantially similar efficiencies as those reported for SuperClausTM syst ems. The MSCC facility operates SuperClausTM systems at this time, as already noted. Review of the available information does not suggest that application of th ese costly “low-temperature Claus” alternative technologies would result in significan t additional reduction as compared to SuperClausTM systems. We also do not expect a vendor to guarantee the higher end of this sulfur recovery percentage range due to atypic al conditions necessarily existing in the upstream Claus system at MSCC.

The recovery percentage ranges also represent the a mount of sulfur removed from the untreated gas stream(s) entering a sulfur recovery facility and not the amount of SO 2 reduction from the existing tail gas stream. The ef fective reduction to existing controlled

44 ECLT includes at least five technologies, BSR/Sele ctox, Sulfreen®, Cold Bed Absorption, Maxisulf, and IFP-1 processes as identified AP-42 Chapter 8.13 Su lfur Recovery, http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13 .pdf

45 Beavon, Beavon MDEA, SCOT, and ARCO are identified in AP-42 Chapter 8.13.

46 Sulfreen® description adapted from “Encyclopedia o f chemical processing and design, Volume 1.” http://books.google.com/books?id=JoZbcFQvHJ8C&pg=PA 210&lpg=PA210&dq=Sulfreen+Process+Desc ription&source=bl&ots=yWr1jJ6Aq3&sig=3yS-ffTUZ7lcwI SqSy3BbopfH7g&hl=en&sa=X&ei=_awoTeQGImyiQKXs721Cg&ved=0CDsQ6AEwAw#v=onepage&q=Sulfre en%20Process%20Description&f=fals

e 47 Sulfreen® Recovery of up to 99.5% per “Concawe Cos t and Cost-Effectiveness, Assessment of Abatement Technology/Techniques for Refineries”. Li nk: http://www.citepa.org/forums/egtei/5-Whiterefineries.pdfMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-12 SO 2 emissions would be substantially lower than the th eoretically possible overall sulfur recovery rates.

2.4.3.2 Shell Claus Off-Gas Treatment (SCOT)

In the SCOT process, and numerous variants, tail ga s from the SRU is re-heated and mixed with a hydrogen-rich reducing gas stream. Hea ted tail gas is treated using a catalytic reactor where the free sulfur, sulfur dio xide, and reduced sulfur compounds are substantially reconverted to H 2 S. The H 2 S-rich gas stream is then routed to a cooling/quench system where the gases are cooled. E xcess condensed water from the quench system is routed to a separate sour water sy stem for treatment and disposal. The cooled quench system gas effluent is then fed t o an absorber section where the acidic gas comes in contact with a selective amine solution and is absorbed into solution; the amine must selectively reject carbon dioxide gas to avoid problems in the following steps, and must not be exposed to unreduc ed gases or oxygen (e.g., unconverted SO 2 or sulfur) that may arise during malfunctions. The rich solution is separately regenerated using steam, cooled and retu rned to the scrubber/absorber. The H 2 S-rich gas released at the regenerator is reprocess ed by the SRU.

In certain applications, particularly newly designe d plants designed for use with Tail Gas Treatment, SCOT can reportedly achieve sulfur recov ery as high as 99.8%-99.9%. 48 Bison and MSCC believe this recovery percentage to be theoretically possible, but unlikely achievable at the MSCC facility which date s to the 1950s. Similar to the Sulfreen® discussion above, this sulfur recovery pe rcentage represents the amount of sulfur removed from the untreated acid gas stream e ntering the upstream SRU and not the amount of further SO 2 reduction from the tail gas stream. The effective r eduction to existing controlled SO 2 emissions would be substantially lower than these overall sulfur recovery rates.

2.4.4 

### Cost-Effectiveness

The cost-effectiveness of the potentially feasible SO 2 control technologies was estimated, to the extent time allowed, based on the methodologies developed by William M. Vatavuk in the book Estimating Costs of Air Pollution Control and the methodologies provided in EPA’s Office of Air Quali ty Planning and Standards (OAQPS) Pollution Cost Control Manual, 6 th Edition

. The emission rate for this analysis was based on (a pproximately) the average emission rate of 2009 and 2010, the most recent reporting ye ars as of the January 6 letter. The results of the analysis are presented in the Result s section of this report. Detailed estimates and supporting information are provided i n Appendix A – Costs of Compliance Analysis.

48 From: http://www.gec.jp/JSIM_DATA/AIR/AIR_6/html/D oc_142.htmlMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 2-13 

### 2.5 Nitrogen Oxides

Nitrogen oxides generated by the SRU and emitted fr om the 100m stack are minimal. Below is a summary of MSCC’s NOx emissions from 200 9 and 2010 annual emission inventories 49 :



### Table 2.2-1: 2008–2009 Annual NOx Emissions

Year NOx (tpy)

2009 3.95

2010 4.10

Based on experience, conducting a cost analysis for additional controls to an emitting unit with such low emissions would show that adding NOx control would be prohibitively expensive with no discernible improvement to visibi lity impacts. Therefore, we conclude that NOx is being controlled to a level that is irr elevant to or which satisfies the RP goals of the RHR and no further cost analysis is warrante d. Please see the Visibility Modeling Results in Section 6.0 of this report which support this conclusion.

49 Emissions estimates from Montana Department of Env ironmental Quality prescribed emission factors in annual emission inventories.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## 3.0 TIME NECESSARY FOR COMPLIANCE

3.1 Time Necessary for Compliance

Based on the modeling results presented in Section 6 of this report, MSCC and Bison consider the facility already in compliance with th e RHR. However, this section of the report will discuss the estimated amount of time to install the SO 2 technologies identified previously in this report, as this is requested in the January 6 letter.

3.1.1 

### Installation of SO 2 

### Controls

The addition of either ECLT (Sulfreen®) or RTGS (SC OT) would require careful planning in order to ensure that sulfur-rich gas st reams from the client refinery are treated as required by law. The installation of new SOx controls would need to be carefully coordinated to allow a parallel treatment path using the existing equipment and to allow processes to remain in operation while the retrofits are applied to another parallel path. When MSCC elected to apply the far s impler SuperClausTM technology in 1998, the time for design and installation, from “g o-date” to on-line was approximately 15 months, with some processing interruptions. When the second system was installed in 2008, the time required was approximately 30 mon ths without process interruptions. Installation of a more complex process can be expec ted to take longer periods. Further, in order for any reduction to be fully effective, a level of redundancy is required to allow for operation during periods of tail-gas treatment downtime and repair. This could require multiple units and consecutive phases. Biso n estimates the time necessary to complete the modifications to the SRU to be 18 to 3 6 months, per unit installed. Installation of these processes would also require the dismantling of the existing SuperClaus TM units without a discernible improvement to visibil ity (see Section 6).Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## 4.0 ENERGY AND NON-AIR QUALITY IMPACTS

4.1 Energy Impacts: SO 2 

### Controls

The example SCOT and Sulfreen® systems require subs tantial additional energy to operate. Both systems require natural gas or fuel g as 50 to heat the Claus tail gas prior to entering a reducing reactor and/or for heating recy cle gas for regeneration requirements. Sulfreen® systems require electric po wer for operation of large regeneration blowers. Low-temperature based system s (either SCOT or Sulfreen®) also typically require additional fuel for reheat o f the final tail gas for incineration prior to discharge. 51 SCOT systems also require substantial electricity to operate numerous pumps, coolers, and a condenser. Additional power i s required to provide relatively large amounts (compared to current) of cooling wate r. Additional fuel and power energy (and equipment) is required for processing of the n ew sour water waste continuously produced in the quench processes necessary for scru bbing.

