## Minnesota Pollution Control Agency

520 Lafayette Road North 

### I 5t. Paul, Minnesota 55155-4194 

### I 651-296-6300

800-657-3864 I 651-282-5332 TTY I www.pca.state.mn.usIEqual Opportunity Employer

August 29, 2011

Ms. Susan Hedman Regional Administrator (R-19J)
U.S. Environmental Protection Agency Region 5
77 West Jackson Boulevard Chicago, Illinois 60604

RE: Proposed Amendment to Minnesota's State Implementation Plan for Sulfur Dioxide

Dear Ms. Hedman:

The Minnesota Pollution Control Agency (MPCA) hereby submits to the U.S. Environmental Protection Agency (EPA) a request for revision of Minnesota's State Implementation Plan (SIP).

The revision concerns Flint Hills Resources (FHR), which has facility-specific restrictions as part of
Minnesota's SIP for sulfur dioxide (S02) in the Pine Bend area of Dakota County. Minnesota's SIP currently includes an Administrative Order issued to FHR, which contains emission limits and other
conditions necessary to attain the S02 National Ambient Air Quality Standard.

The SIP revision is necessary to allow for changes at FHR that impact the S02 modeling parameters.
These include re-routing of process gases, improved energy efficiency of part of the facility, and
installation of a new boiler. Overall, the changes result in a decrease of S02 emissions. The SIP revision
also generally updates the description ofthe facility and emission points to match MPCA's current practice, and to account for actions that have already been taken.

This submittal includes the Amended Findings and Order issued to FHR and supporting technical documentation, including modeling. The MPCA hereby requests that EPA include the Amended Findings
and Order into the SIP, replacing the version of the Order approved into the SIP on July 19, 2007 (72 FR 39568).

A full and accurate electronic copy of all the enclosed materials comprising this SIP submittal is included

on the accompanying compact disc sent to EPA SIP staff. The disc also includes detailed modeling files
for review.Ms. Susan Hedman Page 2 August 29, 2011

Please contact Catherine Neuschler of my staff at 651-757-2607, 

### if you have any questions regarding this
submittal.

# SinC~;J 

# W 

# .C---

Paul W. Aasen Commissioner

PWA/CN:sth

Enclosures

cc: Kathleen D'Agostino, EPA Region 5 (with enclosures)

### 1 

### Background Information for SIP Revision

Flint Hills Resources, Rosemount, MN
This document describes the State Implementation Plan (SIP) revision for Flint Hills Resources Pine Bend Refinery located in the Rosemount/Pine Bend area of the Twin Cities SO 2 

### maintenance area for the three-hour, 24-hour, and annual SO 2 

### National Ambient Air Quality Standards (NAAQS). Flint Hills Resources (FHR) is subject to an Administrative Order (Order) containing SO 2 

### emission limits in order to
ensure that the Pine Bend area continues to maintain the SO 2 

### NAAQS.

The MPCA is amending the Order and requests that EPA include the amended Order into the SIP, replacing the version of the Order approved into the SIP on July 19, 2007 (72 FR 39568).

Because this is the ninth time that the Order for FHR has been amended, the proposed SIP revision is referred to as “SIP9”, particularly in discussions about modeling. The version of the Order currently approved into the SIP, as of 2007, is referred to as “SIP8”.

1. Reasons for Changes to the Administrative Order

FHR requested changes to the SIP-included Order and its associated facility permit in order to make certain changes at the FHR facility. These changes include the following:

• Re-routing process gases from the 34H-3 Merox Incinerator (EU245) to the 31H-2 heater (EU055);

• Improving the energy efficiency of the 94H-1 o il separation and waste treatment plant (OSWTP) Thermal Oxidizer (EU282); and

• Installation of a new boiler (labeled as B-10 in the modeling).

Merox Incinerator Project

The main reason for this SIP revision is to allow for the shutdown of the Merox incinerator, identified as 34H-3 (EU245), and rerouting of gases to another process heater. FHR recently conducted a process hazards analysis on the Merox incinerator, which showed that there are not the desired levels of protection in place to adequately mitigate a potential hazard associated with possible flameout. FHR generally considers three independent layers of protec tion necessary for ensuring safety for scenarios of this sort, while the Merox in cinerator has two layers.

In addition, the Merox incinerator was originally designed to incinerate gases from FHR’s Sulfur Recovery Units #1 and #2. These units are no longer in operation. Because of this initial purpose, the
Merox incinerator is over-sized an d inefficient in dealing with the smaller gas streams it currently handles, using a large amount of fuel gas for destroying the off-gas vapors.

FHR has therefore chosen to reroute or recycle the gas streams that curre ntly go to the Merox incinerator. One of the gas streams can be recycled, but the off-gas from the Merox treating process must be incinerated due to its mercaptan content. The Merox off-gas will theref ore be rerouted to the 31H-2 process heater (EU055). Rerouting the gases to the 31H-2 process heater allows FHR to take

### 2 advantage of a heater that is already being fire d and therefore will result in a reduction of NO X 

### , CO, and greenhouse gas emissions. The Merox incinerator will then be shut down. The Order adds emission limits for the 31H-2 process heater in Table 1.

The proposed changes reduce overall emissions, but a SIP revision is needed due to the impact on emissions and stack parameters on the 31H-2 process heater. In addition, the changes allow FHR to continue to use the 34H-3 Merox incinerator, in case technical issues arise in re-rerouting the process gases to the 31H-2 heater. For this reason, the Orde r retains emission limits on the Merox facility in Table 1; these emission limits are significantly more stringent than the current SIP limits.

94H-1 Thermal Oxidizer Project

FHR is also requesting changes to the Order that impact emission point 94H-1 (EU282), the primary thermal oxidizer for the oil separation and waste treatment plant (OSWTP). FHR plans to improve the energy efficiency of the oxidizer through a convection stack/heat exchanger repl acement. This results in lower stack temperature, which is reflected in the incorporated modeling exhibit.

In addition, language in the Order has been changed to clarify how fuel is used in the OSWTP thermal oxidizers, both the main 94H-1 oxidizer and the backup 94H-3 oxidizer. Both Part II of the Order and a footnote to Table 1 of the Order have been revised in order to clarify that, except when gases are in the process of being switched from one oxidizer to the ot her, only one oxidizer at a time may combust gases from the OSWTP equipment. When one oxidizer is co mbusting OSWTP gases, the other oxidizer may be firing natural gas for standby purposes. This change reflects current practice and what MPCA and FHR believe to have been the intent of previous SIP revi sions, but makes the associated language more clear.

Installation of B-10 Boiler

FHR also desires to have the flexibility to add an additional boiler in the future. FHR included a new boiler (Boiler 10) in the modeling co nducted for this SIP revision, in order to receive authorization to install a new boiler under the SIP. FHR has not yet f iled the necessary permit applications to add this
boiler.

Modeling of the new boiler was done based on the emission rates and stack parameters of FHR’s existing Boiler 9. FHR’s boilers have not been subj ect to specific emission limits in Table 1 of the Administrative Order; however, the Order prohibits the Company from operating a new or modified emission unit “in a manner contrary to the modeling parameters” in the modeling exhibit which is incorporated by reference in the Order. This SI P revision will add modeling parameters for Boiler 10.

Decoking Scenarios

In this SIP revision, FHR is also taking additional restrictions on steam-air de coking activities. Currently, FHR is limited to decoking operations of 432 hours per ye ar at each of four of th e facility’s heaters. The heaters are designated as 21H-1/EU032, 21 H-2/EU033, 23H-1/EU037, and 23H-2/EU038.

### 3 With this revision, FHR is taking an additional rest riction reflecting current operations . The restriction
allows 23H-1 and 23H-2 to be decoked simultaneous ly, but prevents the 21H-1 and 21-H2 from being decoked concurrently or when the 23 unit heaters are being decoked. This change is reflected in the modeling for all averaging times of 24 hours or shorter.

Other Updates

The changes to the Order also refine emissions rates for refinery fuel gas combustion and heater steamair decoking activities. Other changes serve to ma ke some supporting monitoring and recordkeeping requirements in the Order consistent with those de rived from other federal rules (such as NSPS and federal ultra-low sulfur diesel requirements), to avoid unnecessary duplicative reporting. Descriptions of equipment or emission points have been revised to be consistent with MPCA’s current emission unit numbering scheme and FHR’s Title V permit.

In addition, this revision updates stack exit temperature, ve locity data, and SO 2 

### emission rates for various other emission units. Finally, the update ge nerally serves to clarify the requirements of the Order by removing references or placeholders to requirements that have previously been removed from the Order and by also clarifying or removing completed requirements. The resulting Order will replace all previous versions of the Order.

2. Changes Made to Administrative Order

The specific changes made to the Administrative Order are listed below, by section of the Order.

General Changes

• Owner name change from Flint Hills Resources, LP to Flint Hills Resources Pine Bend, LLC.

• Removal of the notation [removed] in various pa rts of the Order, and subsequent renumbering.

• Throughout the Order, changes to the way emission points are numbered or described, as shown in the table in Attachment 3. These changes were made to ensure consistency with MPCA’s current emission unit numbering system, used in the facility’s Title V permit.

Findings

• Findings changed to more clearly reflect past events.

• Removal of findings related to the Sulfuric Acid Units, as these units have been shut down and
were removed from the SIP in the most recent revision.

• Changes to findings related to prior SIP revision to reflect EPA approval.

• Additional finding describing the changes being made in this amendment to the Order.

Order, Part I: Company Property and Access Restrictions

• Changes language that says a guard, FHR employee or contractor from “is present controlling” access to “patrols and moni tors” access at a gate.

### 4 Order, Part II: Sulfur Dioxide Emission Control Plan and Compliance Schedules

• Removal of references to Part A (previously marked as removed), which contained required modifications and compliance schedules. Thes e modifications have been completed.

• Removal of language relating to retained PSD em ission reductions from fuel oil combustion sources that no longer combust refinery fuel oi l. This is no longer relevant. Language was retained, with slight modification, prohibiting the combustion of refinery fuel oil at the facility.

• Refinement of language relating to the combustion of OSWTP gases and natural gas in the OSWTP oxidizers, as described in the section concerning 94H-1, above.

• Addition of language saying that the facility ma y burn natural gas at any combustion source, as long as the company measures the total amount of natural gas burned in the refinery, clarifying that the Facility may keep track of gas usage on a facility basis rather than a unit basis.

• Provisions allowing for the burning of gas not take n from the refinery gas system if the gas is categorically exempt or inherently low in sulf ur content based on the provisions in EPA’s standards of performance for petroleum refineries, NSPS J and Ja. The facility is already allowed to burn refinery fuel gas at all existing emission units.

• Changes to reflect the fact that the #3 Crude Expansion Project is complete and that the continuous monitoring systems (CMS) required afte r the start up of that project are to be operated.

• Reduction in diesel fuel sulfur content from 0. 05% by weight to 0.0015% by weight (15 ppm) in the facility’s stationary diesel engines.

• Change in recordkeeping for diesel fuel sulfur content, from written certifications to the Certificates of Analysis required by the federal Ultra Low Sulfur Diesel rule.

Order, Part III

• Part III of the Order has previously been removed. In this revision, the placeholder is removed and subsequent parts of the Order are renumbered.

Order, Part IV (now Part III): Changes Not Requiring a Modification of This Order

• Several specific modifications allowed under this part were previously completed, so authorization to make those changes has been removed.

• Language allowing the changes as pa rt of this project was added.

Order, Part V (now Part IV): General Monitoring Requirements

• Addition of language so that the Merox incine rator monitoring will also apply to the 31H-2 heater that will now combust the process gase s, as FHR intends to move the continuous monitors currently on the Merox incinerator to the 31H-2 heater when the process gas stream is
rerouted.

• Changes to the fuel gas sulfur monitoring requirements. The first change requires FHR to
maintain an SO 2 

### CMS for 45 unit mix drum fuel gas; this monitoring was already an available option under the Order. The second change is the addition of a CMS to measure reduced sulfur

### 5 in the 41 unit mix drum fuel gas stream. The third change is that continuous measurement of hydrogen sulfide content of the refinery fuel gas will only be required for heaters that receive refinery fuel gas that is not inherently low in sulfur or categorically exempt under NSPS J/Ja.

Order, Part VII (now Part VI): Reporting Requirements

• Addition of language that allows MPCA to extend certain deadlines for notification of performance tests or monitoring certification tests.

• Removal of requirement to notify the MPCA of specific changes made under the “Changes Not Requiring a Modification of This Order”, as these changes have already been completed.

Table 1: Emission Limits

• Reduction in emissions from emission poin t 1, the Merox TO facility, from 230 lbs SO 2 

### per hour and 1007.4 tons SO 2 

### per 12 months to 65.4 lbs SO 2 

### per hour and 286.4 tons SO 2 

### per 12
months.

• Reduction in emissions from emission po int 8, the FCC facility, from 1500 lbs SO 2 

### per hour and
3504 tons SO 2 

### per 12 months to 182.6 lbs SO 2 

### per hour and 800 tons of SO 2 

### per 12 months.

• New emission limits for emission poin t 34, the 31H-2 heater, of 66.4 lbs SO 2 

### per hour and 290.8
tons SO 2 

### per 12 months.

Table 2: Limits on Diesel Powered Equipment

• Removal of hours of operation limit on five di esel engines, which are located at the cooling tower. These limits were originally taken to en sure compliance with the annual standard. Due to reduced sulfur content of diesel fuel and the fact that the facility no longer burns refinery fuel oil, these limits are no longer necessary in or der to ensure compliance with the standards.

3. Emission Changes

The changes being made with this SIP revi sion result in significantly reduced SO 2 

### emissions from the facility, as shown in the table below and desc ribed in more detail in Attachment 4.

Table A: Emission Changes for Each Averaging Time

Emissions Averaging Period 1-Hour 3-Hour 24-Hour Annual Net Emissions Change in g/s -215.6 -207.0 -2 07.0 -106.5 Net Emission Change in lb/hr -1570 -1641 -1641 Net Emission Change in tpy -3699 Net % Change in Emissions -61% -60% -63% -52%

### 6 4. Modeling Data

The tables below show the ambient SO 2 

### concentrations predicted by AERMOD (v09292) modeling, both before and after the completion of the projects outlined in this SIP revision. These results include both FHR and nearby sources. Although the modeling predic ts a slight increase in ambient concentrations, the predicted “after” concentrations remain well be low the existing state one-hour standard and federal three-hour, 24-hour, and annual standards.

Table B: SIP9 Modeling Summary of SO 2 

### Attainment Modeling Demonstration Before and After Merox Project (Short Term Standards) All Concentrations in μg/m 3

Standard 21H-1 Decoking Scenario

Before 21H-1 Decoking Scenario

After 21H-2 Decoking Scenario

Before 21H-2 Decoking Scenario

After 23H-1,2 Decoking Scenario

Before 23H-1,2 Decoking Scenario

After 1-Hr Avg H2H 1300 (MN) 531 664 531 656 606 650 % of Std 45% 55% 45% 55% 51% 54% 3-Hr Avg H2H 1300 240 483 241 473 333 401 % of Std 21% 40% 21% 39% 28% 33% 24-Hr Avg H2H 365 108 155 108 155 117 150 % of Std 34% 47% 34% 47% 37% 46%



### Table C: SIP9 Modeling Summary of SO 2 

### Attainment Modeling Demonstration Before and After Merox Project (Annual Standard) All Concentrations in μg/m 3

Standard 1 μg/m 3 Before Merox Project (All Decoking) After Merox Project (All Decoking)

Annual Avg 80 24 31 % of Std 30% 38.8%



### However, this before and after modeling does not represent an exact comparison between the existing approved SIP and the proposed SIP, due to some mo del source parameter changes. The most recent SIP modeling for Flint Hills was conducted in early 2006 for the SIP amendment submitted to EPA in May 2006 and approved in July 2007 (SIP8). This mo deling was conducted us ing ISCST3 and 1973 – 1977 meteorological data. In December 2006, as shown in 40 CFR Part 51, Appendix A, EPA made AERMOD the preferred dispersion model. In addition, the MPCA has developed updated meteorology data for the years 2000 – 2004, which was used in the SIP9 mode ling. AERMOD is genera lly considered a more conservative model, and thereby ofte n predicts higher concentrations.

For informational purposes, FHR completed a modeli ng run of the current SIP conditions using AERMOD; these results were compared with the AERMOD results for the changes being proposed with this SIP

1 The standard of 80 μg/m 3 is the existing federal standard. Minnesota al so has a state secondary standard of 60 μg/m 3

.

### 7 revision. Table D, below, compares the ICSCT3 mode l results of the approved SIP with AERMOD model results for the approved and proposed SIP scenarios.

Table D: Comparison of Modeling for Current SIP8 and Proposed SIP9
All Concentrations in μg/m 3

Averaging Period Background Used for

SIP8 Total Impacts ISCST3 SIP 8 % of Std Total Impacts Informational

AERMOD SIP8 % of Std Background Used in Proposed SIP9 Total Impacts AERMOD SIP9 % of Std

One-Hour (MAAQS) 52.1 1111 85% 4084 314% 56 720 55%

Three-Hour 36.5 726 56% 1802 139% 34 517 39% 24-Hour 10.4 267 73% 447 123% 17 172 47% Annual 6.1 38.5 48% 24 30% 4 35 44%



### The modeling of the approved SIP represents maximu m emission rates that in some cases are higher than the current potential to emit from the units. In addition, it represents all four heaters being decoked at the same time for all averaging times, while the proposed SIP modeling results show the highest concentration indicated by any one of the th ree decoking scenarios for the short-term averaging periods. The annual average continues to reflect al l heaters being decoked simultaneously. As noted previously, FHR is taking limitati ons on the decoking scenarios.

The model results in Table D demonstrate that, when compared to the existing SIP, the changes being proposed result in decreased ambient air concentr ations. In particular, using the same model and meteorology data, shows fairly significant decrease d ambient concentrations for all the short-term averaging times. Predicted concentrations are well be low the existing state one-hour and federal threehour, 24-hour and annual standards. More in formation can be found in Attachment 4.

5. New NAAQS and Monitoring Data

In June 2010, EPA promulgated a new, lower, federal one-hour SO 2 

### standard. The modeling in this SIP revision addresses only the federal three-hour, 24-hour and annual average standards for SO 2 

### , along with the state one-hour standard. This modeling an alysis is not intended to demonstrate compliance
with the new federal one-hour standard.

The model parameters are quite conservatively represented and need further refinement and appropriate background concentrations needs to be determined. In addition, the modeling conducted here was for comparison to the state one-hour stan dard (a high-second-high form) rather than the federal one-hour standard (a 98 th



### percentile or high-fourth-high form).

In June 2011, the MPCA will submit to EPA a designa tion recommendation for the one-hour standard. Based on EPA guidance, the MPCA will be recomme nding an unclassifiable designation for Dakota County, which includes Flint Hills Resources. This uncl assifiable designation is due to a lack of refined modeling conducted in the appropriate fashio n for FHR or other facilities in the area.

### 8 Ambient air monitoring around the FHR site shows attainment of the current ambient standards along
with the new one-hour standard.

Table E: SO 2 

### Monitoring Result Around Flint Hills 2



### Monitor FHR 420
27-037-0020 

### FHR 423
27-037-0423 

### FHR 442
27-037-0442 

### FHR 443
27-037-0443 

### Standard Years Design Value Design Value Design Value Design Value 1-hour (75 ppb) 2008-2010 20 11 3 2 24-hour (140 ppb) 2010 5.3 4.5 2 2.1

Annual (30 ppb) 2010 0.79 0.68 0.21 0.24

In Summer 2011, the MPCA will collect modeling parame ters for all sources with a potential to emit or allowable emissions over 100 tons per year. The MP CA will then conduct modeling to determine those sources that may cause or contribut e to an exceedance of the one- hour NAAQS. The MPCA will work with these sources to identify enforceable emission reductions that will prevent the source from causing or contributing to an exceedance. These enforceable emission reductions will be included in the SIP due to EPA in June 2013, and compliance will be requi red so that attainment with the one-hour SO 2 

### standard will be shown by the attainment date of July 2017. MPCA fully expects that the area around FHR will attain the new standard, and will submit additional enforceable emission limitations, if shown to be necessary through modeling, for FHR in the June 2013 SIP submittal.

As shown above in Table D, the emission reductions from this SIP revision (shown in Table A) make substantial progress in reducing the modeled one-hour ambient SO 2 

### impacts from FHR.

2 Information on the actual location of these monitors can be found in Appendix A of Minnesota’s Air Monitoring Network Plan, at http://www.pca.state.mn.us/index. php/view-document.html?gid=13401 , pgs A-9, A-10, A-13, and A-14.

### Attachment 1: Administrative Order Issued to FHR, Including Modeling Exhibit

### Page 1 of 22 

### STATE OF MINNESOTA MINNESOTA POLLUTION CONTROL AGENCY

In the matter of Flint Hills Resources Pine Bend, LLC

Proceedings to Develop and Implement a State Implementation Plan for the Pine Bend Industrial Area, Rosemount, Minnesota, to Demonstrate, Attain and Maintain Compliance with the National Ambient Air Quality Standards for Sulfur Dioxide, as required by the Clean Air Act Section 110, 42 U.S.C. § 7410. AMENDED FINDINGS AND ORDER BY CONSENT

The Minnesota Pollution Control Ag ency (MPCA), being fully advised in the premises and with the consent of Flint Hills Resources Pine Bend, LLC, (formerly known as Flint Hills Resources, LP) hereby adopts this Amended Findings and Order. The MPCA first adopted Findings and Order by Stipulation on April 2, 1991 (Order). The Order has been amended eight times and as amended is in effect today.

FINDINGS

1. The State of Minnesota is obligated by section 110(a) of the Clean Air Act, 42 U.S.C. § 7410, to develop a plan which provides for “implementat ion, maintenance, and enforcement” of the primary and secondary national ambient air quality standards (NAAQS) promulgated by the U.S. Environmental Protection Agency (EPA) pursuant to section 109 of the Clean Air Act, 42 U.S.C. § 7409.

2. The EPA has promulgated requirements for the implementation plans required by section 110(a) of the Clean Air Act at 40 CFR Part 51 (2010) (Requirements for Preparation, Adoption and Submittal of Implementation Plans).

3. The EPA has promulgated primary NAAQS for sulf ur dioxide of 0.03 parts per million (ppm) annual arithmetic mean and 0.14 ppm maximum 24-hour concentration, not to be exceeded more than once per year, 40 CFR § 50.4 (2010). This primary NAAQS remains applicable to all areas until one year after the effective date of the designation of an area, pursuant to section 107 of the Clean Air Act, for the primary sulf ur dioxide NAAQS described in Finding 4.

4. In 2010, the EPA promulgated a new primary NAAQS for sulfur dioxide of 75 parts per billion (ppb) one-hour annual average, met when the three-year average of the annual 99 th



### percentile of the daily maximum one-hour concentration is less than or equal to 75 ppb, 40 CFR § 50.17.

5. The EPA has promulgated secondary NAAQS for sulfur dioxide of 0.5 ppm maximum three-hour concentration, not to be exceeded more th an once per year, 40 CFR. § 50.5 (2010).

6. The MPCA is a statutory agency of the state of Minnesota, Minn. Stat. § 116.02, subp. 1 (2010), charged with the responsibility to administer an d enforce laws and promulgate rules to prevent water, air and land pollu tion throughout the state of Minne sota, Minn. Stat. chs. 115, 115B and 116 (2010).

### Page 2 of 22 7. The MPCA is empowered to promulgate standards and rules for the prevention, abatement or control of air pollution related, without limitati on, to “source or emissions of air contamination or air pollution, to the quality or composition of such emissions, or to the quality of or composition of the ambient air or outdoor atmo sphere or to any other matter relevant to the prevention, abatement or control of air polluti on.” Minn. Stat. § 116.07, subp. 4 (2010). See Minn. Stat. § 116.07, subp. 2 (2010).

8. The MPCA has promulgated primary ambient air quality standards for sulfur dioxide of 0.03 ppm annual arithmetic mean and 0.14 ppm maximum 24-hour concentration, not to be exceeded more than once per year. Minn. Rules pt. 7009.0080 (2010). The MPCA has also promulgated secondary ambient air quality standards for sulfur dioxide of 0.5 ppm maximum three-hour concentration, not to be exceeded more than on ce per year in Air Quality Control Region 131. Minn. Rules pt. 7009.0080 (2010).

9. The MPCA has the authority to enforce any statute or rule related to air pollution by, among other things, adopting, issuing, entering into or enforcing “reasonable orders, schedules of compliance and stipulation agreements.” Minn. Stat. § 116.07, subp. 9 (2010).

10. Minn. Stat. § 115.071 (2010) provid es that the provisions of chapters 115 and 116 and “all rules, standards, orders, stipulation agreements, schedules of compliance, and permits adopted or issued” by the MPCA may be enforced by criminal prosecution, action to recover civil penalties, injunction, action to compel performance, or othe r appropriate action. Specifically, in an action to compel performance of an order of the MPCA, the regulated party may be required “to do and perform any and all acts and things within the defendant’s power which are reasonably necessary to accomplish the purposes of th e order.” Minn. Stat. § 115.071, subp. 5 (2010).

11. The seven-county Twin Cities metropolitan area Air Quality Control Region (AQCR) is defined at 40 CFR § 81.27 (2010) and is designated AQCR 131. The area was classified as a nonattainment area for the primary NAAQS for sulfur di oxide at 40 CFR § 81.324 (1991). The area now maintains the standard.

12. In 1981, the EPA approved Minnesota’s State Implem entation Plan (SIP) to control emissions of sulfur dioxide in the Twin Cities nonattai nment area, AQCR 131. 46 FR 20997 (April 8, 1981). See 40 CFR § 52.1222(c)(17) (2010).

13. On July 29, 1982, EPA proposed to conditionally approve Minnesota Rule APC-41 (Offset Rule) as a revision to the Minnesota SIP fulfilling the re quirements of Part D (Plan Requirements for Nonattainment Areas) of the Clean Air Act, 42 U.S.C. §§ 7501-7508. 47 Federal Register 32742 (July 29, 1982).

14. In 1982, MPCA staff computer modeling of allowa ble sulfur dioxide emissions from stationary emission sources in the Pine Be nd area of Dakota County (a portion of AQCR 131) showed the potential for nonattainment of the sulfur dioxide NAAQS.

15. On September 2, 1983, the MPCA formally reques ted that EPA redesignate all of AQCR 131 to attainment for sulfur dioxide except for the Pine Bend area of Dakota County.

16. On September 28, 1984, EPA issued a letter of SIP deficiency pursuant to Section 110(a)(2)(H) of the Clean Air Act, 42 U.S.C. § 7410(a)(2)(H), for mo nitored and modeled violations of the sulfur dioxide NAAQS in the Dakota County portion of AQ CR 131. EPA published this notice at 49 FR 47488 (December 5, 1984), and identified Dakota Co unty as one of the areas in the country with fully or partially approved Part D plans which still do not attain NAAQS.

### Page 3 of 22 17. On June 27, 1986, the MPCA s ubmitted a sulfur dioxide SIP re vision for the Dakota County portion of AQCR 131 to EPA to resolve the SI P deficiency noted in the September 28, 1984, letter from EPA. The MPCA submitted a sulfur di oxide SIP revision for an other portion of AQCR 131 (i.e., the St. Paul Park area of Washingt on and Ramsey Counties) on June 30, 1987. On August 19, 1987, the MPCA submitted a sulfur dioxide SIP revision to EPA demonstrating modeled attainment of NAAQS for the Pine Bend area. On September 10, 1987, the MPCA again submitted a sulfur dioxide SIP revision requesting redesignation of all AQCR 131 as attainment for sulfur dioxide, except for the areas covered by the St. Paul Park and Pine Bend sulfur dioxide SIP submittals. In response to EPA’s June 1990 co mments, the MPCA withdrew these revisions in August 1990. On March 13, 1989, the MPCA submitted a SIP revision to EPA entitled “Revisions to Offset and General Rules” to fulfill the requi rements of Part D of the Clean Air Act.

18. In its 1990 Air Pollution Control Cooperative Ag reement No. A005236-90, EPA stated that it would withhold from the MPCA up to $150,000 in federal funds for the purpose of promulgating a Federal Implementation Plan (FIP) unless an a pprovable sulfur dioxide SIP for the Pine Bend area was submitted to EPA by the end of the third quarter of federal fiscal year 1990.

19. On January 1, 2002, Koch Petroleum Group LP changed its corporate name to Flint Hills Resources, LP. On November 1, 2010, the Pine Bend Refinery an d other assets of the company became Flint Hills Resources Pine Bend, LLC. Flint Hills Resources, Pine Bend, LLC (FHR or Company), a limited liability company organized and existing under the laws of the state of Delaware, is authorized to do business and is doing business in the state of Minnesota at the junction of Highways 52 and 55 in Dakota County, Minnesota.

20. The Company owns and operates a petroleum refinery (Refinery), in the Pine Bend area of Rosemount, Dakota County, Minnesot a. The facility is now known as Flint Hills Resources Pine Bend Refinery.

21. The Refinery emits pollutants into the ambient air in sufficient quantities to require an air emission permit from the MPCA pursuant to Mi nn. Stat. § 116.081 (2010) and Minn. Rules pts. 7001.0030 and 7007.0150, Subp. 1 (2009).
The MPCA issued the Company an air emission permit in 1985, for the operation and expansion of the Refinery. That permit is Air Emission Facility Permit No. 106A-85-OT-1, the Refinery permit. FHR’s Refinery permit has been amende d, and as amended is in effect today. The Refinery’s current permit is Air Emission Pe rmit No. 03700011-007. In conjunction with this Administrative Order, the MPCA is issuing Air Emission Permit No. 03700011-008. This Administrative Order imposes requirements on the FHR refinery (specified in parts I. through VII. below) that will achieve and ma intain compliance with the annual, 24-hour and three-hour NAAQS for sulfur dioxide.

22. The Refinery was found to be a major contributor of sulfur dioxide emissions in the Pine Bend area, and based on computer modeling [ISC-ST (Version 90346) and ISC-LT (Version 90008)] was determined to be a culpable sulfur dioxide emission source in the Pine Bend area.

23. The Refinery produces unleaded gasoline, home heating oil, commercial and industrial heating oils, transportation fuels, jet fuels, petroleu m coke, asphalt, sulfur and carbon dioxide. The Refinery has numerous different processing facilities which contain emission sources that emit sulfur dioxide.

24. On July 29, 1992, the MPCA subm itted a sulfur dioxide state impl ementation plan to bring the Pine Bend area into attainment. The submittal included the origin al version of this Order. On

### Page 4 of 22 September 9, 1994, EPA approved the MPCA’s plan (59 FR 46553).

25. On September 7, 1994, the MPCA submitted a re quest to EPA to redesignate the Pine Bend sulfur dioxide area from nonattainment to atta inment. On May 31, 1995, EPA published a Direct Final Rule (60 FR 28339) indicating that it intended to redesigna te the Pine Bend area from nonattainment for su lfur dioxide to attainment. On July 31, 1995, this rule became effective, and the Pine Bend area was redesignated as an attainment area for sulfur dioxide.

26. On February 10, 2000, EPA promulgated the “Contro l of Air Pollution from New Motor Vehicles: Tier 2 Motor Vehicle Emissions Standards and Gaso line Sulfur Control Requ irements.” This rule, effective April 10, 2000, required most refiners (including the Pine Bend refinery) to meet a corporate average standard for sulfur in gaso line in 2004 and to produce even lower sulfur gasoline by 2006.

27. On December 22, 2000, the U.S. Department of Justice lodged a proposed Complaint and Consent Decree in United States vs. Koch Petroleu m Group LP in U.S. District Court (Civil Action No. 00-2756-PAM-SRN). In this acti on the United States sought ci vil penalties and injunctive relief against Koch Petroleum Gro up, L.P., (“Koch”) pursuant to section 113(b) of the Clean Air Act (“CAA”), 42 U.S.C. 7413(b) (1983), amended by , 42 U.S.C. 7413(b) (Supp. 1991), the Resource Conservation and Recovery Act, (“RCRA”), 42 U.S.C. 6901 et seq. ; the Emergency Planning and Community Right to Know Act (“ EPCRA”), 42 U.S.C. 11004(a); and the Clean Water Act (“CWA”), 33 U.S.C. 1321(b)(3) and (j) for alleged violations at Koch’s 3 refineries: Pine Bend, Minnesota, and the East and West refineries in Corpus Christi, Texas.
The State of Minnesota joined in the settlement as a signatory to the Consent Decree. On April 25, 2001, the Department of Just ice filed the Consent Decree.
The settlement required FHR to pay civil penalties and implement innovative pollution control technologies to greatly reduce emissions of nitr ogen oxides and sulfur dioxide. Implementing some of these control technologies required changes to this Administrative Order.

28. On January 18, 2001, EPA promulgated the “Contro l of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements.” This rule, effective March 19, 2001, requires refiners (including the Pine Bend refinery) to produce diesel fuels for use in highway vehicles with a lower sulfur content. These fuels were required to be available by June 1, 2006.

29. On March 11, 2003, the MPCA amende d this Administrative Order to allow Flint Hills Resources, LP, now Flint Hills Resources Pine Bend, LLC, to modify its refinery. The MPCA found that the requirements of this Order, as amended, and as imposed on FHR would maintain compliance with the NAAQS for sulfur dioxide in the Pine Bend area of AQCR 131, and would allow the refinery to meet requirements establishe d in the Consent Decree (Civil Action No. 00-2756-PAM-SRN) and to make lower sulfur gasoli ne (Tier 2 gasoline) and lower-sulfur diesel fuels.

30. On October 19, 2005, EPA approved this Order as amended which allowed Flint Hills Resources, LP, now Flint Hills Resources Pine Bend, LLC, to modify its refinery in order to meet requirements established in the Consent Decree (Civil Acti on No. 00-2756-PAM-SRN) not addressed in the previous amendment and to make ultra low sulfur diesel fuel.

31. On July 19, 2007, EPA approved amendments to this Order which allowed Flint Hills Resources, LP, now Flint Hills Pine Bend, LLC, to modify it s refinery in order to install one new process heater at the #3 Crude Unit and to account for additional SO 2 

### emissions from refinery fuel gas

### Page 5 of 22 combustion (72 FR 39568).

32. The MPCA is now amending this Administrative Order to allow Flint Hills Resources Pine Bend, LLC to modify its refinery in order to insta ll a new boiler, to decommission 34H-3 (Merox Thermal Oxidizer) and reroute process gases to the existing 31H-2 furnace, to improve the energy efficiency of 94H-1, and to remove fuel oil combustion from the modeling and calculations at certain combustion units. SO 2 

### emission rates for refinery fuel gas combustion at certain emission units and heater steam-air decoki ng activities have been updated and stack exit temperature and velocity data at certain emission units have been updated with this amendment.

33. This iteration of the Administrative Order e liminates previously completed or obsolete provisions from earlier Administrative Orders and amendments issued to FHR and included in Minnesota’s State Implementation Plan.

34. This Order is needed to maintain th e attainment status for the area.

### Page 6 of 22 ORDER

NOW, THEREFORE, IT IS ORDERED, that Flint Hills Resources Pine Bend, LLC shall comply with the requirements listed below in operating its Refinery to demonstrate and maintain compliance with the federal ambient air quality standards for sulfur diox ide as set forth in 40 CFR §§ 50.4 and 50.5 (2010), while making certain facility modifications.

I. COMPANY PROPERTY AND ACCESS RESTRICTIONS
This Part of the Order is the control pl an for preventing general public access to Company-owned property in order to exclude the atmosphere above the property from the definition of “ambient air” subject to the su lfur dioxide NAAQS. Exhibit 1 is the modeling technical support document, which is attached a nd incorporated by reference into this Order. The Company-owned property where the atmosphere above is excluded from modeled compliance with the sulfur dioxide NAAQS is shown in Exhibit 1, attached and incorporated by
reference.

The Company shall meet the following requirements for the property shown in Exhibit 1:

A. Access Control

On the effective date of this Order, the Company shall have enclosed the boundaries of the property with a continuous fence, excluding access points, and shall have installed gates at each access point. The Company shall thereafter keep the gates closed unless: 1) a guard or other FHR employee or contractor patrols and mo nitors access at a gate, or 2) authorized persons are entering or leaving the property through a gate.

B. Inspection, Maintenance, and Repair

The Company shall inspect the fencing and ga tes installed to ensure compliance with Part I.A at least annually.

The Company shall maintain and repair the fencing and gates to maintain continuous compliance with Part I.A. The Company shall complete all repairs and maintenance to the fencing and gates as soon as possible, but no later than 30 days after the date the Company observes the need for repair or maintenance, or after the MPCA notifies the Company of the need for repair or maintenance.

II. SULFUR DIOXIDE EMISSION CONTROL PLAN AND COMPLIANCE SCHEDULES
This Part of the Order is the Refinery’s sulfur dioxide emissions control plan, based upon air dispersion modeling that shows that the cont rol plan will attain compliance with NAAQS. Exhibit 1 is the modeling technical support document. The sulfur dioxide modeling parameters for this equipment are contained in Exhibit 1. The emission limits and operational requirements of this Order apply to the units identified in Exhibit 1.

The remainder of this Part is divided into two sections. The first section contains the Refinery’s sulfur dioxide emission limitations, fuel restrictions, and operational requirements.

### Page 7 of 22 The second section contains the Refinery’s compliance demonstration requirements for the stack emissions, fuel restrictions and operat ional requirements. The Company shall operate equipment as described in Part II.A and shall demonstrate compliance as described in Part II.B.

A. Emission Limitations, Fuel Restrict ions and Operational Requirements

1. Emission Limitations

The Company shall not exceed the emission limitations set forth in Table 1 which is attached and incorporated by re ference herein, for each emission point. The Company’s total facility emissions also sha ll not exceed 3,770 tons per year of sulfur dioxide based on a 365-day rolling average, effe ctive the effective date of this Order.

2. Refinery Fuel Oil Restrictions

The Company shall not burn refinery fuel oil at any Refinery location.

3. Fuel Gas Restrictions
a) Natural Gas limits.
(1) The Company shall only burn natural gas at the following

sources:

i. The Oil Separation and Waste Treatment Plant (OSWTP) oxidizers (94H-1/EU282 and 94H-3/EU254) in conjunction with oxidation of gases from OSWTP equipment; and

ii. Tank heaters (Emission Units EU144 through EU 173 and EUs 274 and 275).

(2) The Company may burn natural gas at all combustion sources provided the Company measures th e total volume of natural gas combusted in the refinery.
b) Refinery Fuel Gas limits. The Company may burn Refinery fuel gas at all existing locations except those sources listed in paragraph (a)(1). Existing sources are listed in Exhibit 1. New sources may combust Refinery fuel gas provided they comply with the emission limitation specified in Section III.A.
c) Supply source. The following provisions apply to refinery gas supplied as
fuel to combustion sources:
(1) Any fuel gas combustion unit other than the units identified in (a)(1), above, may burn Refinery fu el gas not taken from the Refinery fuel gas system provided that th e Company install, operate, and maintain a hydrogen sulfide conti nuous monitoring system (CMS) and flow meter at the fuel gas combustion unit in accordance with the requirements of Part II.B.2 whenever burning Refinery fuel gas not

### Page 8 of 22 taken directly from the Refinery Fuel gas system; or
(2) As an alternative to paragraph II.A.3(c)(1), combustion units may burn Refinery fuel gas not taken from the Refinery fuel gas system if sulfur dioxide emissions are monitored under an EPA-approved Alternative Monitoring Plan (AMP), or are categorically exempt, or are inherently low in sulfur content in accordance with NSPS J (or Ja version) 40 CFR 60.104 and/or 60.105 (40 CFR 60.102a and/or 60.107a).

(3) The Company will operate and maintain a reduced sulfur CMS on the fuel gas supplied from the 41 unit mix drum (41V33/EU256), and a sulfur dioxide CMS on a representative heater firing 45 unit mix drum (45V38/EU265) fuel gas with th e requirements of Part II.B.2
d) Hydrogen Sulfide Content. The Company shall not put fuel gas into the refinery fuel gas distribution system at any time which contains greater than 162 parts per million (ppm) of hydrogen sulf ide (0.10 grains of hydrogen sulfide per dry standard cubic foot of gas) as an average for any consecutive three-hour period.

4. Stationary Diesel Engine Fuel Restrictions

The Company shall only use diesel fuel wi th a sulfur content not in excess of 15 ppm (0.0015%) by weight at each of the Refinery’s stationary diesel engines. Limits on hours of operation for selected stationary diesels are shown in Table 2, which is attached and incorporated by reference herein.

5. Steam-Air Decoking Requirements
a) Authorized Locations. The Company may decoke heater or boiler tubes using steam-air decoking only at the following Refinery heaters or boilers: 21H-1/EU032, 21H-2/EU033, 23H-1/EU037, and 23H-2/EU038.

b) Frequency. The Company may steam-air decoke heater 21H-1/EU032, 21H-2/EU033, 23H-1/EU037, and 23H-2/EU038 no more than 432 hours per year for each heater.

c) Concurrent Operation. The Company may not decoke heaters 21H-1/EU032 and 21H-2/EU033 simultaneous ly, and may not decoke either of these heaters while decoking heat ers 23H-1/EU037, and 23H-2/EU038.