The limited time to evaluate these options has not allowed a detailed energy evaluation for SCOT, and none for Sulfreen®. However, we are a dvised that energy requirements for SCOT are (at least) as follows:

50 Natural gas must be burned either directly in a re -heater or fuel gas/natural gas fired in new boiler equipment to produce high pressure steam in a new boiler. MSCC does not presently own or operate any boilers of the 600 pound pressure class necessa ry for use of steam re-heat.
51 MSCC currently reheats gases for incineration, but this is reheated from a higher temperature than SCOT effluent, and thus has lower fuel requirements

.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### Table 4.1-1: SCOT Utility Estimates

Equipment Normal

Consumption Maximum

Consumption Required Heat

Input (MMBtu/hr)

Low Pressure Steam Service (50 psig) 19,654 lb/hr 22,046

lb/hr 27.5 to 30.9

Superheated MidPressure Steam Service (150 psig) 331 lb/hr 661

lb/hr 0.5 to 1

High Pressure Steam Service (600 psig) 3,382 lb/hr 4,526

lb/hr 4.7 to 6.4

Total Steam: 19,654 22,046 32.7 to 38.1

Power Service 220 kW/h 222 kW/hr ~0.8

Nitrogen Service 5 Nm 3 /h 1404 Nm 3 /h NA

These also necessarily represent increases in green house gas emissions and other pollutants either at MSCC or at provider facilities

.



### 4.2 Non-Air Quality Impacts: SO 2 

### Controls

The quench system in the SCOT system produces a sou r water waste effluent that requires treatment prior to disposal. This effluent would contain hydrogen sulfide, and may contain sulfur and other troublesome species as well, particularly during upsets. MSCC currently does not have sour water treatment f acilities nor access to a public sewer system to accommodate such a waste stream. A permissible solution to this problem would have to be engineered if this system is installed at the facility.

SCOT would also require a few non-fuel consumables of significant cost:

1. Catalyst for the reduction stage,

2. MDEA or proprietary blends of amines,

3. Corrosion inhibitors,

4. Water treatment chemicals.

Other processes evaluated would produce substantial ly greater solid or liquid waste streams requiring treatment and disposal off site. All processes evaluated represent anMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 4-3 increase in solid/liquid waste and energy consumpti on as compared with the current control option (SuperClaus).Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## 5.0 REMAINING USEFUL LIFE OF THE AFFECTED SOURCE

A brief history of MSCC operation was given in Sect ion 2.1. As a summary, the facility began operation in 1955, and has operated continuou sly since then. It is a privatelyheld, family business, now operated by second-gener ation management. Estimates vary on the typical useful life of SRU equipment, b ut in Bison’s view, it would be typical to expect plants to last about 40 years or more. Th anks to careful operation, quality maintenance and continual improvements in reliabili ty, this facility has exceeded that typical expectation. No specific additional life o f the sulfur recovery plant can be offered. The facility has operated under a successi on of essential contracts relating to raw material supply and gas processing. There is no way to assuredly predict if such contracts will continue or will cease. However, fo r purposes of planning, it would reasonable to assume that the facility, which remai ns serviceable, effective and reliable today, would continue to operate at least 15 years into the future.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## 6.0 VISIBILITY MODELING RESULTS

6.1 Visibility Modeling Results

As noted in Section 1 and elsewhere, no analysis wh ich purports to address or implement a plan for “reasonable progress” in visib ility improvement would be complete without ascertaining “visibility improvement.” An a nalysis of cost-effectiveness of alternatives, useful life and other factors could c ertainly play into a decision of what alternatives could be important, but only if such alternatives yield human-perceptible changes in visibility at a nearby mandatory Class I area. After all, visibility improvement in such areas is the sole purpose of the RHR progra m; and visibility is an aesthetic resource at its core, as perceived by the human eye and mind. Any proposal to reduce emissions must first, and foremost, yield visibilit y improvement that could indeed be observed as a result of such proposed emission redu ctions.

No monitoring data was found suitable to determine “visibility” impacts, if any, arising at MSCC in any nearby mandatory Class I area. In order to assess potential impacts to visibility, Bison conducted dispersion modeling for MSCC. 52 The modeling followed the general procedures outlined in the BART program. In the interest of brevity, a complete discussion of the model (Calpuff) and its multiple inputs are not presented in this report. The methods used, data inputs, output and so forth are all available upon request. The model effort conforms to the general procedures use d in previous BART and Reasonable Progress modeling conducted in Montana.

The emissions data used in the model were a measure of “actual” emissions. For this modeling effort, the base case model used the SO 2 rate that was derived from the calendar years 2008 – 2010. Table 6.1-1 summarizes the emission rates used in the baseline visibility modeling analysis.



### Table 6.1-1: Modeled Emission Rates

Pollutant lb/hour tons/year

SO 2 331.5 53 1,452

NOx 0.93 4.06

PM 10 0.106 0.465

A number of mandatory Class I areas were chosen for analysis. These included the following:

52 Bison Engineering, Inc. is a recognized expert in the field of dispersion modeling. Bison has conduct ed numerous PSD permit applications, SIP analyses and visibility impacts for various facilities and purpo ses. Bison conducted several BART analyses and is famili ar with the CALPUFF modeling system.

53 This SO 2 rate represents about 1/3 of the allowable emissio n rate at this stack per the FIP related to the NAAQS for SO 2 [40 CFR 52.1392(g)(3)(i)(A)].Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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Yellowstone National Park, UL Bend Wilderness Area, North Absaroka Wilderness Area,
Gates of the Mountains Wilderness Area.

These areas include all of the nearby areas coverin g the major quadrant directions.



### Figure 6.1-1: Location Class I Areas

As specified in the RHR and BART analysis guideline s, the visibility impacts were calculated and presented using the 98 th percentile modeled visibility impacts from MSCC’s 2008-2010 emission rate on these mandatory C lass I Areas. Table 6.1-2 below provides the results of the modeling using the emis sion rates in the table above. This represents the impacts “base case” emissions from t he facility assuming no additional controls are added to the current operation.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### Table 6.1-2: Base Case Visibility Impacts

Mandatory Class I Area Visibility Impact ( ∆ DV) 24-Hour Maximum

Yellowstone National Park 0.08

UL Bend 0.14

North Absaroka Wilderness Area 0.10

Gates of the Mountains Wilderness Area 0.08

From the data in the table, one observes that the h ighest modeled impact was 0.14 deciview at the UL Bend Wilderness located approxim ately 140 km NNE of the facility.

As an explanation, the deciview metric was develope d (and adopted by EPA) to more easily understand a measure of visibility change an d at the same time provide a more uniform (linear) representation of observed or mode led visibility impairment. More specifically, a “1.0” deciview impact is usually de scribed as a “just noticeable change” (JNC) in a visibility scene. 54

Therefore, it should be clearly understood that a 0 .14 deciview modeled impact is not discernible. As a result, MSCC does not contribute to regional haze at any mandatory Class I areas. That would be the case at current (2 008-2010) emissions or at Potential to Emit emission rates which are substantially high er. That alone reasonably exempts MSCC from consideration of any additional control o ptions that would otherwise be considered as candidates for visibility improvement or reasonable progress toward the 2064 goals.

The above discussion notwithstanding, it is worth n oting EPA’s position on what would be an acceptable impact from a new facility. EPA ge nerally considers an impact, by the facility alone, of less than 0.5 deciviews to be ac ceptable. Therefore, if MSCC were a new source of sulfur dioxide in the Billings area, its 2008-2010 emission impact on the

54 There are numerous articles and explanations for t he deciview metric. This discussion is taken from t he publication “IMPROVE,” Volume 2, No. 1, April 1993. The information itself is taken from a publication by Pitchford and Malm, 1993. The article contains the following quote: “Ideally, a just noticeable change (JNC) in scene v isibility should be approximately a
one or two

dv change in the deciview scale (i.e., a 10% to 20 % fractional change in extinction coefficient) regardless of the baseline visibility.” The idea that a “1” deciview change represents ‘jus t discernible’ to the human eye is also found in ma ny other publications and web sites such as the Arizon a Department of Environmental Quality and the “Group Against Smog and Pollution” (GASP) which may be found at: http://gasp-pgh.org/publications/hotline/spr02-2/ http://www.phoenixvis.net/education.htmlMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 6-4 mandatory Class I areas would be considered quite a cceptable, and definitely negligible at 0.14 deciviews, and also acceptable at levels es sentially three times as high. 55

The data in the table shows that MSCC, by itself as currently configured and controlled, has no perceptible change in visibility at any mand atory Class I area. It is reasonable to conclude that the addition of any additional emissi on controls cannot change that conclusion. Since the statutory purpose and authori zation of the program is to improve regional haze in Class I areas, toward a national g oal in the year 2064, and given MSCC does not now impact regional haze discernibly, no additional controls are warranted. Thus, the addition of controls or furthe r limitations at MSCC would not serve the program’s purpose of creating “reasonable progr ess” toward the national goal, since no measurable progress would be created.

55 See Appendix A for linear equation that predicts d eciview impact based on SO 2 emission rate.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## 7.0 ECONOMIC RESULTS AND IMPACTS TO VISIBILITY

The installation of any SOx controls would ultimate ly require two parallel systems at the MSCC facility. Parallel systems are required becaus e MSCC must operate the facility 8,760 hours a year to treat fuel and acid gases sup plied by the adjacent refinery. Redundant systems enable the current, and evaluated , systems to undergo maintenance and outages while still meeting the enf orceable short-term and long-term emission limits. Therefore, two systems (126 long t ons per day each) with a nominal capacity of half of MSCCs capacity (252 long tons p er day) were evaluated as part of this analysis.

As discussed in Section 2.4, sulfur recovery of the se technologies is based on sulfur removed from the feed gas streams and does not repr esent the percentage of SO 2 removed from the flue gas as emitted from the prese ntly controlled stack. In this section, these removal percentages will be referred to as su lfur recovery percentage and effective incremental SO 2 removal percentage.

The baseline SO 2 emission rate used for this analysis was 1,452 ton s/year. This emission rate was achieved with the current SuperCl aus TM units in place, as measured by CEMS. To identify the comparable incoming rates we have assumed the overall facility achieves 98.5% sulfur recovery from the fe ed gases, consistent with original vendor expectations for this retrofit. The quantity of sulfur dioxide equivalent in the feed gas can then be back-calculated to be 96,800 tpy du ring this period 56 . The theoretically achievable sulfur recovery percentages of each tech nology can then be applied to determine the effective SO 2 removal percentage. This is summarized in the tabl e below:



### Table 7.0-1: Theoretical Sulfur Recovery and Effec tive SO 2 

### Removal

Technology Theoretical

Sulfur Recovery % Representative

SO 2 Emission Rate (tpy) Calculated

Sulfur Dioxide in Feed Gas Based on 98.5% SuperClaus TM Recovery Resultant

SO 2 Emission Rate (tpy) Effective,

Incremental SO 2 Removal (%)

Sulfreen® 99.0% 1452 96,800 tpy 968 tpy 33.3%

SCOT 99.4% 1452 96,800 tpy 580.8 60.0%

MSCC and Bison worked to obtain capital and operati ng costs for these technologies. We contacted Jacobs Comprimo, one of the foremost c ompanies in the world with SCOT experience, to provide us approximate capital and operating costs for a SCOT-

56 Actual recoveries will vary, and actual feed rates also will vary over time. These were used for purp oses of comparison.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 7-2 type system at least theoretically feasible at the MSCC facility. Jacobs Comprimo estimated that the capital cost for two (redundant) 126 tpd systems would be in the range of $55,000,000 to $60,000,000 USD, 57 assuming the existence of adequate nearby plot space and adequacy of existing utilitie s and existence of a viable “sink” for sour water waste. This level of capacity would prov ide a level of redundancy, necessary to the normal operation of the facility 24/7/365. T ime allowed for estimation does not allow for customization or refinement of the estima te, which may be low by as much as 50%, and does not allow for assessment of availabil ity of sufficient plot space, or account for the cost of necessary support utilities , such as steam, power backup, and sour water handling.

Sulfreen® capital and operating costs were estimate d using information available on the web. The following presentation based on refineries in Europe using this technology was used to estimate capital and operating costs fo r this analysis:

Concawe Cost and Cost-Effectiveness Assessment of A batement Technology/Techniques for Refineries, Contributing to the Update of the EGTEI Synopsis Sheets for the Petroleum Sector

. 58

The cost data located in this resource yielded a ca pital cost estimate of $76,500,000 for two 126 tpd Sulfreen units.

Using these resources of information, we were able to roughly estimate the theoretical cost-effectiveness of these two types of technologi es. Table 7.0-2 summarizes the results of the potential addition of SOx controls a nd their emission reductions.

57 Estimates provided by Jacobs Comprimo were caveate d with an accuracy of -25% to +50%. The median of the capital cost estimate range, $57,500, 000 and a retrofit factor of 1.3 were used for this analysis.
58 Please see Appendix A for more details. The presen tation is available at http://www.citepa.org/forums/egtei/5-White-refineri es.pdf.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### Table 7.0-2: Cost-Effectiveness of Alternate SOx C ontrols

Technology Capital

Investment 59 Annual

Operating Cost 60 Sulfur

Recovery Efficiency (%) Tons SOx

Emitted after Control Tons SOx

Reduced (2010 baseline) Effective

SO 2 Removal Efficiency CostEffectiveness ($/ton)

Sulfreen® - Two 126 tpd Units $76,500,000 $18,980,254 99.0% 968 484 33.3% $39,215

Shell Claus Off-Gas Treatment (SCOT) – Two 126 tpd Units $74,750,000 $18,824,971 99.4% 580.8 871.2 60.0% $21 ,608

The potential visibility impacts of installing the more cost-effective of these two classes of controls, SCOT, were determined by predicting th e resultant effective ~60% control of SO 2 emissions from the SRU. 61 The highest predicted impact to the most impacted Class I Area (UL Bend) following control was compar ed to the highest 98th percentile impact from the baseline modeling. Table 7.0-3 summ arizes what the potential effects to visibility would be if this control was installed a nd the cost-effectiveness of this option in $/deciview. Note that “dollars/deciview” in this ca se is a misnomer. Since the maximum estimated “improvement” is imperceptible, at less t han 1 deciview, no amount of cost at MSCC can improve visibility by even one deciview.

59 Capital investment costs include retrofit multipli er of 1.3.

60 Annual Operating Cost includes maintenance, materi als, electrical costs, loan interest, and other cos ts. Please see Appendix A for more details.