6. Operation Requirements for Bypass Stacks and Other Special Stacks
a) E. Flare, W. Flare, U. Flare and N. Flare. The four flares (84ME23/EU301, 84ME24/EU302, 84ME25/EU303, and 84 ME3/EU304) may not receive gases from Refinery operations unless the gases are from pressure relief, are from upsets of Refinery process equipment, or are required for equipment

### Page 9 of 22 maintenance. The Company shall only use commercial natural gas or nitrogen for the purge system and commercial natural gas at the pilot flame for the
flares.
b) SRU 3 and SRU 4 Facility. The Company shall not emit SRU 3 (EU111) tail gas at SV094 unless tail gas from SRU 3 is bypassing the SCOT/TGTU #1 Unit (EU261 and EU262). The Company may use SV093 during periods when tail gas from SRU 4 (EU112) is bypassing the SCOT Unit/TGTU #1. The Company shall not shut down the SCOT Unit except as necessary for maintenance or repair. The Company shall not bypass the SCOT Unit with tailgas from SRU 3 (EU111) or SRU 4 (EU112) except:

(1) during periods of startup, shutdown, or breakdown of SRU 3, SRU 4, the SCOT/TGTU #1 Unit, or SCOT incinerator (EU262); or

(2) to prevent a breakdown of the SCOT Unit.
Sulfur degassing gas may be combusted in the SRU 4 startup/bypass incinerator and emitted from SV094 during instances of startup, shutdown, or
malfunction.
c) SRU 5 Facility. The Company may use SV042 during periods when tail gas from SRU 5 (EU045) is bypassing the Tail Gas Recovery Unit #2 (TGTU #2, 26H-40/EU236 and 26H-41/EU237). The Comp any shall not shut down the TGTU #2 except as necessary for maintenance or repair. The Company shall not bypass the TGTU #2 with tail gas from SRU 5 ex cept: 1) during periods of startup, shutdown, or breakdown (as governed by 40 CFR 60 Subp. A) of SRU 5, the TGTU #2 or TGTU #2 incinerator (26H-4 1/EU237), or 2) to prevent a breakdown of the TGTU #2. Sulfur degassing gas may be combusted in the SRU 5 startup
incinerator and emitted from SV042.
d) FCC Facility. The Company shall only vent emissions from the SV021 stack as follows: 1) during startup or shutdown of the FCC; 2) for an emergency at the FCC reactor or cataly st regenerator which potentially or actually requires a bypass of the large WHCO Boiler or small WHCO Boiler; 3) for an emergency shutdown of the large WHCO Boiler (17H-2) or small WHCO Boiler (17H-4); and 4) required safety inspections of the large WHCO Boiler (17H-2) or small WHCO Boiler (17H-4).

B. Demonstration of Compliance With Emissi on Limitations, Fuel Restrictions and Equipment Operation Requirements

1. Demonstration of Compliance with Emission Limitations

The Company shall implement the compliance methods for monitoring requirements in Section IV. of this Order and recordkeeping requirements in Section

### Page 10 of 22 V.B.2 of this Order to determine compliance with each emission limitation in Table 1. The Company’s emission monitoring programs sh all also comply with Part IV of this
Order.

2. Demonstration of Compliance With Fuel Gas Restrictions

The Company shall implement the complia nce methods in Sections IV.A.2 and V.B.2.a of this Order to determine compliance with the fuel gas restrictions of Part II.A.3 of this Order. The Company’s fuel gas monito ring programs shall also comply with Part
IV of this Order.

3. Demonstration of Compliance with Diesel Fuel Restrictions

For each of the Refinery’s stationary diesel engines, the company shall retain records demonstrating sulfur content is less than 15 ppm (0.0015%) by weight. Certificates of Analysis retained onsite demonstrating that all FHR diesels meet the federal ULSD standard satisfies this requir ement. The records ma y be maintained in either electronic or paper format, unless either form is expressly prohibited.

4. Demonstration of Compliance with Equipment Operation Requirements

The Company shall monitor the start and stop times for heater decoking and compute the hours of heater decoking oper ations to determine compliance with the heater decoking requirements of Part II.A.5 of this Order.

III. CHANGES NOT REQUIRING A MODIFICATION OF THIS ORDER
The Company is authorized to begin construction of the activities listed below at the Refinery without a modification of this Order. The Compan y may conduct activities not listed below without a modification of this Order, if the activities do not emit sulfur dioxide, do not affect the modeling parameters assumed in Exhibit 1, and do not affe ct the continuous emission monitors (CEMs) or continuous monitoring systems (CMSs) used to demo nstrate compliance with this Order. The Company shall, however, obtain an air emission permit pr ior to commencing any new activity or facility modification if one is required by Minnesota st atutes, Minnesota rules or federal statutes and regulations.
After obtaining the appropriate air emission permit (if required) but prior to a modification of this Order, the Company may begin construction of a new unit or modification to an existing unit. However, the Company shall not operate a new emission unit and shall not operate a modified unit in a manner contrary to the modeling parameters in Exhibi t 1 for that unit until the modification to this Order is obtained and approved by EPA.

A. The Company may install and operate any new sulfur dioxide process or control equipment with a maximum potential sulfur dioxid e emissions rate that does not exceed 2.28 pounds per hour, except as expressly allowed elsewhere in this part (Part III.).

The Company may modify and operate any ex isting sulfur dioxide process or control equipment to increase the sulfur dioxide emission rate up to 2.28 lb/hr over the modeled

### Page 11 of 22 emission rate for that source in Exhibit 1.

B. The Company may physically and operationally modify process and control equipment
if the modifications do not increase the modeled sulfur dioxide emissions rate above the amount allowed in paragraph A of this section, decrease the modeled stack emissions exit velocity, or decrease the modeled heat content of the stack exit emissi ons, at the emission
source where the modification occurs and all other potentially affected emission points assumed in the modeling presented in Exhibit 1.

C. The Company may modify or replace and oper ate an existing sulf ur dioxide emissions stack with a new stack if the height of the modifi ed or replacement stack is not less than that of the stack assumed in the modeling presented in Exhibit 1, and if the exit diameter of the modified or replacement stack is not greater than that of the stack assumed in the modeling presented in Exhibit 1.

D. The Company may install and operate new stru ctures, or modify and operate existing
structures if the new or modified structures do not increase the effective structural dimensions assumed in the modeling presented in Exhibit 1.

E. The Company may replace and operate replacement CEMs and CMSs covered by this Order or the Company may install and operate addi tional CEMs and CMSs, so long as the new or replacement CEMs and CMSs are properly certified, comply with this Order, and are operated and tested as required by this Order.

F. The Company may add additional CEMs or CMSs as needed to provide redundancy, providing the Company notifies the MPCA as re quired in Part VI.A.6. The Company may modify the fuel gas delivery system if the following conditions are met: 1) fuel gas flow and hydrogen sulfide content must be continuously measured for all heaters, either by measuring the hydrogen sulfide level in the main Refinery fuel gas system and feeding the heater directly from the system, or by separately monitoring the fuel gas to or sulfur dioxide emissions from the heater; and 2) any new fuel gas monitors added to the system must be certified within 60 days of startup, must meet 40 CFR 60 Appendix F QA/QC requirements, must have a QA/QC plan prepared and implemented within 60 days of startup, and operate in accordance with Minn. Rules pt. 7017.1090 within two quarters of startup.

G. The boundaries of the Company-owned proper ty may be extended and existing fencing removed provided that the property excluded from the definition of “ambient air”, as shown in Exhibit 1, continues to meet the requirements in Part I.A and Part I.B of this Order.

H. The Company may modify its refinery in order to install a new boiler as modeled in Exhibit 1, to improve energy efficiency of 94H-1, to decommission 34H-3 and re-route process gases to the existing 31H-2 furnace. 34H-3 may continue to operate if Merox off-gas is not
routed to 31H-2.

### Page 12 of 22 IV. GENERAL MONITORING REQUIREMENTS

A. Accurate Measurements Required

1. The Company shall install, certify, calib rate, operate and maintain each CEM and CMS as required by this Order, and shal l conduct all non-continuous sampling and analysis as required by this Order to ensure accurate measurements of the parameters
to be monitored.

2. The Company shall measure the stack sulf ur dioxide concentration (ppm), stack velocity and stack temperature and compute the sulfur dioxide emission rate in lb/hr to determine compliance with the emission limit ations listed in Table 1 for EU245 (Merox TO), EU055 (31H-2), SV093 (SRU 3/4), SV 042 (SRU 5), and SV019 (FCCU). The Company shall measure the Refinery fuel gas hydrogen sulfide concentration and fuel gas flow rate to determine compliance with the emission limit in Section II.B.3.c of this Order for sulfur dioxide emissions from Refinery fuel gas combustion.

B. Continuous Monitoring Requirements

1. General
a) Compliance with Minnesota Rules and Federal Regulations. The Company shall meet the requirements of Minn. Rules pt. 7017.1002 – 1020 and
40 CFR Part 60.13 with each CEM and CMS. If the requirements of Minn. Rules pt. 7017.1002 – 1020 and 40 CFR Part 60. 13 differ, the more stringent regulation shall apply.
b) Continuous Operation of CMS and CEM Systems. The Company shall at all times properly operate and maintain each CMS and CEM system to provide continuous, accurate, real time moni toring data for the determination of compliance with the terms and requirements of this Order. In those situations where a CMS or CEM system becomes incapable of meeting the requirement of providing continuous, accurate, real ti me monitoring data, the Company shall expeditiously replace or repair the CM S or CEM system and take all other measures as necessary to meet the requirement as soon as possible.

2. Monitor Certification
a) Sulfur Dioxide CEMs. The Company sha ll certify each sulfur dioxide CEM as required by 40 CFR Part 60, Appendix B, Performance Specification 2 (2010).

b) Emission Rate CMSs. The Company shall certify each continuous monitoring system as required by 40 CFR Part 60, Appendix B, Performance Specification 6 (2010), except that the Company need no t meet calibration drift requirements for those flow monitors that are not designed for conducting calibration drift tests (pitot tube or venturi type).

### Page 13 of 22 c) Hydrogen Sulfide CMSs for Fuel Gas Monitoring. Th e Company shall certify each hydrogen sulfide CMS as required by 40 CFR Part 60, Appendix B (2010), by using the procedures specifie d in Performance Specification 7.
d) Total Reduced Sulfur CMSs for Fuel Gas Monitoring. The Company shall certify each total reduced sulfur CMS as required by 40 CFR Part 60, Appendix B (2010), by using the procedures specifie d in Performance Specification 5.
e) All CEMs and CMS. All CEMs and CMS certification shall be conducted in compliance with Minn. R. 7017.1050 – 7017.1080 (2009).

3. Quality Assurance

The Company shall conduct a quality a ssurance and quality control (QA/QC) program as required by 40 CFR Part 60, Appe ndix F (2010), to properly maintain and
calibrate each CEM and CMS. The Company shall develop a nd follow the master QA/QC Plans for each CEM and CMS required by this Order.

4. Monitoring System Uptime
a) Mass Sulfur Dioxide CEM Systems. The Company shall operate and
maintain each mass sulfur dioxide CEM system in acco rdance with Minn. Rules 7017.1090 so that compliance with each emission limitation of Table 1 is determined from real time certified CEM monitoring.
b) Refinery Fuel Gas Sulfur Monitoring.

The Company shall install, calibrate, maintain and operate a CMS for the hydrogen sulfide content of the refinery fuel gas at each of the inputs to the refinery fuel gas distribution loop. The CMS shall provide a continuous record of the hydrogen sulfide content in ppm.

The Company shall maintain an SO 2 

### CMS at a representative heater which combusts 45 unit mix drum fuel gas. The CMS shall provide a continuous record of the sulfur dioxide content of the heater exhaust in ppm.

The Company shall maintain a CMS which measures reduced sulfur in the 41 unit mix drum fuel gas stream. The CMS shall provide a continuous record of the reduced sulfur content of the fuel gas in ppm.

For heaters receiving refinery fuel gas that is neither inherently low in sulfur, nor categorically exempt in accord ance with NSPS J (or Ja version) 40 CFR 60.104 and/or 60.105 (40 CFR 60.102a and/or 60.107a) from sources other than the main refinery fuel gas distribution loop , the Company shall continuously measure the hydrogen sulfide content of the refinery fuel gas or monitor in accordance with an EPA-approved Al ternative Monitoring Plan (AMP) at a representative point in the line supplying the heater. For heaters receiving

### Page 14 of 22 commercial grade fuels directly, (e.g., commercial grade natural gas and propane), contract guarantees for hydrog en sulfide and heat content shall be utilized for compliance demonstration purposes.
c) Each CEM or CMS must be operated and data recorded during all periods of emission unit operation including periods of emission unit start-up, shutdown, or malfunction. This require ment to operate the monitor applies whether or not an emission limit applies during these periods.

CEM or CMS downtime is unacceptable except for reasonable periods of monitor downtime due to the following causes:
(1) damage to the CEM or CMS due to acts of God such as lightning strikes, tornadoes, or floods that render the CMS inoperative;
(2) sudden and not reasonably preventable CEM or CMS breakdowns;
(3) scheduled maintenance based on equipment manufacturer’s recommended schedule which cannot be reasonably be conducted when the emission unit is not operating; or
(4) unavoidable CEM or CMS downtime to conduct required checks
and audits.

C. Non-Continuous Monitoring Requirements

1. The Company shall perform non-continuo us monitoring as required by Section
II.C.4 of this Order.

2. The Company shall conduct performance stack tests to de termine compliance with the emission limitations and fuel restrictions of this Order as required by the Commissioner pursuant to Minn. Rules pt . 7017.2001 – 2060. Stack tests can also be required by authorized EPA personnel. All performance tests shall be conducted in accordance with the requirements of Minn. Rules pt. 7017.2001 – 2060. The Company shall submit to the MPCA performance stack te st plans, protocols and schedules at least 15 days prior to the pretest meeting required in Part VI.A.5 of this Order.

V. RECORDKEEPING REQUIREMENTS
This Part V of the Order requires the Company to keep specified records so that EPA and the MPCA can evaluate the Company’s compliance with the Order. The first section requires the Company to keep records on maintenance of property acce ss controls. The second sect ion requires the Company to keep records on the Refinery control plans an d compliance schedules. The third section requires the Company to keep records in the form and with the accessibility needed for EPA and MPCA staff inspection.

### Page 15 of 22 A. Property Boundary Fencing and Gates

The Company shall maintain records of ea ch inspection of the fencing and gates required by Part I of this Order. In addition , the Company shall maintain records of each maintenance activity and each repair activity requ ired by Part I of this Order. The Company shall retain each inspection, maintenance and repair record for a minimum of five years from the date the record was generated, despite any Company document retention policy to the contrary. These records shall be kept at the Refinery.

1. The inspection records shall include: the date of inspection; name of the person conducting the inspection; identification of each section of fence and each gate inspected; and identification of each locati on where repair or maintenance is required. The inspection report shall be certified as a ccurate in writing by the person conducting each inspection.

2. The maintenance and repair records sha ll include: the dates of the repairs or maintenance; a description of the repair and maintenance conducted; and the locations where they occurred. The maintenance and repair records shall be certified as accurate by the person(s) overseeing each maintenance or repair action.

B. Recordkeeping Requirements

The Company shall maintain for the Refinery a copy of the records required pursuant to this Part of the Order. Records shall be retained at the Refinery.

1. Permanent Records

The Company shall permanently maintain the following information together with all amendments, revisions, and modifications to this information.
a) Design, Construction and Operation Information. The Company shall maintain information on the design, construction and operation of each emission facility, emission source, fuel system, stack, structures pertinent to modeling for downwash in Exhibit 1, and any other information required to conduct sulfur dioxide ambient air quality modeling of emissions from the Refinery. These records shall also include all information required to demonstrate that the equipment identified in Exhibit 1 is installed as described in that exhibit. Where an activity has been undertaken pursuant to Part III of this Order, the records shall include a description of each activity and all information required to demonstrate that the activity complies with each applicable Part III requirement. The re cords shall also identify and provide information on the design, construction and operation of each modification or new installation at the Refinery required by this Order.
b) Information on Sulfur Dioxide Emission Limits, Operational Requirements, and Modeling Parameters. The Company shall maintain records

### Page 16 of 22 at the Refinery. These records include this Order and the Exhibits and Tables attached and incorporated by reference in this Order.

2. Non-Permanent Records

The Company shall retain the information identified below for a minimum of five years following the date on which th e information was obtained, despite any document retention policy to the contrary. Th is retention period shall be automatically extended upon the Commissioner’s written request.
a) Monitoring, Testing, and Other Records. The Company shall maintain records of all measurements, including: all continuous monitoring system and continuous monitoring device measurem ents; all performance stack testing measurements and operating conditions during the performance stack tests; all continuous monitoring system perfor mance evaluations; all continuous monitoring system or monitoring device calibration checks; all adjustments and maintenance performed on these systems or devices; and all other information required or applicable to verify complianc e with this Order. The Company shall prepare and maintain records of the one-hour averages for stack sulfur dioxide concentration (ppm); stack diameter, stack velocity a nd stack temperature; and the sulfur dioxide emission rate in lb/hr to determine compliance with the
emission limitations listed in Table 1 for SV078/EU245 (34H-3, Merox TO) or SV049/EU055 (31H-2), SV093 (SRU 3/4), SV042 (SRU 5), and SV019 (FCC). The Company shall prepare and maintain records of the one-hour averages of the refinery fuel gas hydrogen sulfide concentration and fuel gas flow rate to determine compliance with the emission limit in Section II.A.3.c. Using the one-hour averages, FHR shall calculate the three-hour, twenty four-hour, and annual rolling averages corresponding to th e emission limits referenced above.
b) Sulfur Dioxide Emissions, Fuel Re cords and Operations Records. The Company shall maintain records to demonstrate compliance with the sulfur dioxide emissions limitations, and fuel use and quality restrictions and operational requirements of this Order. These records shall be designed, and
the information shall be maintained in a form suitable for the Commissioner to quickly determine compliance with each of the emission limitations, fuel restrictions, and operational requirements of this Order.
c) Startup, Shutdown, Bypass, and Breakdown Records. The Company shall maintain records for each startup, sh utdown, bypass and breakdown for each piece of process equipment, control equipment, fuel supply system, emission stack, monitoring system and any other piece of equipment applicable to this Order. These records shall include the date and time of the start and stop of
each event.

### Page 17 of 22 d) Excess Emissions, Exceedances of Fu el Usage and Quality Restrictions and Non-Compliance with Operational Requirements Records. The Company shall maintain a record of each exceedance of an emission limitation, fuel use restriction and fuel quality requirement, and operational requirement at the Refinery for each emission point and fuel system subject to the emission limitations, fuel restrictions, and operational requirements of this Order. The record shall include for each period of exceedance a description of the exceedance, its cause, the magnitude of the exceedance, and the date and time
of commencement and cessation of the exceedance.
e) Operations Records for CEMs and CM Ss. The Company shall maintain an operations record for each CEM and CMS used to establish compliance with the
terms and conditions of this Order. The operations record shall specify each date and time the CEM or CMS was inoperative and the nature of the CEM or CMS repairs or adjustments. The operat ions record shall include for each calendar quarter, the percent of time the CEM or CMS was operating and the percent of time the CEM or CMS was no t operating. The Company shall also record for each calendar quarter, the amount of time the process associated with the CEM or CMS was operated.

C. Record Maintenance

The Company shall maintain all required docu ments, records, reports and plans in a format suitable for determination of FHR’s compli ance with this Order by EPA or MPCA staff. The Company shall maintain the information in a fo rm that is easily accessible for inspection by EPA or MPCA staff, and that is available fo r inspection at all reasonable times.

VI. REPORTING REQUIREMENTS

A. Notifications

1. Notification of Process or Control Equipment Shutdown

The Company shall notify the Commissi oner of shutdown of any control equipment or process equipment governed by this Order in accordance with Minn. Rules pt. 7019.1000, Subp 3.

2. Notification of Process or Control Equipment Breakdown

The Company shall notify the Commissi oner of breakdowns of control equipment or process equipment governed by this Order in accordance with Minn. Rules 7019.1000, subp. 2.

3. Notification of CEM or CMS Breakdown

The Company shall notify the Commissioner of a breakdown or malfunction of any CEM or CMS used to demonstrate complianc e with the terms and conditions of this Order in the next air quality quarterly report (NSPS excess emissions and 1989

### Page 18 of 22 Stipulation Agreement quarterly report) fo llowing the breakdown or malfunction. The Company shall include the information iden tified in Minn. Rules pt. 7017.1110, Subp.
2.B.

4. Notification of CEM or CMS Certificatio n Test and Quality Assurance Audit Test

The Company shall notify the Commissioner in writing at least 30 days prior to conducting any CEM or CMS certification te st for any CEM or CMS required to be certified pursuant to this Order. The Company may request a pretest meeting with the MPCA staff by making the request at least seven days prior to conducting any CEM or CMS certification test for the CEMs or CMS required pursuant to this Order. The Company shall notify the Commissioner in writing at least seven days prior to conducting calendar quarter quality assurance audit test procedures for those CEMs or CMSs required pursuant to this Order. Exce ptions to these deadlines may be approved by MPCA on a case-by-case basis.

5. Notification of Performance Tests

The Company shall notify the Commissi oner of its intent to conduct performance stack tests required pursuant to this Order not less than 30 days prior to conducting each performance stack test as required by Minn. Ru les pt. 7017.2030. The Company may request a pretest meeting with the MPCA staff by making the request at least seven days prior to conducting a performa nce stack test. The test date is subject to the Commissioner’s approval and shall be approved by the Commissioner at least 15 days before the planned test date. Exceptio ns to these deadlines may be approved by MPCA on a case-by-case basis.

6. Notification of Regularly Scheduled Turnaround on any TGTU Unit

The Company shall notify the Commissi oner in writing 30 days prior to performing regularly scheduled turnaround (s cheduled unit shutdown for maintenance) on any TGTU Unit.

B. Quarterly Reports

The Company shall submit to the Commission er each calendar quarter, a report that contains the following information: sulfur dioxide emissions for the Emission Points of Table 1, refinery fuel gas hydrogen sulfide content (in a form that allows direct comparison with the requirements of the Order) on both hard copy a nd computer readable media; 45 mix drum fuel gas total reduced sulfur content, or equivalent stack gas SO 2 

### concentration (in a form that allows direct comparison with the requirements of the Orde r); a record of data used in calculating, and calculations of the sulfur dioxide emissions, refinery fuel gas hydrogen sulfide content; a record of each steam-air decoke event; a record of each startup, shutdown, bypass and breakdown of process and control equipment; a summary re cord of excess sulfur dioxide emissions, exceedances of fuel usage and quality requirements and noncompliance with operational requirements, or the Company shall state if no exceedances or noncompliance conditions

### Page 19 of 22 occurred in the quarter; a summary of CEM and CMS operation records including the amount of time the process equipment was operated; and, any quality assurance test results that do not meet the requirements of 40 CFR Part 60, Appendix F (2010). Quarterly reports shall be postmarked within 30 days following the end of each calendar quarter. Upon written notification by the Commissioner, the Company may cease including sulfur dioxide emissions, fuel usage and quality, records of data used in calculating, and calculations of sulfur dioxide emissions, and fuel usage and quality in the quarterly reports. However, the Company shall submit this data within 30 days of receipt of a written request by the Commissioner.

C. Performance Stack Tests Reports

The Company shall submit to the Commissioner , reports of each performance stack test conducted pursuant to this order. Performance st ack test reports shall be postmarked no later than 45 days following completion of the perfor mance stack test, unless otherwise approved by
the MPCA.

D. CEM Certification Test Results

The Company shall submit to the Commissioner , the results of each CEM certification test required pursuant to this Order. Certification test reports shall be postmarked no later than 45 days after the CEM certification test date, unless otherwise approved by the MPCA.

E. CEM and CMS Audit Test Results

The Company shall submit to the Commission er, the results of quarterly cylinder gas audits and annual relative accuracy tests. Subm itted results of quarterly audits and annual relative accuracy tests shall be included in the quarterly report for the quarter in which they
were conducted.

VII. GENERAL CONDITIONS

A. Before the Company begins operation of new or modified equipment not specifically allowed by Part IV of this Order and which results in additional sulfur dioxide emissions, or changes to sulfur dioxide emission patterns assu med in the modeling presented in Exhibit 1, the Company shall obtain a modification of this Order.

B. This Order is meant to deline ate Minnesota’s strategy for attainment in the Pine Bend area from the present into the future, and is not an admission that the restrictions in 40 CFR § 52.24 (a) and (b) (1991) previously applied or currently apply to the Pine Bend area.

C. This Order does not relieve FHR of the obligation in undertaking all actions required by this Order, to comply with all applicable local, State and Federal laws and regulations, including, but not limited to, federal new source performanc e standards, and laws and regulations related to occupational safety and health. In the event ther e is a conflict in applicable federal or state of local laws or regulations, the more stringent of the conflicting provisions shall apply.

D. The MPCA, EPA or their authorized represen tatives shall have authority to enter all property of the Company in Rosemount, Minnesot a, at all reasonable times for the purposes ofinspecting records, operating logs and contracts related to the Company's compliance with this Order; reviewing the progress of the Company in implementing this Order; conducting such

tests as the EPA or MPCA deem necessary to determine compliance with this Order; and verifying the data submitted to the EPA and MPCA by the Company. The Company shall honor

all reasonable requests for such access by the EPA or MPCA staff, conditioned only upon presentation of proper credentials. This section does not limit any other right of entry and inspection held by the EPA and MPCA pursuant to applicable federal or state laws, rules or permits.

E. This Order shall be binding upon the Company and its respective officers, employees,

successors and assigns. FHR shall provide a copy of this Order to any successor in interest prior

to transfer of that interest, and shall simultaneously inform the MPCA that this notice has been given. Should the Company sell or otherwise conveyor assign any of its right, title or interest in

the Refinery, such conveyance shall not release the Company from any obligation imposed by

this Order, unless the party to whom the right, title or interest has been transferred or assigned

agrees in writing to fulfill the obligations of this Order and the MPCA finds that the new owner
has the ability to fulfill the obligations of this Order, and approves such transfer or assignment.

F. This Order mandates actions and establishes limits necessary to attain, maintain and verify compliance with the federal sulfur dioxide NAAQS by FHR. To the extent that any federal

or state statute, rule, permit, order, stipulation agreement, consent decree or schedule of compliance now in force or subsequently issued imposes limits and requires actions additional

to or more stringent than those required in this Order, FHR shall also comply with the requirements ofthe federal or state statute, rule, permit, order, stipulation agreement, consent

decree or schedule of compliance.

G. This Order is effective upon the date that it is signed by the Commissioner ofthe MPCA.

H. Once EPA approves this Order as part ofthe Minnesota SIP, this Order supersedes the requirements of all previous SIP revisions, as they apply to FHR.

IT IS SO ORDERED.

Scott Lindemann

Vice President and Manufacturing Manager

Flint Hills Resources Pine Bend, LLC

Dated: 

# ul7/lJ Paul Aasen

Commissioner

Minnesota Pollution Control Agency



### Dated: 

# tho/f,

Page 20 of 22Page 21 of 22TABLE 1 – REFINERY EMISSION LIMITATIONSSTACK VENTEMISSION UNITFACILITY ID # SOURCE DESCRIPTION 3-HOUR AAQS(1)24-HOUR AAQS(2)ANNUAL AAQS(3)DATES EMISSION POINTLIMITATIONS BECOMEEFFECTIVESV078EU24534H-3 Merox TO Facility65.4 pounds SO2per hour286.4 tons SO2per 12 monthsEffective the effective dateof this Order.SV093EU111 andEU11245UNIT2-145UNIT3-1SRU 3 and SRU 4 Facility(SCOT)(5)149.0 pounds SO2per hour86.5 pounds SO2per hour324.3 tons SO2per 12 monthsEffective the effective dateof this Order.SV042EU04526UNIT-1 SRU 5 Facility(TGTU #2)(5)170.8 pounds SO2per hour93.6 pounds SO2per hour409.8 tons SO2per 12 monthsEffective the effective dateof this Order.SV019EU22817UNIT1 FCC Facility 182.6 pounds SO2per hour800 tons SO2per12 monthsEffective the effective dateof this Order.SV049EU05531H-2 #2 HDS FractionationHeater66.4 pounds SO2per hour290.8 tons SO2per 12 monthsEffective the effective dateof this Order.SV125SV146EU282EU25494H-194H-3OSWTP Facility(oxidizers(6))50.71 pounds SO2per hour(4)50.71 pounds SO2per hour(4)39.4 tons SO2per12 months(9.0 lb/hr)Effective the effective dateof this Order.(1) These emission limitations are based on three consecutiveone-hour periods (3-hour rolling averages). To demonstrate compliance with thelimitation, emissions shall be calculated insuch manner, exceptfor EU282. (See (4).)(2) These emission limitations are based on 24 consecutive one-hour periods (24-hour rolling averages). To demonstrate compliance with the limitation,emissions shall be calculated in suchmanner, except for EU282. (See (4).)(3) These emission limitations are based on a 12-month rolling average and to demonstrate compliance with the limitation, emissions shall becalculated in such manner, except for Emission Point EU282. (See (4).)(4) This emission limitation is a one hour maximum value to bemet for any one consecutive hour period. Compliance with these emission limits haspreviously been demonstrated by stack tests.(5) Limits include emissions from the incineration of sulfur degassing gas.(6) This emission limit applies to the WWTP during operation ofeither the 94 H-1 oxidizer or the 94 H-3 oxidizer. 94 H-1 is the primary WWTP oxidizer;94 H-3 is the backup. Except when switching WWTP gases from one oxidizer to the other, only oneoxidizer may combust gases fromOSWTP equipmentat a time. The other oxidizer may be fired concurrently with natural gas for standby purposes.Page 22 of 22TABLE 2 – LIMITS ON DIESEL-POWERED UNITSEMISSION UNIT FACILITY ID # DESCRIPTION ANNUAL LIMIT COMMENTSEU131 93 P 160Diesel-powered fire waterpump1000 hoursDedicated fuel storage tank; meterrecords hours of operationEU198 M93 P 400Diesel-powered fire waterpump1000 hoursDedicated fuel storage tank; meterrecords hours of operationEU199 M93 P 570Diesel-powered fire waterpump1000 hoursDedicated fuel storage tank; meterrecords hours of operationEU042 EE 1657M Diesel-powered generator 1000 hoursDedicated fuel storage tank; meterrecords hours of operationEU007 EE 1852M Diesel-powered generator 1000 hoursDedicated fuel storage tank; meterrecords hours of operationEU036 M23 ME 26 Diesel-powered generator 1000 hoursDedicated fuel storage tank; meterrecords hours of operationEU100 EE 1309M Diesel-powered generator 1000 hoursDedicated fuel storage tank; meterrecords hours of operationEU024 EE 1718M Diesel-powered generator 1000 hoursDedicated fuel storage tank; meterrecords hours of operationEU130 M81 P 159Diesel-powered coolingwater pumpNo limitDedicated fuel storage tank; meterrecords hours of operationEU132 M81 P 357Diesel-powered coolingwater pumpNo limitDedicated fuel storage tank; meterrecords hours of operationEU128 M81 P 444Diesel-powered coolingwater pumpNo limitDedicated fuel storage tank; meterrecords hours of operationEU129 M81 P 89Diesel-powered coolingwater pumpNo limitDedicated fuel storage tank; meterrecords hours of operationWood River diesel Diesel-powered pump 2000 hoursDedicated fuel storage tank; meterrecords hours of operationEU127 71C-11Diesel-powered plant aircompressor2500 hoursDedicated fuel storage tank; meterrecords hours of operationEU133 M81 P 598Diesel-powered coolingwater pumpNo limitDedicated fuel storage tank; meterrecords hours of operations

# Exhibit 1 **FHR SIP Modeling**

**Merox Incinerator Shut Down**

**Prepared for Flint Hills Resources Pine Bend, LLC** 

**M ay 2011** 

# Exhibit 1 Table of Contents

1 MPCA Technical Support Document (TSD)

2 Model Protocol

2A Merox Incinerator Remova l Project Model Protocol

2B Underline/Strikeout ve rsion of February 2006 Model Protocol for the #3 Crude Expansion Project 3 Facility Boundary Diagram (See CD-ROM) 4 Source Data Summary Table 5 Building Dimension Information (See CD-ROM) 6 Summary of Model Results 7 AERMOD Model Input Information (See CD-ROM) 8 AERMOD Model Output Data (See CD-ROM) Isopleths “Dot Maps” of High 2 nd 

### High Concentrations 9 Background Concentration Information

# Exhibit 1 - Section 1 MPCA Technical Support Document Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling Analysis

# Exhibit 1 - Section 2 Model Protocol Flint Hills Resource s Pine Bend LLC Ambient Air Quality Modeling Analysis

# Exhibit 1 - Section 2A Merox Incinerator Removal Project Model Protocol Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling Analys isFlint Hills Resources Pine Bend, LLC Justification for Air Quality Modeling Inputs (revised May 2011)

Introduction .................................................................................................................. ........................... 1
“K1_ #1SRU” 34H-3 Merox O ff-Gas (old SRU 1/2) ................................................................................ 4
“K2_#3SRU” SRU 3, SRU 4, and TGTU (SCOT) Plant .......................................................................... 5
“K113__FG” SRU 3 Tail Gas Inci nerator on Hot Standby ...................................................................... 7
“K3_#5SRU” SRU 5 and TGTU #2 ................................................................................................. ....... 8 “K8___FCC” Fluid Catalytic Cracking Unit ............................................................................................ 10

Fuel Combusti on Devi ces ....................................................................................................... .............. 12 Stationary Dies el Engines ..................................................................................................... ................ 20

Portable Di esels .............................................................................................................. ...................... 22
“K348_OXD” OSWTP Th ermal Oxidizer ............................................................................................. .. 23 “K458_VNT” Platformer Cataly st Regenerato r Vent ............................................................................. 2 5
“K459_VNT” Powerf ormer Catalyst Regeneration ................................................................................ 2 6

Process Heater Steam -Air Decoking ............................................................................................. ....... 27

Sulfuric Acid Ha nding Emissions ............................................................................................... ........... 32 Insignificant Sources ......................................................................................................... .................... 341 

### Introduction

This document contains the supporting informatio n used to determine the input parameters for the air quality modeling demonstration of compliance with National Ambient Air Quality Standards for Sulfur Dioxide (SO 2 ) for the Pine Bend, Minnesota area.

General Source Model Information

The modeling analysis was conducted using AERMOD Version 09292 with the urban dispersion option selected. It is important to note that AERMOD is a new model for this analysis; the February 2006 SIP Amendment 8 (SIP8) modeling was conducted using ISC3. As of December 9, 2006, AERMOD was promulgated to replace ISC3 as the preferred dispersion model in 40 CFR Part 51 Appendix A.

MPCA recently-processed 2000–2004 AERMET meteorolog y files were used. Surface and upper air data were from the Minneapolis-St. Paul air port. This meteorological data set is from the same location as the previous SIP8 modeling, but the model years are mo re recent than the SIP8 modeling (which used 1972 – 1976 meteorology). The nearby facilities included in the modeling analysis are the Xcel Energy Inver Hills Generating Plant and Gopher Resource, LLC smel ting facility. Xcel Energy’s six turbine stack source modeled parameters were updated per Air Pe rmit 03700015-003 which reduced the fuel sulfur content to 0.05 percent by weight. The Gopher smelting facility modeled parameters were updated per Appendix B model parameters in Air Permit 03700016-003. This increased the hourly emission rates from 530 lb/hr to 2,080 lb/hr. The MPCA 2008 Option 2 “Rest of TC” SO 2 background conc entrations will be applied to the updated modeling results and are described in further detail in Section 9 of this Exhibit.

The receptor grid was updated following the procedures in: MPCA Guidance for Title V and PSD Air Dispersion Modeling (October 2004). In general, the density of receptors along the facility fence line and beyond was increased to show more refined concentrati on results. Receptor spacing of 10-meters was used along the facility fence line. Receptor spac ing of 50 meters extended from the fence line to a maximum distance of 0.5–kilometers depending on where past modeling maximums occurred. 250-meter spaced receptors extend from the edge of the 50-meter spaced receptor s and end approximately 2- kilometers from the facility boun dary. 500-meter spaced receptors extended to approximately 5 kilometers from the facility boundary. The receptor elevations and hill heights were calculated with AERMAP using 10 meter United States Geological Surv ey (USGS) seamless elevation data. Receptor and elevation data information can be found in the el ectronic modeling files attached to this report. Figures 1 through 3 show the ambient air boundary and the receptor grid modeled for the SIP analysis.

Modeled source locations and parameters we re based on the February 2006 SIP Amendment 8 modeling. With the update from ISC to AERMOD, t he source locations were updated based on recent Title V PM 10 modeling and using ARCGIS tools with current aerial photos. The source modeled elevations were updated using 10 meter USGS seamless elevation data.

The building downwash analysis was updated from the 1992 SIP building downwash analysis to incorporate the revised source/building relationships based on recent aerial photos and Title V PM 10 modeling. A full BPIP-Prime analysis was re-run with all the revised source and building locations and elevations.

A table summarizing the model source parameter changes from SIP 8 to SIP 9 (excluding minor coordinate/elevation changes related to new elevation data and aerial data) is shown below. The majority of changes relate to: 1) modifying limits on fuel gas sulfur content and 2) revisions to stack temperatures and velocities to ensure values conservatively represent full operating range.2 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 34H-3 K1_MEROX Planned re-routing of Merox stack emissions to 31H-2. 230 lb/hr emission rate limit was reduced to 65.4 lb/hr based on historic CEMS SO2 data. Same as SIP 8.

45H-61 K2_#3SRU Emission rate calculation for tail gas incinerator on hot standby updated. See “K2_#3SRU SRU 3, SRU 4, and TGTU SCOT Plant” section for additional detail. Temperature increase from 519.3 K to 578 K and Velocity decrease from 17.4 m/s to 16 m/s per an engineering review of historical data.

26H-21 K3_#5SRU Same as SIP 8. (Minor correction to 1 hour rate to include 1 hour bypass emissions, not 3 hour) Temperature increase from 449.8 K to 464 K per an engineering review of historical data.

71B-7 Boilers 1,2,3,4,6 & 9 K7____BH Source Removed. Source Removed.

FCC ESP K8___FCC 1,500 lb/hr emission rate was reduced to 182.65 lb/hr per demonstrated CEMS data. Temperature decrease from 449.8 K to 366 K and velocity decrease from 15.54 to 15.24 per an engineering review of historical data. 32H-5,6,7 K10_32FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). Temperature decrease from 435 K to 422 K per an engineering review of historical data. Velocity decrease from 2.80 m/s to 1.35 m/s due to velocity calculation using half of the de-rated duty. 19H-1 K11_19FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 441 K to 422 K per an engineering review of historical data. Velocity decrease from 5.01 m/s to 2.4 m/s due to velocity calculation using half of the de-rated duty. 12H-4 K13_12FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). Temperature decrease from 449.8 K to 422 K per an engineering review of historical data. Velocity decrease from 5.13 m/s to 2.41 m/s due to velocity calculation using half of the de-rated duty. 33H-31 K14_33FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 503 K to 553 K per an engineering review of historical data. Velocity decrease from 5.33 m/s to 2.93 m/s due to velocity calculation using half of the de-rated duty. 16H-1 K15_16FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). Temperature decrease from 505 K to 480 K per an engineering review of historical data. Velocity decrease from 3.80 m/s to 1.81 m/s due to velocity calculation using half of the de-rated duty.3 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 11H-3 K16_11FO Source Remo ved. Source Removed. 11H-5 K18_11FO Source Remo ved. Source Removed. 11H-1 K19_11FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 533 K to 466 K per an engineering review of historical data. Velocity decrease from 11.61 m/s to 5.08 m/s due to velocity calculation using half of the de-rated duty. 37H-1,2,6 K20_37FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm. See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 427 K to 422 K per an engineering review of historical data. Velocity decrease from 13.37 m/s to 6.61 m/s due to velocity calculation using half of the de-rated duty. 33H-32 K21_33FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm. See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 555 K to 547 K per an engineering review of historical data. Velocity decrease from 12.28 m/s to 6.05 m/s due to velocity calculation using half of the de-rated duty. 11H-2 K23_11FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 561 K to 508 K per an engineering review of historical data. Velocity decrease from 1.71 m/s to 0.77 m/s due to velocity calculation using half of the de-rated duty.

21H-1S K27_21FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 518 K to 478 K per an engineering review of historical data. Velocity decrease from 3.69 m/s to 1.7 m/s due to velocity calculation using half of the de-rated duty. 21H-1N K28_21FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 518 K to 478 K per an engineering review of historical data. Velocity decrease from 3.69 m/s to 1.7 m/s due to velocity calculation using half of the de-rated duty. 21H-2S K29_21FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 518 K to 489 K per an engineering review of historical data. Velocity decrease from 3.69 m/s to 1.74 m/s due to velocity calculation using half of the de-rated duty. 21H-2N K30_21FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 518 K to 489 K per an engineering review of historical data. Velocity decrease from 3.69 m/s to 1.74 m/s due to velocity calculation using half of the de-rated duty.4 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES33H-4 (33H1&2) K31_33FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 516 K to 550 K per an engineering review of historical data. Velocity decrease from 7.87 m/s to 4.19 m/s due to velocity calculation using half of the de-rated duty. 23H-1 K32_23FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 450 K to 422 K per an engineering review of historical data. Velocity decrease from 9.89 m/s to 4.63 m/s due to velocity calculation using half of the de-rated duty. 31H-1 K33_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 528 K to 566 K per an engineering review of historical data. Velocity decrease from 3.49 m/s to 1.87 m/s due to velocity calculation using half of the de-rated duty.

31H-2 K34_31FG 34H-3 Merox stack emissions re-routed to 31H-2. Increase emissions by 66.4 lb/hr based on historic CEMS SO2 data from 34H-3 (65.4 lb/hr) plus refinery fuel gas PTE value from Title V application (0.97 lb/hr). Temperature increase from 589 K to 666 K per an engineering review of historical data. Velocity decrease from 5.29 m/s to 2.99 m/s due to velocity calculation using half of the de-rated duty.

31H-5 K36_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 394 K to 422 K per an engineering review of historical data. Velocity decrease from 2.18 m/s to 1.17 m/s due to velocity calculation using half of the de-rated duty.

31H-10 K37_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 500 K to 525 K per an engineering review of historical data. Velocity decrease from 2.82 m/s to 1.48 m/s due to velocity calculation using half of the de-rated duty.

32H-9 K41_32FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 575 K to 533 K per an engineering review of historical data. Velocity decrease from 2.20 m/s to 1.02 m/s due to velocity calculation using half of the de-rated duty.

37H-3,4,5 K42_37FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 450 K to 422 K per an engineering review of historical data. Velocity decrease from 5.33 m/s to 2.50 m/s due to velocity calculation using half5 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES of the de-rated duty.

38H-1A K46_38FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 561 K to 600 K per an engineering review of historical data. Velocity decrease from 1.77 m/s to 0.95 m/s due to velocity calculation using half of the de-rated duty. 38H-1B K47_38FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 561 K to 600 K per an engineering review of historical data. Velocity decrease from 1.77 m/s to 0.95 m/s due to velocity calculation using half of the de-rated duty. 38H-2 K48_38FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 428 K to 422 K per an engineering review of historical data. Velocity decrease from 6.47 m/s to 3.19 m/s due to velocity calculation using half of the de-rated duty. 25H-1 K50_25FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 436 K to 422 K per an engineering review of historical data. Velocity decrease from 3.01 m/s to 1.46 m/s due to velocity calculation using half of the de-rated duty. 25H-3 K51_25FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 436 K to 428 K per an engineering review of historical data. Velocity decrease from 2.86 m/s to 1.40 m/s due to velocity calculation using half of the de-rated duty. 25H-4 K52_25FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 436 K to 422 K per an engineering review of historical data. Velocity decrease from 6.75 m/s to 3.27 m/s due to velocity calculation using half of the de-rated duty. 23H-2 K53_23FG Emission rate calculation corrected based on 45 mix drum not 41 mix drum. Temperature decrease from 486 K to 436 K per an engineering review of historical data. Velocity decrease from 11.79 m/s to 5.28 m/s due to velocity calculation using half of the de-rated duty. 27H-1 K54_27FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 411 K to 422 K per an engineering review of historical data. Velocity decrease from 11.87 m/s to 6.09 m/s due to velocity calculation using half of the de-rated duty.6 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 27H-101 K55_27FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Velocity decrease from 10.13 m/s to 5.07 m/s due to velocity calculation using half of the de-rated duty.

27H-102 K56_27FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Velocity decrease from 10.13 m/s to 5.07 m/s due to velocity calculation using half of the de-rated duty.

31H-4 K57_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 477 K to 555 K per an engineering review of historical data. Velocity decrease from 2.79 m/s to 1.63 m/s due to velocity calculation using half of the de-rated duty.

31H-7 K58_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 672 K to 544 K per an engineering review of historical data. Velocity decrease from 6.27 m/s to 2.54 m/s due to velocity calculation using half of the de-rated duty.

31H-8 K59_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 511 K to 519 K per an engineering review of historical data. Velocity decrease from 6.35 m/s to 3.23 m/s due to velocity calculation using half of the de-rated duty.

31H-9 K60_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 541 K to 511 K per an engineering review of historical data. Velocity decrease from 7.02 m/s to 3.32 m/s due to velocity calculation using half of the de-rated duty.

28H-1 K61_28FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 589 K to 811 K per an engineering review of historical data. Velocity decrease from 11.45 m/s to 7.88 m/s due to velocity calculation using half of the de-rated duty. 71B-8 K62_BLR8 Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 433 K to 422 K per an engineering review of historical data. Velocity decrease from 12.21 m/s to 5.95 m/s due to velocity calculation using half of the de-rated duty.7 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 27H-501 K63_27FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 411 K to 422 K per an engineering review of historical data. Velocity decrease from 6.97 m/s to 3.58 m/s due to velocity calculation using half of the de-rated duty. 11H-6 K67_11FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 371 K to 422 K per an engineering review of historical data. Velocity decrease from 7.35 m/s to 4.18 m/s due to velocity calculation using half of the de-rated duty.

71B-9 K68_BLR9 The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 435.8 K to 422 K per an engineering review of historical data. Velocity decrease from 6.23 m/s to 3.02 m/s due to velocity calculation using half of the de-rated duty.

Boiler 10 BLR10 New Source included with SIP 9. Emission Rate is similar to 71B-9 Temperature data from historical Boiler 9 data and velocity based on half of the de-rated duty of Boiler 9 30 H-401 #4 H2 Plant K70_4H2 Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 411 K to 422 K per an engineering review of historical data. Velocity decrease from 8.42 m/s to 4.32 m/s due to velocity calculation using half of the de-rated duty. 29 H-1 Comb Fd& Dist K71HCFD Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Velocity decrease from 0.22 m/s to 0.11 m/s due to velocity calculation using half of the de-rated duty.

71B-6 Boiler K1006_BH Emission rate calculation based on 120 MMBTU duty not 108 MMBTU. 3 and 24 hour emission rates calculated using 300ppm sulfur in fuel gas instead of 162ppm. Temperature decrease from 433 K to 422 K per an engineering review of historical data. Velocity decrease from 6.52 m/s to 3.18 m/s due to velocity calculation using half of the de-rated duty. 45H-6 K113__FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 588.7 K to 422 K per an engineering review of historical data. Velocity decrease from 2.25 m/s to 0.81 m/s due to velocity calculation using half of the de-rated duty. 93P-160 K331_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

93P-400 K332_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.8 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 93P-570 K333_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

94H-1 K348_OXD For the short term averaging times, the oxidizer was modeled at 50.71 lb SO2/hr. This is the calculated emission rate for the design air flow rate from the largest oxidizer air blower (31,500 scfm – 70° F) with an H2S concentration at the NSPS Subpart J limit of 162 ppm H2S Temperature decrease from 695.2 K to 533 K to reflect improved energy efficiency following proposed convection stack/heat exchanger replacement.

EE-1657 K407_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

EE-1692 K408_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

23ME26 K435_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

EE-1309 K453_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

EE-1718 K465_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

81P-159 K505_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

81P-357 K506_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

81P-444 K507_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

81P-89 K508_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

Wood River K510_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

71C-11 K511_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

Portable diesel cap PORT_DSL Non-road engines not modeled Non-road engines not modeled

ULSD Replace K509DSL 81P-450 K513_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

21H-1 dec K600_DEC Emissions decreased from 30 lb/hr to 8 lb/hr based on Source now modeled as volume source instead of point source9 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES decoking engineering study

21H-2 dec K601_DEC Emissions decreased from 30 lb/hr to 8 lb/hr based on decoking engineering study Source now modeled as volume source instead of point source

23H-1 dec K602_DEC Emissions decreased from 47 lb/hr to 20.2 lb/hr based on decoking engineering study Source now modeled as volume source instead of area source

23H-2 dec K603_DEC Emissions decreased from 47 lb/hr to 20.2 lb/hr based on decoking engineering study Source now modeled as volume source instead of area source

Acid Ld & Depress K700ACDL Same as SI P8. Same as SIP8.

Acid Stor Tks K701ACDS Same as SIP8. Same as SIP8.10 The modeling results are summarized in the table bel ow. The short term averaging period results are shown for each decoking scenario (21H-1, 21H-2, and 23H-1,2) since only one decoking source operates during any averaging periods 24 hours or less. Fo r the annual averaging period, all decoking sources were included for the modeling. The results also demonstrate that the SO 2 SIP modeling results pass with 34H-3 emissions still vented from the Merox sta ck and pass with 34H-3 em issions vented out of the 31H-2 stack.

The model results are shown graphically on the a ttached “dot-map” isopleths. These figures have colored dots representing the maximum modeled perc ent of the NAAQS at each receptor from 2000-2004 overlaid on an aerial photo of the Pine Bend, MN area. The attached “dot-map” figures are:

Figures 4 through 6 – 5 Year Maximum 1-Hour Average Results for Decoking Scenarios as Percent of MAAQS

Figures 7 through 9 - 5 Year Maximum 3-Hour Avera ge Results for Decoking Scenarios as Percent of NAAQS

Figures 10 through 12 - 5 Year Maximum 24-Hour Aver age Results for Decoking Scenarios as Percent of NAAQS

Figure 13 – 5 Year Maximum Annual Average Results as Percent of NAAQS

The model inputs and outputs are included in the attached CD. It also contains PDF files of the Figures 4 through 13. The file naming convention is as follows:

SIPso1hR700 - SIPso1hR704 = 1-hour average time using 2000-2004 meteorological data SIPso3hR900 - SIPso3hR904 = 3-hour average time using 2000-2004 meteorological data SIPso24hR900 - SIPso24hR904 = 24-hour average time using 2000-2004 meteorological data SIPsoannR800 - SIPsoannR804 = Annual average time using 2000-2004 meteorological data Averaging Period 21H-1 Decoking Scenario Before Merox Project 21H-2 Decoking Scenario Before Merox Project 23H-1,2 Decoking Scenario Before Merox Project 21H-1 Decoking Scenario After Merox Project 21H-2 Decoking Scenario After Merox Project 23H-1,2 Decoking Scenario After Merox Project

1-Hr Avg High 2nd High 531 531 606 664 656 650 MN Standard 1,300 1,300 1,300 1,300 1,300 1,300 % Standard (Including Background) 45% 45% 51% 55% 55% 54%

3-Hr Avg High 2nd High 240 241 333 483 473 401 EPA/MN Standard 1,300 1,300 1,300 1,300 1,300 1,300 % Standard (Including Background) 21% 21% 28% 40% 39% 33%

24-Hr Avg High 2nd High 108 108 117 155 155 150 EPA/MN Standard 365 365 365 365 365 365 % Standard (Including Background) 34% 34% 37% 47% 47% 46%

Annual Avg MN Standard* % Standard (Including Background)

* EPA standard is 80 ug/m 3

1 Hr Background 56 3 Hr Background 34 24 Hr Background 17 Annual Background 4 46% 31 60 58% Before Merox Project (All Decoking) After Merox Project (All Decoking)

60 24 Flint Hills Resources NAAQS and MAAQS SO 2 Attainment Modeling Demonstration Modeling Results Summary - All SO 2 Concentrations in ug/m 3 May 201111 The following areas are covered for each Emission Point in the Protocol:

A. Emission Point Description B. Justification for Modeled SO 2 Emission Rate C. Consistency Between Modeled SO 2 Emissions and Applicable State and Federal Regulations D. Justification for Modeled Stack Parameters12 

### “K1_ #1SRU” 34H-3 Merox Off-Gas (old SRU 1/2)

A. Emission Point Description This source consists of the products of combustion of excess air from caustic (Merox) treating. Caustic treating is a chemical process used to remove me rcaptans from refinery LPG process streams and to "sweeten" gasoline blend stocks. This existing emis sion source is scheduled for decommission with the approval of the permit amendment an d the emissions will be vented out of the 31H-2 heater stack after project approval. As noted below, FHR proposes to retain the right under the modified SIP order to continue to utilize 34 H-3 if necessary.

B. Justification For Modeled SO 2 Emission Rate The hourly and annual SO 2 PTE values are estimated from the maximum expected fuel sulfur from the Merox off-gas stream using CEMS data at the Merox incinerator. The highest hourly and 365-day rolling SO 2 CEMS reading from the Merox incinerator since 2006 is 45.2 lb/hr and 35.4 tpy, respectively. Three standard deviations from the 2006-2009 data and a 20% safety factor for CEMS accuracy are added to these maximums to yield 65.4 lb/hr and 50.4 tpy.

The 34H-3 Merox stack emission s will be re-routed to 31H-2. Th e 31H-2 emissions were modeled utilizing the 65.4 lb/hr SO 2 rate from the incineration of Merox off-gas and adding the refinery fuel gas PTE values of 31H-2 fuel gas from the Title V application (0.97 lb/hr and 2.3 tpy) which yields a total estimated PTE of 66.4 lb/hr and 52.7 tpy for 31H-2.

At this time, rather than utilizing the 50.4 and 52. 7 tpy (which equates to 11.5 & 12.0 lb/hr) annual emission rates, the model conservatively utilized t he hourly emission rate basis for these annual rates (286.4 tpy and 290.9 tpy).

C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations There are no applicable state or federal SO 2 emissions standards for this source.

D. Justification For Modeled Stack Parameters The 34H-3 Merox Off-gas Incinerator feed stream will be routed to the 31H-2 heater along with its own fuel gas firing after approval of the permit applicat ion and SIP Order authorizing the project. Under the SIP Order, FHR will retain the option to continue to utilize 34H-3 for these emissions in the event technical issues arise that prevent the trans fer of emissions to the 31H-2 heater.13 

### “K2_#3SRU” SRU 3, SRU 4, and TGTU (SCOT) Plant

A. Emission Point Description SRU 3 and SRU 4 are Claus sulfur recovery plants. Under normal operating condi tions, the exhaust gases from both SRU's are ducted to a Tail Gas Treating Unit (TGTU), also known as a Shell Claus Off-gas Treatment (SCOT) plant, for emissions control.

SRU 3 and SRU 4 have bypass incinerators which ar e used under start-up, shutdown and process upset conditions. SRU 3's bypass incinerator vents th rough “K113__FG” and SRU 4's bypass incinerator vents through “K2_#3SRU”. Under normal operating conditi ons the bypass incinerators are in hot standby mode and are fired on refinery fuel gas. The bypass inciner ators were modeled in the hot-stand-by condition. SRU 4 bypass incinerator is also used as an inci nerator for SRU 3 and SRU 4 sulfur degassing gases.

B. Justification For Modeled SO 2 Emission Rate

TGTU Emission Rate

A stack concentration of 500 ppmv was used to calculat e emissions for the 1 and 3 hour averaging periods and a concentration of 250 ppmv was used to calculat e emissions for 24-hour averaging periods. The annual limit is based on a stack concentration of 200 ppmv, which derives from a 30 day rolling average LAER limit.

The emission rate was determined using the design TGTU flow rate from the process flow diagrams (1990) and the stack gas SO 2 concentrations as listed above. The calculations are as follows:

Stack gas flow rates in lb mole/hr (from process flow diagram):

Total 4551.60 Water vapor (411.89) Air (237.43) (49.86/0.21 = 237.43) Air/water free 3902.28

For 1 and 3 hour average modeling @ 500 ppm:

3902.28 lbmol

* 500
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 hr lbmol stack gas lbmol SO 2 = 124.99 lb SO 2 /hr

For 24 hour average modeling @ 250 ppm:

3902.28 lbmol

* 250
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 hr lbmol stack gas lbmol SO 2 = 62.49 lb SO 2 /hr

For annual modeling @ 200 ppm:

3902.28 lbmol

* 200
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 hr lbmol stack gas lbmol SO 2 = 50.00 lb SO 2 /hr

SRU 4 Tail Gas Incinerator Emission Rates on Hot Standby

The SRU 4 bypass incinerator require s 15.477 MMBtu/Hr of heat input to operate in the hot standby mode. The tail gas incinerator is operated on refinery fuel gas. The SO 2 emission rate is calculated using the fuel gas emissions factor (see the Fuel Combustion Devi ces section) times the hot standby energy requirement. With the fuel gas HHV assigned as 1093 MMBtu /scf the calculated emission rates are:14 For the 1 hour averaging period: 15.477 MMBtu

* 10 6 Btu * 1 * 300 * 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 = 0.717 lb SO 2 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO 2 Hr

For the 3 hour, 24 hour and annual averaging periods: 15.477 MMBtu

* 10 6 Btu * 1 * 162 * 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 = 0.387 lb SO 2 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO 2 Hr Sulfur Degassing The emissions from sulfur degassing are calculated as follows:

450 LT/Day Sulfur feed to S RU 3 and 4 combined (1990 data)

300 ppm wt H 2 S equilibrium concentration in liquid sulfur

300 lb H 2 S

* 2240 lb S

* 450 LT S

* 64.06 lb SO 2 * 1 Day = 23.68 lb SO 2 per hour 10 6 lb S LT S Day 34.08 lb H 2 S 24 hr

The total emission rates are:

1 hr average: 149.35 lb/hr SO 2 3 hr average: 149.04 lb/hr SO 2 24 hr average: 86.54 lb/hr SO 2 Annual average: 74.05 lb/hr SO 2

C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations

Emissions from SRU 3 through the TGTU are limited to 250 ppmv SO 2 on a dry, oxygen free basis for a twelve hour period by 40 CFR Part 60.104 (Subpart J). Emissions from SRU 4 through the TGTU are limited to 150 ppmv SO 2 on a dry, oxygen free basis as a 30 day rolling average due to a Lowest Achievable Emission Rate (LAER) limit. Under normal c onditions, with both SRUs venting to the TGTU the limit is 150 ppmv SO 2 on a dry, oxygen free basis as a 30-day rolling average.

The gases from the sulfur degassing are included in the 40 CFR Part 60.104 limit per EPA’s December 7, 1999 NSPS J applicability determination. The Continuou s Emission Monitor (CEM) for TGTU 1 is now located on the SRU 4 main stack (K2_#3SRU), so th at the CEM measures the combined exhaust gases from TGTU 1, sulfur degassing, and SRU 4 standby incinerator operation.

The fuel gas used to maintain the SRU 4 incinerator in hot standby mode is subject to a 0.10 gr/dscf (162 ppm) limit by NSPS J.

D. Justification For Modeled Stack Parameters

The SRU 3/4 stack parameters shown below are cons istent with SIP8 modeled parameters. The exit temperature and velocity were revised per an enginee ring review of historical operating data.

Parameter Proposed Value SIP8 Value Stack Exit Velocity m/sec 16 17.4 Stack Exit Temperature **** K 578 519.3 Stack Exit Diameter m 1.448 1.448 Stack Height m 60.96 60.9615 

### “K113__FG” SRU 3 Tail Gas Incinerator on Hot Standby

A. Emission Point Description This source is the tail gas incinerator for SRU 3. This incinerator is a safety and environmental control device designed to combust the tail gas from SRU 3 if the TGTU must be bypassed. Under normal operating conditions the tail gas incinerators are in hot standby mode and are fired on refinery fuel gas. The tail gas incinerators were modeled in the hot-stand-by condition. See “K2_#3SRU” for additional information on SRU 3/4 and the TGTU.

B. Justification For Modeled SO 2 Emission Rate The SRU 3 bypass Incinerator requires 11.141 MMBtu/hr of heat input to operate in the hot standby mode. The bypass incinerator is operated only on refinery fuel gas. The SO 2 emission rate is calculated using the fuel gas emissions factor (see the Fuel Combustion Devices section) times the hot standby energy requirement.

For the 1 hour averaging period:

11.141 MMBtu

* 10 6 Btu * 1 * 300 * 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 = 0.516 lb SO 2 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO 2 Hr

For the 3 hour, 24 hour and annual averaging periods:

11.141 MMBtu

* 10 6 Btu * 1 * 162 * 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 = 0.278 lb SO 2 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO 2 Hr

The SRU 3 bypass incinerator also accepts an exhaust gas stream from the SRU 3 Process Tail Gas Analyzer. The exhaust is a 1 inch line routed to the 45H6. The SO 2 emissions rate quantification from this stream is estimated from the SO 2 ppm concentration maximum of 30 ppm. This value is determined from the actual demonstrated maximum as observed from Ja nuary 2009 to November 2009. Emission rates are determined from the stack gas flow rate maximum demonstrated in the standby operation during the two years prior to November 2010. As such the maximum expected emission rate associated with the analyzer exhaust in the SRU 3 bypass incinerator is:

(30 * 10 -6 * 64 lbsSO 2 * 60 min * 2500 ft 3 * 1 lb-molSO 2 = 0.747 lb SO 2 lb-molSO 2 hr min 385.3 Hr

C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations The fuel gas used to maintain the SRU 3 bypass inciner ator in hot standby mode is subject to a 0.10 gr/dscf (162 ppm) limit by NSPS J. The gases from the sour water tanks and sulfur deg assing are not subject to this restriction.

D. Justification For Modeled Stack Parameters The stack exit velocity was determined using the hot standby energy requirement and the process heater and boiler stack velocity formula. The following stack parameters were used:

Parameter Modeled Value Stack Exit Velocity m/sec 0.81 Stack Exit Temperature **** K 422 Stack Exit Diameter m 1.016 Stack Height m 53.6816 

### “K3_#5SRU” SRU 5 and TGTU #2

A. Emission Point Description SRU 5 is a Claus sulfur recovery plant. Under norm al operating conditions, the exhaust gases from the SRU are ducted to TGTU #2 for emissions control.

SRU 5 has a bypass incinerator (26H-21) which is used under start-up, shutdown and process upset conditions. This incinerator is a safety and environme ntal control device designed to combust the tail gas from SRU 5 if TGTU #2 must be bypassed. SRU 5's ta il gas vent is routed through the same stack as the bypass incinerator. Under normal operating conditions the bypass incinerator is in hot standby mode and is fired on refinery fuel gas. The bypass incinerator wa s modeled in the hot standby condition. SRU 5 bypass incinerator is also used as an inciner ator for SRU 5 sulfur degassing gases.

B. Justification For Modeled SO 2 Emission Rate This source has emissions limits of 170.8 lb SO 2 per hour for 1-hour periods, 170.8 lb SO 2 per hour averaged for 3-hour periods, and 93.6 lb SO 2 per hour averaged for 24-hour periods. The 24-hour limit is also used as the annual modeled emission rate. Em issions from TGTU #2 are limited by NSPS J to 250 ppm SO 2 on a dry, oxygen free basis. A stack concentr ation of 500 ppmv was used to calculate emissions for the 1 and 3-hour average periods and a concentrat ion of 250 ppmv was used to calculate emissions for 24-hour and annual average periods. The TGTU #2 emis sion rate was determined from the design process flow rate and the stack gas SO 2 concentrations as listed above. This source includes a contribution of 15.80 lb SO 2 per hour to account for emissions from sulfur de-gassing. MPCA staff has requested that Flint Hills Resources employ sulf ur de-gassing to reduce H 2 S and TRS emissions from sulfur storage and loading. The calculations are as follows:

TGTU Emission Rates

Stack gas flow rate lb mole/hr

Total 6155.03 Water vapor (746.82) Air (582.91) (122.41/0.21 = 582.91) Air/water free 4825.30

For 1 & 3 hour average modeling @ 500 ppm:

4825.30 lbmol

* 500
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 = 154.55 lb SO 2 /hr hr lbmol stack gas lbmol SO 2
For 24 hour and annual average modeling @ 250 ppm:

4825.30 lbmol

* 250
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 = 77.28 lb SO 2 /hr hr lbmol stack gas lbmol SO 2
SRU 5 Bypass Incinerator Emission Rates on Hot Standby

The SRU 5 bypass incinerator require s 20.0 MMBtu/Hr of heat input to operate in the hot standby mode. The tail gas incinerator is operated only on refinery fuel gas. The SO 2 emission rate is calculated using the fuel gas emissions factor (see the Fuel Combustion Devices section) times the hot standby energy requirement.

For the 1 hour averaging period: 20.0 MMBtu

* 0.0441 lb SO 2 = 0.882 lbs SO 2 Hr MMBtu Hr17 For the 3, 24 hr and annual averaging periods: 20.0 MMBtu

* 0.0238 lb SO 2 = 0.476 lbs SO 2 Hr MMBtu Hr

Sulfur Degassing The emissions from sulfur degassing are calculated as follows:

300 LT/Day Sulfur feed to SRU 5

300 ppm wt H 2 S equilibrium concentration in liquid sulfur

300 lb H 2 S

* 2240 lb S

* 300 LT S

* 64.06 lb SO 2 * 1 Day = 15.80 lb SO 2 per hour 10 6 lb S LT S Day 34.08 lb H 2 S 24 hr

The total emission rates are:

1 hr average: 171.23 lb/hr SO 2 3 hr average: 170.83 lb/hr SO 2 24 hr average: 93.56 lb/hr SO 2 Annual average: 93.56 lb/hr SO 2

C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations NSPS J limits the SO 2 content from TGTU #2 to 250 ppmv on a dry, oxygen free basis for a twelve-hour period. Therefore, the 24-hour av erage stack concentration was limit ed to 250 ppmv. The 3-hour average emissions limit was kept at 500 ppmv in order to limit the pot ential for exceedance of NSPS.

The gases from the sulfur degassing are included in the 40 CFR Part 60.104 limit per EPA’s December 7, 1999 NSPS J applicability determination. The Continuou s Emission Monitor (CEM) for TGTU 2 is now located on the SRU 5 main stack (K3_#5SRU) so th at the CEM measures the combined exhaust gases from TGTU 2, sulfur degassing and SRU 5 standby incinerator operation

The fuel gas used to maintain the SRU 5 incinerator in hot standby mode is subject to a 0.10 gr/dscf (162 ppm) limit by NSPS J.

D. Justification For Modeled Stack Parameters

The SRU 3/4 stack parameters shown below are cons istent with SIP8 modeled parameters. The exit temperature was revised per an engineering re view of historical operating data.

Parameter Proposed Value SIP8 Value Stack Exit Velocity m/sec 9.3 9.3 Stack Exit Temperature **** K 464 449.82 Stack Exit Diameter m 2.103 2.103 Stack Height m 65.0 65.018 

### “K8___FCC” Fluid Catalytic Cracking Unit

A. Emission Point Description The Fluid Catalytic Cracking unit (FCC) is a process unit that converts gas oil into Liquefied Petroleum Gas (LPG), gasoline and fuel oil. Gas oil is a refinery stock that is similar in gravity and appearance to motor oil. The conversion is accomplished by catalytically cra cking (breaking) the gas o il molecules into smaller molecules. The reaction takes place in a fluidized bed reactor. Coke is formed as a side reaction and is deposited on the catalyst. After passing through the reactor, the oil and cata lyst are separated by cyclones. The reaction products (LPG, gasoline and fuel oil) are separated by distillati on and sent on for further refinery processing. The coke deposits on the cata lyst are removed in the catalyst regenerator and the catalyst is recycled to the FCC reactor.

The FCC catalyst regenerator decokes the FCC catalyst by fluidized bed combustion. Sulfur in the coke is oxidized to SO 2 . The FCC regenerator flue gas and the regenerated catalyst are separated by cyclones.The catalyst is returned to the reactor. The regenerator flue gas is sent to the Large Waste Heat Carbonmonoxide (WHCO) Boiler (17H-2) and the Small WHCO Boiler (17H-4) for heat recovery and to oxidize residual regenerator exhaust gas CO. The exhaust gases are then ducted to an Electrostatic Precipitator (ESP) to reduce the particulate emissions. Emissions from caustic neutralization may also be vented through the FCC emission points.

B. Justification For Modeled SO 2 Emission Rate This source is modeled at 182.6 lb/hr (800 tpy) (thr ough K8__FCC) for 1, 3, 24-hour, and annual averaging periods. These emission rates represent the maximu m expected hourly average emission rate based on a review of monitoring data from the period December 31, 2005 - July 31, 2009 plus three times the standard deviation of the entire data set for a conservative base. This emission rate is also a Title V limit.

C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations The FCC is subject to NSPS J, which limits SO 2 emissions to 50 ppmv; Flint H ills Resources monitors these emissions with a CEMS, per NSPS J requirements, to ensure compliance with this limit. An FCC SO 2 emission rate of 182.6 lb SO 2 /hr is consistent with 0.3-wt% sulfur feed (which is an alternate method of compliance).

D. Justification For Modeled Stack Parameters

The FCC stack parameters shown below are consis tent with SIP8 modeled parameters. The exit temperature and velocity were revised per an enginee ring review of historical operating data.

Parameter Proposed Value SIP8 Value Stack Exit Velocity m/sec 15.24 15.54 Stack Exit Temperature **** K 366 449.8 Stack Exit Diameter m 2.94 2.94 Stack Height m 69.27 69.2719 

### Fuel Combustion Devices “K10...” through “K99...”, “K1001...” through “K 1006...”, and “K454...” through “K457...”

A. Emission Point Description Process heaters are used throughout the refinery to heat up the refinery process streams to the proper temperature for chemical reactions or distillation. Bo ilers are used to generate steam for heating process streams in heat exchangers, process line heat tracing and operating turbine driven pumps.

The refinery currently operates these sources on gaseou s fuels. These fuels include natural gas, refinery fuel gas, LPG fuel and PSA off gas. Natural gas, refinery gas and LPG are blended and distributed through the refinery’s fuel gas supply system. In so me cases sources may also burn natural gas directly from the natural gas supply system. Refinery fuel ga s is a mixture of low molecular weight hydrocarbons that is produced as a byproduct of the refining pr ocess. PSA off gas is a byproduct of hydrogen production; its fuel value comes from carbon monoxid e, hydrogen and methane. It is combusted only in the #2, #3, and #4Hydrogen plants.

Emissions from refinery fuel oil combustion have been removed from the model in this SIP update. Historically, the refinery has used refinery fuel oil as an energy source, but the use of refinery fuel oil was discontinued in September 2001.

There are three existing boilers (71B-6, 71B-8, and 71 B-9) and one future boiler (BLR10) that were included in the SIP modeling and they are modeled as separate stacks. Boiler 10 is located due south of 71B-9 and its parameters are included in Section 4 of this Exhibit. The refinery boiler house that ducted four boilers (1-4) to a common stack, “K7__BH”, was demolished and removed from the SIP modeling analysis. The facility has accepted facility wide SO 2 limit of 3,770 ton/yr.

Merox off-gas to 31H-2 Project:

The Merox Off-gas Incinerator feed stream will be rout ed to the 31H-2 heater along with its own fuel gas firing. Therefore the emissions at 31H-2 after the project will be equivalent to existing 31H-2 emissions plus Merox off-gas incinerator emissions. FHR intends to decommission the 34H-3 Merox incinerator after successful project completion; however, FHR in tends to continue to utilize 34H-3 in the event that technical issues arise that prevent implementation of this project.

With this update, the Merox Incinerator hourly and annual emission rates were updated to reflect the most recent SO 2 emissions monitoring data from December 31, 2005 through July 31, 2009. This effectively reduced the modeled hourly emission rate from 230 lb/hr to 65.4 lb/hr and the annual emission rate from 1,007 ton/yr to 52.7 ton/yr.

B. Justification For Modeled SO 2 Emission Rate

Fuel Gas Combustion

SO 2 emissions from fuel gas combustion are calculat ed using the maximum energy input of each heater and boiler, the energy content of the fuel gas as the High Heating Value (HHV) in BTU/scf and the sulfur content of the fuel gas.

Refinery fuel gas enters the refinery fuel gas system through two mix drums (41V-33 and 45V-39) referred to as the 41 mix drum and the 45 mix drum. An H 2 S analyzer is located on the outlet of each mix drum. The analyzers are used to monitor refinery fuel gas for compliance with applicable H 2 S limits. Since the makeup of the refinery fuel gas is diffe rent at each mix drum, t he average fuel gas heating values and sulfur content at each mix drum is diffe rent. The fuel gas from mix drum 41V-33 has an H 2 S20 concentration that correlates well with SO 2 emissions from the combustion unit stacks, since there is not a significant concentration of non-H 2 S sulfur compounds present in the 41 mix drum fuel gas. Fuel gas from the 45V-39 mix drum contains a larger percentage of sulfur compounds that are not regulated under New Source Performance Standards (N SPS). These additional sulfur co mpounds in the 45 mix drum are associated with upstream processes, primarily the coker gas recovery units. Therefore, the calculated SO 2 emission rate takes into account which fuel gas mix drum supplies each heater and boiler. Actual SO 2 emission rates are now monitored via stack SO 2 CEMS representative of 45 mix drum sourced heaters and via a reduced sulfur compound CEMS on the 41 mix drum.

For this SIP Modification, SO 2 emissions from the 45 mix drum fuel gas remain based on 500 ppm sulfur in fuel gas which equates to approximately 54 ppm SO 2 at the heater stack on an O 2 free basis using an F factor basis. The average annual concentration is pr oposed to be decreased from 500 ppm (SIP 8) to 400 ppm with this modification. SO 2 emissions from the 41 mix drum fuel gas are conservatively based on reduced sulfur contents limited to 300 ppm for the 1-hour, 3-hour, and 24-hour averaging periods and 162 ppm reduced sulfur for the annual averaging period. T hese input parameters remain consistent with SIP 8 with the exception of the 3-hour a nd 24-hour averaging periods which are proposed to be increased from 162 to 300 ppm to provide consistency with the 1- hour standard and account for inherent process variability during low rate operation.

The SO 2 emissions from fuel gas firing for each mix drum are calculated as follows:

41 Mix Drum (Reduced Sulfur CEMS Basis):

SCF [=] Standard Cubic Feet (at 60 **** F)

FG HHV = Fuel Gas High Heating Value in BTU/SCF

Where fuel gas flow is measured at 60 **** F and 1 Atm

Heater Duty MMBtu * 1

**** 10 6 Btu * 1 * C TRS scf sulfur (as predominantly H 2 S) * Hr MMBtu FG HHV Btu/scf 10 6 scf Fuel Gas

1 lbmole sulfur (as H 2 S) * 64 lb SO 2 * 453.59 g * 1 Hr = _____ gram SO 2 379 scf lbmole SO 2 lb 3600 sec sec

45 Mix Drum (Stack SO2 @ 0% O2 CEMS & Fd factor Basis):

Heater Duty MMBtu * 8511 dscf flue gas * C SO2 scf sulfur (as SO 2 @ 0% O2) * Hr MMBtu 10 6 dscf Flue Gas

1 lbmole SO 2 * 64 lb SO 2 * 453.59 g * 1 Hr = _____ gram SO 2 379 scf lbmole SO 2 lb 3600 sec sec21 The heating values were assigned to heaters and boilers as follows:

In many cases, refinery fuel gas is used to calculate the SO 2 emission rate for sources combusting natural gas and PSA off gas. Since the H2S content of refinery fuel gas is highe r than the sulfur content of natural gas and PSA off gas, the model ed emission rate is conservative.

**** Commercial natural gas sulfur content is limit ed to 0.02 gr/dscf vs. the NSPS refinery fuel gas limit of 0.10 gr H 2 S/dscf (162 ppm)

**** PSA off gas typically has an H2S content of 1 ppm or less vs. the NSPS refinery fuel gas limit of 162 ppm H 2 S.

SO 2 Emissions from refinery fuel oil combustion

Emissions from refinery fuel oil combustion have been removed from the model since the use of refinery fuel oil was discontinued in September 2001.

Merox off-gas to 31H-2 Project:

The Merox Off-gas Incinerator feed stream will be rout ed to the 31H-2 heater along with its own fuel gas firing. Therefore the emissions at 31H-2 after the project will be equivalent to existing 31H-2 emissions plus Merox off-gas incinerator emissions. FHR intends to decommission the 34H-3 Merox incinerator after successful project completion; however, FHR in tends to continue to utilize 34H-3 in the event that technical issues arise that prevent implementation of this project.

With this update, the Merox Incinerator hourly and annual emission rates were updated to reflect the most recent SO 2 emissions monitoring data from December 31, 2005 through July 31, 2009. This effectively reduced the modeled hourly emission rate from 230 lb/hr to 65.4 lb/hr and the annual emission rate from 1,007 ton/yr to 52.7 ton/yr. The Merox emissions were summed with the 31H-2 emission rates for the modeled emission rate. Source Descri p tion ISC_id HHV Btu/sc f Source Descri p tion ISC_id HHV Btu/scf Source Description ISC_id HHV Btu/scf 32H-5,6,7 K10_32FG 1197 31H-1 K33_31FG 1197 27H-102 K56_27FG 1093 19H-1 K11_19FO 1197 31H-2 K34_31FG 1197 31H-4 K57_31FG 1197 12H-4 K13_12FG 1197 31H-5 K36_31FG 1197 31H-7 K58_31FG 1197 33H-31 K14_33FO 1093 31H-10 K37_31FG 1197 31H-8 K59_31FG 1197 16H-1 K15_16FG 1197 32H-9 K41_32FG 1197 31H-9 K60_31FG 1197 11H-1 K19_11FO 1197 37H-3,4,5 K42_37FG 1093 28H-1 K61_28FG 1093 37H-1,2,6 K20_37FG 1093 38H-1 A K46_38FG 1093 71B-8 K62_BLR8 1093 33H-32 K21_33FG 1093 38H-1B K47_38FG 1093 27H-501 K63_27FG 1093 11H-2 K23_11FG 1197 38H-2 K48_38FG 1093 11H-6 K67_11FG 1197 21H-1S FO fired K27_21FO 1197 25H-1 K50_25FG 1093 71B-9 K68_BLR9 1197 21H-1N FO fired K28_21FO 1197 25H-3 K51_25FG 1093 30 H-401 #4 H2 Plant K70#4H2 1093 21H-2S FO fired K29_21FO 1197 25H-4 K52_25FG 1093 29 H-1 Comb Fd& Dist K71HCFD 1093 21H-2N FO fired K30_21FO 1197 23H-2 K53_23FG 1093 71B-6 Boiler K1006_BH 1197 33H-4 (33H-1&2) K31_33FG 1093 27H-1 K54_27FG 1093 45H-6 K113__FG 1093 23H-1 FO fired K32_23FO 1093 27H-101 K55_27FG 1093 Boiler 10 BLR10 1197 Refinery Fuel Gas Heating Value Assignments November 201022 C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations Minnesota rule 7005.2120 Subpart 2 and Federal rule 40 CFR 60.104(1) limits the amount of H 2 S in fuel gas burned in new fuel gas combustion devices (h eaters and boilers) to 0.1 gr per dscf. This concentration can be converted to ppm as follows: 0.10 gr/dscf of H 2 S at 1 atm, 20 **** C

0.10 gr
* 1 lb H 2 S

* 1 lbmol H 2 S

* 385.4 dscf

* 10 6 = 162 ppm dscf 7000 gr 34.076 lb H 2 S lbmol H 2 S

NSPS standard conditions ar e: 1 Atm (101.3 kPa) & 20 **** C (293 **** K)

dscf/lbmol: 1 lbmol = 359.05 ft 3 at 0 **** C, 1 ATM

359.05 ft 3

* 293 **** K = 385.4 dscf/lbmol (STP for NSPS) 273 **** K

Minnesota rules 7005.2110 subpart 2 and 7005.2120 subpar t 3 limit the sulfur content of fuels burned in new and existing indirect heating equipment (heaters and boilers) to 3.0 lb SO 2 /MMbtu for any individual piece of equipment and 1.75 lb SO 2 /MMbtu for the aggregate facility.

D. Justification For Modeled Stack Parameters

Stack parameters for heaters and boilers are based on their maximum fired duties, fuel gas combustion stoichiometry at 0% excess O2, and the listed stack dimensions and stack temperatures represent the minimum operating temperature and velocity under normal operating conditions for each Emission Point.

In general, for the purposes of this model, most fi red sources were modeled at a temperature and exit velocity well below that at which they normally operate and, as it relates to temperature, at a level which they could not operate without risk of corrosion damage in the heaters. The purpose of this is to allow greater operational flexibility.

The following flue gas generation rates were used to calculate stack velocities:

**** Refinery Fuel Gas (Mix Drum 41) = 10,215 scf flue gas per MMBtu HHV of fired duty

**** Refinery Fuel Gas (Mix Drum 45) = 10, 208 scf flue gas per MMBtu HHV of fired duty

**** #2 H2 Plant PSA Purge Gas = 10,883 scf flue gas per MMBtu HHV of fired duty

**** #3 H2 Plant PSA Purge Gas = 11,113 scf flue gas per MMBtu HHV of fired duty

**** #4 H2 Plant PSA Purge Gas = 11,000 scf flue gas per MMBtu HHV of fired duty

The basis for the flue gas generation rates were determined from fuel gas compositions from 7/1/99 – 7/1/01. FHR is in the process of updating these values to more recent values. This data is used to calculate stack velocity used in the model. These calculated velocities were then reduced by half this amount for the model. Therefore we believe the velocities used in the model are conservative.

The combustion stoichiometry calculations are based on the following:

**** One carbon (c) atom is conver ted to one carbon dioxide (CO 2 ) atom.

**** Two hydrogen (H) atoms are converted to one water (H 2 O) atom.

**** Each oxygen (O2) atom consumed, 3.79*(0.79/0.21 ) atoms of atmospheric nitrogen pass into the flue gas.23 These factors are represented by scf CO 2 per scf fuel, scf H 2 O per scf fuel and scf N 2 per scf fuel in the following spreadsheet calculations for fuel combustion stoichiometry.

The following tables show the combustion stoichiometry calculations for refinery fuel gas in mix drums 41 and 45 and the fuel gas/PSA off gas mixtures used at the #2 and #3 Hydrogen Plants. The #4 Hydrogen Plant is designed to have the same fuel gas/PSA off gas composition as the #3 Hydrogen Plant.