61 Deciview impact was determined by a linear equatio n developed by modeling 50% and 99.9% control of the baseline emission rate. See Appendix A for m ore information.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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### Table 7.0-3: Cost-Effectiveness of SO 2 

### Control in $/Deciview

Control Option Emission

Rate (tpy) Max

Prediction ( ∆ DV) Class I

Area Impacted Incremental

Deciview Change Annual

Operating Cost CostEffectiveness ($/deciview)

Base Case,
current redundant controls 1452 0.136 UL Bend --- --- ---

SCOT, Two 126 tpd Units 580.8 0.053 UL Bend 0.08 $18,824,971 $226,730,391Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## 8.0 SUMMARY

As requested by EPA, MSCC, via Bison Engineering, h as analyzed its Sulfur Recovery Unit (SRU) at the facility for the purposes of meet ing the Reasonable Progress goals of the Regional Haze Rule (RHR). MSCC retained Bison E ngineering, Inc. to assist MSCC in evaluating possible control alternatives, in the extremely limited time frame provided for response.

The analysis concluded that the particulate matter and NOx emissions from the SRU facility are minimal (approximately 0.5 tpy particu late and 4 tpy of NOx). As a result, these small emissions would not reasonably be expec ted to impact regional haze at any nearby mandatory Class I area. (The nearest area i s approximately 120 km from the plant site.)

The analysis, given the severely limited time, was able to identify two potentially technically feasible alternate controls approaches for SO 2 : ECLT and RTGS. Sulfreen® and SCOT were selected and evaluated as being repre sentative of ECLT and RTGS, respectively. It should be noted that the technolog y presently employed at MSCC (Claus+SuperClaus TM ) is already roughly equivalent in published contro l effectiveness as ECLT. In addition, it is essential for the reade r to understand that combining these technologies does not result in cumulative benefits or reductions. Similarly, SuperClaus TM technology cannot be applied upstream of SCOT tech nology as the oxidative chemistry of SuperClaus TM is incompatible with the reduction technology invoked by SCOT.

As the intent of the RHR is to protect visibility i n mandatory Class I Areas, Bison also conducted visibility modeling. The modeling was con ducted to assess the predicted impacts from MSCC’s current facility emissions and from emissions that could result from the addition of alternative SO 2 controls. The modeling analysis has shown that current (and allowable) emission rates result in im pacts well below 1.0 deciview. EPA employs 1.0 deciview as a level to indicate a disce rnible visible impact. Also, EPA routinely considers an impact below 0.5 deciviews ( for new or modified facilities) as a permissible contribution to modeled visibility impa ct. Effectively, an impact less than 0.5 deciviews would be considered de minimis

. The alternative controls reviewed in this report al l result in modeled predictions much less than 0.5 deciviews. This conclusion is also va lid for current emissions as well as allowable emissions [40 CFR 52.1392(g)(3)].

The short time allowed for response (essentially fo ur weeks) did not allow sufficient review of other potential technologies that may hav e been considered given adequate time. However, even with the most effective proven technology typically applied to new Claus plants, irrespective of cost, no discernible visibility benefits accrue.

As part of the analysis, EPA requested that MSCC an alyze the costs of compliance related to the installation and operation of altern ative control technologies. These values have been analyzed as required despite a limited ti me and limited data. Regardless, theMontana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 Page 8-2 costs identified are very high both on both a ‘cost per ton of pollutant removed’ as well as a ‘cost per deciview improvement’ basis. EPA’s d ocument Guidance for Setting Reasonable Progress Goals under the Regional Haze P rogram 62 states:
“...the cost of compliance factor can be interpreted to encompass the cost of compliance for individual sources or source categor ies, and more broadly the implication of compliance to the health and vitality of industries within a state.”

The two technically “feasible” identified additiona l SO 2 control options identified would have major adverse impacts on the facility and its ability to remain in operation, and thus on its employees and owners.

As a result of all of the analyses conducted in thi s document, we conclude that no additional controls at the MSCC facility are consis tent with the Reasonable Progress national goals since:

(a) The cost of additional controls are excessive;

(b) The existing controls and operation MSCC facili ty does not demonstrate any discernible impact on any nearby mandatory Class I area;

(c) The addition of emission controls at MSCC would not improve discernible visibility attributes in any nearby mandatory Class I area.

62 Guidance for Setting Reasonable Progress Goals Und er the Regional Haze Program, U.S. Environmental Protection Agency Office of Air Quali ty Planning and Standards Air Quality: http://www.epa.gov/ttncaaa1/t1/memoranda/reasonable _progress_guid071307.pdf.Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