Flue Gas Calculations from Fuel Gas Combustion Products for 41 mix drum

Component 4 1 mix dru m SCF N2 per SC F SCF N2 S CF CO2 per SC F SCF CO2 SCF H2O per SC F SCF H2O Total SCF Flue Gas Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 8.70 1.88 0.16 0 0 1 0.09 0.25 C1 52.15 7.52 3.92 1 0.5215 2 1.04 5.49 C2 13.82 13.17 1.82 2 0.2764 3 0.41 2.51 C2O 9.69 11.29 1.09 2 0.1938 2 0.19 1.48 C3 2.26 18.81 0.43 3 0.0678 4 0.09 0.58 C3O 2.70 16.93 0.46 3 0.081 3 0.08 0.62 IC4 1.22 24.45 0.30 4 0.0488 5 0.06 0.41 NC4 1.06 24.45 0.26 4 0.0424 5 0.05 0.35 IC4O 0.12 22.57 0.03 4 0.0048 4 0.00 0.04 TC4O 0.17 22.57 0.04 4 0.0068 4 0.01 0.05 CC4O 0.13 22.57 0.03 4 0.0052 4 0.01 0.04

B1 0.16 22.57 0.04 4 0.0064 4 0.01 0.05 IC5 0.54 30.10 0.16 5 0.027 6 0.03 0.22 NC5 0.10 30.10 0.03 5 0.005 6 0.01 0.04 CO 1.14 1.88 0.02 1 0.0114 0 0.00 0.03 CO2 0.21 0.00 0.00 1 0.0021 0 0.00 0.00 N2 5.75 1.00 0.06 0 0 0 0.00 0.06 total 99.92 8.84 1.30 2.09 12.23 flow mmscfd 29.9 btu/scf hhv 1197

btu/scf fuel 1,197 Basis corrected fuel gas compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 12.23 flue gas per mmbtu hhv 10,215

Flue Gas Calculations from Fuel Gas Combustion Products for 45 mix drum

Component 4 5 mix dru m SCF N2 per SC F SCF N2 S CF CO2 per SC F SCF CO2 SCF H2O per SC F SCF H2O Total SCF Flue Gas Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 24.19 1.88 0.45 0 0 1 0.24 0.70 C1 47.72 7.52 3.59 1 0.4772 2 0.95 5.02 C2 16.82 13.17 2.22 2 0.3364 3 0.50 3.06 C2O 1.22 11.29 0.14 2 0.0244 2 0.02 0.19 C3 4.43 18.81 0.83 3 0.1329 4 0.18 1.14 C3O 1.43 16.93 0.24 3 0.0429 3 0.04 0.33 IC4 0.35 24.45 0.09 4 0.014 5 0.02 0.12 NC4 0.98 24.45 0.24 4 0.0392 5 0.05 0.33 IC4O 0.08 22.57 0.02 4 0.0032 4 0.00 0.02 TC4O 0.06 22.57 0.01 4 0.0024 4 0.00 0.02 CC4O 0.03 22.57 0.01 4 0.0012 4 0.00 0.01

B1 0.11 22.57 0.02 4 0.0044 4 0.00 0.03 IC5 0.27 30.10 0.08 5 0.0135 6 0.02 0.11 NC5 0.14 30.10 0.04 5 0.007 6 0.01 0.06 CO 0.32 1.88 0.01 1 0.0032 0 0.00 0.01 CO2 0.04 0.00 0.00 1 0.0004 0 0.00 0.00 N2 1.74 1.00 0.02 0 0 0 0.00 0.02 total 99.93 8.84 1.10 2.05 11.16 flow mmscfd 37.7 btu/scf hhv 1093

btu/scf fuel 1,093 Basis corrected fuel gas compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 11.16 flue gas per mmbtu hhv 10,20824 The modeled stack velocity is calculated as follows:

Stack velocity = Heater Duty MMBtu * 1 * scf flue gas * 1 Hr * 0.028317 m 3 * Hr 2 MMBtu 3,600 sec ft 3

T°K * 1 = _____ exit vel m/sec 288.7 **** K (D 2 /4) * PI

Where MMBtu/Hr = fired duty of heater (Dut y is conservatively reduced by half) T°K = stack temperature, °K D = stack inner diameter in meters

Standard conditions (STP) for flow measurement are 60 **** F and 1 Atm (14,7 psia) #2 H2 Plant Flue Gas Calculations from PSA Off Gas/Fuel Gas Combustion Products

Component #2 H2 plant Fuel Gas to Flow Wt SCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF SCF H2O Total SCF Flue Gas PSA gas #2 H2 plant Average Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 38.50 17.34 35.10 1.88 0.66 0 0 1 0.35 1.01 C1 14.10 49.68 19.81 7.52 1.49 1 0.20 2 0.40 2.08 C2 0.00 15.49 2.49 13.17 0.33 2 0.05 3 0.07 0.45 C2O 0.00 4.97 0.80 11.29 0.09 2 0.02 2 0.02 0.12 C3 0.00 3.47 0.56 18.81 0.10 3 0.02 4 0.02 0.14 C3O 0.00 1.99 0.32 16.93 0.05 3 0.01 3 0.01 0.07 IC4 0.00 0.73 0.12 24.45 0.03 4 0.00 5 0.01 0.04 NC4 0.00 1.02 0.16 24.45 0.04 4 0.01 5 0.01 0.05 IC4O 0.00 0.10 0.02 22.57 0.00 4 0.00 4 0.00 0.00 TC4O 0.00 0.11 0.02 22.57 0.00 4 0.00 4 0.00 0.01 CC4O 0.00 0.07 0.01 22.57 0.00 4 0.00 4 0.00 0.00

B1 0.00 0.13 0.02 22.57 0.00 4 0.00 4 0.00 0.01 IC5 0.00 0.39 0.06 30.10 0.02 5 0.00 6 0.00 0.03 NC5 0.00 0.12 0.02 30.10 0.01 5 0.00 6 0.00 0.01 CO 1.00 0.68 0.95 1.88 0.02 1 0.01 0 0.00 0.03 CO2 44.40 0.12 37.29 0.00 0.00 1 0.37 0 0.00 0.37 N2 2.00 3.51 2.24 1.00 0.02 0 0.00 0 0.00 0.02 total 100.00 99.93 99.99 2.87 0.69 0.89 4.46 flow mmscfd 32.6 6.23 Avg HHV btu/scf hhv 270 1139 409.42

Summary btu/scf fuel 409 Basis corrected fuel gas & PSA compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 4.46 scf flue gas per mmbtu hhv 10,883

#3 H2 Plant Flue Gas Calculations from PSA Off Gas/Fuel Gas Combustion Products

Component #3 H2 plant Fuel Gas to Flow Wt SCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF SCF H2O Total SCF Flue Gas PSA gas #3 H2 plant Average Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 29.00 17.34 28.10 1.88 0.53 0 0 1 0.28 0.81 C1 16.40 49.68 18.97 7.52 1.43 1 0.19 2 0.38 2.00 C2 0.00 15.49 1.20 13.17 0.16 2 0.02 3 0.04 0.22 C2O 0.00 4.97 0.38 11.29 0.04 2 0.01 2 0.01 0.06 C3 0.00 3.47 0.27 18.81 0.05 3 0.01 4 0.01 0.07 C3O 0.00 1.99 0.15 16.93 0.03 3 0.00 3 0.00 0.04 IC4 0.00 0.73 0.06 24.45 0.01 4 0.00 5 0.00 0.02 NC4 0.00 1.02 0.08 24.45 0.02 4 0.00 5 0.00 0.03 IC4O 0.00 0.10 0.01 22.57 0.00 4 0.00 4 0.00 0.00 TC4O 0.00 0.11 0.01 22.57 0.00 4 0.00 4 0.00 0.00 CC4O 0.00 0.07 0.01 22.57 0.00 4 0.00 4 0.00 0.00

B1 0.00 0.13 0.01 22.57 0.00 4 0.00 4 0.00 0.00 IC5 0.00 0.39 0.03 30.10 0.01 5 0.00 6 0.00 0.01 NC5 0.00 0.12 0.01 30.10 0.00 5 0.00 6 0.00 0.00 CO 7.80 0.68 7.25 1.88 0.14 1 0.07 0 0.00 0.21 CO2 45.10 0.12 41.63 0.00 0.00 1 0.42 0 0.00 0.42 N2 1.70 3.51 1.84 1.00 0.02 0 0.00 0 0.00 0.02 total 100.00 99.93 99.99 2.44 0.73 0.73 3.90 flow mmscfd 18.4 1.54 Avg HHV btu/scf hhv 285 1139 350.96

Summary btu/scf fuel 351 Basis corrected fuel gas & PSA compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 3.90 scf flue gas per mmbtu hhv 11,11325 The actual stack height is used in the modeling exce pt for those sources (boiler house, 37H-3,4,5, 25H-1, and 25H-3) whose stacks are taller than 65 meters (federal GEP stack height analysis trigger). For these sources, the GEP stack height is used for the 1hour, 3 hour, 24 hour, and federal annual modeling.26 

### Stationary Diesel Engines “K331_DSL”, “K332_DSL”, “K333_DSL”, “K407_D SL”, “K408_DSL”, “K435_DSL”, “K453_DSL”, “K465_DSL”, “K505_DSL” through “K508_DSL”, “K510_DSL” “K511_DSL”, “K513_DSL”

A. Emission Point Description Stationary diesel engines are used throughout t he refinery to power emergency standby equipment (generators and pumps).

There are currently five diesel powered electric generators in the refinery. The diesel electric generators are turned on to prevent power interruptions to critical control and lighting equipment. They operate less than 83.3 hours per month, and are operated for exte nded periods only in emergency situations.

There are five diesel powered cooling water pumps to provide emergency cooling water in the event of an electric power failure or electrical pump failure. T hey run 10 - 15 minutes per week for test purposes and less than 83.3 hours per month.

There are three diesel powered firewater pumps (93-P S ource ID) to provide water for fire fighting in the event of an electrical power failure or electrical pump failure. They are run 10 - 15 minutes per week for test purposes and less than 83.3 hours per month. They are operated for extended periods only in emergency situations.

The pump that was used to reverse the crude oil flow in the Wood River Crude Oil Pipeline (K510_DSL) has been removed from service, but is continued in the model for conservative purposes.

There is one diesel that is part of the plant air co mpressor 71C-11. This diesel will operate less than 2500 hours per year.

B. Justification For Modeled SO 2 Emission Rate

The SO 2 emission rates for the diesel engines are bas ed on AP-42 emission factors. The AP-42 factors are accepted standards, which will be us ed frequently in the future for a variety of pollutants. These emission factors have been scaled down based on the sulf ur content of the diesel fuel to account for a limit of 0.0015 wt % S in the fuel.

ENGINES < 600 hp: 4.611E-5 g/s SO 2 per hp-hr (AP-42 Table 3.3—1 Oct ’96 adjusted to 0.0015% S)

AP-42 lists emission factors of 2.05E-03 lb SO 2 /hp-hr and 0.29 lb SO 2 /MMBtu fuel input. Footnote C states that diesel fuel has a heating value of 19,300 Bt u/lb. Using the heating value of the fuel, the sulfur content basis for the emission factor is calculated to be:

0.29 lb SO 2 * 1 lb S * 1 MMBtu * 19,300 Btu * 100% = 0.280% S MMBtu fuel 2 lb SO 2 1E+06 Btu lb diesel

The adjustment for 0.0015% S diesel fuel is as follows

2.05 E-3 lb SO2 * 0.0015% S * 453.59 g * 1 Hr = 1.43 E-6 g/sec SO 2 Hp-Hr 0.28%S. 1 lb 3600 Sec Hp-Hr27 ENGINES > 600 hp: 5.097E-5 g/s SO 2 per hphr (AP-42 Table 3.4-1 Oct ’96 adjusted to 0.0015% S)

AP-42 lists an emission factor of 8.09 E-3 * %S in di esel fuel. Converting to g/s with 0.0015%S diesel fuel:

8.09 E-3 lb SO 2 * 0.0015%S * 453.59 g * 1 Hr = 1.58 E-6 g/s SO 2 Hp-Hr 1 lb 3600 S Hp-Hr

C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations Minnesota Rule 7005.1200 Subpart 2 limits SO 2 emissions from stationary internal combustion engines to 1.75 lb SO 2 per million BTU actual heat input. These emission points will be limited to diesel fuel containing no more than 0.0015 % sulfur in the Cl ean Fuels Permit. At this sulfur content, SO 2 emissions from combustion of diesel fuel are limited to 0.0015 lb S0 2 per million Btu of actual heat input.

D. Justification For Modeled Stack Parameters The stack velocity for the diesel engines is based on the engine horsepower rating. Diesel engines are rated on the average they deliver in horsepower. Th e fuel consumption of an internal combustion engine is 3 to 5 times its energy output because it is only 30% - 40% efficient. The stack velocity is calculated assuming 50% efficiency. To determine the diesel engine stack velocity formula, convert (horsepowerhour) -1 to MMBtu/hr and combine with current stack ve locity formula based on MMBtu/hr heater duty.

hp

* 2545 Btu

* 1 MMBtu

* 4.473
. 10 -4

* T ( **** K)

* 1 = hp * 2.276 10 -6 * T ( **** K)

* 1 = Exit velocity(m/s) hp hr 10 6 Btu D 2 (m) 50% D 228 

### Portable Diesels

Flint Hills Resources periodically requires the use of portable equipment powered by diesel engines at various locations around the refinery (e.g. portable electric generators). These diesel engines are used for recurring temporary work around the refinery such as pumping water during heavy precipitation events, powering welding equipment for repairs, and generating power for air compressors for jack hammers. As defined in Title I and II of the Clean Air Act, these sources are non-road engines and not subject to regulation under 40 CFR Parts 52 and 71. Non-road engines are not regulated under 40 CFR Part 52, 52.21 or 40 CFR Part 71, 71.3 as thes e rules apply specifically to stationary sources “any source of an air pollutant except those emissions resulting directly from an internal combustion engine for transportation purposes or from a non-road engine or non-road vehicle as defined in section 216.” This definition explicitly exclude s non-road engines; therefore, the portab le diesels do not need to be included in the SIP modeling analysis.

The non-road definitions that apply to the portable dies els are part of the Clean Air Act in Title I 40 CFR Parts 89.2 and 90.3 for non-road compression ignition engines and small spark ignition engines and Section 216 of Title II.

A “non-road engine” according to the definition in Section 216 of Title II of the Clean Air Act is:

“ An internal combustion engine (including the fuel system) that is not used in a motor vehicle or a vehicle used solely for competition, or that is not subject to standards promulgated under section 7411 of this title or section 7521 of this title.”

It defines a moving source as “any self-propelled vehicle designed for transporting persons or property on a street or highway.” Based on the description of the portable di esels, they are considered a non-road engine, not a moving source.

The non-road engine descriptions in 40 CFR Part 89. 2 and 90.3 that correspond to the portable diesels are listed below.

“That, by itself or in or on a piece of equipment, is portable or transportable, meaning designed to be and capable of being carried or moved from one location to another. Indicia of transportability include, but are not limited to, wheels, skids, carrying ha ndles, dolly, trailer, or platform.”

The description below is for an internal combustion source not being a non-road engine and this does not describe the operations of the portable diesels.

“The engine otherwise included in paragraph (1)(iii) of this definition remains or will remain at a location for more than 12 consecutive months or a shorter period of time for an engine located at a seasonal source. A location is any site at a building, structure, facility, or installation. Any engine (or engines) that replace(s) an engine at a location and that is intend ed to perform the same or similar function as the engine replaced will be included in calculating the c onsecutive time period. An engine located at a seasonal source is an engine that remains at a seas onal source during the full annual operating period of the seasonal source. A seasonal source is a statio nary source that remains in a single location on a permanent basis (i.e., at least two years) and that operates at that single location approximately three months (or more) each year. This paragraph does not apply to an engine after the engine is removed from the location.”29 

### “K348_OXD” OSWTP Thermal Oxidizer

A. Emission Point Description The Oil Separation and Waste Treatment Plant (OSWTP ) Oxidizer is an emissions control device which oxidizes odorous compounds and Volatile Organic Compounds (VOC's). The OSWTP is a permitted wastewater treatment plant. Oily wastewater from the refinery proce ss units is sent to the OSWTP for clean up. This is a two-step process. First the oil is removed from the wastewater, and then the remaining contaminants in the wastewater are biol ogically removed by activated sludge treatment. Treating air from the OSWTP is collected and routed to the Oxidizer for cleanup.

Most of the treatment tanks at the OSWTP are cover ed. They are connected to the Oxidizer by a duct system. The Oxidizer blower pulls a vacuum on the du ct system to pull the treating air containing Volatile Organic Compounds (VOC's) and odors from the treatm ent tanks into the Oxidizer. The air and VOC's flow from the blower discharge into a heat exc hanger. The heat exchanger uses hot stack gases to preheat the oxidizer feed. A natural gas fired burner heats the oxidizer f eed up to approximately 1,400 **** F and the VOC's are oxidized into CO 2 and Water. The de-contaminat ed air then passes through the heat exchanger and is discharged to the atmosphere through the stack. The oxidizer was modeled assuming catalytic operation. When the oxidizer is operated thermally, the stack temperature and velocity are increased. Since the SO 2 emission limit remains the same, the current modeling assumptions are conservative. A schematic flow diagram and description of the Oxidizer is also described in Flint Hills Resources' Air Quality Permit 106A-90-I/O-28.

Flint Hills Resources added a back-up thermal oxidizer to treat wastewater treatment plant off gases during periods wh en the main thermal oxidizer is out of serv ice. Flint Hills Re sources routes OWSTP vapor to only one oxidizer at a time; the backup oxidizer is designed to automatically start up in the event of a main oxidizer shutdown. In the event of a main oxidizer shutdow n, there will be vent gases vented to both oxidizers for a brief period during the switch. Flin t Hills Resources used t he main oxidizer in the source inventory. The backup oxidizer can operate in hot standby on natural gas. It does not have heat recovery equipment; so the temperature and flow rate of the exhaust gas are higher than the main oxidizer at the same operating rate. So, use of the main oxidizer in the source inventory represents the highest potential ambient impact from oxid izer operation at the wastewater plant.

B. Justification For Modeled SO 2 Emission Rate The wastewater feed to the OSWTP contains sma ll amounts of odorous sulfur bearing compounds (H 2 S and mercaptans). These compounds are transferred from the wastewater to the treating air in the basins and are oxidized to SO 2 in the oxidizer. Stack testing indicated that this source has shown emission rates as high as 6.2 lb/hr SO 2
. For the 1, 3 and 24 hour averaging times, the oxidizer was modeled at 50.71 lb SO 2 /hr. This is the calculated emission rate for the design air flow rate fr om the largest oxidizer ai r blower (31,500 scfm – 70° F) with an H 2 S concentration at the NSPS Subpart J limit of 162 ppm H 2 S

The blower flow rate adjusted to standard conditions at 68° F is:

31,500 ft 3 * (68°F + 460°F) = 31,381 ft 3 Min (70°F + 460°F) Min

31,381 ft 3 * 162

**** 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 * 453.59 gm * 1 Min = 6.389 gram SO 2 Min scf Fuel Gas 385 scf lbmole SO 2 lb 60 sec sec

The annual emission rate, the oxidizer was modeled at 9.0 lb SO 2 /hr. This limits SO 2 emissions from the WWTP thermal oxidizer to an emission rate which is below the PSD major modification threshold of 40 ton/yr SO 2
.30 C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations The Oxidizer was designed and built to meet the requirements of 40 CFR 60.692-5(a). This standard addresses the design requirements of control devices for the control of VOC Emissions from Petroleum Refinery Wastewater System (40 CFR 60 S ubpart QQQ). This standard does not address SO 2 emissions from VOC control devices for petrol eum refinery wastewater systems.

The Oxidizer uses only natural gas as its fuel source . There are no other applicable state or federal SO 2 emissions standards.

D. Justification For Modeled Stack Parameters With the exception of stack temperature, the Ther mal Oxidizer stack parameters are consistent with parameters modeled for SIP 8 and listed below. The st ack temperature in the model was decreased from 792 **** F to 500 **** F to allow for a project which will improve the energy efficiency of the 94H1 thermal oxidizer.

Stack height = 72.53 ft = 22.11 m Stack diameter = 5.63 ft = 1.716 m Stack temperature = 500 **** F = 533 **** K Sept 2002 performance test Flow Rate = 21,119 dscfm 21,119 dscfm* (792 **** F + 460)/(68 **** F + 460) = 50,848 acfm Stack velocity = 50,848 ft 3 /min

* 1 min / 60 sec

* 4 / [ **** (5.63 ft) 2 ] = 33.53 ft/sec = 10.36 m/sec31 

### Process Heater Steam-Air Decoking

Sources “K600_DEC” through “K603_DEC”.

A.Emission Point Description

The tubes inside of process heaters become fouled wi th coke during operation. The coke formation on the inside of the heater tubes reduces the heat tran sfer efficiency of the heater and increases the pressure required to pump the feed through the heat er and increases the temperature on the furnace side of the heater tube required to maintain fluid heating. Periodically the coke must be removed in order to maintain efficient operation of the unit. This removal process is called steam-air decoking, referred to as “decoking” for the remainder of this section.

One method for decoking is to inject steam and air into the heater tubes to oxidize the coke at a controlled rate. To begin decoking the heater, stea m is injected into the heater tubes to physically remove loose coke. Steam injection continues as the heater burners are fired with fuel gas in order to bring the tube temperature up to coke combustion temper atures. Next, air is injected at a controlled rate to oxidize the coke. Water is in jected into the decoking piping connected to the heater outlet to quench the hot gases. After the quench line, the gas/water mixture flows into a quench pit to further condense water vapor and control sulfur dioxide emissions via submerged fill.

FHR’s quench pits are concrete lined basins filled with water. The decoking quench lines route the heater decoking flue gas into the water in the quench pits. Depending on the process unit, the pit may be covered or open to the atmosphere. Emission Po ints K600_DEC (21H-1), K601_DEC (21H-2), K602_DEC (23 H-1) and K603_DEC (23 H-2) are the de coking operations, which utilize quench pits. The 21 unit heaters (21 H-1 and 21 H-2) are routed to encl osed quench pits with several openings to the atmosphere. The 23 Unit heaters (23 H_1 and 23 H-2) both vent to the same open top decoking quench pit. The 23 heaters may be decoked simultaneo usly. The 21 unit heaters are not decoked simultaneously with each other or the 23 unit heaters.

B. Justification For Modeled SO 2 Emission Rate

With SIP modification 9 (2010), FHR is refining the form er emission rate basis to improve the accuracy of both the uncontrolled and controlled emission rates.

Uncontrolled Emission Rate Basis

The SO 2 emission rates calculated for decoking process h eaters are based on the su lfur content of the coke, the amount of air used to decoke the heater, and the SO 2 removal efficiency of the quench system. The coke which forms in the tubes of the delayed co king unit heaters is assumed to have the same sulfur content as the product coke.

The emission calculations assume that all of the carbon and sulfur in the coke is oxidized. The coke burn stoichiometry is as follows:

C(s) + O 2 (g) --> CO 2 (g) s [=] solid, g [=] gas S(s) + O 2 (g) --> SO 2 (g)

(Assume all carbon is completely oxidized to CO 2 , and all sulfur is oxidized to SO 2 .)32 Since 1 mole of CO 2 is produced per mole of O 2 consumed, and 1 mole of SO 2 is produced per mole of O 2 consumed there will be no volume change in the stack gas due to reaction.

Assuming that the coke contains only Carbon (C) an d Sulfur (S) (conservative as there is ~5% - 6% hydrogen content) and that all Oxygen (O 2 ) in the decoking air is consumed, heater decoking SO 2 emissions are calculated for each pound of oxygen in the decoking air as follows:

lb O 2 = 1 lb C

* 1 lbmol C

* 1 lbmol O 2 * 32 lb O 2 + 1 lb S

* 1 lbmol S

* 1 lbmol O 2 * 32 lb O 2 12 lb C lbmol C lbmol O 2 32 lb S lbmol S lbmol O 2

which reduces to: lb O 2 = 2.667 * lb C + lb S

For coke containing only carbon and sulfur, lb C = lb coke - lb S

lb O 2 = 2.667*(lb coke - lb S) + lb S = 2.667 * lb coke - 1.667 lb S

lb O 2 / lb S = 2.667

* lb coke/lb S - 1.667 = 2.667/ (wt frac S) - 1.667

Since 1 lb S oxidizes to 2 lb SO 2 , 2 lb O 2 / lb SO 2 = 2.667/ (wt frac S) - 1.667

Rearranging, lb SO 2 = lb O 2 * [(1.333/wt frac S) - 0.833] -1

The amount of O 2 used in decoking can be determined from the decoking air use rate as follows:

lb O 2 = Air SCF/min

* 60 min/hr

* Burn Time hr

* 1 lbmol air

* 29 lb air

* 0.232 lb O 2 379 SCF lbmol air lb air

This reduces to the following equation: lb O 2 = Air SCF/min * Burn Time hr * 1.064

lb SO 2 = Air SCF/min * Burn Time hr * 1.064* [(1.333/wt frac S) - 0.833] -1

For the two 21 unit heaters, FHR has utilized peak air (O 2 ) addition rates metered during past heater decoking events to calculate worst case uncontrolled SO 2 emission rates. For the 23 unit heaters, FHR utilizes a slightly different approach based on an engineering model recently performed on the 23H-2 heater by the consulting company CBI. The model calcul ates the quantity of coke (carbon) in the heater tubes at end-of-run conditions basis, end-of-run operating conditions and model input parameters. Referencing end of run coke mass, coke sulfur cont ent, time required to decoke, and the stoichiometry detailed above, uncontrolled emission rate potentials are calculated.

Heater Total O 2 Consumption (lbs) Decoke Duration (hrs) Ave Uncontrolled SO 2 rate (lb/hr) Peak Uncontrolled SO 2 rate (lb/hr) 23H-1 20,114 20 47.8 67.0 23H-2 21,198 24 42.0 58.8 21H-1 12,970 17.5 35.3 49.4 21H-2 12,970 17.5 35.3 49.4

Controlled Emission Rate Basis:

The controlled emission rates will be calculated as follows:

lb SO 2 emitted = lb SO 2 *(1- Quench System SO 2 Removal Efficiency/100%)33 After completing an engineering study in 2010 of the quench piping and pit configurations as well as an emissions quantification study on t he quench pit of the 21-1 unit du ring a decoking event, the company proposes to model all heater decoki ng as sources with emission controls.

Heater Decoking

These sources are quenched in a pi ping system that maximizes flue gas/quench water mixing. The principle design characteristics are:

1. It has a minimum of three (3) quench water injection points. 2. The piping section is greater than 50 feet l ong and contains several bends (elbows) to ensure thorough mixing of the decoking flue gas with the quench water. 3. The quench water discharge-piping exit is well submerged below the quench pit water level to provide additional opportunity to solubilize emissions.

Measured Control Efficiency

In October of 2010, FHR contract ed Pace Analytical to utilize stack test methods to quantify SO2 emission rates during a heater burn. The tests we re conducted for approximately 12 hours during the peak air addition rate periods of the burn. An air mo ver was installed in an opening on the roof of the 21-1 quench pit and Pace utilized a pitot tube and FTIR to quantify the flow and concentration to determine the emission rates.

The average emission rate throughout the burn was approximately 2 lb/hr with a max hourly rate of 4 lb/hr. Back calculating using the max hourly uncontro lled emission rate and that measured during the 21- 1 burn:

4.0 lb SO 2 emitted = 49.4 lb SO 2 *(1- Quench System SO 2 Removal Efficiency/100%)

A control efficiency of 92% is estima ted. However, while the air mover lik ely captured the vast majority of emissions which released with the non-condensable burn relate d gases in the pit, FHR proposes to utilize a conservative 50% capture efficiency until additional studies can be completed with higher pit vapor flow rates (planned for 1 st quarter 2011).

(4.0) lb SO 2 emitted * (2 lb emitted / 1 lb Captured) = 49.4 lb SO 2 *(1- Quench System SO 2 Removal Efficiency/100%)

A control efficiency of 84% is theref ore estimated. FHR prop oses to utilize the same control efficiency at each of the other heaters due to the simila rities in quench systems noted earlier.

Decoking emissions have been calculated for the following heaters: 21H-1, 21H-2, 23H-1 and 23H-2. The annual modeled emission rates assume that each heater will be decoked for a period of up to 432 hours per year.

The SO 2 emissions from heater decoking are summarized in the following table:

Heater Peak Uncontrolled SO 2 rate (lb/hr) Control Efficiency Peak Hourly Controlled SO 2 Rate (lb/hr) 23H-1,2 126 84% 20.2 21H-1 49.4 84% 8.0 21H-2 49.4 84% 8.0

The 23 unit heaters are represented as simultaneou s burns and discharge location in the model with a combined emission rate of 20.2 lb/hr.34 Volume Source SO 2 Emission Rate From 21H-1 and 21H-2 and 23H-1 and 23H-2 Decoking (“K601 21H1D”, “K601 21H2D”, “K602 23H1D”, “K603 23H2D”

Each of these sources is quenched into concrete quench pits. 23H-1 and 23H-2 are routed together into a single, uncovered quench pit. The 21 unit pits are covered, but have small openings on both the tops and sides which can release liquids to the sluiceway. The 21 and 23 Unit decoking sources are modeled as volume sources. FHR believes these are appropriate to model as volume sources due to the multiple locations and elevations of the pit openings (21u) an d the significant temperature difference between the quench pit water/vapor and the atmosphere (50 – 100 F degrees) which results in vertical buoyancy of the non-condensable burn gases and sparge air (23u) re leasing from the water surface. The volume source emission rate for sources 601 - 603 is shown in the following table:

C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations There are no state or federal emissions standar ds for steam-air decoking of process heaters.

D. Justification For Modeled Stack Parameters

As previously noted 21H-1, 21H-2, 23H-1, and 23H-2 ar e routed to individual quench pits. The pit is modeled as a volume source and the modeled parameters are listed in the table below. 1 Hr Avg Annual

g/sec g/sec K600_DEC 21H-1 decoke 1.008 1.008 K601_DEC 21H-2 decoke 1.008 1.008 K602/603_DEC 23H-1, 2 decoke* 2.545 2.545 *Both 23 unit heaters modeled as one source; both heaters decoked to the same quench pit

. SO 2 Emissions Heater Decoking SO 2 Emission Rate

Source Description

Side Length Release Height Syinit Szinit
ft ft m m K600_DEC 21H-1 decoke 32 5 2.24 1.4 K601_DEC 21H-2 decoke 32 5 2.24 1.4 K602/603_DEC 23H-1, 2 decoke* 32 5 2.24 1.4 *Both 23 unit heaters modeled as one source; both heaters decoked to the same quench pit. Description Heater Decoking Volume Source Parameters

Model Source Parameters
Source35 

### Sulfuric Acid Handing Emissions

A. Emission Point Description

FHR uses sulfuric acid as a catalyst in the Alkylation Unit. The sulfuric acid used at the Alkylation Unit contains small amounts of dissolved SO 2 . FHR has found that some of this SO 2 is emitted when sulfuric acid is transferred into storage tanks and cargo vessels

Historically, FHR has received its fresh acid from the Flint Hills Resources Sulfur ic Acid Plant (FHSAU) by pipeline. Spent acid was returned to FHSAU by the same pipeline for reprocessing. FHR originally had four (4) acid storage tanks for this purpose.

Recently FHR upgrated its sulfuric acid handling facilities to allow shipment and receipt of sulfuric acid by rail. The upgrades include three rail loading/unloading sites at an existing rail loading rack and one (1) new storage tank. Acid pump capacity and piping configuration limit the loading and unloading rate of sulfuric acid

FHR unloads fresh acid from rail cars to the fresh ac id tank. Empty rail cars are used to ship out spent acid for re-processing. Spent acid is loaded into ra il cars at atmospheric pressure. Once the cars are filled, they must be pressure tested before shipment. This is accomplished by filling the rail car vapor space with nitrogen. The test pressure is 30 psig. After the test is complete, the car is depressurized and the nitrogen is vented to atmosphere through a kno ck out (KO) pot. The KO pot is used to prevent sulfuric acid from being released to the atmosphere durring depressurization. The depressurization vent is treated as a separate source in the modeling.

FHR currently has four (4) spent acid tanks. One tank receives spent acid from the alkylation unit, one tank is used for filling rail cars and the remaining tanks are used for gravity separation of hydrocarbons from the spent sulfuric acid. A spent acid storage tank must not be disturbed for a period of 24 hours to accomplish the acid/hdrocarbon separation. Each ta nk is filled, left standing for at least 24 hours then pumped out to rail loading. All spent acid tanks are rotated thorough this sequence.

B. Justification For Modeled SO 2 Emission Rate

SO 2 emissions occur during the filling of rail cars and storage tanks. SO 2 evolves from sulfuric acid during storage, and is emitted during vessel filling as contaminated air is pushed out of the vessel. Based on Draeger tube testing of the storage tanks and cargo vessels, SO 2 emissions are estimated to be approximately 1 lb SO 2 /hr from each emission point. Emission were calculated as follows:

Acid Loading gal * 1 ft 3 * 60 min * PPM SO 2 * 1 lb-mole * 64.06 lb SO 2 = lb SO 2 min 7.48 gal hr 1E +06 379.5 scf lb-mole hr

An emission rate of 2.27 lb SO 2 /hr was used for each source to conservatively estimate the modeled impact of these sources. The sources modeled include:

**** 1 Rail Car Loading

**** 1 Rail Car Depressurization Vent

**** 1 Fresh Acid Storage Tank

**** 1 Spent Acid Storage Tank

As noted above, SO 2 is emitted as a tank receives acid. So , two tanks (the fresh acid tank and one spent acid tank) were used to establish the SO2 emission ra te from storage tanks. The other two spent acid tanks are not included in the SO 2 emission calculation because they are either being emptied to rail loading or have a constant level during grav ity separation of acid and hydrocarbon liquids.36 C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations

There are no state or federal emissions stand ards for sulfuric acid loading and storage.

D. Justification For Modeled Stack Parameters

Each of the sulfuric acid handling emission points was modeled as a volume source per MPCA modeling guidelines.37 

### Insignificant Sources

The following sources were not included in the modeled source inventory because emissions from these sources were too small to have a significant modeled im pact as determined by either the sulfur content of the fuel or the emission rate of the source.

The low sulfur gas streams have average H2S conten ts of 0 ppm – 1 ppm. At these levels, the SO2 emission rate is 0.00015 lb SO 2 /MMBtu. As an example, a 100 MMBtu/hr heater would emit 0.015 lb SO 2 /Hr vs. 2.38 lb SO2/Hr for refinery fuel gas at 162 ppm H2S.

Source Fuel Source PPM H 2 S 1 Emission Rate Lb/Hr SO 2 Comments

Platformer Catalyst Reg Vent lb/hr NA 0.007 Emission rate as measured by performance test. Platformer Catalyst Lock Hopper Off Gas 1 NA Do not include in calculated emission rate from 37 H-345 Powerformer Catalyst Reg Vent lb/hr NA 0.03 Emission rate as measured by performance test. Central SVE TO 0.8 NA Emission rate as measured by performance test. West Tank Farm SVE TO 0.6 NA Rail Loading TO 0 NA Thermal oxidizer for rail loading of gasoline. Average gasoline sulfur content is 7ppm. Butane TO NA Flare Pilots NA #2 H2 Plant PSA Off Gas 0 NA Do not include in calculated emission rate from 27 H-1. Note evaluate S/U firing condition w full duty on fuel gas (pre PSA off gas generation).

#3 H2 Plant PSA Off Gas 0 NA Used data from #2 H2. #3 H2 plant is based on the same design as #2 H2.

Nat Gas fired asphalt tank heaters NA Max Emis Rate 0.0018 Average Emis Rate 0.0012 Max asphalt tank heater duty 3.1 MMBtu/hr; Average – 2.1 MMBtu/hr. Emissions calc’d basis AP-42

1 H2S measurement by Draeger Tube to demonstrate that the source contained minimal amounts of sulfur.

# Exhibit 1 - Section 2B Underline/Strikeout version of February 200 6 Model Protocol for the #3 Crude Expansion Project Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling AnalysisFlint Hills Resources LP Pine Bend, LLC Justification for Air Quality Modeling Inputs (revised February 2006 May 2011 )

Introduction .................................................................................................................. ........................... 1
“K1_ #1SRU” 34H-3 Merox O ff-Gas (old SRU 1/2) ................................................................................ 4
“K2_#3SRU” SRU 3, SRU 4, and TGTU (SCOT) Plant .......................................................................... 5
“K113__FG” SRU 3 Tail Gas Inci nerator on Hot Standby ...................................................................... 7
“K3_#5SRU” SRU 5 and TGTU #2 ................................................................................................. ....... 8 “K8___FCC” Fluid Catalytic Cracking Unit ............................................................................................ 10

Fuel Combusti on Devi ces ....................................................................................................... .............. 12 Stationary Dies el Engines ..................................................................................................... ................ 20

Portable Di esels .............................................................................................................. ...................... 22
“K348_OXD” OSWTP Th ermal Oxidizer ............................................................................................. .. 23 “K458_VNT” Platformer Cataly st Regenerato r Vent ............................................................................. 2 5
“K459_VNT” Powerf ormer Catalyst Regeneration ................................................................................ 2 6

Process Heater Steam -Air Decoking ............................................................................................. ....... 27

Sulfuric Acid Ha nding Emissions ............................................................................................... ........... 32 Insignificant Sources ......................................................................................................... .................... 341 

### Introduction

This document contains the supporting informatio n used to determine the input parameters for the air quality modeling demonstration of compliance with National Ambient Air Quality Standards for Sulfur Dioxide (SO 2 ) for the Pine Bend, Minnesota area. The text also inclu des a placeholder for future revisions to the NO x emissions justification; no updates for NO x are planned at this time.

General Source Model Information

The modeling analysis was prepared using ISC3 Version 02035 in the urban mode.

1973

– 1977 NOAA meteo rological data were used. Surface data were from the Minneapolis

- St. Paul airport. Upper air data were from St. Cloud MN. This is the same meteorological data set used in the original SIP modeling.

The receptor grid is based on the grid used in the or iginal SIP modeling. All original receptors were included in this analysis. Additional receptors were added along the facility’s east fence line to bring the grid density to 0.05

- kilometer spacing. The original grid only had receptors down the middle of the highway 52 corridor. In general, receptor spacing of 0.05

- kilometers was used along the facility fence line and in areas, which have shown high

- modeled concentrations in the past. The receptor grid density was increased from 0.1 km to 0.05 km per the request of Randy Robinson of US EPA Region 5. Lower receptor densities were used in areas that historically have had lower modeled concentrations. Receptor information can be found in the electronic model output files attached to this report.

The 1992 SIP modeling accounted for restricted areas at the CNRC by modeling Flint Hills Resources impacts at these receptors separately in company

- to

- company impact modeling. Because the KSAU facility is permanently shut down , its impacts will not be included. I n this submittal, the restricted access receptors on CNRC propert y were added to the general receptor grid. So, th is impact is accounted for in the model results, and no separate company

- to

- company modeling is needed.

The refinery source coordinates in the 1992 SIP modeling were based on the refinery coordinate system. The refinery 0,0 coordinate was assigned a UTM coordinate using the Metropolitan Council aerial photograph images of the area (Met Council ima ge 3734), which are referenced in UTM NAD83 datum coordinates. Individual source coordinates were c onverted to UTM’s using the refinery 0,0 coordinate as a basis. These coordinates have all been convert ed to NAD83 and adjusted per the (0,0) refinery coordinates. The 1992 SIP modeling was conducte d in UTM NAD27 datum coordinates.

The 1992 SIP building downwash analysis has been retained for this source inventory. It was conducted in refinery coordinates and used the original stack ba se elevations. This maintained the source/building geometrical relationships. The source/building relationships were verified by overlaying the source/building modeling coordinates on the aerial photograph. A building downwash analysis using BPIP was conducted on new sources added to the original source inventory (1 1 H

- 6 , Boiler #6, and Boiler # 9 ). In addition, building downwash parameters fr om each decoking source’s corresponding heater were included for the decoking sources. After the addition of downwash for the decoking sources and translation of refinery coord inates to UTM NAD83 datum, all of the source base elevations were updated.

Additional structures were added to the model input to account for structural wake effects associated with the Ultra Low Sulfur Diesel P roject and the #3 Crude Unit Expansion Project . The new structures include the heater/reactor structure for the new #4 H ydrogen P lant and the reactor structure for the Hydrocracking Unit. The structure inventory for the existing refinery was also upgraded to i nclude building wake effects associated with the #2 Hydr ogen Plant, the #3 Hydrogen Plant, and structures around the Boiler #8 . BPIP was used for the building downwash analysis. The analysis included the structures noted above to evaluate the impact of f uture and existing refinery structures on new ULSD2 project sources and existing sources in the vicinity of the ULSD site and a BPIP analysis was performed for the new 25H

- 4 heater associated with the #3 Crude Unit Expansion Project.3 The results of the modeling can be summarized as follows:

Flint Hills Resources NAAQS and MAAQS SO 2 Attainment Modeling Demonstration Modeling Results Summary - All SO 2 Concentrations in ug/m 3 February 3, 2006

Meterological Data Year 1973 1974 1975 1976 1977 Maximum Max Conc % of Std

1-Hr Avg High 2nd High 1,081 1,087 1,085 1,111 1,082 1,111 85% Current SIP 1,065 1,069 1,069 1,096 1,083 1,096 84% MN Standard 1,300 1,300 1,300 1,300 1,300 1,300

3-Hr Avg High 2nd High 720 726 793 685 560 793 61% Curent SIP 671 669 662 655 543 671 52% EPA/MN Standard 1,300 1,300 1,300 1,300 1,300 1,300

24-Hr Avg High 2nd High 256 261 225 267 226 267 73% Current SIP 223 237 213 237 215 237 65% EPA/MN Standard 365 365 365 365 365 365

Annual Avg 33 36 33 38 37 38 63% Current SIP 39 43 41 44 45 45 75% MN Standard* 60 60 60 60 60 60

* EPA standard is 80 ug/m 3

1 Hr Background 52.1 3 Hr Background 36.5 24 Hr Background 10.4 Annual Background 6.1

The 1 , 3 and 24

– hour average background values are from the MPCA. These values were used in another modeling analysis in the Minneapolis

- St. Paul metropolitan area. The background value for the annual average is from the 1992 Pine Bend modeling analysis. It was used because it is more conservative than the annual average used in the metropolitan area modeling

. The modeling analysis was conducted using AERMOD Version 09292 with the urban dispersion option selected. It is important to note that AERMOD is a new model for this analysis; the February 2006 SIP Amendment 8 (SIP8) modeling was conducted using ISC3. As of December 9, 2006, AERMOD was promulgated to replace ISC3 as the preferred dispersion model in 40 CFR Part 51 Appendix A.

MPCA recently-processed 2000–2004 AERMET meteorolog y files were used. Surface and upper air data were from the Minneapolis-St. Paul air port. This meteorological data set is from the same location as the previous SIP8 modeling, but the model years are mo re recent than the SIP8 modeling (which used 1972 – 1976 meteorology). The nearby facilities included in the modeling analysis are the Xcel Energy Inver Hills Generating Plant and Gopher Resource, LLC smel ting facility. Xcel Energy’s six turbine stack source modeled parameters were updated per Air Pe rmit 03700015-003 which reduced the fuel sulfur content to 0.05 percent by weight. The Gopher smelting facility modeled parameters were updated per Appendix B model parameters in Air Permit 03700016-003. This increased the hourly emission rates4 from 530 lb/hr to 2,080 lb/hr. The MPCA 2008 Option 2 “Rest of TC” SO 2 background conc entrations will be applied to the updated modeling results and are described in further detail in Section 9 of this Exhibit.

The receptor grid was updated following the procedures in: MPCA Guidance for Title V and PSD Air Dispersion Modeling (October 2004). In general, the density of receptors along the facility fence line and beyond was increased to show more refined concentrati on results. Receptor spacing of 10-meters was used along the facility fence line. Receptor spac ing of 50 meters extended from the fence line to a maximum distance of 0.5–kilometers depending on where past modeling maximums occurred. 250-meter spaced receptors extend from the edge of the 50-meter spaced receptor s and end approximately 2- kilometers from the facility boun dary. 500-meter spaced receptors extended to approximately 5 kilometers from the facility boundary. The receptor elevations and hill heights were calculated with AERMAP using 10 meter United States Geological Surv ey (USGS) seamless elevation data. Receptor and elevation data information can be found in the el ectronic modeling files attached to this report. Figures 1 through 3 show the ambient air boundary and the receptor grid modeled for the SIP analysis.

Modeled source locations and parameters we re based on the February 2006 SIP Amendment 8 modeling. With the update from ISC to AERMOD, t he source locations were updated based on recent Title V PM 10 modeling and using ARCGIS tools with current aerial photos. The source modeled elevations were updated using 10 meter USGS seamless elevation data.

The building downwash analysis was updated from the 1992 SIP building downwash analysis to incorporate the revised source/building relationships based on recent aerial photos and Title V PM 10 modeling. A full BPIP-Prime analysis was re-run with all the revised source and building locations and elevations.

A table summarizing the model source parameter changes from SIP 8 to SIP 9 (excluding minor coordinate/elevation changes related to new elevation data and aerial data) is shown below. The majority of changes relate to: 1) modifying limits on fuel gas sulfur content and 2) revisions to stack temperatures and velocities to ensure values conservatively represent full operating range.5 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 34H-3 K1_MEROX Planned re-routing of Merox stack emissions to 31H-2. 230 lb/hr emission rate limit was reduced to 65.4 lb/hr based on historic CEMS SO2 data. Same as SIP 8.

45H-61 K2_#3SRU Emission rate calculation for tail gas incinerator on hot standby updated. See “K2_#3SRU SRU 3, SRU 4, and TGTU SCOT Plant” section for additional detail. Temperature increase from 519.3 K to 578 K and Velocity decrease from 17.4 m/s to 16 m/s per an engineering review of historical data.

26H-21 K3_#5SRU Same as SIP 8. (Minor correction to 1 hour rate to include 1 hour bypass emissions, not 3 hour) Temperature increase from 449.8 K to 464 K per an engineering review of historical data.

71B-7 Boilers 1,2,3,4,6 & 9 K7____BH Source Removed. Source Removed.

FCC ESP K8___FCC 1,500 lb/hr emission rate was reduced to 182.65 lb/hr per demonstrated CEMS data. Temperature decrease from 449.8 K to 366 K and velocity decrease from 15.54 to 15.24 per an engineering review of historical data. 32H-5,6,7 K10_32FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). Temperature decrease from 435 K to 422 K per an engineering review of historical data. Velocity decrease from 2.80 m/s to 1.35 m/s due to velocity calculation using half of the de-rated duty. 19H-1 K11_19FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 441 K to 422 K per an engineering review of historical data. Velocity decrease from 5.01 m/s to 2.4 m/s due to velocity calculation using half of the de-rated duty. 12H-4 K13_12FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). Temperature decrease from 449.8 K to 422 K per an engineering review of historical data. Velocity decrease from 5.13 m/s to 2.41 m/s due to velocity calculation using half of the de-rated duty. 33H-31 K14_33FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 503 K to 553 K per an engineering review of historical data. Velocity decrease from 5.33 m/s to 2.93 m/s due to velocity calculation using half of the de-rated duty. 16H-1 K15_16FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). Temperature decrease from 505 K to 480 K per an engineering review of historical data. Velocity decrease from 3.80 m/s to 1.81 m/s due to velocity calculation using half of the de-rated duty.6 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 11H-3 K16_11FO Source Removed. Source Removed. 11H-5 K18_11FO Source Removed. Source Removed.
11H-1 K19_11FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 533 K to 466 K per an engineering review of historical data. Velocity decrease from 11.61 m/s to 5.08 m/s due to velocity calculation using half of the de-rated duty. 37H-1,2,6 K20_37FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm. See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 427 K to 422 K per an engineering review of historical data. Velocity decrease from 13.37 m/s to 6.61 m/s due to velocity calculation using half of the de-rated duty. 33H-32 K21_33FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm. See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 555 K to 547 K per an engineering review of historical data. Velocity decrease from 12.28 m/s to 6.05 m/s due to velocity calculation using half of the de-rated duty. 11H-2 K23_11FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 561 K to 508 K per an engineering review of historical data. Velocity decrease from 1.71 m/s to 0.77 m/s due to velocity calculation using half of the de-rated duty.

21H-1S K27_21FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 518 K to 478 K per an engineering review of historical data. Velocity decrease from 3.69 m/s to 1.7 m/s due to velocity calculation using half of the de-rated duty. 21H-1N K28_21FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 518 K to 478 K per an engineering review of historical data. Velocity decrease from 3.69 m/s to 1.7 m/s due to velocity calculation using half of the de-rated duty. 21H-2S K29_21FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 518 K to 489 K per an engineering review of historical data. Velocity decrease from 3.69 m/s to 1.74 m/s due to velocity calculation using half of the de-rated duty. 21H-2N K30_21FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 518 K to 489 K per an engineering review of historical data. Velocity decrease from 3.69 m/s to 1.74 m/s due to velocity calculation using half of the de-rated duty.7 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES33H-4 (33H1&2) K31_33FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 516 K to 550 K per an engineering review of historical data. Velocity decrease from 7.87 m/s to 4.19 m/s due to velocity calculation using half of the de-rated duty. 23H-1 K32_23FO Emission rate revised to replace fuel oil emission rates with fuel gas emission rates. Fuel Oil usage is being eliminated with SIP 9. Temperature decrease from 450 K to 422 K per an engineering review of historical data. Velocity decrease from 9.89 m/s to 4.63 m/s due to velocity calculation using half of the de-rated duty. 31H-1 K33_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 528 K to 566 K per an engineering review of historical data. Velocity decrease from 3.49 m/s to 1.87 m/s due to velocity calculation using half of the de-rated duty.

31H-2 K34_31FG 34H-3 Merox stack emissions re-routed to 31H-2. Increase emissions by 66.4 lb/hr based on historic CEMS SO2 data from 34H-3 (65.4 lb/hr) plus refinery fuel gas PTE value from Title V application (0.97 lb/hr). Temperature increase from 589 K to 666 K per an engineering review of historical data. Velocity decrease from 5.29 m/s to 2.99 m/s due to velocity calculation using half of the de-rated duty.

31H-5 K36_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 394 K to 422 K per an engineering review of historical data. Velocity decrease from 2.18 m/s to 1.17 m/s due to velocity calculation using half of the de-rated duty.

31H-10 K37_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 500 K to 525 K per an engineering review of historical data. Velocity decrease from 2.82 m/s to 1.48 m/s due to velocity calculation using half of the de-rated duty.

32H-9 K41_32FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 575 K to 533 K per an engineering review of historical data. Velocity decrease from 2.20 m/s to 1.02 m/s due to velocity calculation using half of the de-rated duty.

37H-3,4,5 K42_37FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 450 K to 422 K per an engineering review of historical data. Velocity decrease from 5.33 m/s to 2.50 m/s due to velocity calculation using half8 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES of the de-rated duty.

38H-1A K46_38FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 561 K to 600 K per an engineering review of historical data. Velocity decrease from 1.77 m/s to 0.95 m/s due to velocity calculation using half of the de-rated duty. 38H-1B K47_38FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 561 K to 600 K per an engineering review of historical data. Velocity decrease from 1.77 m/s to 0.95 m/s due to velocity calculation using half of the de-rated duty. 38H-2 K48_38FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 428 K to 422 K per an engineering review of historical data. Velocity decrease from 6.47 m/s to 3.19 m/s due to velocity calculation using half of the de-rated duty. 25H-1 K50_25FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 436 K to 422 K per an engineering review of historical data. Velocity decrease from 3.01 m/s to 1.46 m/s due to velocity calculation using half of the de-rated duty. 25H-3 K51_25FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 436 K to 428 K per an engineering review of historical data. Velocity decrease from 2.86 m/s to 1.40 m/s due to velocity calculation using half of the de-rated duty. 25H-4 K52_25FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 436 K to 422 K per an engineering review of historical data. Velocity decrease from 6.75 m/s to 3.27 m/s due to velocity calculation using half of the de-rated duty. 23H-2 K53_23FG Emission rate calculation corrected based on 45 mix drum not 41 mix drum. Temperature decrease from 486 K to 436 K per an engineering review of historical data. Velocity decrease from 11.79 m/s to 5.28 m/s due to velocity calculation using half of the de-rated duty. 27H-1 K54_27FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 411 K to 422 K per an engineering review of historical data. Velocity decrease from 11.87 m/s to 6.09 m/s due to velocity calculation using half of the de-rated duty.9 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 27H-101 K55_27FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Velocity decrease from 10.13 m/s to 5.07 m/s due to velocity calculation using half of the de-rated duty.

27H-102 K56_27FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Velocity decrease from 10.13 m/s to 5.07 m/s due to velocity calculation using half of the de-rated duty.

31H-4 K57_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 477 K to 555 K per an engineering review of historical data. Velocity decrease from 2.79 m/s to 1.63 m/s due to velocity calculation using half of the de-rated duty.

31H-7 K58_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 672 K to 544 K per an engineering review of historical data. Velocity decrease from 6.27 m/s to 2.54 m/s due to velocity calculation using half of the de-rated duty.

31H-8 K59_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 511 K to 519 K per an engineering review of historical data. Velocity decrease from 6.35 m/s to 3.23 m/s due to velocity calculation using half of the de-rated duty.

31H-9 K60_31FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 541 K to 511 K per an engineering review of historical data. Velocity decrease from 7.02 m/s to 3.32 m/s due to velocity calculation using half of the de-rated duty.

28H-1 K61_28FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 589 K to 811 K per an engineering review of historical data. Velocity decrease from 11.45 m/s to 7.88 m/s due to velocity calculation using half of the de-rated duty. 71B-8 K62_BLR8 Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 433 K to 422 K per an engineering review of historical data. Velocity decrease from 12.21 m/s to 5.95 m/s due to velocity calculation using half of the de-rated duty.10 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 27H-501 K63_27FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 411 K to 422 K per an engineering review of historical data. Velocity decrease from 6.97 m/s to 3.58 m/s due to velocity calculation using half of the de-rated duty. 11H-6 K67_11FG The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature increase from 371 K to 422 K per an engineering review of historical data. Velocity decrease from 7.35 m/s to 4.18 m/s due to velocity calculation using half of the de-rated duty.

71B-9 K68_BLR9 The 3 and 24 hour emission rates were calculated using the same basis as the 1 hr emission rate (300 ppm TS in fuel gas instead of 162 ppm). See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 435.8 K to 422 K per an engineering review of historical data. Velocity decrease from 6.23 m/s to 3.02 m/s due to velocity calculation using half of the de-rated duty.

Boiler 10 BLR10 New Source included with SIP 9. Emission Rate is similar to 71B-9 Temperature data from historical Boiler 9 data and velocity based on half of the de-rated duty of Boiler 9 30 H-401 #4 H2 Plant K70_4H2 Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature increase from 411 K to 422 K per an engineering review of historical data. Velocity decrease from 8.42 m/s to 4.32 m/s due to velocity calculation using half of the de-rated duty. 29 H-1 Comb Fd& Dist K71HCFD Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Velocity decrease from 0.22 m/s to 0.11 m/s due to velocity calculation using half of the de-rated duty.

71B-6 Boiler K1006_BH Emission rate calculation based on 120 MMBTU duty not 108 MMBTU. 3 and 24 hour emission rates calculated using 300ppm sulfur in fuel gas instead of 162ppm. Temperature decrease from 433 K to 422 K per an engineering review of historical data. Velocity decrease from 6.52 m/s to 3.18 m/s due to velocity calculation using half of the de-rated duty. 45H-6 K113__FG Annual emission rate calculated using 400ppm sulfur in fuel gas instead of 500ppm.See “Fuel Combustion Devices” section for additional detail. Temperature decrease from 588.7 K to 422 K per an engineering review of historical data. Velocity decrease from 2.25 m/s to 0.81 m/s due to velocity calculation using half of the de-rated duty. 93P-160 K331_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

93P-400 K332_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.11 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES 93P-570 K333_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

94H-1 K348_OXD For the short term averaging times, the oxidizer was modeled at 50.71 lb SO2/hr. This is the calculated emission rate for the design air flow rate from the largest oxidizer air blower (31,500 scfm – 70° F) with an H2S concentration at the NSPS Subpart J limit of 162 ppm H2S Temperature decrease from 695.2 K to 533 K to reflect improved energy efficiency following proposed convection stack/heat exchanger replacement.

EE-1657 K407_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

EE-1692 K408_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

23ME26 K435_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

EE-1309 K453_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

EE-1718 K465_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

81P-159 K505_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

81P-357 K506_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

81P-444 K507_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

81P-89 K508_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

Wood River K510_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

71C-11 K511_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

Portable diesel cap PORT_DSL Non-road engines not modeled Non-road engines not modeled

ULSD Replace K509DSL 81P-450 K513_DSL Emissions based on 0.0015% Sulfur content not 0.05% sulfur content Same as SIP 8.

21H-1 dec K600_DEC Emissions decreased from 30 lb/hr to 8 lb/hr based on Source now modeled as volume source instead of point source12 SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER CHANGES decoking engineering study

21H-2 dec K601_DEC Emissions decreased from 30 lb/hr to 8 lb/hr based on decoking engineering study Source now modeled as volume source instead of point source

23H-1 dec K602_DEC Emissions decreased from 47 lb/hr to 20.2 lb/hr based on decoking engineering study Source now modeled as volume source instead of area source

23H-2 dec K603_DEC Emissions decreased from 47 lb/hr to 20.2 lb/hr based on decoking engineering study Source now modeled as volume source instead of area source

Acid Ld & Depress K700ACDL Same as SIP8. Same as SIP8.

Acid Stor Tks K701ACDS Same as SIP8. Same as SIP8.13 The modeling results are summarized in the table bel ow. The short term averaging period results are shown for each decoking scenario (21H-1, 21H-2, and 23H-1,2) since only one decoking source operates during any averaging periods 24 hours or less. Fo r the annual averaging period, all decoking sources were included for the modeling. The results also demonstrate that the SO 2 SIP modeling results pass with 34H-3 emissions still vented from the Merox sta ck and pass with 34H-3 em issions vented out of the 31H-2 stack.

The model results are shown graphically on the a ttached “dot-map” isopleths. These figures have colored dots representing the high second high maximum modeled percent of the NAAQS at each receptor from 2000-2004 overlaid on an aerial photo of the Pine Bend, MN area. The attached “dot-map” figures are:

Figure 8

- Figures 4

- through 6 – 5 Year Maximum 1-Hour Average High Second High Concentrations. Results for Decoking Scenarios as Percent of MAAQS Figure 8

- 5

- Figures 7 through 9 - 5 Year Maximum 3-Hour Average High Second High Concentrations. Results for Decoking Scenarios as Percent of NAAQS Figure 8

- 6

- Figures 10 through 12 - 5 Year Maximum 24-Hour Average High Second High Concentrations. Results for Decoking Scenarios as Percent of NAAQS

Figure 8

- 7

- 13 – 5 Year Maximum Annual Average Concentrations. Results as Percent of NAAQS

The model inputs and outputs are included in the attached CD. It also contains PDF files of the Figures 4 through 13. The file naming convention is as follows:

crs41h 3.out SIPso1hR700 - SIPso1hR704 = 1-hour average time using 1973 2000-2004 meteorological data crs4 1h4.out = 1 SIPso3hR900 - SIPso3hR904 = 3 -hour average time using 1974 2000-2004 meteorological data Averaging Period 21H-1 Decoking Scenario Before Merox Project 21H-2 Decoking Scenario Before Merox Project 23H-1,2 Decoking Scenario Before Merox Project 21H-1 Decoking Scenario After Merox Project 21H-2 Decoking Scenario After Merox Project 23H-1,2 Decoking Scenario After Merox Project

1-Hr Avg High 2nd High 531 531 606 664 656 650 MN Standard 1,300 1,300 1,300 1,300 1,300 1,300 % Standard (Including Background) 45% 45% 51% 55% 55% 54%

3-Hr Avg High 2nd High 240 241 333 483 473 401 EPA/MN Standard 1,300 1,300 1,300 1,300 1,300 1,300 % Standard (Including Background) 21% 21% 28% 40% 39% 33%

24-Hr Avg High 2nd High 108 108 117 155 155 150 EPA/MN Standard 365 365 365 365 365 365 % Standard (Including Background) 34% 34% 37% 47% 47% 46%

Annual Avg MN Standard* % Standard (Including Background)

* EPA standard is 80 ug/m 3

1 Hr Background 56 3 Hr Background 34 24 Hr Background 17 Annual Background 4 46% 31 60 58% Before Merox Project (All Decoking) After Merox Project (All Decoking)

60 24 Flint Hills Resources NAAQS and MAAQS SO 2 Attainment Modeling Demonstration Modeling Results Summary - All SO 2 Concentrations in ug/m 3 May 201114 crs4 1h5.out = 1 SIPso24hR900 - SIPso24hR904 = 24 -hour average time using 1975 2000-2004 meteorological data crs4 1h6.out = 1

- hour SIPsoannR800 - SIPsoannR804 = Annual average time using 1976 2000-2004 meteorological data crs4 1h7.out = 1

- hour average time using 1977 meteorologi cal data

crs4 3h3.out = 3

- hour average time using 1973 meteorological data crs4 3h4.out = 3

- hour average time using 1974 meteorological data crs4 3h5.out = 3

- hour average time using 1975 meteorological data crs4 3h6.out = 3

- hour average time using 1976 meteorological data crs4 3h7.out = 3

- hour average time using 1977 meteorological data

crs4 24h3.out = 24

- hour average time using 1973 meteorological data crs4 24h4.out = 24

- hour average time using 1974 meteorologi cal data crs4 24h5.out = 24

- hour average time using 1975 meteorological data crs4 24h6.out = 24

- hour average time using 1976 meteorological data crs4 24h7.out = 24

- hour average time using 1977 meteorological data

crs4 an3.out = annual average time using 1973 meteorological data crs4 an4.out = annual average time using 1974 meteorological data crs4 an5.out = annual average time using 1975 meteorological data crs4 an6.out = annual average time using 1976 meteorological data crs4 an7.out = annual average time using 1977 meteorological data

The enclosed CD also contains jpeg files of the “dot map” isopleths.

The following areas are covered for each Emission Point in the Protocol:

A. Emission Point Description B. Justification for Modeled SO 2 Emission Rate C. Reserved for Updated Justification of Modeled NO x Emission Rate D C . Consistency Between Modeled SO 2 Emissions and Applicable State and Federal Regulations E D . Justification for Modeled Stack Parameters15 

### “K1_ #1SRU” 34H-3 Merox Off-Gas (old SRU 1/2)

A. Emission Point Description This source consists of the products of combustion of excess air from caustic (Merox) treating. Caustic treating is a chemical process used to remove me rcaptans from refinery LPG process streams and to "sweeten" gasoline blend stocks. This existing emission source is scheduled for decommission with the approval of the permit amendment an d the emissions will be vented out of the 31H-2 heater stack after project approval. As noted below, FHR proposes to retain the right under the modified SIP order to continue to utilize 34 H-3 if necessary.

B. Justification For Modeled SO 2 Emission Rate This source is currently modeled at 230 lb/hr, which is equivalent to 1,007 Ton/yr. This emission rate is consistent with the maximum expected hourly average emission rate based on a review o f monitoring data from the period April 1999

- June 2000.

C. Reserved for Updated Justification of Modeled NO x Emission Rate

D The hourly and annual SO 2 PTE values are estimated from the ma ximum expected fuel sulfur from the Merox off-gas stream using CEMS data at the Merox incinerator. The highest hourly and 365-day rolling SO 2 CEMS reading from the Merox incinerator since 2006 is 45.2 lb/hr and 35.4 tpy, respectively. Three standard deviations from the 2006-2009 data and a 20% safety factor for CEMS accuracy are added to these maximums to yield 65.4 lb/hr and 50.4 tpy.

The 34H-3 Merox stack emission s will be re-routed to 31H-2. Th e 31H-2 emissions were modeled utilizing the 65.4 lb/hr SO 2 rate from the incineration of Merox off-gas and adding the refinery fuel gas PTE values of 31H-2 fuel gas from the Title V application (0.97 lb/hr and 2.3 tpy) which yields a total estimated PTE of 66.4 lb/hr and 52.7 tpy for 31H-2.

At this time, rather than utilizing the 50.4 and 52. 7 tpy (which equates to 11.5 & 12.0 lb/hr) annual emission rates, the model conservatively utilized t he hourly emission rate basis for these annual rates (286.4 tpy and 290.9 tpy).

C . Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations There are no applicable state or federal SO 2 emissions standards for this source.

E D . Justification For Modeled Stack Parameters

This source has a Continuous Emissions Monitor (CEM ) that includes stack velocity measurement. Actual stack monitoring data were used to establish the modeling par ameters. CEM data from the period September 1999

– August 2002 were reviewed to identify the minimum 24

- hour average stack temperature and velocity. These values were used as model inputs. This period is representative of unit operations. Since the stack tip diameter is less than the stack diameter at the flow sensor location, the measured velocity is adjusted to account for the stac k exit diameter by the st ack area ratio listed below.

SRU 1/2 Stack Parameters (for SO2 modeling)

Stack height = 176' 3" = 176.25 ft = 53.72 m

Stack temperature = 581 **** F = 578.0 **** K

Stack diameter = 5' 2" = 5.17 ft = 1.57 m

Stack dia meter @ probe location = 5' 5" = 5.42 ft16 Measured stack velocity = 11.4 ft/sec

Stack exit velocity = Measured velocity * 5.42 2 = 12.6 ft/sec 5.17 2 Modeled exit velocity = 3.84 m/s (12.6 ft/sec) The 34H-3 Merox Off-gas Incinerator feed stream will be routed to the 31H-2 heater along with its own fuel gas firing after approval of the permit application and SIP Order authorizing the project. Under the SIP Order, FHR will retain the option to continue to utilize 34H-3 for these emissi ons in the event technical issues arise that prevent the tr ansfer of emissions to the 31H-2 heater.17 

### “K2_#3SRU” SRU 3, SRU 4, and TGTU (SCOT) Plant

A. Emission Point Description SRU 3 and SRU 4 are Claus sulfur recovery plants. Under normal operating condi tions, the exhaust gases from both SRU's are ducted to a Tail Gas Treating Unit (TGTU), also known as a Shell Claus Off-gas Treatment (SCOT) plant, for emissions control.

SRU 3 and SRU 4 have bypass incinerators which ar e used under start-up, shutdown and process upset conditions. SRU 3's bypass incinerator vents th rough “K113__FG” and SRU 4's bypass incinerator vents through “K2_#3SRU”. Under normal operating conditi ons the bypass incinerators are in hot standby mode and are fired on refinery fuel gas. The bypass inciner ators were modeled in the hot-stand-by condition. SRU 4 bypass incinerator is also used as an inci nerator for SRU 3 and SRU 4 sulfur degassing gases.

B. Justification For Modeled SO 2 Emission Rate

TGTU Emission Rate

A stack concentration of 500 ppmv was used to calculat e emissions for the 1 and 3 hour averaging periods and a concentration of 250 ppmv was used to calculat e emissions for 24-hour averaging periods. The annual limit is based on a stack concentration of 200 ppmv, which derives from a 30 day rolling average LAER limit.

The emission rate was determined using the design TGTU flow rate from the process flow diagrams (1990) and the stack gas SO 2 concentrations as listed above. The calculations are as follows:

Stack gas flow rates in lb mole/hr (from process flow diagram):

Total 4551.60 Water vapor (411.89) Air (237.43) (49.86/0.21 = 237.43) Air/water free 3902.28

For 1 and 3 hour average modeling @ 500 ppm:

3902.28 lbmol

* 500
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 hr lbmol stack gas lbmol SO 2 = 124.99 lb SO 2 /hr

For 24 hour average modeling @ 250 ppm:

3902.28 lbmol

* 250
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 hr lbmol stack gas lbmol SO 2 = 62.49 lb SO 2 /hr

For annual modeling @ 200 ppm:

3902.28 lbmol

* 200
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 hr lbmol stack gas lbmol SO 2 = 50.00 lb SO 2 /hr

SRU 4 Tail Gas Incinerator Emission Rates on Hot Standby

The SRU 4 bypass incinerator require s 15.477 MMBtu/Hr of heat input to operate in the hot standby mode. The tail gas incinerator is operated on refinery fuel gas. The SO 2 emission rate is calculated using the fuel gas emissions factor (see the Fuel Combustion Devices section) times the hot standby energy requirement. With the fuel gas HHV assigned as 1093 MMBtu/scf the calculated emission rates are:18 For the 1 hour averaging period: 15.477 MMBtu

* 0.0441 10 6 Btu * 1 * 300 * 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 = 0. 68 717 lb SO 2 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO 2 Hr

For the 3 hour, 24 hour and annual averaging periods: 15.477 MMBtu

* 0.0238 10 6 Btu * 1 * 162 * 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 = 0. 37 387 lb SO 2 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO 2 Hr Sulfur Degassing The emissions from sulfur degassing are calculated as follows:

450 LT/Day Sulfur feed to S RU 3 and 4 combined (1990 data)

300 ppm wt H 2 S equilibrium concentration in liquid sulfur

300 lb H 2 S

* 2240 lb S

* 450 LT S

* 64.06 lb SO 2 * 1 Day = 23.68 lb SO 2 per hour 10 6 lb S LT S Day 34.08 lb H 2 S 24 hr

The total emission rates are now :

1 hr average: 149.35 lb/hr SO 2 3 hr average: 149.04 lb/hr SO 2 24 hr average: 86.54 lb/hr SO 2 a A nnual average: 74.05 lb/hr SO 2

C. Reserved for Updated Justification of Modeled NO x Emission Rate

C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations

Emissions from SRU 3 through the TGTU are limited to 250 ppmv SO 2 on a dry, oxygen free basis for a twelve hour period by 40 CFR Part 60.104 (Subpart J). Emissions from SRU 4 through the TGTU are limited to 150 ppmv SO 2 on a dry, oxygen free basis as a 30 day rolling average due to a Lowest Achievable Emission Rate (LAER) limit. Under normal c onditions, with both SRUs venting to the TGTU the limit is 150 ppmv SO 2 on a dry, oxygen free basis as a 30-day rolling average.

The gases from the sulfur degassing are included in the 40 CFR Part 60.104 limit per EPA’s December 7, 1999 NSPS J applicability determination. The Continuou s Emission Monitor (CEM) for TGTU 1 is now located on the SRU 4 main stack (K2_#3SRU ) ), so that the CEM measures the combined exhaust gases from TGTU 1, sulfur degassing

, and SRU 4 standby incinerator operation

. The fuel gas used to maintain the SRU 4 incinerator in hot standby mode is subject to a 0.10 gr/dscf (162 ppm) limit by NSPS J.

E D . Justification For Modeled Stack Parameters

The company proposes to update the SRU 3/4 stack parameters shown below are consistent with th e following: SIP8 modeled parameters. The exit temperatur e and velocity were revised per an engineering review of historical operating data.

Parameter Proposed Value Historical SIP8 Value Stack Exit Velocity m/sec 17.4 16 21.7 17.419 Stack Exit Temperature **** K 519.3 578 547.04 519.3 Stack Exit Diameter m 1.448 1.448 Stack Height m 60.96 60.9620 The SRU 3/4 SO2 CEM system was recently relocated from the TGTU incinerator out let to the main stack. Since that time, the measured stack velocity during low sulfur production rates was 21.7 m/sec. The proposed stack conditions include a reduction in stac k velocity by 20% from this value to provide a ma rgin of safety in the modeled impact of SRU 3/4.



### “K113__FG” SRU 3 Tail Gas Incinerator on Hot Standby

A. Emission Point Description This source is the tail gas incinerator for SRU 3. This incinerator is a safety and environmental control device designed to combust the tail gas from SRU 3 if the TGTU must be bypassed. Under normal operating conditions the tail gas incinerators are in hot standby mode and are fired on refinery fuel gas. The tail gas incinerators were modeled in the hot-stand-by condition. See “K2_#3SRU” for additional information on SRU 3/4 and the TGTU.

B. Justification For Modeled SO 2 Emission Rate The SRU 3 bypass Incinerator requires 11.141 MMBtu/hr of heat input to operate in the hot standby mode. The bypass incinerator is operated only on refinery fuel gas. The SO 2 emission rate is calculated using the fuel gas emissions factor (see the Fuel Combustion Devices section) times the hot standby energy requirement.

For the 1 hour averaging period:

11.141 MMBtu

* 0.0441 lb SO 2 = 0.49 10 6 Btu * 1 * 300 * 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 = 0.516 lb SO 2 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO 2 Hr

For the 3 hour, 24 hour and annual averaging periods:

11.141 MMBtu

* 0.0238 10 6 Btu * 1 * 162 * 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 = 0. 27 278 lb SO 2 Hr MMBtu Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO 2 Hr

C. Reserved for Updated Justificat ion of Modeled NO x Emission Rate

D The SRU 3 bypass incinerator also accepts an exhau st gas stream from t he SRU 3 Process Tail Gas Analyzer. The exhaust is a 1 inch line routed to the 45H6. The SO 2 emissions rate quantification from this stream is estimated from the SO 2 ppm concentration maximum of 30 ppm. This value is determined from the actual demonstrated maximum as observed from Ja nuary 2009 to November 2009. Emission rates are determined from the stack gas flow rate maximum demonstrated in the standby operation during the two years prior to November 2010. As such the maximum expected emission rate associated with the analyzer exhaust in the SRU 3 bypass incinerator is:

(30 * 10 -6 * 64 lbsSO 2 * 60 min * 2500 ft 3 * 1 lb-molSO 2 = 0.747 lb SO 2 lb-molSO 2 hr min 385.3 Hr

C . Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations The fuel gas used to maintain the SRU 3 bypass inciner ator in hot standby mode is subject to a 0.10 gr/dscf (162 ppm) limit by NSPS J. The gases from the sour water tanks and sulfur deg assing are not subject to this restriction.

E D . Justification For Modeled Stack Parameters21 The stack exit velocity was determined using the hot standby energy requirement and the process heater and boiler stack velocity formula. The following stack parameters were used:

Stack Height 176.1 ft (53.68 m)

Stack Inner Diameter 3.33 ft (1.02 m)

Stack Temperature 600 **** F (589 **** K)

Stack Velocity 4882 acfm = 2.25 m/sec Parameter Modeled Value Stack Exit Velocity m/sec 0.81 Stack Exit Temperature **** K 422 Stack Exit Diameter m 1.016 Stack Height m 53.6822 

### “K3_#5SRU” SRU 5 and TGTU #2

A. Emission Point Description SRU 5 is a Claus sulfur recovery plant. Under norm al operating conditions, the exhaust gases from the SRU are ducted to TGTU #2 for emissions control.

SRU 5 has a bypass incinerator (26H-21) which is used under start-up, shutdown and process upset conditions. This incinerator is a safety and environme ntal control device designed to combust the tail gas from SRU 5 if TGTU #2 must be bypassed. SRU 5's ta il gas vent is routed through the same stack as the bypass incinerator. Under normal operating conditions the bypass incinerator is in hot standby mode and is fired on refinery fuel gas. The bypass incinerator wa s modeled in the hot standby condition. SRU 5 bypass incinerator is also used as an inciner ator for SRU 5 sulfur degassing gases.

B. Justification For Modeled SO 2 Emission Rate This source has emissions limits of 170.8 lb SO 2 per hour for 1-hour periods, 170.8 lb SO 2 per hour averaged for 3-hour periods, and 93.6 lb SO 2 per hour averaged for 24-hour periods. The 24-hour limit is also used as the annual modeled emission rate. Em issions from TGTU #2 are limited by NSPS J to 250 ppm SO 2 on a dry, oxygen free basis. A stack concentr ation of 500 ppmv was used to calculate emissions for the 1 and 3-hour average periods and a concentrat ion of 250 ppmv was used to calculate emissions for 24-hour and annual average periods. The TGTU #2 emis sion rate was determined from the design process flow rate and the stack gas SO 2 concentrations as listed above. This source includes a contribution of 15.80 lb SO 2 per hour to account for emissions from sulfur de-gassing. MPCA staff has requested that Flint Hills Resources employ sulf ur de-gassing to reduce H 2 S and TRS emissions from sulfur storage and loading. The calculations are as follows:

TGTU Emission Rates

Stack gas flow rate lb mole/hr

Total 6155.03 Water vapor (746.82) Air (582.91) (122.41/0.21 = 582.91) Air/water free 4825.30

For 1 & 3 hour average modeling @ 500 ppm:

4825.30 lbmol

* 500
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 = 154.55 lb SO 2 /hr hr lbmol stack gas lbmol SO 2
For 24 hour and annual average modeling @ 250 ppm:

4825.30 lbmol

* 250
. 10 -6 lbmol SO 2 * 64.06 lb SO 2 = 77.28 lb SO 2 /hr hr lbmol stack gas lbmol SO 2
SRU 5 Bypass Incinerator Emission Rates on Hot Standby

The SRU 5 bypass incinerator require s 20.0 MMBtu/Hr of heat input to operate in the hot standby mode. The tail gas incinerator is operated only on refinery fuel gas. The SO 2 emission rate is calculated using the fuel gas emissions factor (see the Fuel Combustion Devices section) times the hot standby energy requirement.

For the 1 hour averaging period: 20.0 MMBtu

* 0.0441 lb SO 2 = 0.882 lbs SO 2 Hr MMBtu Hr23 For the 3, 24 hr and annual averaging periods: 20.0 MMBtu

* 0.0238 lb SO 2 = 0.476 lbs SO 2 Hr MMBtu Hr

Sulfur Degassing The emissions from sulfur degassing are calculated as follows:

300 LT/Day Sulfur feed to SRU 5

300 ppm wt H 2 S equilibrium concentration in liquid sulfur

300 lb H 2 S

* 2240 lb S

* 300 LT S

* 64.06 lb SO 2 * 1 Day = 15.80 lb SO 2 per hour 10 6 lb S LT S Day 34.08 lb H 2 S 24 hr

The total emission rates are now :

1 hr average: 171.23 lb/hr SO 2 3 hr average: 170.83 lb/hr SO 2 24 hr average: 93.56 lb/hr SO 2 a A nnual average: 93.56 lb/hr SO 2
C. Reserved for Updated Justification of Modeled NO x Emission Rate

D C . Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations NSPS J limits the SO 2 content from TGTU #2 to 250 ppmv on a dry, oxygen free basis for a twelve-hour period. Therefore, the 24-hour av erage stack concentration was limit ed to 250 ppmv. The 3-hour average emissions limit was kept at 500 ppmv in order to limit the pot ential for exceedance of NSPS.

The gases from the sulfur degassing are included in the 40 CFR Part 60.104 limit per EPA’s December 7, 1999 NSPS J applicability determination. The Continuou s Emission Monitor (CEM) for TGTU 2 is now located on the SRU 5 main stack (K3_#5SRU) so th at the CEM measures the combined exhaust gases from TGTU 2, sulfur degassing and SRU 5 standby incinerator operation

The fuel gas used to maintain the SRU 5 incinerator in hot standby mode is subject to a 0.10 gr/dscf (162 ppm) limit by NSPS J.

E D . Justification For Modeled Stack Parameters

The com pany proposes to update the SRU 5 3/4 stack parameters shown below are consistent with the following: SIP8 modeled parameters. The exit temperatur e was revised per an engineering review of historical operating data.

Parameter Proposed Value Historical SIP8 Value Stack Exit Velocity m/sec 9.3 11.6 9.3 Stack Exit Temperature **** K 449.82 464 449.82 Stack Exit Diameter m 2.103 2.103 Stack Height m 65.0 65.024 The SRU 5 SO2 CEM system was recent ly relocated from the TGTU incine rator outlet to the main stack. Since that time, the measured stack velocity during low sulfur production rates was 11.6 m/sec. The proposed stack conditions include a reduction in s tack velocity by 20% from th is value to provide a margin of safety in the modeled impact of SRU 5.25 

### “K8___FCC” Fluid Catalytic Cracking Unit

A. Emission Point Description The Fluid Catalytic Cracking unit (FCC) is a process unit that converts gas oil into Liquefied Petroleum Gas (LPG), gasoline and fuel oil. Gas oil is a refinery stock that is similar in gravity and appearance to motor oil. The conversion is accomplished by catalytically cra cking (breaking) the gas o il molecules into smaller molecules. The reaction takes place in a fluidized bed reactor. Coke is formed as a side reaction and is deposited on the catalyst. After passing through the reactor, the oil and cata lyst are separated by cyclones. The reaction products (LPG, gasoline and fuel oil) are separated by distillati on and sent on for further refinery processing. The coke deposits on the cata lyst are removed in the catalyst regenerator and the catalyst is recycled to the FCC reactor.

The FCC catalyst regenerator decokes the FCC catalyst by fluidized bed combustion. Sulfur in the coke is oxidized to SO 2 . The FCC regenerator flue gas and the regenerated catalyst are separated by cyclones.The catalyst is returned to the reactor. The regenerator flue gas is sent to the Large Waste Heat Carbonmonoxide (WHCO) Boiler (17H-2) and the Small WHCO Boiler (17H-4) for heat recovery and to oxidize residual regenerator exhaust gas CO. The exhaust gases are then ducted to an Electrostatic Precipitator (ESP) to reduce the particulate emissions. Emissions from caustic neutralization may also be vented through the FCC emission points.

This source represents the new WHCO Boiler stack. Since the construction of the new stack is not related to reductions in SO 2 , Federal GEP Guidelines require that the source be modeled for SO 2 with the existing stack exit parameter s unless the source emits less than 5000 Ton/yr of SO 2 . Since Flint Hills Resources committed to this emission limit, the old stack parameters need no longer be used for SO 2
.

B. Justification For Modeled SO 2 Emission Rate This source is modeled at 1,500 182.6 lb/hr ( 800 tpy) ( through K8__FCC) for 1, 3 and

, 24-hour averaging periods. It is modeled at 685 lb/hr for the , and annual averaging period s . These emission rates are consistent with the current per mitted represent the maximum expected hourly average emission rate for the FCC Unit. based on a review of monitoring data from the period December 31, 2005 - July 31, 2009 plus three times the standard deviation of the entire data set for a conservative base. This emission rate is also a Title V limit.

C. Reserved for Updated Justification of Modeled NO x Emission Rate

D C . Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations The FCC is subject to NSPS J, which limits SO 2 emissions to 50 ppmv; Flint H ills Resources monitors these emissions with a CEMS, per NSPS J requirements, to ensure compliance with this limit. An FCC SO 2 emission rate of 1,500 182.6 lb SO 2 /hr is consistent with 0.3-wt% sulfur feed (which is an alternate method of compliance).

E D . Justification For Modeled Stack Parameters

The company proposes to update the FCC stack parameters with the following conditions. FCC stack parameters shown below are consist ent with SIP8 modeled parameters. The exit temperature and velocity were revised per an engineering review of historical operating data.

Parameter Modeled Proposed Value Measured SIP8 Value Stack Exit Velocity m/sec 15. 54 24 30.00 15.54 Stack Exit Temperature **** K 449.8 366 488.5 449.8 Stack Exit Diameter m 2.94 2.9426 Stack Height m 69.27 69.27

The stack conditions, which have generat ed the lowest measured stack velocity in the last five years, were 18.29 m/sec at 478 **** K. Since these values are lower than the hi storical model inputs, it seems appropriate to reduce the FCC stack parameters. The proposed stac k conditions include a reduction in stack velocity by 15% from this value to provide a margin of safety in the mode led impact of the FCC

.

Note that the actual stack hei ght of the new stack is 80.00 m and that the GEP stack height, as agreed to by the MPCA and Flint Hills Resources Refining Company

, is 69.27 m.27 

### Fuel Combustion Devices
“K 7 10

.. . ” through “K99 ..”, ...”, “K1001 ..” ...” through “K1006 ..”, ...”, and “K454 ..” ...” through “K457 ..” ...”

A. Emission Point Description Process heaters are used throughout the refinery to heat up the refinery process streams to the proper temperature for chemical reactions or distillation. Bo ilers are used to generate steam for heating process streams in heat exchangers, process line heat tracing and operating turbine driven pumps.

The refinery currently operates these sources on gaseou s fuels. These fuels include natural gas, refinery fuel gas, LPG fuel and PSA off gas. Natural gas, refinery gas and LPG are blended and distributed through the refinery’s fuel gas supply system. In so me cases sources may also burn natural gas directly from the natural gas supply system. Refinery fuel ga s is a mixture of low molecular weight hydrocarbons that is produced as a byproduct of the refining pr ocess. PSA off gas is a byproduct of hydrogen production; its fuel value comes from carbon monoxid e, hydrogen and methane. It is combusted only in the #2, #3, and #4Hydrogen plants.

Emissions from refinery fuel oil combustion have been removed from the model in this SIP update. Historically, the refinery has used re finery fuel oil as an energy source . The , but the use of refinery fuel oil was discontinued in September 2001. Emissions from refinery fuel oil combustion have been

There are three existing boilers (71B-6, 71B-8, and 71 B-9) and one future boiler (BLR10) that were included in the model to preserve the emission reduction credits for PSD netting purposes.

The SIP modeling and they are modeled as separate stac ks. Boiler 10 is located due south of 71B-9 and its parameters are included in Section 4 of this Exhibit. The refinery boiler house currently has that ducted four boilers (1-4) that are ducted to a common stack, “K7__BH ”. ”, was demolished and removed from the SIP modeling analysis. The facility has accepted facility wide SO 2 limit of 3,770 ton/yr and uses the common stack for all boiler house SO 2 modeling as allowed under PSD regulations for sources emitting less t han 5000 Ton/yr of SO 2
. A new boiler (71B

- 9) was added outside of the boiler house and Boiler 6 is operating out of its own stack instead of the combined stack 71B

- 7. To allow a more conservative result, Boilers 6 and 9 were modeled twice, each as separa te stacks and as a part of the boiler house.

. #3 Crude Unit Expansion Merox off-gas to 31H-2 Project:

To meet its requirements to produce ultra low sulfur diesel fuel, FHR i nstall ed three new process heaters (29H

- 1, 29H

- 2 and 30H

- 401 ) and a diesel powered emergency cooling w ater pump (K_513)

. In the previous version of the SIP modeling, 30H

- 401 and 29H

- 1 , 2 were modeled in 3 locations to allow flexibility in process unit design. 29H

- 1 is the charge heater for the Hydrocracker, and 29H

- 2 will be the fractionator heater for th e Hydrocracker. These heaters were designed as two separate heaters or one heater with a split firebox (one firebox section for each service). The combined duty of 29H

- 1 and 29 H

- 2 was used to determine the SO2 emission rate to account for the maximum pot ential SO2 emission rate (i.e. a combined firebox emission rate). The de

- rated (minimum) duty for 29H

- 2 was used to determine stack velocity. This matches the minimum stack ve locity associated with constructing two separate heaters. The locations of the tw o process heaters 30H

- 401 and 29H

- 1 , 2 are known and the UTM coordinates were used in this model run

.

A new vacuum heater (25H

- 4) with an air pre

- heat system was added as a point source with fuel gas coming from mix drum 45. Two other heater s that get fuel from mix drum 45 (25H

- 1 , 3 ) have been modified with a new convection system, additional burners, and a conversion to an 8 pass system. The 25H

- 3 burner has also been modified to operate as a vacuum prefractionator heater. The Merox Off-gas Incinerator feed stream will be rout ed to the 31H-2 heater along with its own fuel gas firing. Therefore the emissions at 31H-2 after the project will be equivalent to existing 31H-2 emissions28 plus Merox off-gas incinerator emissions. FHR intends to decommission the 34H-3 Merox incinerator after successful project completion; however, FHR in tends to continue to utilize 34H-3 in the event that technical issues arise that prevent implementation of this project.