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## APPENDIX A –COSTS OF COMPLIANCE ANALYSISMSCCSOx Cost SummarySulfreen® with two, 126 t/d units99.0%96,800$76,500,000$18,980,2541,452968.048433.3%$39,215Shell Claus Off-Gas Treatment (SCOT)with two, 126 tpd Units99.4% 96,800 $74,500,000 $18,824,971 1,452 580.8 871 60.0% $21,608Average AnnualCost Effectiveness($/ton)SO2Control OptionSulfur %RecoveryTotal CapitalInvestmentTotal AnnualCostAnnualEmissionReduction(tpy)AnnualEmissionsAfter ControlReduction(tpy)Sulfur inFeedgas(tpy)Baseline SO2Emissions (tpy)EffectiveSO2Removal %Typical SuperClaus Sulfur Recovery: 98.5% Per MSCC, 3Stages %Representative SO2 Emissions out Stack: 1452 tpyBack Calculating SO2 in Feed Stock: 96800 tpyAdd On TechnologySCOT - two, 126tpd UnitsSulfreen - two, 126 tpdUnitsAssumed Recovery %: 99.4% 99.0%Resultant SO2 Emissions (tpy) 580.8 968.0Baseline Deciview Impact (No Control): 0.136 0.136Predicted Deciview Impact of Controla:0.053 0.09Deiview Improvement: 0.083 0.048Calculated $/Deciview Improvementb:226,730,391.18$ $393,944,655.64Notes:a Predictive equation derived based on highest modeled impact at the UL Bend Wilderness.Y =0.00009x+.0007SO2 Emission Rate (tpy) Deciview Impact Using Predictive Equation NotesWhere:1000 0.0907-Y = Deciview Impact1452 0.13138 Baseline Modeled RateX =SO2 EmissionRate (tpy)2000 0.1807-3000 0.2707-4000 0.3607-4355 0.39265 Maximum Allowed by Permit5000 0.4507-55480.5 Emission Rate to Have 0.5 deciview ImpactEmission Calculations and Deciview Impact SummaryPredictive Equation:$/Deciview improvement calculated by dividing the annual operating costs for each technology by thepredicted deciview improvement.b1000145220003000400043555000554800.10.20.30.40.50.60 1000 2000 3000 4000 5000 6000Deciview Impact vs. SO2 Emission Rate UsingPredictive EquationDeciview Impact vs. SO2Emission Rate UsingPredictive EquationLinear (Deciview Impact vs.SO2 Emission Rate UsingPredictive Equation)MSCCSO2 Control AnalysisCosts for TGTU (SCOT)Estimated using OAQPS example for Acid Gas RemovalBased on methodology described inEPA Pollution Cost Control Manual, 6th EditionJanuary 2002Section 5.2, Chapter 1 Wet Scrubbers for Acid Gas RemovalCost ItemFactorCostCost ItemCostDIRECT COSTSFixed Operating CostPurchased equipment costsNumber of systems required:2Size of System (Long Tons/Sulphur per Day);126Cost of system(s) + auxiliary equipmenta:25,648,107$Fixed Operating Cost (4%/y Capital Cost):Reference: http://www.citepa.org/forums/egtei/5-White-refineries.pdf$2,980,000Total system+ auxiliary equipmentA 25,648,106.60$Instrumentation0.10 A $2,564,811Sales taxes0.03 A $769,443.20Freight0.05 A $1,282,405Variable Operating CostPurchased equipment cost, PECB = 1.18 A$30,264,766$8.05/ton S ProcessedReference: http://www.citepa.org/forums/egtei/5-White-refineries.pdf$740,439Direct installation costsFoundations & supports0.12 B $3,631,772Handling & erection0.40 B $12,105,906INDIRECT ANNUAL COSTS, ICElectrical0.01 B $302,648Piping0.30 B $9,079,430 Administrative Charges2% of TCI $1,490,000Insulation for ductwork0.01 B $302,648 Property Taxes1% of TCI $745,000Painting0.01 B $302,648 Insurance1% of TCI $745,000Direct installation cost0.85 B$25,725,051Capital Recovery Factor (Annualized Capital Cost, 10 yrs at 10%)$12,124,532Retrofit Factor:1.3TOTAL ANNUAL COST (SCOT):$18,824,971Direct Installation cost Including Retrofit Factor:$33,442,56698.5% Per MSCC, 3 Stages %Site preparationAs required, estimate $100,0001452 tpyBuildingsAs required, Estimate. $100,00096800 tpyTotal Direct Cost, DC1.30 B + SP + Bldg.$63,907,332Baseline Emissions (tons/yr):1452Sulfur Recovery %99.4%INDIRECT COSTS (Installation)Effective SO2 Removal %:60.0%Engineering0.10 B $3,026,477Tons SO2 Emitted With New Control (tons/yr):580.80Construction and field expenses0.10 B $3,026,477Tons Removed (tons/yr)b:871.2Contractor fees0.10 B $3,026,477Start-up0.01 B $302,648Cost-Effectiveness ($/ton):$21,608Performance test0.01 B $302,648Contingencies0.03 B $907,943Total Indirect Cost, IC0.35 B$10,592,668TOTAL CAPITAL INVESTMENT (TCI) = DC + IC2.20 B + SP + Bldg.$74,500,000Notes:bTons SO2removed calculated by comparing the base case emissions to the tons emitted following add on control.aBased on vendor estimate of $55 - $60M for two, 126tpd capacity units. The capital investment was back calculated based on a total capitalinvestment of the median of this range ($57.5M). Aretrofit factor of 1.3 was used, resulting in the total capital investment of $74,750,000.Typical SuperClaus Sulfur Recovery at MSCC:Representative SO2 Emissions out Stack:Back Calculating Uncontrolled SO2:MSCCSO2 Control AnalysisCosts for Lower Temperature Liquid Phase (Sulfreen®)Estimated using OAQPS example for Acid Gas RemovalBased on methodology described inEPA Pollution Cost Control Manual, 6th EditionJanuary 2002Section 5.2, Chapter 1 Wet Scrubbers for Acid Gas RemovalCost ItemFactorCostCost ItemCostDIRECT COSTSFixed Operating CostPurchased equipment costsNumber of systems required:2Capacity of Each Unit (tpd)126Cost of system(s) + auxiliary equipmenta:$26,338,500Fixed Operating Cost (4%/y Capital Cost):Reference: http://www.citepa.org/forums/egtei/5-White-refineries.pdf$3,060,000Total system+ auxiliary equipmentA$26,338,500Instrumentation0.10 A$2,633,850Sales taxes0.03 A$790,154.99Freight0.05 A$1,316,925Variable Operating CostPurchased equipment cost, PECB = 1.18 A$31,079,430$4.46/ton S ProcessedReference: http://www.citepa.org/forums/egtei/5-White-refineries.pdf$410,231Direct installation costsFoundations & supports0.12 B$3,729,532Handling & erection0.40 B$12,431,772INDIRECT ANNUAL COSTS, ICElectrical0.01 B$310,794Piping0.30 B$9,323,829Administrative Charges2%of TCI$1,530,000Insulation for ductwork0.01 B$310,794Property Taxes1%of TCI$765,000Painting0.01 B$310,794Insurance1%of TCI$765,000Direct installation cost0.85 B$26,417,515Capital Recovery Factor (Annualized Capital Cost, 10 yrs at 10%)$12,450,023Retrofit Factor:1.3TOTAL ANNUAL COST (SCOT):$18,980,254Direct Installation cost Including Retrofit Factor:$34,342,77098.5% Per MSCC, 3 Stages %Site preparationAs required, estimate$100,0001452 tpyBuildingsAs required, Estimate.$100,00096800 tpyTotal Direct Cost, DC1.30 B + SP + Bldg.$65,622,200Baseline Emissions (tons/yr):1452Sulfur Recovery %:99.0%INDIRECT COSTS (Installation)Effective SO2 Removal %:33.3%Engineering0.10 B$3,107,943Tons SO2 Emitted With New Control (tons/yr):968.0Construction and field expenses0.10 B $3,107,943Tons Removed (tons/yr)b:484.0Contractor fees0.10 B$3,107,943Start-up0.01 B$310,794Cost-Effectiveness ($/ton):$39,215Performance test0.01 B$310,794Contingencies0.03 B$932,383Total Indirect Cost, IC0.35 B$10,877,800TOTAL CAPITAL INVESTMENT (TCI) = DC + ICa2.20 B + SP + Bldg.$76,500,000Notes:bTons SO2removed calculated by comparing the base case emissions to the tons emitted following add on control.Typical SuperClaus Sulfur Recovery at MSCC:Representative SO2 Emissions out Stack:Back Calculating Uncontrolled SO2:aEstimate based on "Concawe Cost and Cost-Effectiveness Assessment of Abatement Technology/TechniquesFor Refineries Contributing tothe Update of the EGTEI Synopsis Sheets For the Petroleum Sector" L. White, Special Advisor, May 6th ,2011,http://www.citepa.org/forums/egtei/5-White-refineries.pdfSulfreen Capital and Operating Cost ReferencesBased on: Concawe Cost and Cost-EffectivenessAssessment of AbatementTechnology/Techniques For RefineriesContributing to the Update of the EGTEISynopsis Sheets For the Petroleum SectorL. White, Special Advisor, May 6th , 2011Link:http://www.citepa.org/forums/egtei/5-White-refineries.pdfReference Size of Plant Used for Estimate: 33,333tS/yearReference Size of Plant Used for Estimate: 91tS/dayNominal Size of Plant at MSCC (tS/day) 252tS/dayNominal Size of Plant at MSCC (tS/year) 91,980tS/yearConversion from Euros to USD (January 2012): 1.3213http://www.google.com/search?q=%E2%82%AC+to+dollars&ie=utf-8&oe=utf8&aq=t&rls=org.mozilla:enUS:official&client=firefox-aYear of Cost Data2006Chemical Engineering Plant Cost Index 2006 499.6Chemical Engineering Plant Cost Index 2011 596Sulfreen (252 t/d) Sulfreen (Single 126t/d Unit) Sulfreen (2nd,126 t/d unit)Capital Cost Low (Euro)15,000,000 € 15,000,000 € ---Capital Cost High (Euro)25,000,000 € 25,000,000 € ---Capital Cost Median (Euro)20,000,000 € 20,000,000 € ---Cost vs. Unit Size (Cost Ref *(Feed Rate/Feed RateReference)^.636,772,351 € 24,260,704 € 48,521,408 €Convert Capital Cost to 2011 USD:57,962,440$38,240,949$ 76,481,898.65$Fixed Operating Cost (4%/y Capital Cost): 2,318,497.62$1,529,637.97$ 3,059,275.95$Sulfreen Variable Operating Cost Factor (Euro/tS)2.83 € 2.83 € 2.83 €Variable Operating Cost Factor (2006 USD/tS) 3.74$3.74$3.74$Variable Operating Cost Factor (2011 USD/tS) 4.46$4.46$4.46$Variable Operating Cost (USD): 410,303.39$205,151.70$ 410,303.39$SCOT Variable Operating Cost Factor (Euro/tS):5.11 €Variable Operating Cost Factor (2006 USD/tS) 6.75$Variable Operating Cost Factor (2011 USD/tS) 8.05$Annual Variable Operating Cost (USD): 740,865.84$Montana Sulphur & Chemical Company Regional Haze R ule Section 114 Response