With this update, the Merox Incinerator hourly and annual emission rates were updated to reflect the most recent SO 2 emissions monitoring data from December 31, 2005 through July 31, 2009. This effectively reduced the modeled hourly emission rate from 230 lb/hr to 65.4 lb/hr and the annual emission rate from 1,007 ton/yr to 52.7 ton/yr.

B. Justification For Modeled SO 2 Emission Rate

Fuel Gas Combustion

SO 2 emissions from fuel gas combustion are calculat ed using the maximum energy input of each heater and boiler, the energy content of the fuel gas as the High Heating Value (HHV) in BTU/scf and the SO 2 sulfur content of the fuel gas.

Refinery fuel gas enters the refinery fuel gas system through two mix drums (41V-33 and 45V-39) referred to as the 41 mix drum and the 45 mix drum. An H 2 S analyzer is located on the outlet of each mix drum. The analyzers are used to monitor refinery fuel gas for compliance with applicable H 2 S limits. Since the make up makeup of the refinery fuel gas is different at each mix drum, the average fuel gas heating values and sulfur content at each mix drum is different. The fuel gas from mix drum 41V-33 has an H 2 S concentration that correlates well with SO 2 emissions from the combustion unit stacks, since there is not a significant concentration of non-H 2 S sulfur compounds present in the 41 mix drum fuel gas. Fuel gas from the 45V-39 mix drum contains a larger percentage of sulfur compounds that are not regulated under New Source Perform ance Standards (NSPS). These additional sulfur compounds in the 45 mix drum are associated with upstream processes, primarily the coker gas recovery units. The presence of higher s ulfur levels in the 45 mix drum and not in the 41 mix drum was determined by the placing and measurement of SO 2 monitors in heaters 25H

- 3 ( representing the 45 mix drum ) and 11H

- 6 ( representing the 41 mix drum ). Therefore, the calculated SO 2 emission rate takes into account which fuel gas mix drum supplies each heater and boiler. Actual SO 2 emission rates are now monitored via stack SO 2 CEMS representative of 45 mix drum sourced heaters and via a reduced sulfur compound CEMS on the 41 mix drum.

For this SIP Modification, SO 2 emissions from the 45 mix drum fuel gas remain based on 500 ppm sulfur in fuel gas which equates to approximately 54 ppm SO 2 at the heater stack on an O 2 free basis using an F factor basis. The average annual concentration is pr oposed to be decreased from 500 ppm (SIP 8) to 400 ppm with this modification. SO 2 emissions from the 41 mix drum fuel gas is are conservatively based

on the H 2 S content reduced sulfur contents limited to 162 300 ppm for the 1-hour, 3-hour, and 24-hour

, and annual averaging periods and 300 162 ppm H 2 S reduced sulfur for the 1

- hour annual averaging period. For heaters and boilers firing fuel gas from the 45 mix drum

, These input parameters remain consistent with SIP 8 with the H 2 S content is conservatively assumed to be 500 ppm for all exception of the 3-hour and 24-hour averaging periods

. The heating values were assigned to heaters which are proposed to be increased from 162 to 300 ppm to provide consistency with the 1-hour standard and boilers as follows: account for inherent process variability during low rate operation.

The SO 2 emissions per MMbtu (10 6 btu) per hour of fuel burned at the fuel sulfur content limits from fuel gas firing for each mix drum are calculated as follows:

1 Hour Fuel Gas SO 2 Emission @ 300 ppm 41 Mix Drum (Reduced Sulfur CEMS Basis):29 SCF [=] Standard Cubic Feet (at 60 **** F)

FG HHV = Fuel Gas High Heating Value in BTU/SCF

Where fuel gas flow is measured at 60 **** F and 1 Atm

Heater Duty MMBtu * 1

**** 10 6 Btu * 1 * 300

**** 10 - 6 C TRS scf sulfur (as predominantly H 2 S * 1 lbmole H 2 S * 64 lb SO 2 ) * Hr MMBtu FG HHV Btu/scf 10 6 scf Fuel Gas 379 scf

1 lbmole SO 2
sulfur (as H 2 S) * 64 lb SO 2 * 453.59 gm g * 1 Hr = _____ gm gram SO 2

379 scf lbmole SO 2 lb 3600 sec sec

3 Hour, 24 Hour, and Annual Fuel Gas SO 2 Emissions @ 162 ppm

45 Mix Drum (Stack SO2 @ 0% O2 CEMS & Fd factor Basis):

Heater Duty MMBtu * 1

**** 10 6 Btu * 1 * 162

**** 10 - 6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 8511 dscf flue gas * C SO2 scf sulfur (as SO 2 @ 0% O2) * Hr MMBtu FG HHV Btu/scf scf Fuel 10 6 dscf Flue Gas 379 scf

1 lbmole SO 2 * 64 lb SO 2 * 453.59 gm g * 1 Hr = _____ gm gram SO 2 379 scf lbmole SO 2 lb 3600 sec sec

1, 3, 24 hour and Annual Fuel Gas SO 2 Emissions at 500 ppm (Oxygen Free)

10 6 Btu * 1 scf * 500ppm * 1 MMBtu = 4.48 *10 - 5 ppm*MMBtu = 45 ppm*Btu Hr 1093 Btu 10 6 10208 scf hr hr

Refinery Fuel Gas Heating Value Assignments P:\23\19\939\SIP\newModel Input Basis
Source Description ISC_id HHV Btu/scf Source Description ISC_id HHV Btu/scf Source Description ISC_id HHV Btu/scf 71B-7 Boilers 1,2,3,4,6 & 9 K7____BH 1197 33H-4 (33H-1&2) K31_33FG 1093 27H-101 K55_27FG 1093

32H-5,6,7 K10_32FG 1197 23H-1 FO fired K32_23FO 1197 27H-102 K56_27FG 1093 19H-1 K11_19FO 1197 31H-1 K33_31FG 1197 31H-4 K57_31FG 1197 12H-4 K13_12FG 1197 31H-2 K34_31FG 1197 31H-7 K58_31FG 1197 33H-31 K14_33FO 1093 31H-5 K36_31FG 1197 31H-8 K59_31FG 1197 16H-1 K15_16FG 1197 31H-10 K37_31FG 1197 31H-9 K60_31FG 1197 11H-3 K16_11FO 32H-9 K41_32FG 1197 28H-1 K61_28FG 1093 11H-5 K18_11FO 37H-3,4,5 K42_37FG 1093 71B-8 K62_BLR8 1093 11H-1 K19_11FO 1197 38H-1A K46_38FG 1093 27H-501 K63_27FG 1093 37H-1,2,6 K20_37FG 1093 38H-1B K47_38FG 1093 11H-6 K67_11FG 1197 33H-32 K21_33FG 1093 38H-2 K48_38FG 1093 71B-9 K68_BLR9 1197 11H-2 K23_11FG 1197 25H-1 K50_25FG 1093 30 H-401 #4 H2 Plant K70#4H2 1093

21H-1S FO fired K27_21FO 1197 25H-3 K51_25FG 1093 29 H-1 Comb Fd& Dist K71HCFD 1093

21H-1N FO fired K28_21FO 1197 25H-4 K52_25FG 1093 71B-6 Boiler K1006_BH 1197 21H-2S FO fired K29_21FO 1197 23H-2 K53_23FG 1197 45H-6 K113__FG 1093 21H-2N FO fired K30_21FO 1197 27H-1 K54_27FG 109330 Refinery31 The heating values were assigned to heaters and boilers as follows:

In many cases, refinery fuel gas is used to calculate the SO 2 emission rate for sources combusting natural gas and PSA off gas. Since the H2S content of refinery fuel gas is highe r than the sulfur content of natural gas and PSA off gas, the model ed emission rate is conservative.

**** Commercial natural gas sulfur content is limit ed to 0.02 gr/dscf vs. the NSPS refinery fuel gas limit of 0.10 gr H 2 S/dscf (162 ppm)

**** PSA off gas typically has an H2S content of 1 ppm or less vs. the NSPS refinery fuel gas limit of 162 ppm H 2 S.

SO 2 Emissions from refinery fuel oil combustion

Historically, the refinery has used Emissions from refinery fuel oil as an energy source. The combustion have been removed from the model since the use of refinery fuel oil was discontinued in September 2001. Emissions from refinery fuel oil combustion have been included

Merox off-gas to 31H-2 Project:

The Merox Off-gas Incinerator feed stream will be rout ed to the 31H-2 heater along with its own fuel gas firing. Therefore the emissions at 31H-2 after the project will be equivalent to existing 31H-2 emissions plus Merox off-gas incinerator emissions. FHR intends to decommission the 34H-3 Merox incinerator after successful project completion; however, FHR intends to continue to utilize 34H-3 in the model to preserve the SO 2 emission reduction credits for PSD netting purposes. To ensure event that the emission reductions are fully creditable, each source burning fuel oil was technical issues arise that prevent implementation of this project.

With this update, the Merox Incinerator hourly and annual emission rates were updated to reflect the most recent SO 2 emissions monitoring data from December 31, 2005 through July 31, 2009. This effectively reduced the modeled with an SO 2 hourly emission rate equal from 230 lb/hr to 65.4 lb/hr and the sum of its maximum SO 2 annual emission rate burning refinery fuel gas plus its historical average SO 2 emission rate from fuel oil combustion. No SO 2 from fuel gas combustion was included in the from 1,007 ton/yr to 52.7 ton/yr. The Merox emissions were summed with the 31H-2 emission rates for the modeled emission rates for heaters 11H

- 3 and 11H

- 5. These heaters were still mode led in this latest model run for PSD netting purposes, but they were removed from service and replaced by heater 11H

- 6 rate

. Source Descri p tion ISC_id HHV Btu/sc f Source Descri p tion ISC_id HHV Btu/scf Source Description ISC_id HHV Btu/scf 32H-5,6,7 K10_32FG 1197 31H-1 K33_31FG 1197 27H-102 K56_27FG 1093 19H-1 K11_19FO 1197 31H-2 K34_31FG 1197 31H-4 K57_31FG 1197 12H-4 K13_12FG 1197 31H-5 K36_31FG 1197 31H-7 K58_31FG 1197 33H-31 K14_33FO 1093 31H-10 K37_31FG 1197 31H-8 K59_31FG 1197 16H-1 K15_16FG 1197 32H-9 K41_32FG 1197 31H-9 K60_31FG 1197 11H-1 K19_11FO 1197 37H-3,4,5 K42_37FG 1093 28H-1 K61_28FG 1093 37H-1,2,6 K20_37FG 1093 38H-1 A K46_38FG 1093 71B-8 K62_BLR8 1093 33H-32 K21_33FG 1093 38H-1B K47_38FG 1093 27H-501 K63_27FG 1093 11H-2 K23_11FG 1197 38H-2 K48_38FG 1093 11H-6 K67_11FG 1197 21H-1S FO fired K27_21FO 1197 25H-1 K50_25FG 1093 71B-9 K68_BLR9 1197 21H-1N FO fired K28_21FO 1197 25H-3 K51_25FG 1093 30 H-401 #4 H2 Plant K70#4H2 1093 21H-2S FO fired K29_21FO 1197 25H-4 K52_25FG 1093 29 H-1 Comb Fd& Dist K71HCFD 1093 21H-2N FO fired K30_21FO 1197 23H-2 K53_23FG 1093 71B-6 Boiler K1006_BH 1197 33H-4 (33H-1&2) K31_33FG 1093 27H-1 K54_27FG 1093 45H-6 K113__FG 1093 23H-1 FO fired K32_23FO 1093 27H-101 K55_27FG 1093 Boiler 10 BLR10 1197 Refinery Fuel Gas Heating Value Assignments November 201032 During the two

- year baseline period of June 1998 to May 2000

, an average of 144,453 Bbl/yr of fuel oil were combusted. This fuel oil use rate represents the average fuel oil use rate at the start of negotiations with EPA, which resulted in a consent decree requi rement to reduce or eliminate fuel oil combustion. During this period the average sulfur content of the refinery fuel oil was 0.922 wt % S. The average density of refinery fuel oil is 388 lb/Bbl, and its heat content is 6.7 MMBtu HHV/Bbl.

The SO2 emissi on rate in gm/sec is calculated as follows:

Historical FO use Bbl * 388 lb * 0.922 % S * 2lb SO 2 * 453.59 gm * 1 yr * 1 Hr = ___ gm SO 2 Yr Bbl FO 100% lb S lb 8,760 Hr 3,600 Sec Sec

The historical refinery fuel oil use per source was as follows:



### Historical Refinery Fuel Oil Use

Source Description ISC_id Hist FO Use Bbl/yr Fuel Oil %S 0.922%
71B-7 Boilers 1,2,3,4,6 K7____BH 37,165

19H-1 K11_19FO 3,170 33H-31 K14_33FO 40,763 11H-3 K16_11FO 17,842
11H-5 K18_11FO 8,101
11H-1 K19_11FO 11,154 21H-1S K27_21FO 4,846 21H-1N K28_21FO 4,846 21H-2S K29_21FO 4,642
21H-2N K30_21FO 4,642 23H-1 K32_23FO 7,282

C. Reserved for Updated Justification of Modeled NO x Emission Rate

D33 C . Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations Minnesota rule 7005.2120 Subpart 2 and Federal rule 40 CFR 60.104(1) limits the amount of H 2 S in fuel gas burned in new fuel gas combustion devices (h eaters and boilers) to 0.1 gr per dscf. This concentration can be converted to ppm as follows: 0.10 gr/dscf of H 2 S at 1 atm, 20 **** C

0.10 gr
* 1 lb H 2 S

* 1 lbmol H 2 S

* 385.4 dscf

* 10 6 = 162 ppm dscf 7000 gr 34.076 lb H 2 S lbmol H 2 S

NSPS standard conditions ar e: 1 Atm (101.3 kPa) & 20 **** C (293 **** K)

dscf/lbmol: 1 lbmol = 359.05 ft 3 at 0 **** C, 1 ATM

359.05 ft 3

* 293 **** K = 385.4 dscf/lbmol (STP for NSPS) 273 **** K

Minnesota rules 7005.2110 subpart 2 and 7005.2120 subpar t 3 limit the sulfur content of fuels burned in new and existing indirect heating equipment (heaters and boilers) to 3.0 lb SO 2 /MMbtu for any individual piece of equipment and 1.75 lb SO 2 /MMbtu for the aggregate facility. Based upon the quality of the refinery's fuels, the SO 2 emission rate per MMbtu o f fired duty is as follows:

Refinery Fuel Oil is 388 lb/Bbl and 6.7 MMBtu/Bbl HHV for fuel oil. The average sulfur content of fuel oil during the baseline period was 0.922 wt % S.

1 Bbl * 388 lb * 0.922 %S * 2 lb SO 2 = 1.07 lb SO2 of fuel oi l burned 6.7 MMBtu Bbl 100% lb S MMBtu

At 1.07 lb SO 2 /MMbtu, any Emission Point burning 100% refinery fuel oil would be in compliance with the individual source limit of 3.0 lb SO 2 /Mmbtu and wi th the aggregate facility limit of 1.75 lb SO 2 /MMBtu.

E D . Justification For Modeled Stack Parameters

Stack parameters for heaters and boilers are based on their maximum fired duties, fuel gas combustion stoichiometry at 0% excess O2, and the listed stack dimensions and stack temperatures represent the minimum operating temperature and velocity under normal operating conditions for each Emission Point.

In general, for the purposes of this model, most fi red sources were modeled at a temperature and exit velocity well below that at which they normally operate and, as it relates to temperature, at a level which they could not operate without risk of corrosion damage in the heaters. The purpose of this is to allow greater operational flexibility.

The following flue gas generation rates were used to calculate stack velocities:

**** Refinery Fuel Gas (Mix Drum 41) = 10,215 scf flue gas per MMBtu HHV of fired duty

**** Refinery Fuel Gas (Mix Drum 45) = 10, 208 scf flue gas per MMBtu HHV of fired duty

**** #2 H2 Plant PSA Purge Gas = 10,883 scf flue gas per MMBtu HHV of fired duty

**** #3 H2 Plant PSA Purge Gas = 11,113 scf flue gas per MMBtu HHV of fired duty

**** #4 H2 Plant PSA Purge Gas = 11,000 scf flue gas per MMBtu HHV of fired duty

The basis for the flue gas generation rates were determined from fuel gas compositions from 7/1/99 – 7/1/01. FHR is in the process of updating these values to more recent values. This data is used to34 calculate stack velocity used in the model. These calculated velocities were then reduced by half this amount for the model. Therefore we believe the velocities used in the model are conservative.

The combustion stoichiometry calculations are based on the following:

**** One carbon (c) atom is conver ted to one carbon dioxide (CO 2 ) atom.

**** Two hydrogen (H) atoms are converted to one water (H 2 O) atom.

**** Each oxygen (O2) atom consumed, 3.79*(0.79/0.21 ) atoms of atmospheric nitrogen pass into the flue gas.

These factors are represented by scf CO 2 per scf fuel, scf H 2 O per scf fuel and scf N 2 per scf fuel in the following spreadsheet calculations for fuel combustion stoichiometry.

The following tables show the combustion stoichiometry calculations for refinery fuel gas in mix drums 41 and 45 and the fuel gas/PSA off gas mixtures used at the #2 and #3 Hydrogen Plants. The #4 Hydrogen Plant is designed to have the same fuel gas/PSA off gas composition as the #3 Hydrogen Plant.

Flue Gas Calculations from Fuel Gas Combustion Products for 41 mix drum

Component 4 1 mix dru m SCF N2 per SC F SCF N2 S CF CO2 per SC F SCF CO2 SCF H2O per SC F SCF H2O Total SCF Flue Gas Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 8.70 1.88 0.16 0 0 1 0.09 0.25 C1 52.15 7.52 3.92 1 0.5215 2 1.04 5.49 C2 13.82 13.17 1.82 2 0.2764 3 0.41 2.51 C2O 9.69 11.29 1.09 2 0.1938 2 0.19 1.48 C3 2.26 18.81 0.43 3 0.0678 4 0.09 0.58 C3O 2.70 16.93 0.46 3 0.081 3 0.08 0.62 IC4 1.22 24.45 0.30 4 0.0488 5 0.06 0.41 NC4 1.06 24.45 0.26 4 0.0424 5 0.05 0.35 IC4O 0.12 22.57 0.03 4 0.0048 4 0.00 0.04 TC4O 0.17 22.57 0.04 4 0.0068 4 0.01 0.05 CC4O 0.13 22.57 0.03 4 0.0052 4 0.01 0.04

B1 0.16 22.57 0.04 4 0.0064 4 0.01 0.05 IC5 0.54 30.10 0.16 5 0.027 6 0.03 0.22 NC5 0.10 30.10 0.03 5 0.005 6 0.01 0.04 CO 1.14 1.88 0.02 1 0.0114 0 0.00 0.03 CO2 0.21 0.00 0.00 1 0.0021 0 0.00 0.00 N2 5.75 1.00 0.06 0 0 0 0.00 0.06 total 99.92 8.84 1.30 2.09 12.23 flow mmscfd 29.9 btu/scf hhv 1197

btu/scf fuel 1,197 Basis corrected fuel gas compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 12.23 flue gas per mmbtu hhv 10,21535 Flue Gas Calculations from Fuel Gas Combustion Products for 45 mix drum

Component 4 5 mix dru m SCF N2 per SC F SCF N2 S CF CO2 per SC F SCF CO2 SCF H2O per SC F SCF H2O Total SCF Flue Gas Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 24.19 1.88 0.45 0 0 1 0.24 0.70 C1 47.72 7.52 3.59 1 0.4772 2 0.95 5.02 C2 16.82 13.17 2.22 2 0.3364 3 0.50 3.06 C2O 1.22 11.29 0.14 2 0.0244 2 0.02 0.19 C3 4.43 18.81 0.83 3 0.1329 4 0.18 1.14 C3O 1.43 16.93 0.24 3 0.0429 3 0.04 0.33 IC4 0.35 24.45 0.09 4 0.014 5 0.02 0.12 NC4 0.98 24.45 0.24 4 0.0392 5 0.05 0.33 IC4O 0.08 22.57 0.02 4 0.0032 4 0.00 0.02 TC4O 0.06 22.57 0.01 4 0.0024 4 0.00 0.02 CC4O 0.03 22.57 0.01 4 0.0012 4 0.00 0.01

B1 0.11 22.57 0.02 4 0.0044 4 0.00 0.03 IC5 0.27 30.10 0.08 5 0.0135 6 0.02 0.11 NC5 0.14 30.10 0.04 5 0.007 6 0.01 0.06 CO 0.32 1.88 0.01 1 0.0032 0 0.00 0.01 CO2 0.04 0.00 0.00 1 0.0004 0 0.00 0.00 N2 1.74 1.00 0.02 0 0 0 0.00 0.02 total 99.93 8.84 1.10 2.05 11.16 flow mmscfd 37.7 btu/scf hhv 1093

btu/scf fuel 1,093 Basis corrected fuel gas compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 11.16 flue gas per mmbtu hhv 10,208

#2 H2 Plant Flue Gas Calculations from PSA Off Gas/Fuel Gas Combustion Products

Component #2 H2 plant Fuel Gas to Flow Wt SCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF SCF H2O Total SCF Flue Gas PSA gas #2 H2 plant Average Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 38.50 17.34 35.10 1.88 0.66 0 0 1 0.35 1.01 C1 14.10 49.68 19.81 7.52 1.49 1 0.20 2 0.40 2.08 C2 0.00 15.49 2.49 13.17 0.33 2 0.05 3 0.07 0.45 C2O 0.00 4.97 0.80 11.29 0.09 2 0.02 2 0.02 0.12 C3 0.00 3.47 0.56 18.81 0.10 3 0.02 4 0.02 0.14 C3O 0.00 1.99 0.32 16.93 0.05 3 0.01 3 0.01 0.07 IC4 0.00 0.73 0.12 24.45 0.03 4 0.00 5 0.01 0.04 NC4 0.00 1.02 0.16 24.45 0.04 4 0.01 5 0.01 0.05 IC4O 0.00 0.10 0.02 22.57 0.00 4 0.00 4 0.00 0.00 TC4O 0.00 0.11 0.02 22.57 0.00 4 0.00 4 0.00 0.01 CC4O 0.00 0.07 0.01 22.57 0.00 4 0.00 4 0.00 0.00

B1 0.00 0.13 0.02 22.57 0.00 4 0.00 4 0.00 0.01 IC5 0.00 0.39 0.06 30.10 0.02 5 0.00 6 0.00 0.03 NC5 0.00 0.12 0.02 30.10 0.01 5 0.00 6 0.00 0.01 CO 1.00 0.68 0.95 1.88 0.02 1 0.01 0 0.00 0.03 CO2 44.40 0.12 37.29 0.00 0.00 1 0.37 0 0.00 0.37 N2 2.00 3.51 2.24 1.00 0.02 0 0.00 0 0.00 0.02 total 100.00 99.93 99.99 2.87 0.69 0.89 4.46 flow mmscfd 32.6 6.23 Avg HHV btu/scf hhv 270 1139 409.42

Summary btu/scf fuel 409 Basis corrected fuel gas & PSA compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 4.46 scf flue gas per mmbtu hhv 10,88336 #3 H2 Plant Flue Gas Calculations from PSA Off Gas/Fuel Gas Combustion Products

Component #3 H2 plant Fuel Gas to Flow Wt SCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF SCF H2O Total SCF Flue Gas PSA gas #3 H2 plant Average Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 29.00 17.34 28.10 1.88 0.53 0 0 1 0.28 0.81 C1 16.40 49.68 18.97 7.52 1.43 1 0.19 2 0.38 2.00 C2 0.00 15.49 1.20 13.17 0.16 2 0.02 3 0.04 0.22 C2O 0.00 4.97 0.38 11.29 0.04 2 0.01 2 0.01 0.06 C3 0.00 3.47 0.27 18.81 0.05 3 0.01 4 0.01 0.07 C3O 0.00 1.99 0.15 16.93 0.03 3 0.00 3 0.00 0.04 IC4 0.00 0.73 0.06 24.45 0.01 4 0.00 5 0.00 0.02 NC4 0.00 1.02 0.08 24.45 0.02 4 0.00 5 0.00 0.03 IC4O 0.00 0.10 0.01 22.57 0.00 4 0.00 4 0.00 0.00 TC4O 0.00 0.11 0.01 22.57 0.00 4 0.00 4 0.00 0.00 CC4O 0.00 0.07 0.01 22.57 0.00 4 0.00 4 0.00 0.00

B1 0.00 0.13 0.01 22.57 0.00 4 0.00 4 0.00 0.00 IC5 0.00 0.39 0.03 30.10 0.01 5 0.00 6 0.00 0.01 NC5 0.00 0.12 0.01 30.10 0.00 5 0.00 6 0.00 0.00 CO 7.80 0.68 7.25 1.88 0.14 1 0.07 0 0.00 0.21 CO2 45.10 0.12 41.63 0.00 0.00 1 0.42 0 0.00 0.42 N2 1.70 3.51 1.84 1.00 0.02 0 0.00 0 0.00 0.02 total 100.00 99.93 99.99 2.44 0.73 0.73 3.90 flow mmscfd 18.4 1.54 Avg HHV btu/scf hhv 285 1139 350.96

Summary btu/scf fuel 351 Basis corrected fuel gas & PSA compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 3.90 scf flue gas per mmbtu hhv 11,113

Flue Gas Calculations from Fuel Gas Combustion Products for 41 mix drum

Component 4 1 mix dru m SCF N2 per SC F SCF N2 S CF CO2 per SC F SCF CO2 SCF H2O per SC F SCF H2O Total SCF Flue Gas Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 8.70 1.88 0.16 0 0 1 0.09 0.25 C1 52.15 7.52 3.92 1 0.5215 2 1.04 5.49 C2 13.82 13.17 1.82 2 0.2764 3 0.41 2.51 C2O 9.69 11.29 1.09 2 0.1938 2 0.19 1.48 C3 2.26 18.81 0.43 3 0.0678 4 0.09 0.58 C3O 2.70 16.93 0.46 3 0.081 3 0.08 0.62 IC4 1.22 24.45 0.30 4 0.0488 5 0.06 0.41 NC4 1.06 24.45 0.26 4 0.0424 5 0.05 0.35 IC4O 0.12 22.57 0.03 4 0.0048 4 0.00 0.04 TC4O 0.17 22.57 0.04 4 0.0068 4 0.01 0.05 CC4O 0.13 22.57 0.03 4 0.0052 4 0.01 0.04

B1 0.16 22.57 0.04 4 0.0064 4 0.01 0.05 IC5 0.54 30.10 0.16 5 0.027 6 0.03 0.22 NC5 0.10 30.10 0.03 5 0.005 6 0.01 0.04 CO 1.14 1.88 0.02 1 0.0114 0 0.00 0.03 CO2 0.21 0.00 0.00 1 0.0021 0 0.00 0.00 N2 5.75 1.00 0.06 0 0 0 0.00 0.06 total 99.92 8.84 1.30 2.09 12.23 flow mmscfd 29.9 btu/scf hhv 1197

btu/scf fuel 1,197 Basis corrected fuel gas compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 12.23 flue gas per mmbtu hhv 10,21537 Flue Gas Calculations from Fuel Gas Combustion Products for 45 mix drum

Component 4 5 mix dru m SCF N2 per SC F SCF N2 S CF CO2 per SC F SCF CO2 SCF H2O per SC F SCF H2O Total SCF Flue Gas Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 24.19 1.88 0.45 0 0 1 0.24 0.70 C1 47.72 7.52 3.59 1 0.4772 2 0.95 5.02 C2 16.82 13.17 2.22 2 0.3364 3 0.50 3.06 C2O 1.22 11.29 0.14 2 0.0244 2 0.02 0.19 C3 4.43 18.81 0.83 3 0.1329 4 0.18 1.14 C3O 1.43 16.93 0.24 3 0.0429 3 0.04 0.33 IC4 0.35 24.45 0.09 4 0.014 5 0.02 0.12 NC4 0.98 24.45 0.24 4 0.0392 5 0.05 0.33 IC4O 0.08 22.57 0.02 4 0.0032 4 0.00 0.02 TC4O 0.06 22.57 0.01 4 0.0024 4 0.00 0.02 CC4O 0.03 22.57 0.01 4 0.0012 4 0.00 0.01

B1 0.11 22.57 0.02 4 0.0044 4 0.00 0.03 IC5 0.27 30.10 0.08 5 0.0135 6 0.02 0.11 NC5 0.14 30.10 0.04 5 0.007 6 0.01 0.06 CO 0.32 1.88 0.01 1 0.0032 0 0.00 0.01 CO2 0.04 0.00 0.00 1 0.0004 0 0.00 0.00 N2 1.74 1.00 0.02 0 0 0 0.00 0.02 total 99.93 8.84 1.10 2.05 11.16 flow mmscfd 37.7 btu/scf hhv 1093

btu/scf fuel 1,093 Basis corrected fuel gas compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 11.16 flue gas per mmbtu hhv 10,208

#2 H2 Plant Flue Gas Calculations from PSA Off Gas/Fuel Gas Combustion Products

Component #2 H2 plant Fuel Gas to Flow Wt SCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF SCF H2O Total SCF Flue Gas PSA gas #2 H2 plant Average Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 38.50 17.34 35.10 1.88 0.66 0 0 1 0.35 1.01 C1 14.10 49.68 19.81 7.52 1.49 1 0.20 2 0.40 2.08 C2 0.00 15.49 2.49 13.17 0.33 2 0.05 3 0.07 0.45 C2O 0.00 4.97 0.80 11.29 0.09 2 0.02 2 0.02 0.12 C3 0.00 3.47 0.56 18.81 0.10 3 0.02 4 0.02 0.14 C3O 0.00 1.99 0.32 16.93 0.05 3 0.01 3 0.01 0.07 IC4 0.00 0.73 0.12 24.45 0.03 4 0.00 5 0.01 0.04 NC4 0.00 1.02 0.16 24.45 0.04 4 0.01 5 0.01 0.05 IC4O 0.00 0.10 0.02 22.57 0.00 4 0.00 4 0.00 0.00 TC4O 0.00 0.11 0.02 22.57 0.00 4 0.00 4 0.00 0.01 CC4O 0.00 0.07 0.01 22.57 0.00 4 0.00 4 0.00 0.00

B1 0.00 0.13 0.02 22.57 0.00 4 0.00 4 0.00 0.01 IC5 0.00 0.39 0.06 30.10 0.02 5 0.00 6 0.00 0.03 NC5 0.00 0.12 0.02 30.10 0.01 5 0.00 6 0.00 0.01 CO 1.00 0.68 0.95 1.88 0.02 1 0.01 0 0.00 0.03 CO2 44.40 0.12 37.29 0.00 0.00 1 0.37 0 0.00 0.37 N2 2.00 3.51 2.24 1.00 0.02 0 0.00 0 0.00 0.02 total 100.00 99.93 99.99 2.87 0.69 0.89 4.46 flow mmscfd 32.6 6.23 Avg HHV btu/scf hhv 270 1139 409.42

Summary btu/scf fuel 409 Basis corrected fuel gas & PSA compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 4.46 scf flue gas per mmbtu hhv 10,88338 The modeled stack velocity is calculated as follows:

Stack velocity = Heater Duty MMBtu * 1 * scf flue gas * 1 Hr * 0.028317 m 3 * Hr 2 MMBtu 3,600 sec ft 3

T°K * 1 = _____ exit vel m/sec 288.7 **** K (D 2 /4) * PI

Where MMBtu/Hr = fired duty of heater (Duty is conservatively reduced by half) T°K = stack temperature, °K D = stack inner diameter in meters

Standard conditions (STP) for flow measurement are 60 **** F and 1 Atm (14,7 psia)

Under the terms of the consent decr ee between EPA and FHR (Civil Action No. 00

- 2756

- PAM

- SRN), FHR must meet the specified NO x control requirements on its heaters and boilers. The specific requirements are dependent on the maximum physical duty rating of the heater or boiler. FHR may reduce the fired duty of a heater or boiler to qualify for less stringent NO x control requirements. To allow FHR to de

- rate heaters and boilers, as well as to make minor mechanical changes, without additional modifications to the Administrative Order, the following model parameter assumptions were use d:

**** If a heater or boiler’s fired duty is lowered by de

- rating; its stack velocity w ill decrease. To account for potential decreases in stack velocity, sources which FHR may de

- rate were modeled with a stack velocity based on the de

- rated duty.

**** The mode led SO 2 emission rate for these sources was not decreased. Current heater and boiler duties for these sources were used to calculate the modeled SO 2 emissions. Using the original duties accounts for operation of these so urces under current conditions (i. e. prior to de

- rating).

The revised source parameters for de

- rated heaters and boilers are listed in Exhibit 8.

For sources combusting only refinery fuel oil (11H

- 3 and 11H

- 5), the stack veloci ty will be based on the heater duty burning 100% refinery fu el gas.

Stack Height : the #3 H2 Plant Flue Gas Calculations from PSA Off Gas/Fuel Gas Combustion Products

Component #3 H2 plant Fuel Gas to Flow Wt SCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF SCF H2O Total SCF Flue Gas PSA gas #3 H2 plant Average Component per SCF Fuel Component per SCF Fuel Component per SCF Fuel per SCF Fuel H2 29.00 17.34 28.10 1.88 0.53 0 0 1 0.28 0.81 C1 16.40 49.68 18.97 7.52 1.43 1 0.19 2 0.38 2.00 C2 0.00 15.49 1.20 13.17 0.16 2 0.02 3 0.04 0.22 C2O 0.00 4.97 0.38 11.29 0.04 2 0.01 2 0.01 0.06 C3 0.00 3.47 0.27 18.81 0.05 3 0.01 4 0.01 0.07 C3O 0.00 1.99 0.15 16.93 0.03 3 0.00 3 0.00 0.04 IC4 0.00 0.73 0.06 24.45 0.01 4 0.00 5 0.00 0.02 NC4 0.00 1.02 0.08 24.45 0.02 4 0.00 5 0.00 0.03 IC4O 0.00 0.10 0.01 22.57 0.00 4 0.00 4 0.00 0.00 TC4O 0.00 0.11 0.01 22.57 0.00 4 0.00 4 0.00 0.00 CC4O 0.00 0.07 0.01 22.57 0.00 4 0.00 4 0.00 0.00

B1 0.00 0.13 0.01 22.57 0.00 4 0.00 4 0.00 0.00 IC5 0.00 0.39 0.03 30.10 0.01 5 0.00 6 0.00 0.01 NC5 0.00 0.12 0.01 30.10 0.00 5 0.00 6 0.00 0.00 CO 7.80 0.68 7.25 1.88 0.14 1 0.07 0 0.00 0.21 CO2 45.10 0.12 41.63 0.00 0.00 1 0.42 0 0.00 0.42 N2 1.70 3.51 1.84 1.00 0.02 0 0.00 0 0.00 0.02 total 100.00 99.93 99.99 2.44 0.73 0.73 3.90 flow mmscfd 18.4 1.54 Avg HHV btu/scf hhv 285 1139 350.96

Summary btu/scf fuel 351 Basis corrected fuel gas & PSA compositions 7/1/99 - 7/1/01 scf flue gas per scf fuel 3.90 scf flue gas per mmbtu hhv 11,11339 The actual stack height is used in the modeling exce pt for those sources (boiler house, 37H-3,4,5, 25H-1, and 25H-3) whose stacks are taller than 65 meters (federal GEP stack height analysis trigger). For these sources, the actual height is used for the 1 hour and state annual modeling and the GEP stack height is used for the stack height for the 1hour, 3 hour, 24 hour, and federal annual modeling.40 

### Stationary Diesel Engines “K331_DSL”, “K332_DSL”, “K333_DSL”, “K407_D SL”, “K408_DSL”, “K435_DSL”, “K453_DSL”, “K465_DSL”, “K505_DSL” through “K508_DSL”, “K510_DSL” “K511_DSL”, “K513_DSL”

A. Emission Point Description Stationary diesel engines are used throughout t he refinery to power emergency standby equipment (generators and pumps).

There are currently five diesel powered electric generators in the refinery. The diesel electric generators are turned on to prevent power interruptions to critical control and lighting equipment. They operate less than 83.3 hours per month, and are operated for ex tended periods only in emergency situations. The ULSD project require d a diesel powered emergency cooling water pump (K513_DSL) ; it was modeled adjacent to the #6 Cooling Tower and the original pump (K509_DSL) it replaced was removed.

There are five diesel powered cooling water pumps to provide emergency cooling water in the event of an electric power failure or electrical pump failure. T hey run 10 - 15 minutes per week for test purposes and less than 83.3 hours per month.

There are three diesel powered firewater pumps (93-P S ource ID) to provide water for fire fighting in the event of an electrical power failure or electrical pump failure. They are run 10 - 15 minutes per week for test purposes and less than 83.3 hours per month. They are operated for extended periods only in emergency situations.

The pump that was used to reverse the crude oil flow in the Wood River Crude Oil Pipeline (K510_DSL) has been removed from service, but is continued in the model for conservative purposes.

There is one diesel that is part of the plant air co mpressor 71C-11. This diesel will operate less than 2500 hours per year.

B. Justification For Modeled SO 2 Emission Rate

The SO 2 emission rates for the diesel engines are bas ed on AP-42 emission factors. The AP-42 factors are accepted standards, which will be us ed frequently in the future for a variety of pollutants. These emission factors have been scaled down based on the sulf ur content of the diesel fuel to account for a limit of 0. 05 0015 wt % S in the fuel.

ENGINES < 600 hp: 4.611E-5 g/s SO 2 per hp-hr (AP-42 Table 3.3—1 Oct ’96 adjusted to 0. 05 0015 % S)

AP-42 lists emission factors of 2. 05 E

- 3 05E-03 lb SO 2 /hp-hr and 0.29 lb SO 2 /MMBtu fuel input. Footnote C states that diesel fuel has a heating value of 19,300 Btu/lb. Using the heating value of the fuel, the sulfur content basis for the emissi on factor is calculated to be:

0.29 lb SO 2 * 1 lb S * 1 MMBtu * 19,300 Btu * 100% = 0.280% S MMBtu fuel 2 lb SO 2 1 E

- 6 1E+06 Btu lb diesel

The adjustment for 0. 05 0015 % S diesel fuel is as follows

2.05 E-3 lb SO2 * 0. 05 0015 % S * 453.59 g * 1 Hr = 4.61 1.43 E- 5 6 g/sec SO 2 Hp-Hr 0.28%S. 1 lb 3600 Sec Hp-Hr41 ENGINES > 600 hp: 5.097E-5 g/s SO 2 per hphr (AP-42 Table 3.4-1 Oct ’96 adjusted to 0. 05 0015 % S)

AP-42 lists an emission factor of 8.09 E-3 * %S in diesel fuel. Converting to g/s with 0. 05 0015 %S diesel fuel:

8.09 E-3 lb SO 2 * 0. 05 0015 %S * 453.59 g * 1 Hr = 5.097 1.58 E- 5 6 g/s SO 2 Hp-Hr 1 lb 3600 S Hp-Hr

C. Reserved for Updated Justification of Modeled NO x Emission Rate

D

C . Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations Minnesota Rule 7005.1200 Subpart 2 limits SO 2 emissions from stationary internal combustion engines to 1.75 lb SO 2 per million BTU actual heat input. These emission points will be limited to diesel fuel containing no more than 0. 05 0015 % sulfur in the Clean Fuels Permit. At this sulfur content, SO 2 emissions from combustion of diesel fuel are limited to 0. 05 0015 lb S0 2 per million Btu of actual heat input.

E D . Justification For Modeled Stack Parameters The stack velocity for the diesel engines is based on the engine horsepower rating. Diesel engines are rated on the average they deliver in horsepower. Th e fuel consumption of an internal combustion engine is 3 to 5 times its energy output because it is only 30% - 40% efficient. The stack velocity is calculated assuming 50% efficiency. To determine the diesel engine stack velocity formula, convert (horsepowerhour) -1 to MMBtu/hr and combine with current stack ve locity formula based on MMBtu/hr heater duty.

hp

* 2545 Btu

* 1 MMBtu

* 4.473
. 10 -4

* T ( **** K)

* 1 = hp * 2.276 10 -6 * T ( **** K)

* 1 = Exit velocity (m/s) (m/s) hp hr 10 6 Btu D 2 (m) 50% D 2 hp hr 10 6 Btu D 2 (m) 50% D 242 

### Portable Diesels

Flint Hills Resources occasionally periodically requires the use of portable equipment powered by diesel engines at various locations around the refinery (e.g. portable electric generators). Based on information contained These diesel engines are used for recurring temporary work around the refinery such as pumping water during heavy precipitation events, powering welding equipment for repairs, and generating power for air compressors for jack hammers. As defined in Title I and II of the Clean Air Act, these sources are non-road engines and not subject to regulation under 40 CFR Parts 52 and 71. Non-road engines are not regulated under 40 CFR Part 52, 52.21 or 40 CFR Part 71, 71.3 as these rules apply specifically to stationary sources “any source of an air pollutant except those emissions resulting directly from an internal combustion engine for transportation purposes or from a non-road engine or non-road vehicle as defined in section 216.” This definition explicitly exclude s non-road engines; therefore, the portable diesel permit application, the total capacity of po rtable diesels at the refinery is 13,027 horsepower (hp) with at utilization rate of 6,36 9,6 00 hp

- hours/year. do not need to be included in the SIP modeling analysis.

The average horsepower non-road definitions that apply to the portable diesels are part of an individual the Clean Air Act in Title I 40 CFR Parts 89.2 and 90.3 for non-road compression ignition engines and small spark ignition engines and Section 216 of Title II.

A “non-road engine” according to the definition in Section 216 of Title II of the Clean Air Act is:

“ An internal combustion engine (including the fuel system) that is not used in a motor vehicle or a vehicle used solely for competition, or that is not subject to standards promulgated under section 7411 of this title or section 7521 of this title.”

It defines a moving source as “any self-propelled vehicle designed for transporting persons or property on a street or highway.” Based on the description of the portable diesel engine is 211 hp. diesels, they are considered a non-road engine, not a moving source.

Flint Hills Resources also utilizes diesel engines associated with mo bile maintenance equipment which are not regulated by the portable diesel permit (e.g. engines used to power crane lift mechanisms). These engines represent an additional 3,000 HP of diesel engine capacity.

Flint Hills Resources will model SO2 emissions based on a 16,000 hp

- hr utilization rate for 1, 3 and 24

- hour average periods and 6,36 9,6 00 hp

- hours/year for the annual average. The emission rate is calculated using 0.05% sulfur content and the emission ca lculation procedure for stationary diesel engine s rated at less than 600 HP as noted above. This is the total horsepower rating for equipment covered by the portable diesel permit and diesel powered maintenance equipment not covered by the portable diesel permit. One source will be modeled with the com bined emissions from all 16,000 HP of diesel operation. However, the stack parameters fo r that source will be based on one diesel engine at 211 HP to give the portable diesel source a representative plume rise. This represents the highest potential model ed impact of portable diesel operation so t hat no administrative order restrictions are required for the type or location portable diesel operation.

The portable diesel engine point source is located on A Street near the property boundary on the east side of the refinery in the general vicinity of the FCC unit and the administration building. The source coordinates for the portable diesels were chosen so that the diesels would be in line with the receptor which has the high second high one hour average modeled concentration and the refinery sources with the highest culpability for that event. Data from previous model runs, which showed the high second high impact to be along the facility’s east fence line, were used to select the portable diesel location. The current model output shows the high second high 1

- hour average concentration (1019 ug/m 3 ) to be south of the refinery. However, the portable diesel impact at this receptor was not significant. The model43 co ntinues to show 1

- hour average concentrations (981 ug/m 3 ) along the facility’s east fence line at concentrations slightly below the high second high. The portable diesels continue to show a high culpability at these receptor s, so the original siting analy sis remains valid. The non-road engine descriptions in 40 CFR Part 89.2 and 90.3 that corr espond to the portable diesels are listed below.

“That, by itself or in or on a piece of equipment, is portable or transportable, meaning designed to be and capable of being carried or moved from one location to another. Indicia of transportability include, but are not limited to, wheels, skids, carrying handles, dolly, trailer, or platform.”

The description below is for an internal combustion source not being a non-road engine and this does not describe the operations of the portable diesels.

“The engine otherwise included in paragraph (1)(iii) of this definition remains or will remain at a location for more than 12 consecutive months or a shorter period of time for an engine located at a seasonal source. A location is any site at a building, structure, facility, or installation. Any engine (or engines) that replace(s) an engine at a location and that is intend ed to perform the same or similar function as the engine replaced will be included in calculating the c onsecutive time period. An engine located at a seasonal source is an engine that remains at a seas onal source during the full annual operating period of the seasonal source. A seasonal source is a statio nary source that remains in a single location on a permanent basis (i.e., at least two years) and that operates at that single location approximately three months (or more) each year. This paragraph does not apply to an engine after the engine is removed from the location.”44 

### “K348_OXD” OSWTP Thermal Oxidizer

A. Emission Point Description The Oil Separation and Waste Treatment Plant (OSWTP ) Oxidizer is an emissions control device which oxidizes odorous compounds and Volatile Organic Compounds (VOC's). The OSWTP is a permitted wastewater treatment plant. Oily wastewater from the refinery proce ss units is sent to the OSWTP for clean up. This is a two-step process. First the oil is removed from the wastewater, and then the remaining contaminants in the wastewater are biol ogically removed by activated sludge treatment. Treating air from the OSWTP is collected and routed to the Oxidizer for cleanup.

Most of the treatment tanks at the OSWTP are cover ed. They are connected to the Oxidizer by a duct system. The Oxidizer blower pulls a vacuum on the du ct system to pull the treating air containing Volatile Organic Compounds (VOC's) and odors from the treatm ent tanks into the Oxidizer. The air and VOC's flow from the blower discharge into a heat exc hanger. The heat exchanger uses hot stack gases to preheat the oxidizer feed. A natural gas fired burner heats the oxidizer f eed up to approximately 1,400 **** F and the VOC's are oxidized into CO 2 and Water. The de-contaminat ed air then passes through the heat exchanger and is discharged to the atmosphere through the stack. The oxidizer was modeled assuming catalytic operation. When the oxidizer is operated thermally, the stack temperature and velocity are increased. Since the SO 2 emission limit remains the same, the current modeling assumptions are conservative. A schematic flow diagram and description of the Oxidizer is also described in Flint Hills Resources' s Air Quality Permit 106A-90-I/O-28.

Flint Hills Resources added a back-up thermal oxidizer to treat wastewater treatment plant off gases during periods wh en the main thermal oxidizer is out of service. Flint Hills Resources operates routes OWSTP vapor to only one oxidizer at a time; the backup oxidiz er is designed to automatically start up in the event of a main oxidizer shutdown. In the event of a main oxidizer shutdown, there will be vent gases vented to both oxidizers for a brief period during the switch. Flint Hills Resources used the main oxidizer in the source inventory. The backup oxidizer can operate in hot standby on natural gas. It does not have heat recovery equipment; so

, the temperature and flow rate of t he exhaust gas are higher than the main oxidizer at the same operating rate. So, use of the main oxidizer in the source inventory represents the highest potential ambient impact from oxid izer operation at the wastewater plant.

B. Justification For Modeled SO 2 Emission Rate The wastewater feed to the OSWTP contains sma ll amounts of odorous sulfur bearing compounds (H 2 S and mercaptans). These compounds are transferred from the wastewater to the treating air in the basins and are oxidized to SO 2 in the oxidizer. Stack testing indicated that this source has shown emission rates as high as 6.2 lb/hr SO 2
. For the 1, 3 and 24 hour averaging times, the oxidizer was modeled at 50.71 lb SO 2 /hr. This is the calculated emission rate for the design air flow rate fr om the largest oxidizer ai r blower (31,500 scfm – 70° F) with an H 2 S concentration at the NSPS Subpart J limit of 162 ppm H 2 S

The blower flow rate adjusted to standard conditions at 68° F is:

31,500 ft 3 * (68°F + 460°F) = 31,381 ft 3 Min (70°F + 460°F) Min

31,381 ft 3 * 162

**** 10 -6 scf H 2 S * 1 lbmole H 2 S * 64 lb SO 2 * 453.59 gm * 1 Min = 6.389 gm gram SO 2 Min scf Fuel Gas 385 scf lbmole SO 2 lb 60 sec sec45 The annual emission rate, the oxidizer was modeled at 9.0 lb SO 2 /hr. This limits SO 2 emissions from the WWTP TO thermal oxidizer to an emission rate which is below the PSD major modification threshold of 40 ton/yr SO 2
. C. Reserved for Updated Justification of Modeled NO x Emission Rate

D C . Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations The Oxidizer was designed and built to meet the requirements of 40 CFR 60.692-5(a). This standard addresses the design requirements of control devices for the control of VOC Emissions from Petroleum Refinery Wastewater System (40 CFR 60 S ubpart QQQ). This standard does not address SO 2 emissions from VOC control devices for petrol eum refinery wastewater systems.

The Oxidizer uses only natural gas as its fuel source . There are no other applicable state or federal SO 2 emissions standards.

E D . Justification For Modeled Stack Parameters The stack velocity used for modeling the Oxidizer was calculated from September 2002 performance test data. Test data were used because design data used in the original modeling were no longer appropriate. The oxidizer stack temperature has increased due to the replacement of the oxidizer’s heat recovery exchanger; the current equipment is less efficient that the original design basis. The stack te st was performed under normal o perating conditions and the appropriate EPA reference methods were used. The following data were used as model inputs:

With the exception of stack temperature, the Ther mal Oxidizer stack parameters are consistent with parameters modeled for SIP 8 and listed below. The st ack temperature in the model was decreased from 792 **** F to 500 **** F to allow for a project which will improve the energy efficiency of the 94H1 thermal oxidizer.

Stack height = 72.53 ft = 22.11 m Stack diameter = 5.63 ft = 1.716 m Sept 2002 performance test stack temp = 792 Stack temperature = 500 **** F = 695.2 533 **** K Sept 2002 performance test Flow Rate = 21,119 dscfm 21,119 dscfm* (792 **** F + 460)/(68 **** F + 460) = 50,848 acfm Modeling stack vel Stack velocity = 50,848 ft 3 /min

* 1 min / 60 sec

* 4 / [ **** (5.63 ft) 2 ] = 33.53 ft/sec = 10.36 m/sec46 Please note that the modeled stack velocity is conser vatively low because the conversion from dry standard cubic feet per minute to actual cubic feet per minute did not include a correction for the actual moisture content of the stack gas. The original value of 10.21 m/sec for the modeling stack velocity has been increased to 10.36 m/sec ( 50,848 acfm )

.47 

### “K458_VNT” Platformer Catalyst Regenerator Vent

This source has been removed from the modeling inventory as an insignificant source of SO2 emissions. See t he Insignificant Source Section for additional information.48 

### “K459_VNT” Powerformer Catalyst Regeneration

This source has been removed from the modeling inventory as an insignificant source of SO2 emissions. See the Insignificant Source Section for additional information.49 

### Process Heater Steam-Air Decoking

Sources “K600_DEC” through “K603_DEC”.

A.Emission Point Description

The tubes inside of process heaters become fouled wi th coke during operation. The coke formation on the inside of the heater tubes reduces the heat tran sfer efficiency of the heater and increases the pressure required to pump the feed through the heater

. and increases the temperature on the furnace side of the heater tube required to maintain fluid heating. Periodically the coke must be removed in order to maintain efficient operation of the unit . This removal process is call ed steam-air decoking, referred to as “decoking” for the remainder of this section

. One method for decoking is to inject steam and air into the heater tubes to oxidize the coke at a controlled rate. To begin decoking the heater, stea m is injected into the heater tubes to physically remove loose coke. Steam injection c ontinues as the heater burners are fired on with fuel gas in order to bring the tube temperature up to coke combustion temperatures. Next

, air is injected at a controlled rate to oxidize the coke. Water is in jected into the decoking piping connected to the heater outlet to quench the hot gases. After the quench line, the gas /water mixture flows into a quench pit for flue gas disengaging to further condense water vapor and contro l sulfur dioxide emissions via submerged fill

.
Quench FHR’s quench pits are concrete lined basins filled with water. The decoking quench line routes lines route the heater decoking flue gas into the water in the quench pit. The pits. Depending on the process unit, the pit may be covered or open to the atmosphere. Emission Points K600_DEC (21H-1), K601_DEC (21H-2), K602_DEC (23 H-1) and K603_DEC (23 H-2) are the decoking operations, which utilize quench pits. Each of the The 21 unit heaters (21 H-1 and 21 H-2) is vented are routed to its own covered enclosed quench pit pits with several openings to the atmosphere . The 23 Unit heaters (23 H_1 and 23 H-2) both vent to the same open top decoking quench pit. All The 23 heaters may be decoked simultaneously . The 21 unit heaters are not decoked simult aneously with each other or the 23 unit heaters

.

B. Justification For Modeled SO 2 Emission Rate

With SIP modification 9 (2010), FHR is refining the form er emission rate basis to improve the accuracy of both the uncontrolled and controlled emission rates.

Uncontrolled Emission Rate Basis

The SO 2 emission rates calculated for decoking process h eaters are based on the su lfur content of the coke, the amount of air used to decoke the heater, and the SO 2 removal efficiency of the quench system. The coke produced at the delayed coking units has the sa me sulfur content as the feed to the unit. So, the The coke which forms in the tubes of the delayed coking unit heaters is assumed to have the same sulfur content as the unit feed and product coke.

The emission calculations assume that all of the carbon and sulfur in the coke is oxidized. The coke burn stoichiometry is as follows:

C(s) + O 2 (g) --> CO 2 (g) s [=] solid, g [=] gas S(s) + O 2 (g) --> SO 2 (g)

(Assume all carbon is completely oxidized to CO 2 , and all sulfur is oxidized to SO 2 .)50 Since 1 mole of CO 2 is produced per mole of O 2 consumed, and 1 mole of SO 2 is produced per mole of O 2 consumed there will be no volume change in the stack gas due to reaction.

Assuming that the coke contains only Carbon (C) and Sulfur (S) (conservative as there is ~5% - 6% hydrogen content) and that all Oxygen (O 2 ) in the decoking air is consumed, heater decoking SO 2 emissions are calculated for each pound of oxygen in the decoking air as follows:

lb O 2 = 1 lb C

* 1 lbmol C

* 1 lbmol O 2 * 32 lb O 2 + 1 lb S

* 1 lbmol S

* 1 lbmol O 2 * 32 lb O 2 12 lb C lbmol C lbmol O 2 32 lb S lbmol S lbmol O 2

which reduces to: lb O 2 = 2.667 * lb C + lb S

For coke containing only carbon and sulfur, lb C = lb coke - lb S

lb O 2 = 2.667*(lb coke - lb S) + lb S = 2.667 * lb coke - 1.667 lb S

lb O 2 / lb S = 2.667

* lb coke/lb S - 1.667 = 2.667/ (wt frac S) - 1.667

Since 1 lb S oxidizes to 2 lb SO 2 , 2 lb O 2 / lb SO 2 = 2.667/ (wt frac S) - 1.667

Rearranging, lb SO 2 = lb O 2 * [(1.333/wt frac S) - 0.833] -1

The amount of O 2 used in decoking can be determined from the decoking air use rate as follows:

lb O 2 = Air SCF/min

* 60 min/hr

* Burn Time hr

* 1 lbmol air

* 29 lb air

* 0.232 lb O 2 379 SCF lbmol air lb air

This reduces to the following equation: lb O 2 = Air SCF/min * Burn Time hr * 1.064

lb SO 2 = Air SCF/min * Burn Time hr * 1.064* [(1.333/wt frac S) - 0.833] -1

For the two 21 unit heaters, FHR has utilized peak air (O 2 ) addition rates metered during past heater decoking events to calculate worst case uncontrolled SO 2 emission rates. For the 23 unit heaters, FHR utilizes a slightly different approach based on an engineering model recently performed on the 23H-2 heater by the consulting company CBI. The model calcul ates the quantity of coke (carbon) in the heater tubes at end-of-run conditions basis, end-of-run operating conditions and model input parameters. Referencing end of run coke mass, coke sulfur cont ent, time required to decoke, and the stoichiometry detailed above, uncontrolled emissi on rate potentials are calculated.

Heater Total O 2 Consumption (lbs) Decoke Duration (hrs) Ave Uncontrolled SO 2 rate (lb/hr) Peak Uncontrolled SO 2 rate (lb/hr) 23H-1 20,114 20 47.8 67.0 23H-2 21,198 24 42.0 58.8 21H-1 12,970 17.5 35.3 49.4 21H-2 12,970 17.5 35.3 49.4

Controlled Emission Rate Basis:

The controlled emission rates will be calculated as follows:

lb SO 2 emitted = lb SO 2 *(1- Quench System SO 2 Removal Efficiency/100%)51 As After completing an engineering study in the original SIP modeling 2010 of the quench piping and pit configurations as well as an emissions quantificat ion study on the quench pit of the 21-1 unit during a decoking event , the company proposes to model 21 Unit all heater decoking as sources with emission controls and the balance of the sources as uncontrolled. On a source

- by

- source basis, the following control efficiencies are used

.

**** 21 H

- 1 heater decoking is modeled with a quench system removal efficiency of 50%.

**** 21 H

- 2 heater decoking is modeled with a quench system removal efficiency of 50%.

**** 23 H

- 1 heater decoking is modeled as an uncont rolled source (0% control efficiency).

**** 23 H

- 2 heater decoking is modeled as an uncont rolled source (0% control efficiency).

21H

- 1 and 21H

- 2 Heater Decoking (“K600 21H1D”, “K601 21H2D”

These sources are quenched in a pi ping system that maximizes flue gas/quench water mixing. The principle design characteristics are:

1. It has a minimum of four (4 three (3 ) quench water injection points. 2. It has a “U” shaped section of piping for mixing. The “U” shaped piping section is approximate ly 75 greater than 50 feet long and contains at least four (4) several bends (elbows) to ensure complete thorough mixing of the decoking flue gas with the quench water. 3. The quench water discharge-piping exit is at least four (4) feet well submerged below the quench pit water level to provide additional mixing opportunity to solubilize emissions

. For calculation purposes, the volume of water for the SO 2 to dissolve into is assumed to be the flow rate of the quench water at the heater outlet. The temperature of the water is assumed to be 50 **** C since the quench water entering the pit is about 65 **** C and the water in the pit is about 20 **** C. Finally, it is assumed that the SO 2 reaches 50% of its equilibrium concentration in the water. This is roughly equivalent to a single distillation tray at 50% efficiency. In process equipment such as scrubbers, ab sorbers, and distillation columns, the transfer of gaseous compounds into liquids takes place on distillation trays or tower packing. Distillation tray efficiencies range from 50%

- 75%. In other words, 50%

- 75% of the gases that could be dissolved in t he liquid at chemical equilibrium (the maximum possible) are dissolved on one tray. The scrubbing of SO 2 from heater decoking flue gas by quench water in the quench pit allows for a much longer contact time than would be achieved on one distillation tray. Therefore, assuming that the heater decoking scrubbing is equiva lent to one distillation tray at 50% efficiency is a very conservative estimate. 21H

- 1 and 21H

- 2 are identical heaters. The emission calculations for Emission Points 600 and 601 (21 H

- 1 and 21 H

- 2) are as follows:

The example calculations are based on a 36 hour decoking event; actual times will vary upon heater conditions.

Decoking air rate: 1,120 SCFM, 21% O 2

1,120 SCF air * 0.21 SCF O 2 * 1 lbmol O 2 * 60 min * 36 hours = 1340.5 lbm ol O 2 per heater min SCF air 379 SCF O 2 hr decoke decoke

1340.5 lbmol O 2 * 32 lb O 2 = 42,896 lb O 2 decoke lbmol

Total lbmol air = 1,340.5/ Measured Control Efficiency

In October of 2010, FHR contract ed Pace Analytical to utilize stack test methods to quantify SO2 emission rates during a heater burn. The tests we re conducted for approximately 12 hours during the peak air addition rate periods of the burn. An air mo ver was installed in an opening on the roof of the 21-152 quench pit and Pace utilized a pitot tube and FTIR to quantify the flow and concentration to determine the emission rates.

The average emission rate throughout the burn was approximately 2 lb/hr with a max hourly rate of 4 lb/hr. Back calculating using the max hourly uncontro lled emission rate and that measured during the 21- 1 burn:

4.0 lb SO 2 emitted = 49.4 lb SO 2 *(1- Quench System SO 2 Removal Efficiency/100%)

A control efficiency of 92% is estima ted. However, while the air mover lik ely captured the vast majority of emissions which released with the non-condensable burn relate d gases in the pit, FHR proposes to utilize a conservative 50% capture efficiency until additional studies can be completed with higher pit vapor flow rates (planned for 1 st quarter 2011).

(4. 0 .21 = 6,383.3 lbmol air per decoke

Sulfur content of coke = 6.5% = 0.065 weight fraction S

42,896 lb O 2 * [(1.333/0.065)

- 0.833] - 1 = 2,180.3 lb SO 2

2,180.3 ) lb SO 2 * (1 lbmol/64.06 emitted * (2 lb ) = 34.03 lbmol SO 2
Partial pressure emitted / 1 lb Captured) = 49.4 lb SO 2 *(1- Quench System SO 2 = 34.03/6,383.3*760mmHg/Atmosphere = 4.05 mmHg Removal Efficiency/100%)

Solubility o f SO 2 @ stated conditions = 0.044 lb SO 2 100 lb H 2 O

(Perry's Chemical Engineers Handbook, 6 th Ed., p. 3

- 103)

Quench water rate = 400 gpm

400 gal

* 8.33 lb H 2 O

* 60 min

* 36 hr

* 0.044 lb SO 2 * (50% A control efficiency ) = 1,583.4 lb SO 2 removed min gal hr decoke 100 lb H 2 O per htr decoke

Net release of SO 2 84% is therefore estimated. FHR proposes to utilize the air per 36 hour example heater decoking event:

(2,180.3

– 1,583.4) lb SO 2 = 596.9 lb S O 2 decoke decoke

This results in a calculated same control efficiency of 75%. (1,583.4/2180.3*100% = 73%) at each of the other heaters due to the similarities in quench systems noted earlier.

A similar result can by shown using a chemical process simulation model. The simulation model uses standard chemical engineering principles and calc ulation techniques to determine the SO2 chemical absorption rate in the quench system at heater decoking operating conditions (temperature, pressure SO 2 concentrations and quench water rates).

The company h as added a safety factor to this analysis by using a removal efficiency of 50% in the SO 2 modeling

.53 Decoking emissions have been calculated for the following heaters: 21H-1, 21H-2, 23H-1 and 23H-2. The annual modeled emission rates assume that each heater will be decoked for a period of up to 432 hours per year.

The SO 2 emissions from heater decoking are summarized in the following table:

Heater Decoking SO2 Emission Rate at Listed Scubbing Efficiency for All Sources

Source Description w t frac S air rate Steam Burn Total Max Burn SO2 1,3-hr 24-hr SO2 Annual SO2 scfm hr hr hr hr lb/hr g/sec lb/hr g/sec t/yr g/sec

K600_DEC 21H-1 decoke 0.065 1,120 2 22 24 36 30.285 3.816 30.285 3.816 6.541 0.188

K601_DEC 21H-2 decoke 0.065 1,120 2 22 24 36 30.285 3.816 30.285 3.816 6.541 0.188

K602_DEC 23H-1 decoke* 0.065 872 2 22 24 36 47.157 5.942 47.157 5.942 10.186 0.293

K603_DEC 23H-2 decoke* 0.065 0 2 22 24 36 0.000 0.000 0.000 0.000 0.0000 0.000

* Model both 23 Unit heaters as one source; both heaters decoked to the same quench pit. Air rate listed for 23 H-1 is total a ir for both heaters 50% SO2 control Efficiency for 21 Unit Decoking Quench Systems 0% SO2 control Efficiency for 23 Unit Decoking Quench Systems

Area Heater Peak Uncontrolled SO 2 rate (lb/hr) Control Efficiency Peak Hourly Controlled SO 2 Rate (lb/hr) 23H-1,2 126 84% 20.2 21H-1 49.4 84% 8.0 21H-2 49.4 84% 8.0

The 23 unit heaters are represented as simultaneou s burns and discharge location in the model with a combined emission rate of 20.2 lb/hr.

Volume Source SO 2 Emission Rate From 21H-1 and 21H-2 and 23H-1 and 23H-2 Decoking (“ K601 21H1D”, “K601 21H2D”, “ K602 23H1D”, “K603 23H2D”

Each of these sources is quenched into a common concrete quench pits. 23H-1 and 23H-2 are routed together into a single, uncovered quench pit. The quench pit is uncovered. For this reason, the 21 unit pits are covered, but have small openings on both t he tops and sides which can release liquids to the sluiceway. The 21 and 23 Unit decoking sources were are modeled as an area source. The 23 Unit volume sources. FHR believes these are appropriate to model as volume sources due to the multiple locations and elevations of the pit openings (21u) an d the significant temperature difference between the quench pit is a 20 ft x water/vapor and the atmosphere ( 50 ft concrete pit located southwest corner of the 23 Unit. The area – 100 F degrees) which results in vertical b uoyancy of the non-condensable burn gases and sparge air (23u) releasing from the water surface. The volume source emission rate for sources 602 and 601 - 603 is shown in the following table:54 Heater Decoking SO2 Emission Rate to Area Source Conversion

SO2 Emissions Source Description Length Width Area Area 1 Hr Avg Annual
ft ft ft 2 m 2 g/sec g/sec-m 2 g/sec g/sec-m 2

K602_DEC 23H-1 decoke* 50 20 1000 92.903 5.942 0.063956 0.293 0.003154

K603_DEC 23H-2 decoke* 50 20 1000 92.903 0.000 0 0.000 0

* Model both 23 Unit heaters as one source; both heaters decoked to the same quench pit.

C. Reserved for Updated Justification of Modeled NO x Emission Rate

D

C . Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations There are no state or federal emissions standar ds for steam-air decoking of process heaters.

E D . Justification For Modeled Stack Parameters

As shown by the combustion stoichiometry, the amount of flue gas generated is equal to the volume of air added. It is assumed that all steam is condensed previously noted 21H-1, 21H-2, 23H-1, and removed in the 23H-2 are routed to individual quench system. Due to the amount of contact with quench water required to achieve the desired removal efficiency, the decoking flue gas temperature is cooled to 120 **** F. Therefore, the stack temperatur es used in the previous mode ling for decoking sources have been reduced to 120 **** F.

pits. The decoking pit for 21 H

- 1 has a metal cover. Most of the flue gas vented from 21 H

- 1 decoking will be released from a 3 ft x 3 ft hat ch which is opened for insertion of the quench line. Since the emissions are limited to a small area; it has been is modeled as a point volume source with a stack opening of 3.39 ft (1.032 m) and a 1 meter stack height.

The decoking pit for 21 H

- 2 also has a metal cover. Most of the flue gas vente d from 21 H

- 2 decoking will be released from a 15” x 20” opening in the cover for the quench line. Since emissions are limited to a small area, it has been the modeled as a point source with a stack opening of 1.63 ft (0.469 m) and a 1 meter stack height.

A s previously noted 23 H

- 1 and 23 H

- 2 are routed to a quench pit. The pit is modeled as an area source with an elevation of 1 meter.

Stack Flow Calculations: 1 Hr Avg Annual g/sec g/sec K600_DEC 21H-1 decoke 1.008 1.008 K601_DEC 21H-2 decoke 1.008 1.008 K602/603_DEC 23H-1, 2 decoke* 2.545 2.545 *Both 23 unit heaters modeled as one source; both heaters decoked to the same quench pit

. SO 2 Emissions Heater Decoking SO 2 Emission Rate

Source Description55 Stack temperature = 120 **** F = 48.9 **** C

Stack Velocity = air flow (SCFM)

* (120 **** F+460) **** R

* 4
* 1 min

= Vel. (ft/s) 520 **** R **** D 2 ft 2 60 s

This reduces to: Vel (ft/s) = air flow (SCFM) * 0.0237/D 2

The calculated stack parameters for heater decoking are listed in the following table : below.

Heater Decoking Stack Velocif y

Source Description air rate scfm Stack Dia ft Stack Ht ft Temp Deg F Vel ft/sec Vel m/sec Comments

K600_DEC 21H-1 decoke 1,120 3.39 3.28 120 2.31 0.71 Vent from 3' x 3' Quench Pit Hatch in #1 Coker Quench Pit

K601_DEC 21H-2 decoke 1,120 1.63 3.28 120 9.99 3.05 Vent from 15" x 20" Cover Opening in #2 Coker Quench Pit56 Side Length Release Height Syinit Szinit
ft ft m m K600_DEC 21H-1 decoke 32 5 2.24 1.4 K601_DEC 21H-2 decoke 32 5 2.24 1.4 K602/603_DEC 23H-1, 2 decoke* 32 5 2.24 1.4 *Both 23 unit heaters modeled as one source; both heaters decoked to the same quench pit. Description Heater Decoking Volume Source Parameters

Model Source Parameters
Source57 

### Sulfuric Acid Handing Emissions

A. Emission Point Description

FHR uses sulfuric acid as a catalyst in the Alkylation Unit. The sulfuric acid used at the Alkylation Unit contains small amounts of dissolved SO 2 . FHR has found that some of this SO 2 is emitted when sulfuric acid is transferred into storage tanks and cargo vessels

Historically, FHR has received its fresh acid from the Flint Hills Resources Sulfur ic Acid Plant (FHSAU) by pipeline. Spent acid was returned to FHSAU by the same pipeline for reprocessing. FHR originally had four (4) acid storage tanks for this purpose.

Recently FHR upgrated its sulfuric acid handling faci ti li ti es to allow shipment and receipt of sulfuric acid by rail. The upgrades include three rail loading/unlo a ding sites at an existing rail loading rack and one (1) new storage tank. Acid pump capacity and piping configuration limit the loading and unloading rate of sulfuric acid

FHR unloads fresh acid from rail cars to the fresh ac id tank. Empty rail cars are used to ship out spent acid for re-processing. Spent acid is loaded into ra il cars at atmospheric pressure. Once the cars are filled, they must be pressure tested before shipment. This is accomplished by filling the rail car vapor space with nitrogen. The test pressure is 30 psig. After the test is complete, the car is depressurized and the nitrogen is vented to atmosphere through a kno ck out (KO) pot. The KO pot is used to prevent sulfuric acid from being released to the atmosphere durring depressurization. The depressurization vent is treated as a separate source in the modeling.

FHR currently has four (4) spent acid tanks. One tank receives spent acid from the alky a l a tion unit, one tank is used for filling rail cars and the remaining tanks are used for gravity separation of hydrocarbons from the spent sulfuric acid. A spen d t acid storage tank must not be disturbed for a period of 24 hours to accomplish the acid/hdrocarbon s p eparation. Each tank is filled, left standing for at least 24 hours then pumped out to rail loading. All spent acid tanks are rotated thor o ugh this sequence.

B. Justification For Modeled SO 2 Emission Rate

SO 2 emissions occur during the filling of rail cars and storage tanks. SO 2 evolves from sulfuric acid during storage, and is emitted during vessel filling as contaminated air is pushed out of the vessel. Based on Draeger tube testing of the storage tanks and cargo vessels, SO 2 emissions are estimated to be approximately 1 lb SO 2 /hr from each emission point. Emission were calculated as follows:

Acid Loading gal * 1 ft 3 * 60 min * PPM SO 2 * 1 lb-mole * 64.06 lb SO 2 = lb SO 2 min 7.48 gal hr 1 e6 1E +06 379.5 scf lb-mole hr

An emission rate of 2.27 lb SO 2 /hr was used for each source to conservatively estimate the modeled impact of these sources. The sources modeled include:

**** 1 Rail Car Loading

**** 1 Rail Car Depressurization Vent

**** 1 Fresh Acid Storage Tank

**** 1 Spent Acid Storage Tank

As noted above, SO 2 is emitted as a tank receives acid. So , two tanks (the fresh acid tank and one spent acid tank) were used to establish the SO2 emission ra te from storage tanks. The other two spent acid tanks are not included in the SO 2 emission calculation because they are either being emptied to rail loading or have a constant level during grav ity separation of acid and hydrocarbon liquids.58 C. Reserved for Updated Justification of Modeled NO x Emission Rate

D. C. Consistency Between Modeled SO 2 Emissions And Applicable State And Federal Regulations

There are no state or federal emissions stand ards for sulfuric acid loading and storage.

E. D. Justification For Modeled Stack Parameters

Each of the sulfuric acid handling emission points was modeled as a volume source per MPCA modeling guidelines.59 

### Insignificant Sources

The following sources were not included in the modeled source inventory because emissions from these sources were too small to have a significant modeled im pact as determined by either the sulfur content of the fuel or the emission rate of the source.

The low sulfur gas streams have average H2S conten ts of 0 ppm – 1 ppm. At these levels, the SO2 emission rate is 0.00015 lb SO 2 /MMBtu. As an example, a 100 MMBtu/hr heater would emit 0.015 lb SO 2 /Hr vs. 2.38 lb SO2/Hr for refinery fuel gas at 162 ppm H2S.

Source Fuel Source PPM H 2 S 1 Emission Rate Lb/Hr SO 2 Comments

Platformer Catalyst Reg Vent lb/hr NA 0.007 Emission rate as measured by performance test. Platformer Catalyst Lock Hopper Off Gas 1 NA Do not include in calculated emission rate from 37 H-345 Powerformer Catalyst Reg Vent lb/hr NA 0.03 Emission rate as measured by performance test. Central SVE TO 0.8 NA Emission rate as measured by performance test. West Tank Farm SVE TO 0.6 NA Rail Loading TO 0 NA Thermal oxidizer for rail loading of gasoline. Average gasoline sulfur content is 7ppm. Butane TO NA Flare Pilots NA #2 H2 Plant PSA Off Gas 0 NA Do not include in calculated emission rate from 27 H-1. Note evaluate S/U firing condition w full duty on fuel gas (pre PSA off gas generation).

#3 H2 Plant PSA Off Gas 0 NA Used data from #2 H2. #3 H2 plant is based on the same design as #2 H2.

Nat Gas fired asphalt tank heaters NA Max Emis Rate 0.0018 Average Emis Rate 0.0012 Max asphalt tank heater duty 3.1 MMBtu/hr; Average – 2.1 MMBtu/hr. Emissions calc’d basis AP-42

1 H2S measurement by Draeger Tube to demonstrate that the source contained minimal amounts of sulfur.

# Exhibit 1 - Section 3 Facility Boundary Diagram

Facility Boundary File name is: “Fig 1 Ambient Air Boundary.pdf”

Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling Analysis

# ! ;

NBarr Footer: Date: 5/3/2011 4:19:57 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure1_Ambient_Air_Boundary.mxd User: jjm