2/6/12 

## APPENDIX B - MODELING

# Appendix B

Dispersion Modeling Report

Assessment of Visibility Impacts: Mandatory Class I AreasAppendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-1 

## 1.0 INTRODUCTION

This appendix provides a summary of the dispersion modeling conducted in support of MSCC’s response to EPA’s December 30, 2011, letter (received by MSCC on January 6, 2012). 1 Dispersion modeling was not specifically required in response to the request; therefore, this appendix is only a brief summary of the model and various options used. More details of model options along with all modeli ng input and output files are available upon request. Summary information is provided herei n.

The January 6, 2012, letter from EPA asked MSCC to “ Please submit an analysis of control options ” for the MSCC facility located near Billings, Mont ana. The request relates to EPA’s effort to “address requirements under the RHR for reasonable progress (RP) goals and strategies (see 40 CFR 51.308(d)(l) and 51.308(d)(3)).”

Although the request did not specifically seek or a ddress MSCC’s visibility impacts on any nearby mandatory Class I areas, we believe that such an analysis is required and appropriate in order to address the underlying requ irements of the RHR program.

We note that the entire program of protecting visib ility is found at 40 CFR 51, Subpart P (subsections 300 through 309). A review of Subpart P indicates the purpose and goals of the program. To begin, the overall purpose of th e program is outlined as follows:

“ The primary purposes of this subpart are . . .to as sure reasonable progress toward meeting the national goal of preven ting any future, and remedying any existing, impairment of visibility in mandatory Class I Federal areas . . . . ” [40 CFR 51.300(a)].

Insofar as regional haze is concerned, the followin g is noted when describing the “core requirements” 2 for an implementation plan for regional haze.

“ For each mandatory Class I Federal area . . ., the State must establish goals . . . that provide for reasonable progress to wards achieving natural visibility conditions. The reasonable progress goals must provide for an improvement in visibility for the most impaired days . . .” [40 CFR 51.308(d)(1)].

The rules go on to provide states (EPA in this case ) with what must be considered in developing reasonable progress. These details were outlined in the January 6, 2012, letter, which sought information relating to reason able progress goals.

1 The letter was dated December 30, 2011, by EPA. Th e letter itself was mailed on or after January 3 an d not received by MSCC until January 6, 2012. For pur poses of consistency, this letter will be reference d as the January 6, 2012, letter since that is the date on which MSCC first became aware of EPA’s request.

2 40 CFR 51.308(d).Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-2 The review of control options notwithstanding, it s eems the visibility program is clear as to its intent. That is, the purpose of the program is to protect visibility (remedy, prevent impairment) as perceived in mandatory Class I areas . Based on the 51.308(d)(1) language above, it is also quite clear that any act ivity or goal (proposed or otherwise) that does not “improve visibility” is not, therefor e, a candidate for those “reasonable progress” plans or goals.

As a result, we believe an analysis that only addre sses emission control options is not sufficient for inclusion into reasonable progress e lements unless those emission controls actually improve visibility. It would be a t odds with the program to include an emission control scenario that did not improve visi bility (i.e., did not predictably produce a discernible change in deciviews).

To that end, we have chosen to conduct an analysis of modeled impacts this facility has on the nearest mandatory Class I areas, and also to relate these numeric values to discernible visibility improvements. In order to co nduct the analysis we have chosen, as a matter of convenience and consistency, to follow the general elements of the BART dispersion modeling effort relating to visibility i mpacts. The modeling effort used by BART, including this submittal, is found in 40 CFR 51, Appendix Y.Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-3 

## 2.0 MODEL SELECTION

For this analysis, and as generally required by EPA for assessing visibility impacts, we used the CALPUFF dispersion model system. This is t he same system that was applied for the BART analyses carried out under 40 CFR 51.3 08(e). BART is, itself, an element of the regional haze program and an element in the overall protection of visibility found in 40 CFR 51, Subpart P.

CALPUFF is a non-steady-state Lagrangian dispersion model that simulates pollutant releases as a continuous series of “puffs.” It is s upported by two primary sub-programs, CALMET and CALPOST. CALMET is used in refined analy ses to simulate threedimensional wind fields based on multiple sources o f geophysical and meteorological data. The output of the CALPUFF model consists of b inary data files with information on pollutant concentrations, wet and dry flux rates, a nd visibility parameters. CALPOST processes these data based on specified input param eters or assumptions, and reports calculated impact values.

The CALPUFF analyses utilized for this project are noted below and were obtained from the CALPUFF developer, Atmospheric Studies Group (A SG) at:

http://www.src.com/calpuff/calpuff1.htm

. Geophysical Data Processors

• TERREL (Version 3.311, Level 030709)

• CTGCOMP

• CTGPROC (Version 2.42, Level 030709)

• MAKEGEO (Version 2.22, Level 030709)

Meteorological Preprocessors

• SMERGE (Version 5.31a, Level 040706)

• PXTRACT

• PMERGE (Version 5.31, Level 030528)

• READ62 (Version 5.52, Level 040716)

Main Models

• CALMET (Version 6.211, Level 060414)

• CALPUFF (Version 6.112, Level 060412)

Postprocessors

• CALPOST (Version 6.131, Level 060410)

• PRTMET

The version and level identifiers for the major mod ules used for this project are identified above. Electronic executable files for t he primary modules and the primaryAppendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-4 electronic input and output files associated with t his analysis are available upon request from Bison Engineering, Inc.Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-5 

## 3.0 CALMET

CALMET, the meteorological preprocessor for CALPUFF , was used to compile and process land use data, terrain data, and meteorolog ical data for use in the CALPUFF model. The CALMET output files define gridded field s of wind speed, wind direction, mixing heights, stabilities, micrometeorological pa rameters, and precipitation – all parameters required for input to the CALPUFF disper sion model. The following sections provide a brief description of each of these data s ets. The CALMET input files are provided on the portable hard drives that accompany this dispersion modeling report.



### 3.1 Land Use Data

CALMET uses specific land use data developed by the U.S. Geological Survey (USGS) [available for download from the USGS Earth Resourc es Observation and Science (EROS) web site]. The data files used by this proje ct are 1:250,000-scale files. Each land use cell, typically 200 meters square, is assi gned a land use code by USGS.



### 3.2 Terrain Data

CALMET uses USGS 1:250k Digital Elevation Models (D EMs) to determine the terrain elevation in the model domain. The terrain data are preprocessed into a data set recognizable by CALMET and used to help create the CALMET output file.



### 3.3 Meteorological Data

CALMET output files representing meteorological dat a for the 2001, 2002, and 2003 calendar years were prepared for this analysis. The input surface and upper air meteorological data and the Mesoscale Model version 5 (MM5) data (processed with the CALMM5 processor) are those data sets used for the Montana Best Available Retrofit Technology (BART) modeling conducted by EP A.

3.3.1 Mesoscale Model Data

The MM5 meteorological data for the 2001, 2002, and 2003 calendar years were obtained from the Western Regional Air Partnership (WRAP) web site at http://pah.cert.ucr.edu/aqm/308/bart.shtml . These data are generated by the CALMM5 processor from MM5 mesoscale meteorological model o utput files. The CALMM5 data have a spatial resolution of 36 kilometers. The mes oscale models are limited-area, nonhydrostatic or hydrostatic, terrain-following si gma-coordinate models designed to simulate or predict mesoscale and regional-scale at mospheric circulation. The data are used as a basis for generating an “initial guess fi eld” of multilayer meteorological parameters in CALMET.Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-6 3.3.2 Surface Data

Hourly surface meteorological data for 2001, 2002, and 2003 also were obtained from the WRAP internet site. This data set includes data from 39 locations for 2001 and 36 locations for 2002 and 2003. The WRAP data are in t he SMERGE format and are ready for input into CALMET Version 6. The data have been manually converted for use with CALMET Version 5.8 (involving only minor changes to the header records in the data files).

Surface data from the following locations were used in the CALMET analysis:

• Badger Peak, MT (2001 only)

• Billings, MT

• Bismarck, ND

• Boise, ID

• Bozeman, MT

• Butte, MT

• Casper, WY

• Coeur d’Alene, ID

• Cut Bank, MT

• Dickinson, ND

• Dillon, MT

• Estevan, SK

• Havre, MT

• Kalispell, MT

• Garfield Peak, MT (2001 only)

• Glacier National Park, MT

• Glasgow, MT

• Great Falls, MT

• Helena, MT

• Havre, MT

• Lander, WY

• Lewistown, MT

• Livingston, MT

• Medicine Hat, AB

• Miles City, MT

• Minot, ND

• Missoula, MT

• Morningstar, MT (2001 only)

• Peabody Coal, MT

• Pocatello, ID

• Rapid City, SD

• Rexburg, ID • Riverton, WY

• Salmon, ID

• Sheridan, WY

• Spokane, WA

• Spring Creek Coal, MT

• Theodore Roosevelt National Park, ND

• Williston, ND

• Yellowstone National Park, WYAppendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-7 3.3.3 Upper Air Data

Upper air rawinsonde data collected at seven Nation al Weather Service (NWS) stations were obtained from the rawinsonde data repository m aintained by the National Oceanic and Atmospheric Administration (NOAA) at http://esrl.noaa.gov/raobs/ . The data were provided in the standard FSL data format for use in the CALMET system. The seven NWS upper air rawinsonde locations used for this pr oject are:

• Bismarck, ND

• Boise, ID

• Glasgow, MT

• Great Falls, MT

• Rapid City, SD

• Riverton, WY

• Spokane, WA

3.3.4 Precipitation Data

Hourly precipitation data in the National Climatic Data Center (NCDC) TD-3240 format were obtained from the data set developed by the Mo ntana Department of Environmental Quality (MDEQ) for their BART modelin g analysis effort. All precipitation stations located within the CALMET modeling domain were extracted from the data set and used in the CALMET analysis. A total of 286 sta tions were selected for each of the three modeled years. A complete list of precipitati on stations is included in the CALMET input files.



### 3.4 CALMET Technical Options

The CALMET meteorological processor was executed us ing the technical options recommended in the EPA/IWAQM guidance, the EPA Mode l Clearinghouse memorandum of May 15, 2009, and the EPA-Federal Lan d Managers (FLM) Model Clearinghouse clarification memorandum of August 31 , 2009. A table of the values used is available upon request.Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-8 

## 4.0 CALPUFF

4.1 CALPUFF Technical Options

CALPUFF applies mathematical algorithms to calculat e pollutant concentrations at specified receptor locations. CALPUFF’s output file s contain concentration values for every receptor and every hour modeled. These output files must be processed through CALPOST to evaluate model results against regulator y limits or guideline thresholds. CALPUFF requires inputs of CALMET data files, sourc e characteristics and emission rates, and receptor grids to model impacts.

For brevity, a complete list of the technical optio ns chosen for this modeling exercise is not presented. As noted earlier, the same options u sed for the Montana BART analyses were used here as well. A copy of the technical opt ions along with all other input and output files are available on request.



### 4.2 Receptors The receptors chosen for this modeling were those o f the nearby mandatory Class I areas. The mandatory Class I areas chosen were:

• Gates of the Mountain Wilderness

• UL Bend Wildlife Wilderness Area

• North Absaroka Wilderness

• Yellowstone National Park

These four areas represent the closest areas to the facility and also display a relatively wide range in direction from the plant. The nearest of these areas is approximately 120 kilometers from MSCC’s location at Lockwood, Montan a. Figure B-1 below shows the relative distance from the MSCC facility.

The specific receptors used for the runs are the sa me as those generated by the federal land managers and used in the prior BART analyses. The exact receptor locations are not presented here to keep this report brief.Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-9 

### Figure B-1: Class I Locations and Distances 3

MSCC UL Bend

Yellowstone National Park

North Absaroka

Gates of the Mountain

120 Kilometers



### 4.3 Modeled Sources and Emission Rates The modeled source for this analysis was the MSCC f acility in Billings, Montana. Emissions from the Sulphur Recovery Unit (SRU) vent to a 100-meter stack. In very rare cases, emissions from the SRU will be routed t o a 30-meter stack, but this is uncommon. Certain low sulfur emissions are permitte d from the 30-meter stack, although such emissions are rare and have not occur red since before 1998.

3 Map obtained from: http://wrapfets.org/map.cfm?StartDate=02%2F04%2F201 2&EndDate=02%2F04%2F2012&SumSelector= V2MapXMLEvents.cfm&view=Lower48&vMapZoom=7&vMapCent erLat=45.85176&vMapCenterLon=- 109.127197265625&StartDateObj=&EndDateObj=&vMapType =Terrain&clust=&full_submit=Submit&tribe =on&class1=onAppendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-10 The emission rate for this analysis was based on (a pproximately) the average emission rate of 2008 through 2010, the most recent reportin g years. 4 Additional modeling was conducted using arbitrarily lower emission rates (5 0% and 99.9% reduction to SO 2 ) that were based on control option analyses contained in this report so that an estimate could be made of the impact a specific option could have on the nearest mandatory Class I

areas. 5

The baseline emission rates 6 used in the model are shown in the table below.



### Table B-1: Modeled Emission Rates

SO 2 (tpy) NOx

(tpy) PM 10

(tpy)

1,452 4.1 0.47

4 The BART analysis (40 CFR 51, Appendix Y) used emi ssion years from early 2000. It was decided to use the two most recent years of data as a better r epresentation of impacts.

5 For reference, the nearest mandatory Class I area is about 120 kilometers from the plant.

6 Baseline means the emission rate (as discussed in footnote 4 above) and does not include the effect o f the control options discussed elsewhere in this doc ument.Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-11 

## 5.0 CALPOST CLASS I VISIBILITY ASSESSMENT

Visibility impacts (expressed in terms of percentag e change in 24-hour average background extinction relative to natural backgroun d visibility) were calculated using the CALPUFF modeling system and data. The analysis was conducted using concentration files produced by CALPUFF and CALSUM. The visibility assessment is based solely on the MSCC facility.

The methods recommended in the BART program were fo llowed in the visibility analyses. CALPOST Version 6.131, Level 060410 was u sed in these analyses. The technical options employed in the CALPOST analyses are not presented here for the sake of brevity. It is noted, however, that some vi sibility options are specific to the mandatory Class I area being evaluated. Those area- specific data were applied as appropriate.Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-12 

## 6.0 RESULTS

6.1 Visibility Analysis

The methodology for the visibility analysis portion of this project is the same as the methods used for the BART program discussed elsewhe re in this appendix. The analysis is conducted by calculating concentrations of particulate, sulfate, nitrate and other compounds in the atmosphere from the modeled facility in question. The concentration of those compounds in the atmosphere is used to estimate changes to visibility that could occur.

Impacts to natural background visibility, expressed in terms of percentage change in 24-hour average background extinction ( **∆** Bex) were calculated by CALPOST processor (an integral part of the CALPUFF modeling system). The BART guidelines also reference 40 CFR §51.301(a) in asserting that determinations must be made on a “...case-by-case basis taking into account the geog raphic extent, intensity, duration, frequency and time of visibility impairments....” In accordance with 40 CFR 51, Appendix Y, the 24-hour average 98th percentile imp act results are summarized in the following table.

To serve as a baseline, the table below shows the r esults of the CALPUFF modeling results. The data uses a baseline emission rate tha t approximates the 2008-2010 average rate and assumes no additional controls as discussed in the main document. The emission rates were shown in Section 4.3 above.



### Table B-2: Visibility Impacts: Baseline 2008-2010 Case

Class I Area Visibility ( ∆ DV) % of a Discernible

Change in Visibility % of a ‘de minimis’ Change in Visibility

Yellowstone National Park 0.08 8% 16%

UL Bend 0.14 14% 27%

North Absaroka 0.10 10% 20%

Gates of the Mountains 0.08 8% 16%

The results of this analysis are revealing. The dec iview values themselves represent the change in modeled visibility ( **∆** DV) that could occur as a result of the facility as currently operating. The values in the table are al l below 0.5 deciview (see comparison in the last column). EPA has used this ‘ threshold” value for some time as a measure and demonstration of a non-measurable or nil impact, for example in new source permitting. The modeling analysis has shown that current emission rates also result in impacts well below the 1.0 deciview level (see column 3) EPA also employs as a level to indicate that a source causes a visib ility impact, and are also below theAppendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-13 0.5 deciview level that EPA has proposed as the lev el at which even a new source may contribute to a visibility impact. According to general guidance, if a facility’s impact, by itself, is less than 0.5 dv, then the fa cility’s impact is de minimis

.
Since the impact predicted from this facility, with out the consideration of additional reduction or controls, is de minimis , then clearly the addition of additional controls contributes nothing toward the national goal or tow ard reasonable progress. Since the addition of controls does not create any “progress” toward the national goal, no additional controls at MSCC constitute “reasonable progress.”

As a matter of interest, it was decided to provide an estimate of the improvement to visibility, regardless how small, that would be exp ected to occur, based on the model, as a result of reducing emissions beyond their curr ent baseline level. Since a particular strategy is not up for discussion, it wa s decided to execute the model using a 50% and 99.9% reduction of SO 2 . These two values, coupled with the base case, made it possible to estimate visibility impacts fro m any number of possible emissions scenarios. 7 These reductions are consistent with the lower end and highest reductions from SO 2 controls (e.g., Flue Gas Desulfurization and Shell Claus Off-Gas Treatment).

The results of the modeling are shown in the tables below.



### Table B-3: Visibility Impacts: 50% Reduction SO 2

Class I Area Visibility ( ∆ DV)

Baseline After 50% Reduction “Improvement”

to Visibility “Improvement”

Discernible or Greater than De Minimis?

Yellowstone National Park 0.08 0.04 0.04 No

UL Bend 0.14 0.07 0.07 No

North Absaroka 0.10 0.05 0.05 No

Gates of the Mountains 0.08 0.04 0.04 No

7 It is known, a priori

, that the model provides a linear relationship bet ween emissions and ambient (visibility) impact; provided that there is only on e source, stack parameters remain constant, and oth er visibility pollutants (NOx and particulate) are zer o or near zero. All of the above conditions are met for this analysis. The modeling that was done here prov ides empirical evidence that such is the case. The results, presented below, showed a straight-line (l inear) impact. These results were then used to determine visibility impacts from a particular scen ario (specific equipment such as Scot).Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-14



### Table B-4: Visibility Impacts: 99.9% Reduction SO 2

Class I Area Visibility ( ∆ DV)

Baseline 99.9%

Reduction 8 “Improvement”

to Visibility Improvement”

Discernible or Greater than De Minimis?

Yellowstone National Park 0.080 0.000 0.080 No

UL Bend 0.14 0.001 0.14 No

North Absaroka 0.10 0.001 0.10 No

Gates of the Mountains 0.08 0.000 0.08 No

The results of these model runs (which do not relat e to any particular equipment under consideration in the body of this report) sho w a linear relationship between the SO 2 emission rate and visibility impacts. Appendix A c ontains a graphic showing the relationship between SO 2 and visibility.

The above analysis makes three conclusions clear:
(i) The emissions from the MSCC facility, as config ured, lead to no predicted (or otherwise observed) visibility impacts at any n earby Mandatory Class I

areas. (ii) The addition of emission controls at MSCC woul d lead to no humanly perceptible improvement in visibility (regional haz e) at any of the nearby Mandatory Class I areas.
(iii) The modeling and graphic illustrate the expec ted linearity of the subliminal (imperceptible) modeled effects.

To complete the discussion, the table below has bee n created to compare the modeled visibility impact of the MSCC facility in a range of emission scenarios including allowable, actual and with additional con trols. The table shows that the MSCC facility in any configuration does not yield a discernible impact on the mandatory Class I areas. In addition, all of the sc enarios show an impact below ‘de minimis.’

8 The 98 th percentile value for Yellowstone National Park and the Gates of the Mountains was below the reporting algorithms of the model. This means t hat the predicted visibility impact at the Park wou ld be less than 0.0005 deciviews.Appendix B MSCC 2/6/2012 Section114 Request

Visibility Modeling Report Page B-15



### Table B-5: Visibility Impacts: Multiple Scenarios

Class I Area Emission Scenarios

Allowable (FIP & Permit) Actual

(2008 – 2010) 50%

Reduction in Actuals 90%

Reduction in Actuals

Yellowstone National Park 0.25 0.08 0.04 0.01

UL Bend 0.43 0.14 0.07 0.01

North Absaroka 0.31 0.10 0.05 0.01

Gates of the Mountains 0,24 0.08 0.04 0.01

Units: Deciviews ( ∆ DV) – reported to 2 decimals

Note: All values are less than discernible visibi lity impacts and all values are less than 0.5, the de facto ‘de minimis’ value for an impact on a mandatory Class I area.

Therefore, the only logical and reasonable conclusi on for this report is that existing controls and emission limitations are sufficient, a nd no additional emission controls or restrictions at this facility are justified based o n reasonable progress or the national goal of improved visibility at Class I areas.