500 0 500 Meters 

### Figure 1

Ambient Air Boundary

SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN Ambient Air Boundary

# Exhibit 1 - Section 4 Source Data Summary Table Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling AnalysisFlint Hills ResourcesNAAQS and MAAQS SO2 Attainment Modeling DemonstrationModel Input Summary -- Merox Off-Gas ProjectMay 2011Print Date: 5/9/2011 3:23 PMDescrip AERMOD_id Type UTM_E UTM_N Elv_m Ht_m GEP_m Dia_m Max. HeatInputCapacityDuty orSizeRatingDe-RatedDuty forStk VelCal'sMix Drum HHVBtu/scfUnits T_K Syinit Szinit scf fluegas perMMBtu fuelgas1-,3-hr_V_m/sSO2ppmSO2_1hr_ g/s SO2_3hr_g/s SO2_24hr_g/s SO2_Ann_g/s Sourcetype34H-3 K1_MEROXPOINT496781.2 4957077.0 281.953.72 53.721.575NA578.0NA3.848.2408.240 8.2408.240Oxidizer45H-61 K2_#3SRU POINT496906.7 4956920.9 282.760.9660.96 1.448122.0 NA578NA16.0018.822 18.781 10.9069.332SRU26H-21 K3_#5SRU POINT496868.5 4956631.4 277.665.0065.00 2.10356.8 NA464NA9.3021.575 21.520 11.79311.793SRU71B-7Boilers1,2,3,4,6 & 9K7____BHBoilerFCC ESP K8___FCC POINT496993.1 4956990.2 283.680.0069.27 2.937NANA366NA15.2423.013 23.013 23.01323.013FCC32H-5,6,7 K10_32FG POINT496775.9 4957022.0 281.962.4862.48 2.730160.0160.0 135.0 411197 MMBtuper HrHHV42210,2151.35 0.852 0.852 0.852 0.460ProcHeater19H-1 K11_19FO POINT496585.4 4957137.0 280.458.5258.52 2.134145.6173 146 411197 MMBtuper HrHHV42210,2152.40 0.921 0.921 0.921 0.498ProcHeater12H-4 K13_12FG POINT496667.2 4957137.0 280.960.5060.50 2.070138.2150 138 411197 MMBtuper HrHHV42210,2152.41 0.799 0.799 0.799 0.431ProcHeater33H-31 K14_33FO POINT496981.5 4956855.0 283.557.5255.78 1.969115.7174 116 451093 MMBtuper HrHHV55310,2082.93 1.691 1.691 1.691 1.353ProcHeater16H-1 K15_16FG POINT496627.7 4957108.0 280.858.8358.83 3.340236.9236.9411197 MMBtuper HrHHV48010,2151.81 1.262 1.262 1.262 0.681ProcHeater11H-3 K16_11FOProcHeater11H-5 K18_11FOProcHeater11H-1 K19_11FO POINT496649.9 4957059.0 281.039.9339.93 1.397119.9160 120 411197 MMBtuper HrHHV46610,2155.08 0.852 0.852 0.852 0.460ProcHeater37H-1,2,6 K20_37FG POINT496870.1 4956697.0 280.260.9660.96 1.009123.090451093 MMBtuper HrHHV42210,2086.61 0.875 0.875 0.875 0.700ProcHeater33H-32 K21_33FG POINT496923.7 4956848.0 283.056.9456.12 1.436128.8128.8451093 MMBtuper HrHHV54710,2086.05 1.252 1.252 1.252 1.002ProcHeater11H-2 K23_11FG POINT496637.9 4957060.0 281.035.0535.05 1.86757.057 30 411197 MMBtuper HrHHV50810,2150.77 0.304 0.304 0.304 0.164ProcHeater21H-1S FOfiredK27_21FO POINT496551.5 4957092.5 280.738.7138.71 1.41066.0 66.0 40.0 41 1197 MMBtuper HrHHV47810,2151.700.3510.351 0.3510.190ProcHeater21H-1N FOfiredK28_21FO POINT496551.5 4957101.5 280.638.7138.71 1.41066.0 66.0 40.0 41 1197 MMBtuper HrHHV47810,2151.700.3510.351 0.3510.190ProcHeater21H-2S FOfiredK29_21FO POINT496550.8 4957025.2 280.939.9339.93 1.41066.0 66.0 40.0 41 1197 MMBtuper HrHHV48910,2151.740.3510.351 0.3510.190ProcHeater21H-2N FOfiredK30_21FO POINT496550.8 4957034.2 280.939.9339.93 1.41066.0 66.0 40.0 41 1197 MMBtuper HrHHV48910,2151.740.3510.351 0.3510.190ProcHeater33H-4 (33H1&2)K31_33FG POINT496921.1 4956899.0 282.930.4830.48 1.829182.6 182.6 144.0 45 1093 MMBtuper HrHHV55010,2084.191.7751.775 1.7751.420ProcHeater23H-1 FOfiredK32_23FO POINT496531.7 4956882.6 272.957.9157.91 1.631165.0165451093 MMBtuper HrHHV42210,2084.63 1.604 1.604 1.604 1.283ProcHeater31H-1 K33_31FG POINT496768.3 4957087.0 281.920.4220.42 1.11123.023411197 MMBtuper HrHHV56610,2151.87 0.122 0.122 0.122 0.066ProcHeaterSource has been removed from serviceSource has been removed from serviceSource has been removed from service\\barr.com\projects\Mpls\23 MN\19\23191034 Merox Off-gas to 31H-2 Permitting\WorkFiles\Amendment_9\SIP 9\SIP 9 Exhibit 1 Merox Incinerator Removal\SIP 9 Model Justification\Section 4\SIP9_MPCA_2011_04_19_3_24hr_fix.xlsx SIP 9 (Modeled)Page 1 of 4Flint Hills ResourcesNAAQS and MAAQS SO2 Attainment Modeling DemonstrationModel Input Summary -- Merox Off-Gas ProjectMay 2011Print Date: 5/9/2011 3:23 PMDescrip AERMOD_id Type UTM_E UTM_N Elv_m Ht_m GEP_m Dia_m Max. HeatInputCapacityDuty orSizeRatingDe-RatedDuty forStk VelCal'sMix Drum HHVBtu/scfUnits T_K Syinit Szinit scf fluegas perMMBtu fuelgas1-,3-hr_V_m/sSO2ppmSO2_1hr_ g/s SO2_3hr_g/s SO2_24hr_g/s SO2_Ann_g/s Sourcetype31H-2 K34_31FG POINT496769.0 4957077.0 281.918.5918.59 0.95323.023411197 MMBtuper HrHHV66610,2152.99 8.363 8.363 8.363 8.363ProcHeater31H-5 K36_31FG POINT496802.9 4957102.0 282.217.9817.98 0.80010.010411197 MMBtuper HrHHV42210,2151.17 0.053 0.053 0.053 0.029ProcHeater31H-10 K37_31FG POINT496802.9 4957112.0 282.230.4830.48 1.37229.830411197 MMBtuper HrHHV52510,2151.48 0.160 0.160 0.160 0.086ProcHeater32H-9 K41_32FG POINT496774.0 4957037.0 281.921.6421.64 0.9149.09 411197 MMBtuper HrHHV53310,2151.02 0.048 0.048 0.048 0.026ProcHeater37H-3,4,5 K42_37FG POINT496914.2 4956703.2 279.881.9971.20 3.417391.0390.7451093 MMBtuper HrHHV42210,2082.50 3.798 3.798 3.798 3.038ProcHeater38H-1A K46_38FG POINT496952.1 4956560.5 281.544.5044.50 1.80329.038.2 29 451093 MMBtuper HrHHV60010,2080.95 0.371 0.371 0.371 0.297ProcHeater38H-1B K47_38FG POINT496952.1 4956571.3 281.544.5044.50 1.80329.038.2 29 451093 MMBtuper HrHHV60010,2080.95 0.371 0.371 0.371 0.297ProcHeater38H-2 K48_38FG POINT496979.3 4956563.4 281.760.9660.96 0.83856.062 30 451093 MMBtuper HrHHV42210,2083.19 0.603 0.603 0.603 0.482ProcHeater25H-1 K50_25FG POINT496755.4 4956642.0 274.577.2765.00 3.600253.0253 253 451093 MMBtuper HrHHV42210,2081.46 2.459 2.459 2.459 1.967ProcHeater25H-3 K51_25FG POINT496786.2 4956635.0 275.873.7165.00 3.500206.0227 227 451093 MMBtuper HrHHV42810,2081.40 2.207 2.207 2.207 1.765ProcHeater25H-4 K52_25FG POINT496800.5 4956636.9 276.860.9660.96 1.930163.0163 163 451093 MMBtuper HrHHV42210,2083.27 1.584 1.584 1.584 1.268ProcHeater23H-2 K53_23FG POINT496532.5 4956853.8 269.857.9157.91 1.335122.0122451093 MMBtuper HrHHV43610,2085.28 1.186 1.186 1.186 0.949ProcHeater27H-1 K54_27FG POINT496725.5 4956511.4 277.145.7245.72 3.132800.0800451093 MMBtuper HrHHV42210,2086.09 7.776 7.776 7.776 6.221ProcHeater27H-101 K55_27FG POINT496811.6 4956500.1 276.645.7245.72 1.11384.084451093 MMBtuper HrHHV42210,2085.07 0.817 0.817 0.817 0.653ProcHeater27H-102 K56_27FG POINT496813.3 4956402.9 276.045.7245.72 1.11384.095 84 451093 MMBtuper HrHHV42210,2085.07 0.923 0.923 0.923 0.739ProcHeater31H-4 K57_31FG POINT496798.1 4957001.0 282.032.4632.46 1.34771.071 30 411197 MMBtuper HrHHV55510,2151.63 0.378 0.378 0.378 0.204ProcHeater31H-7 K58_31FG POINT496798.0 4957025.0 282.028.6528.65 1.06768.468.4 30 411197 MMBtuper HrHHV54410,2152.54 0.364 0.364 0.364 0.197ProcHeater31H-8 K59_31FG POINT496799.2 4957036.0 282.128.8028.80 1.04938.638.6411197 MMBtuper HrHHV51910,2153.23 0.206 0.206 0.206 0.111ProcHeater31H-9 K60_31FG POINT496798.8 4957018.0 282.024.8424.84 0.90550.050 30 411197 MMBtuper HrHHV51110,2153.32 0.266 0.266 0.266 0.144ProcHeater28H-1 K61_28FG POINT496837.8 4956502.2 276.945.7245.72 0.78734.034451093 MMBtuper HrHHV81110,2087.88 0.330 0.330 0.330 0.264ProcHeater71B-8 K62_BLR8 POINT496698.3 4956542.5 277.59.049.04 1.524185.0185451093 MMBtuper HrHHV42210,2085.95 1.798 1.798 1.798 1.439Boiler27H-501 K63_27FG POINT496722.3 4956358.0 275.135.0535.05 3.150475.0475451093 MMBtuper HrHHV42210,2083.58 4.617 4.617 4.617 3.694ProcHeater11H-6 K67_11FG POINT496630.1 4956988.4 280.756.6254.86 2.642390.0390411197 MMBtuper HrHHV42210,2154.18 2.077 2.077 2.077 1.122ProcHeater71B-9 K68_BLR9 POINT496569.0 4957199.8 280.012.1912.19 1.829235.0235 135 411197 MMBtuper HrHHV42210,2153.02 1.251 1.251 1.251 0.676Boiler\\barr.com\projects\Mpls\23 MN\19\23191034 Merox Off-gas to 31H-2 Permitting\WorkFiles\Amendment_9\SIP 9\SIP 9 Exhibit 1 Merox Incinerator Removal\SIP 9 Model Justification\Section 4\SIP9_MPCA_2011_04_19_3_24hr_fix.xlsx SIP 9 (Modeled)Page 2 of 4Flint Hills ResourcesNAAQS and MAAQS SO2 Attainment Modeling DemonstrationModel Input Summary -- Merox Off-Gas ProjectMay 2011Print Date: 5/9/2011 3:23 PMDescrip AERMOD_id Type UTM_E UTM_N Elv_m Ht_m GEP_m Dia_m Max. HeatInputCapacityDuty orSizeRatingDe-RatedDuty forStk VelCal'sMix Drum HHVBtu/scfUnits T_K Syinit Szinit scf fluegas perMMBtu fuelgas1-,3-hr_V_m/sSO2ppmSO2_1hr_ g/s SO2_3hr_g/s SO2_24hr_g/s SO2_Ann_g/s SourcetypeBoiler 10 BLR10 POINT496568.6 4957194.3 280.012.1912.19 1.829235.0235 135 411197 MMBtuper HrHHV43610,2153.12 1.251 1.251 1.251 0.67630 H-401#4 H2 PlantK70_4H2 POINT496664.6 4956414.6 274.435.0535.05 2.896900.0900 450 451093 MMBtuper HrHHV42211,0004.32 8.748 8.748 8.748 6.999ProcHeater29 H-1Comb Fd&DistK71HCFD POINT496923.0 4956351.0 277.040.7840.78 2.629241.0220 10 451093 MMBtuper HrHHV42210,2080.11 2.138 2.138 2.138 1.711ProcHeater71B-6 Boiler K1006_BH POINT496566.9 4957213.0 280.121.3421.34 1.372120.0 108.0 80.0411197 MMBtuper HrHHV42210,2153.18 0.639 0.639 0.639 0.345Boiler45H-6 K113__FG POINT496901.4 4956953.5 282.753.6853.68 1.016122.011.141451093 MMBtuper HrHHV42210,2080.81 0.202 0.202 0.202 0.181Oxidizer93P-160 K331_DSL POINT496832.2 4956976.5 282.34.274.27 0.102NA 175 HP616 23.60 0.0003 0.0003 0.0003 0.0003Diesel93P-400 K332_DSL POINT496753.3 4957695.5 270.94.574.57 0.152NA624 HP61637.900.0010.001 0.0010.001Diesel93P-570 K333_DSL POINT495957.0 4956960.1 262.25.495.49 0.305NA 624 HP616 9.41 0.001 0.001 0.001 0.001Diesel94H-1 K348_OXD POINT496636.2 4957613.5 276.022.1122.11 1.717100.053310.366.3896.389 6.3891.134EE-1657 K407_DSL POINT496799.3 4956593.5 275.16.106.10 0.203NA600 HP61620.430.0010.001 0.0010.001DieselEE-1692 K408_DSL POINT496684.0 4957064.0 281.14.114.11 0.203NA603 HP61620.530.0010.001 0.0010.001Diesel23ME26 K435_DSL POINT496526.5 4956971.5 278.67.017.01 0.152NA685 HP61641.600.0010.001 0.0010.001DieselEE-1309 K453_DSL POINT496910.2 4956656.0 278.47.927.92 0.152NA685 HP61641.600.0010.001 0.0010.001DieselEE-1718 K465_DSL POINT496908.4 4957114.5 283.04.574.57 0.203NA603 HP61620.530.0010.001 0.0010.001Diesel81P-159 K505_DSL POINT496846.2 4956974.5 282.55.495.49 0.203NA546 HP61618.590.0010.001 0.0010.001Diesel81P-357 K506_DSL POINT496838.3 4956933.5 282.26.106.10 0.203NA500 HP61617.020.0010.001 0.0010.001Diesel81P-444 K507_DSL POINT496646.3 4956932.5 281.14.574.57 0.254NA630 HP61613.700.001 0.0010 0.00100.0010Diesel81P-89 K508_DSL POINT496639.3 4956990.5 280.94.574.57 0.102NA325 HP61643.830.0005 0.0005 0.00050.0005DieselWood RiverK510_DSL POINT495926.3 4957212.5 262.24.574.57 0.305NA1195 HP61618.020.0020.002 0.0020.002Diesel71C-11 K511_DSL POINT496987.9 4956786.1 282.16.106.10 0.254NA705 HP61615.330.0010.001 0.0010.001DieselPortablediesel capPORT_DSL POINT497006.0 4957000.0 283.74.274.27 0.102211 &6,369,600211 HPHP-Hrper Yr61628.46DieselULSDReplaceK509DSL81P-450K513_DSL POINT496672.2 4956267.3 271.99.759.75 0.3051200 HP47714.020.0020.002 0.0020.002Diesel21H-1 dec K600_DEC VOLUME496522.1 4957081.7 280.6 1.50NANA 2.24 1.4NA1.0081.008 1.0080.05021H-2 dec K601_DEC VOLUME496528.9 4957028.6 280.8 1.50NANA 2.24 1.4NA1.0081.008 1.0080.05023H-1 dec K602_DEC VOLUME496461.0 4956855.0 264.1 1.50NANA 2.24 1.4NA2.5452.545 2.5450.12623H-2 dec K603_DEC VOLUME496461.0 4956855.0 264.1 1.50NANA 2.24 1.4NA0.0000.000 0.0000.000Acid Ld &DepressK700ACDL VOLUME496560.0 4957484.0 280.6 3.103.9 1.40.572 0.572 0.572 0.572Acid Stor Tks K701ACDS VOLUME496837.0 4957122.0 282.6 7.605 3.50.572 0.572 0.572 0.572NSP NSP_IGH1 POINT496686.8 4958733.5 287.59.759.75 4.2128391,150,00038.95 61.550 61.550 61.550 38.730PowerTurbineNSP NSP_IGH2 POINT496686.8 4958694.9 286.99.759.75 4.2128391,150,00038.95 61.550 61.550 61.550 38.730PowerTurbineNSP NSP_IGH3 POINT496676.9 4958698.7 287.19.759.75 4.2128391,150,00038.95 61.550 61.550 61.550 38.730PowerTurbineSource has been removed from modeling per 40 CFR Parts 52 and71\\barr.com\projects\Mpls\23 MN\19\23191034 Merox Off-gas to 31H-2 Permitting\WorkFiles\Amendment_9\SIP 9\SIP 9 Exhibit 1 Merox Incinerator Removal\SIP 9 Model Justification\Section 4\SIP9_MPCA_2011_04_19_3_24hr_fix.xlsx SIP 9 (Modeled)Page 3 of 4Flint Hills ResourcesNAAQS and MAAQS SO2 Attainment Modeling DemonstrationModel Input Summary -- Merox Off-Gas ProjectMay 2011Print Date: 5/9/2011 3:23 PMDescrip AERMOD_id Type UTM_E UTM_N Elv_m Ht_m GEP_m Dia_m Max. HeatInputCapacityDuty orSizeRatingDe-RatedDuty forStk VelCal'sMix Drum HHVBtu/scfUnits T_K Syinit Szinit scf fluegas perMMBtu fuelgas1-,3-hr_V_m/sSO2ppmSO2_1hr_ g/s SO2_3hr_g/s SO2_24hr_g/s SO2_Ann_g/s SourcetypeNSP NSP_IGH4 POINT496677.2 4958657.2 286.39.759.75 4.2128391,150,00038.95 61.550 61.550 61.550 38.730PowerTurbineNSP NSP_IGH5 POINT496686.2 4958661.4 286.49.759.75 4.2128391,150,00038.95 61.550 61.550 61.550 38.730PowerTurbineNSP NSP_IGH6 POINT496686.5 4958621.5 286.39.759.75 4.2128391,150,00038.95 61.550 61.550 61.550 38.730PowerTurbineGopher GOPHER POINT490625.4 4964656.5 272.960.6660.66 1.82936121.38262.080 262.080 262.080262.080Smelter\\barr.com\projects\Mpls\23 MN\19\23191034 Merox Off-gas to 31H-2 Permitting\WorkFiles\Amendment_9\SIP 9\SIP 9 Exhibit 1 Merox Incinerator Removal\SIP 9 Model Justification\Section 4\SIP9_MPCA_2011_04_19_3_24hr_fix.xlsx SIP 9 (Modeled)Page 4 of 4

# Exhibit 1 - Section 5 Building Dimension Information Located on CD

- ROM in folder Section 5

Updated Building Dimensions are in files: “SIP9.BPI” “SIP9.PRO”

Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling Analysis

# Exhibit 1 - Secti on 6 Summary of Model Results Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling AnalysisAveraging Period 21H-1 Decoking Scenario Before Merox Project 21H-2 Decoking

Scenario Before Merox Project 23H-1,2 Decoking

Scenario Before Merox Project 21H-1 Decoking

Scenario After Merox Project 21H-2 Decoking

Scenario After Merox Project 23H-1,2 Decoking

Scenario After Merox Project

1-Hr Avg High 2nd High 531 531 606 664 656 650 MN Standard 1,300 1,300 1,300 1,300 1,300 1,300 % Standard (Including Background) 45% 45% 51% 55% 55% 54%

3-Hr Avg High 2nd High 240 241 333 483 473 401 EPA/MN Standard 1,300 1,300 1,300 1,300 1,300 1,300 % Standard (Including Background) 21% 21% 28% 40% 39% 33%

24-Hr Avg High 2nd High 108 108 117 155 155 150 EPA/MN Standard 365 365 365 365 365 365 % Standard (Including Background) 34% 34% 37% 47% 47% 46%

Annual Avg MN Standard* % Standard (Including Background)

* EPA standard is 80 ug/m 3

1 Hr Background 56 3 Hr Background 34 24 Hr Background 17 Annual Background 4 46% 31 60 58% Before Merox Project (All Decoking) After Merox Project (All Decoking)

60 24 Flint Hills Resources NAAQS and MAAQS SO 2 Attainment Modeling Demonstration Modeling Results Summary - All SO 2 Concentrations in ug/m 3 May 2011

# Exhibit 1 - Section 7 AERMOD Model Input Information Located on CD-ROM in folder Section 7

All meteorology data is located in subfolder METDATA: 2000 met data is in file “MSPMPX00.SFC and MSPMPX00.PFL” 2001 met data is in file “MSPMPX01.SFC and MSPMPX01.PFL” 2002 met data is in file “MSPMPX02.SFC and MSPMPX02.PFL” 2003 met data is in file “MSPMPX03.SFC and MSPMPX03.PFL” 2004 met data is in file “MSPMPX04.SFC and MSPMPX04.PFL”

Source Locations and Para meters are in files: “SIPso1hR700.adi - SIPso1hR704.adi” “SIPso3hR900.adi – SIPso3hR904.adi” “SIPso24hR900.adi – SIPso4hR904.adi” “SIPsoannR800.adi – SIPsoannR804.adi”

Receptor Elevations are in file: “SIP9.ROU”

Receptor Grid figures are in files: “Figure 2 Far Field Receptor Grid.pdf” “Figure 3 Near Field Receptor Grid.pdf”

Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling Analysis!!!!!!!!!!!! !!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!! !!!!!!!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!

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NBarr Footer: Date: 5/3/2011 4:22:34 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure3_Near_Field_Receptor_Grid.mxd User: jjm

500 0 500 Meters 

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Near Field Receptor Grid SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN ! 

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# Exhibit 1 - Section 8 AERMOD Model Output Located on CD-ROM in folder Section 8

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SO 2 

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SO 2 

# 3 hr NAAQS complia nce figures are: “Figure 7 3 Hour SO2 Results 21H-1 Decoking Scenario.pdf” “Figure 8 3 Hour SO2 Results 21H-2 Decoking Scenario.pdf” “Figure 9 3 Hour SO2 Results 23 H-1, 2 Decoking Scenario.pdf”

SO 2 

# 24 hr NAAQS compliance figures are: “Figure 10 24 Hour SO2 Results 21H-1 Decoking Scenario.pdf” “Figure 11 24 Hour SO2 Results 21H-2 Decoking Scenario.pdf” “Figure 12 24 Hour SO2 Results 23H-1, 2 Decoking Scenario.pdf”

SO 2 

# Annual NAAQS complia nce figures are: “Figure 13 Annual SO2 Results.pdf”

Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling Analysis! !!!! !!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!
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NBarr Footer: Date: 5/3/2011 4:23:31 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure4_1Hour_SO2_Results_21H1DecokingScenario.mxd User: jjm

1 0 1 2 Kilometers 

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1 Hour SO2 Results 21H-1 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

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1 0 1 2 Kilometers 

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1 Hour SO2 Results 21H-2 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

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NBarr Footer: Date: 5/3/2011 4:25:16 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure6_1Hour_SO2_Results_23H12DecokingScenario.mxd User: jjm

1 0 1 2 Kilometers 

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1 Hour SO2 Results 23H-1,2 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

## Percent of 1 Hour MAAQS

! 

### 15% - 35%

! 

### 36% - 40%

! 

### 41% - 45%

! 

### 46% - 50%

! 

### 51% - 54%

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NBarr Footer: Date: 5/3/2011 4:27:51 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure7_3Hour_SO2_Results_21H1DecokingScenario.mxd User: jjm

1 0 1 2 Kilometers 

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3 Hour SO2 Results 21H-1 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

## Percent of 3 Hour NAAQS

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NBarr Footer: Date: 5/3/2011 4:28:36 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure8_3Hour_SO2_Results_21H2DecokingScenario.mxd User: jjm

1 0 1 2 Kilometers 

### Figure 8

3 Hour SO2 Results 21H-2 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

## Percent of 3 Hour NAAQS

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NBarr Footer: Date: 5/3/2011 4:29:35 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure9_3Hour_SO2_Results_23H12DecokingScenario.mxd User: jjm

1 0 1 2 Kilometers 

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3 Hour SO2 Results 23H-1,2 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

## Percent of 3 Hour NAAQS

! 

### 9% - 15%

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### 31% - 33% NAAQS = 1,300 ug/m3 Background Concentration of 34 ug/m3 included.! !!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!! ! !!

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1 0 1 2 Kilometers 

### Figure 10

24 Hour SO2 Results 21H-1 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

## Percent of 24 Hour NAAQS

! 

### 10% - 30%

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1 0 1 2 Kilometers 

### Figure 11

24 Hour SO2 Results 21H-2 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

## Percent of 24 Hour NAAQS

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### 10% - 30%

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NBarr Footer: Date: 5/3/2011 4:42:18 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure12_24Hour_SO2_Results_23H12DecokingScenario.mxd User: jjm

1 0 1 2 Kilometers 

### Figure 12

24 Hour SO2 Results 23H-1,2 Decoking Scenario SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

## Percent of 24 Hour NAAQS

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### 11% - 25%

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### 31% - 35%

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### 41% - 46% NAAQS = 365 ug/m3 Background Concentration of 17 ug/m3 included.! !!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!! !!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!! !!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!! ! !!!!!!!!!!!!!!!!! !!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!! !!

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NBarr Footer: Date: 5/3/2011 4:44:06 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure13_Annual_SO2_Results.mxd User: jjm

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### Figure 13

Annual SO2 Results SO2 SIP 9 Exhibit 1 Flint Hills Resources Pine Bend, MN 

## Percent of Annual NAAQS

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### 11% - 20%

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### 41% - 50%

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### 51% - 58% NAAQS = 60 ug/m3 Background Concentration of 4 ug/m3 included.

# Exhibit 1 - Section 9 Backgr ound Concentration Information Flint Hills Resources Pine Bend LLC Ambient Air Quality Modeling Analysis

### Exhibit 1 Section 9.

The modeling analysis used the following values for background concentrations in ug/m 3 

### for the listed averaging times:

1 - Hour Averages 56 ug/m 3 

### ( MPCA 2008 Option 2 values for “Rest of TC” ) 3 - Hour Averages 34 ug/m 3 

### (MPCA 2008 Option 2 values for “Rest of TC”) 24 - Hour Averages 17 ug/m 3 

### (MPCA 2008 Option 2 values for “Rest of TC”) Annual Averages 4 ug/m 3 

### (MPCA 2008 Option 2 values for “Rest of TC”)

The 1, 3, 24

– hour, and annual average background values are taken from an updated background values table in the “MPCA Guidance for Title V and PSD Air Dispersion Modeling”. The background values for the area described as “Rest of TC” include Dakota County which is the location of the Flint Hills Refinery. Option 2 values represent 80% of the background and are used when the modeling includes explicitly modeled nearby facilities.

These background values are representative of the area surrounding the Flint Hills Refinery and are similar in magnitude to the SIP 8 background values.

### Attachment 2: Markup versio n of Administrative Order

### Page 1 of 25 STATE OF MINNESOTA MINNESOTA POLLUTION CONTROL AGENCY

In the matter of Flint Hills Resources , LP Pine Bend, LLC

Proceedings to Develop and Implement a State Implementation Plan for the Pine Bend Industrial Area, Rosemount, Minnesota, to Demonstrate, Attain and Maintain Compliance with the National Ambient Air Quality Standards for Sulfur Dioxide, as required by the Clean Air Act Section 110, 42 U.S.C. § 7410. AMENDED FINDINGS AND ORDER BY CONSENT

The Minnesota Pollution Control Agency (MPCA), being fu lly advised in the premises and with the consent of Flint Hills Resources Pine Bend, LLC, (formerly known as Flint Hills Resources, LP) hereby adopts the following this Amended Findings and Order. The MPCA first adopted Findings and Order by Stipulation on April 2, 1991 (Order). The Order has been amended eight times and as amended is in effect today

.

FINDINGS

1. The State of Minnesota is obligated by section 110(a) of the Clean Air Ac t, 42 U.S.C. § 7410, to develop a plan which provides for “implementation, maintenanc e, and enforcement” of the primary and secondary national ambient air quality standards (NAAQS) prom ulgated by the U.S. Environmental Protection Agency (EPA) pursuant to section 109 of the Clean Air Act, 42 U.S.C. § 7409.

2. The EPA has promulgated requirements for the implem entation plans required by section 110(a) of the Clean Air Act at 40 CFR Part 51 ( 1991 2010 ) (Requirements for Preparation, Adoption and Submittal of Implementation Plans).

3. The EPA has promulgated primary NAAQS for sulfur dioxide of 0. 03 parts per million (ppm) annual arithmetic mean and 0.14 ppm maximum 24-hour conc entration, not to be ex ceeded more than once per year, 40 CFR § 50.4 (1991), and (2010). This primary NAAQS remains applicable to all areas until one year after the effective date of the designation of an area, pursuant to section 107 of the Clean Air Act, for the primary sulfur dioxide NAAQS described in Finding 4.

4. In 2010, the EPA promulgated a new primary NAAQS fo r sulfur dioxide of 75 parts per billion (ppb) one-hour annual average, met when the three-year average of the annual 99 th



### percentile of the daily maximum one-hour concentration is less th an or equal to 75 ppb, 40 CFR § 50.17.

4. 5. The EPA has promulgated secondary NAAQS for sulfur dioxide of 0.5 ppm maximum three-hour concentration, not to be exceeded more than once per year, 40 CFR. § 50.5 ( 1991 2010 ).

5. 6. The MPCA is a statutory agency of the state of Minnesota, Minn. Stat. § 116.02, subp. 1 ( 1990 2010 ), charged with the responsibility to administer and en force laws and promulgate rules to prevent water, air and land pollution throughou t the state of Minnesota, Minn. Stat. chs. 115, 115B and 116 ( 1990 2010 ).

### Page 2 of 25 6. 7. The MPCA is empowered to promulgate standards and rules for the prevention, abatement or control of air pollution related, without limitat ion, to “source or emissions of ai r contamination or air pollution, to the quality or composition of such emissions, or to the quality of or composition of the ambient air or outdoor atmosphere or to any other matter relevant to the prevention, abatement or control of air pollution.” Minn. Stat. § 116.07, subp. 4 ( 1990). 2010). See Minn. Stat. § 116.07, subp. 2 ( 1990 2010 ).

7. 8. The MPCA has promulgated primary ambient air quality standards for sulfur dioxide of 0.03 ppm annual arithmetic mean and 0.14 ppm maximum 24-hour conc entration, not to be ex ceeded more than once per year. Minn. Rules pt. 7005 7009 .0080 ( 1991). 2010). The MPCA has also promulgated secondary ambient air quality standards for sulfur dioxide of 0. 5 ppm maximum three-hour concentration, not to be exceeded more than once per year in Air Quality Control Region 131. Minn. Rules pt. 7005 7009 .0080 ( 1991 2010 ).

8. 9. The MPCA has the authority to enforce any statute or rule related to air pollution by, among other things, adopting, issuing, entering into or enforc ing “reasonable orders, sc hedules of compliance and stipulation agreements.” Minn. Stat. § 116.07, subp. 9 ( 1990 2010 ).

9. 10. Minn. Stat. § 115.071 ( 1990 2010 ) provides that the provisions of chapters 115 and 116 and “all rules, standards, orders, stipulation agreements, schedules of compliance, and permits adopted or issued” by the MPCA may be enforced by criminal prosecution, action to recover civil penalties, injunction, action to compel performance, or other appropriate action. Specifically, in an action to compel performance of an order of the MPCA, the regulated party may be required “to do and perform any and all acts and things within the defendant’s power which are reasonably necessary to accomplish the purposes of the order.” Minn. Stat. § 115.071, subp. 5 ( 1990 2010 ).

10. 11. The seven-county Twin Cities metropolitan area Ai r Quality Control Region (AQCR) is defined at 40 CFR § 81.27 ( 1991 2010 ) and is designated AQCR 131 and . The area was classified as a nonattainment area for the primary NAAQS for sulfur dioxide at 40 CFR § 81.324 (1991). The area now maintains the standard.

11. 12. In 1981, the EPA approved Minnesota’s State Impl ementation Plan (SIP) to control emissions of sulfur dioxide in the Twin Cities nonattainment ar ea, AQCR 131. 46 Federal Register 20997 (April 8, 1981). See 40 CFR § 52. 1220 1222 (c)( 16) (1991 17) (2010 ).

12. 13. On July 29, 1982, EPA proposed to conditionally approve Minnesota Rule APC-41 (Offset Rule) as a revision to the Minnesota SIP fulfilling the requirements of Part D (Plan Requirements for Nonattainment Areas) of the Clean Ai r Act, 42 U.S.C. §§ 7501-7508. 47 F ederal R egister 32,742 32742 (July 29, 1982).

13. 14. In 1982, MPCA staff computer modeling of allowable sulfur dioxide emissions from stationary emission sources in the Pine Bend area of Dakota County (a portion of AQCR 131) showed the potential for nonattainment of the sulfur dioxide NAAQS.

14. 15. On September 2, 1983, the MPCA formally requested that EPA re designate all of AQCR 131 to attainment for sulfur dioxide except for the Pine Bend area of Dakota County.

15. 16. On September 28, 1984, EPA issued a letter of SIP deficiency to the MPCA pursuant to Section 110(a)(2)(H) of the Clean Air Act, 42 U.S.C. § 7410(a)(2)(H), for monitored and modeled violations of the sulfur dioxide NAAQS in the Dakota County portion of AQCR 131. EPA published this notice at 49 F ederal R

egister 47488 (December 5, 1984), and identified Dakota County as one of the areas in the country with fully or partially approved Part D pl ans which still do not attain NAAQS.

16. 17. On June 27, 1986, the MPCA submitted a sulfur dioxide SIP revision for the Dakota County portion of AQCR 131 to EPA to resolve the SIP deficiency noted in a the September 28, 1984, letter from

### Page 3 of 25 EPA to Governor Rudy Perpich of Minnesota . The MPCA submitted a sulfur dioxide SIP revision for another portion of AQCR 131 (i.e., the St. Paul Park area of Washingt on and Ramsey Counties) on June 30, 1987. On August 19, 1987, the MPCA submitted to EPA a sulfur dioxide SIP revision to EPA demonstrating modeled attainment of NAAQS for the Pine Bend area. On September 10, 1987, the MPCA again demonstrating modeled attainment of th e NAAQS for the Pine Bend area. On September 10, 1987, the MPCA again submitted a sulfur dioxide SIP re vision requesting redesignation of all AQCR 131 as attainment for sulfur dioxide, except for the areas covered by the St. Paul Park and Pine Bend sulfur dioxide SIP submittals . In response to EPA's comments in EPA’s June 1990 comments , the MPCA withdrew these revisions in August 1990. On March 13, 1989, the MPCA submitted a SIP revision to EPA entitled “Revisions to Offset and Ge neral Rules” to fulfill the requirements of Part D of the Clean Air Act.

17. 18. In its 1990 Air Pollution Control Cooperative Agreement No. A005236-90, EPA stated that it would withhold from the MPCA up to $150,000 in federal funds fo r the purpose of promulgating a Federal Implementation Plan (FIP) unless an approvable sulfur dioxide SIP for the Pine Bend area was submitted to EPA by the end of the third quarter of federal fiscal year 1990.

18. 19. On January 1, 2002, Koch Petr oleum Group LP changed its corporate name to Flint Hills Resources, LP. On November 1, 2010, the Pine Bend Refinery and other assets of the company became Flint Hills Resources Pine Bend, LLC. Flint Hills Resources, Pine Bend, LLC LP (FHR or Company ) is ), a corporation limited liability corporating organized and existing under the laws of the state of Delaware, is authorized to do business and is doing business in th e state of Minnesota at the junction of Highways 52 and 55 in Dakota County, Minnesota.

19. 20. The Company owns and operates a petroleum refi nery (Refinery), in the Pine Bend area of Rosemount, Dakota County, Minnesota. The refinery facility is now known as Flint Hills Resources LP

– Pine Bend Refinery

. 20. 21. The Refinery emits pollutants into the ambient air in sufficient quantities to require an air emission permit from the MPCA pursuant to Minn. Stat. § § 116.081 (2010) and Minn. Rules pts. 7001.0030 and 7007.0150, Subp. 1 (2009). 116.081 (2004) and Minn. Ru les pts. 7001.0030 and 7007.0150, Subp. 1 (2005).

The MPCA issued Koch Petroleum Group LP, now known as Flint Hills Resources LP, the Company an air emission permit in 1985, for the operation and expansion of the Refinery. That permit is Air Emission Facility Permit No. 10 6A-85-OT-1, the Refinery permit. FHR’s Refinery permit has been amended, and as amended is in effect today. The Refinery’s current permit is Air Emission Permit No. 03700011-007. In conjunction with th is Administrative Order, the MPCA is issuing Air Emission Permit No. 03700011-008.
On March 29, 2001, the MPCA issued a Part 70 permit for the FHR SAU (Air Emission Permit No.
03700006

- 001). The permit incorporated requirements c ontained in this Administrative Order regarding
FHR’s S ulfuric Acid Units (SAU). The issuance of that permit removed the need to include SO2 requirements for the FHR SAU in this Administrative Or der. The MPCA is adding that permit to its State Implementation Plan in 2006. This Administrative Order imposes requirements on the FHR Pine Bend refinery ( i.e., specified in parts I. through VIII VII . below) that will achieve and maintain compliance with the annual, 24-hour and three-hour NAAQS for sulfur dioxide

.

21. 22. The Refinery is was found to be a potential major contributor of sulfur dioxide emissions in the Pine Bend area, and based on computer modeling [I SC-ST (Version 90346) and ISC-LT (Version 90008)] it is was determined to be a culpable sulfur dioxide emission source in the Pine Bend area.

### Page 4 of 25 [Removed.]

22. 23. The Refinery produces unleaded gasoline, home heating oil, commercial and industrial heating oils, transportation fuels, jet fuels, petroleum coke, asphalt, sulfur and carbon dioxide. The Refinery has numerous different processing fa cilities which contain emission so urces that emit sulfur dioxide.

23. 24. On July 29, 1992, the MPCA submitted a sulfur dioxide state implementation plan to bring the Pine Bend area into attainment. The submittal included this the original version of this Order. On September 9, 1994, EPA approved the MPCA’s plan (59 FR 46553).

24. 25. On September 7, 1994, the MPCA submitted a re quest to EPA to redesignate the Pine Bend sulfur dioxide area from nonattainme nt to attainment. On May 31, 1995, the EPA published a Direct Final Rule (60 FR 28339) indicating that it intended to rede signate the Pine Bend area from nonattainment for sulfur dioxide to attainment. On July 31, 1995, this rule became effe ctive, and the Pine Bend area was redesignated as an attainment area for sulfur dioxide.

25. 26. On February 10, 2000, EPA promulgated the “Contr ol of Air Pollution from New Motor Vehicles: Tier 2 Motor Vehicle Emissions Standards and Gaso line Sulfur Control Requirements.” This rule, effective April 10, 2000, required most refiners (inc luding the Pine Bend refinery) to meet a corporate average standard for sulfur in gasoline in 2004 and to produce even lower sulfur gasoline by 2006.

26. 27. On December 22, 2000, the U.S. Department of Justice lodged a proposed Complaint and Consent Decree in United States vs . Koch Petroleum Group LP in U.S. District Court (Civil Action No. 00-2756-PAM-SRN). In this action the United States sought ci vil penalties and injunctive relief against Koch Petroleum Group, L.P., (“Koch”) pursuant to se ction 113(b) of the Clean Ai r Act (“CAA”), 42 U.S.C. 7413(b) (1983), amended by, 42 U.S.C. 7413(b) (Supp. 1991), the Resource Co nservation and Recovery Act, (“RCRA”), 42 U.S.C. 6901 et seq.; the Em ergency Planning and Community Right to Know Act (“EPCRA”), 42 U.S.C. 11004(a); and the Clean Water Act (“CWA”), 33 U. S.C. 1321(b)(3) and (j) for alleged violations at Koch’s 3 refineries: Pine Bend, Minne sota, and the East and West refineries in Corpus Christi, Texas. The State of Minnesota joined in the settlement as a signatory to the Consent Decree. On April 25, 2001, the Department of Justice filed the Consent Decree.
The settlement required FHR to pay civil penalties and implement innovative pollution control technologies to greatly reduce emissions of nitrogen oxides and sulfur dioxide. Implementing some of these control technologies reduces the dispersion from affected stacks, and requires required changes to this Administrative Order.

27. 28. On January 18, 2001, EPA promulgated the “Contro l of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements.” This rule, effective March 19, 2001, requires refiners (incl uding the Pine Bend refinery) to produce diesel fuels for use in highway vehicles wi th a lower sulfur content. These fuels must were required to be available by June 1, 2006.

28. 29. On March 11, 2003, the MPCA amended this Admini strative Order to allow Flint Hills Resources

, LP, now Flint Hills Resources Pine Bend, LLC, LP to modify its refinery. The MPCA found that the requirements of this Order, as amended, and as imposed on FHR will would maintain compliance with the NAAQS for sulfur dioxide in the Pine Bend area of AQCR 131, and will would allow the refinery to meet requirements established in the Consent Decree (Civil Action No. 00-2756-PAM-SRN) and to make lower sulfur gasoline (Tier 2 gasoline) and lower-sulfur diesel fuels.

29. 30. On October 19, 2005, EPA approved the MPCA/Flint Hills Adminis trative this Order as amended which allowed Flint Hills Resources , LP, now Flint Hills Resources Pine Bend, LLC, LP to modify its refinery in order to meet requirements established in th e Consent Decree (Civil Ac tion No. 00-2756-PAM-SRN)

### Page 5 of 25 not addressed in the previous amendment and to make ultra low sulfur diesel fuel.

30. 31. 31. The MPCA is now amending On July 19, 2007, EPA approved amendments to this Administrative Order to allow which allowed Flint Hills Resources

, LP , now Flint Hills Resources Pine Bend, LLC, to modify its refinery in order to install one new process heater at the #3 Crude Unit and to account for additional SO 2 

### emissions from refinery fuel gas combustion

. (72 FR 39568).

32. The MPCA is now amending this Ad ministrative Order to allow Flint Hills Resources Pine Bend, LLC to modify its refinery in order to install a new boiler, to decommission 34H-3 (Merox Thermal Oxidizer) and re-route process gases to the existi ng 31H-2 furnace, to improve the en ergy efficiency of 94H-1, and to remove fuel oil combustion from the modeling and calculations at certain combustion units. SO 2 

### emission rates for refinery fuel ga s combustion at certain emission units and heater steam-air decoking activities have been updated and stack exit temperatur e and velocity data at certain emission units have been updated with this amendment.

33. This iteration of the Administrative Order eliminates previo usly completed or obsolete provisions from earlier Administrative Orders and amendments is sued to FHR and included in Minnesota’s State Implementation Plan.

31. 34. This Order is needed to maintain th e attainment status for the area.

### Page 6 of 25 ORDER

NOW, THEREFORE, IT IS ORDERED, that Flint Hills Resources , LP Pine Bend, LLC shall comply with the requirements listed below in operating its Refinery to demonstrate and maintain compliance with the federal ambient air quality standards for sulfur dioxid e as set forth in 40 CFR §§ 50.4 and 50.5 ( 1991 2010 ), while making certain facility modifications.

I. COMPANY PROPERTY AND ACCESS RESTRICTIONS

This Part of the Order is the control plan for preventing general public access to Company-owned property in order to exclude the atmosphere above th e property from the definition of “ambient air” subject to the sulfur dioxide NAAQS. Exhibit 8 1 is the modeling technical support document, which is attached and incorporated by reference into this Order. The Company-owned property where the atmosphere above is excluded from modeled compliance with the sulfur dioxide NAAQS is shown in
Exhibit 8 1 , attached and incorporated by reference.

The Company shall meet the following requirements for the property shown in Exhibit 8 1 :

A. Access Control

On the effective date of this Order, the Comp any shall have enclosed the boundaries of the property with a continuous fence, excluding access po ints, and shall have insta lled gates at each access point. The Company shall thereafter keep the gates clos ed unless: 1) a guard or other FHR employee or

contractor is present controlling patrols and monitors access at a gate, or 2) authorized persons are entering or leaving the property through a gate.

B. Inspection, Maintenance, and Repair

The Company shall inspect the fencing and gates in stalled to ensure compliance with Part I.A at least annually.

The Company shall maintain and repair the fenci ng and gates to maintain continuous compliance with Part I.A. The Company shall complete all re pairs and maintenance to the fencing and gates as soon as possible, but no later than 30 days after th e date the Company observes the need for repair or maintenance, or after the MPCA notifies the Company of the need for repair or maintenance.

II. SULFUR DIOXIDE EMISSION CONTROL PLAN AND COMPLIANCE SCHEDULES
This Part of the Order is the Refinery’s sulfur dioxide emissions control plan, based upon air dispersion modeling that shows that the control pl an will attain compliance with NAAQS. Exhibit 8 1 is the modeling technical support document. The sulf ur dioxide modeling parameters for this equipment
are contained in Exhibit 8 1 . The emission limits and operational requirements of this Order apply to the
units identified in Exhibit 8 1

.
The remainder of this Part is divided into three two sections. The first section contains the required Refinery modifications and compliance schedules. The second section contains the Refinery's Refinery’s sulfur dioxide emission limitations, fuel restrictions, and operational requirements.
The third second section contains the Refinery’s complianc e demonstration requirements for the stack emissions, fuel restrictions and operational requirements. The Company shall operate equipment as

### Page 7 of 25 described in Part II. B A and shall demonstrate compliance as described in Part II. C B

.

A. [Removed.]
A. B. Emission Limitations, Fuel Restrictions and Operational Requirements

1. Emission Limitations

The Company shall not exceed the emission limitations set forth in Table 1 which is attached and incorporated by refere nce herein, for each emission point. The Company's total facility emissions also shall not ex ceed 3,770 tons per year of sulfur dioxide based on a 365-day rolling average, effective the effective date of this Order.

2. Refinery Fuel Oil Restrictions

(a) The Company shall not burn refinery fu el oil at any Refinery location.

(b) [Removed.]

(c) [Removed.]

(d) Retained PSD emission reductions. Table 4 provides a summary of a number of fuel oil combustion sources that no longer combust Refinery fuel oil. The sources were in cluded in the ambient air quality modeling (in Exhibit 8). Reductions achieved by el iminating them as fuel oil emissions sources may qualify for Prevention of Significant Deterioration (PSD; 40 CFR 52.21) netting purposes.

3. Fuel Gas Restrictions
a) Natural Gas limits.
(1) The Company shall only burn natural gas at the following sources:

i. The Oil y Se paration wer Wa s te r Treatment Plant (OSWTP) oxidizers (94H-1 /EU282 and 94H-3 ); /EU254) in conjunction with oxidation of gases from OSWTP equipment; and

ii. ii. Tank heaters (Emission Point Nos. 70 Units EU144 through 99 EU
173 and EUs 274 and 275 ).

(2) 2. The Company may burn natural gas at all combustion sources provided the Company measures the total volume of natural gas combusted in the refinery

. b) Refinery Fuel Gas limits. The Company may burn Refinery fuel gas at all existing locations except those source s listed in paragraph (a)(1). Existing sources are listed in
Exhibit 8. 1. New sources may combust Refinery fuel gas provided they comply with the emission limitation specified in Section I II V .A.
c) Supply source. The following provisions apply to refinery gas supplied as fuel to

### Page 8 of 25 combustion sources:
(1) Any fuel gas combustion unit other than those the units identified in (a

)(1 ), above, may burn Refinery fuel gas not taken from the Refinery fuel gas system provided that the Company insta ll, operate, and maintain a hydrogen
sulfide continuous monitoring system ( CMS ) and flow meter at the heater fuel gas
combustion unit in accordance with the requirements of Part II. C B

. 2 3 whenever burning Refinery fuel gas not taken directly from the Refinery Fuel gas system; or
(2) As an alternative to paragraph II.A .3(c)(1), combustion units may burn Refinery fuel gas not taken from the Refinery fuel gas system if sulfur dioxide emissions are monitored under an EPA-approved Alternative Monitoring Plan (AMP ). The Company currently monitors the #2 and #3 Hydrogen Plant
Pressure

- Swing Adsorption (PSA) off

- gas; railcar loading off

- gas; bottom loading
off

- g as; soil

- vapor extraction off

- gas; wastewater treatment process vapors; and reformer lock hopper and switch valv e vent gases in accordance with
EPA

- approved AMPs. (These AMPs were approved in a February 13, 2001 letter
from ), or are categorically exempt, or are inherently low in sulfur content in accordance with NSPS J (or Ja versio n) 40 CFR 60.104 and/or 60.105 (40 CFR 60.102a and/or 60.107a).

U.S. EPA.) The Company is applying for approval of an AMP to monitor the #4 Hydrogen Plant Pressure

- Swing Adsorption (PSA) off

- gas.

(3) The Company will install, operate

, and maintain a total reduced sulfur CMS on the fuel gas supplied from the 45 41 unit mix drum , or an SO2 (41V33/EU256), and a sulfur dioxide CMS on a representative heater firing 45
unit mix drum (45V38/EU265) fuel gas with the requirements of Part II. C.3, effective upon startup of the #3 crude oil processing expansion project but no later
th an May 30, 2007. B.2
d) (d) Hydrogen Sulfide Content. The Company shall not put fuel gas into the refinery fuel gas distribution system at an y time which contains greater than 162 parts per million (ppm) of hydrogen su lfide (0.10 grains of hydrog en sulfide per dry standard cubic foot of gas) as an average fo r any consecutive three-hour period.

4. Stationary Diesel Engine Fuel Restrictions

The Company shall only use diesel fuel wi th a sulfur content not in excess of 15 ppm ( 0. 05 percent 0015%) by weight at each of the Refinery’s stationary diesel engines. Limits on hours of operation for selected stationary diesels are shown in Table 5 2, which is attached and incorporated by reference herein

.
5. Steam-Air Decoking Requirements
a) Authorized Locations. The Company may decoke heater or boiler tubes using steam-air decoking only at the following Refinery heaters or boilers: 21H-1 /EU032

,

### Page 9 of 25 21H-2 /EU033 , 23H-1 /EU037 , and 23H-2 /EU038

.

(b) [Removed.] b) (c) Frequency. The Company may steam-air decoke heater 21H-1 /EU032

, 21H-2 /EU033 , 23H-1 /EU037, and 23H-2 /EU038 no more than 432 hours per year for
each heater.

c) Concurrent Operation. The Company may not decoke heaters 21H-1/EU032 and 21H-2/EU033 simultaneously, and may not decoke either of these heaters while decoking heaters 23H-1/EU037, and 23H-2/EU038.

(d) [Removed.]

(e) [Removed.]

(f) [Removed.]

6. Operation Requirements for Bypass Stacks and Other Special Stacks

(a) [Removed.]

(b) No. 3 Flare. This flare (Emission Point No. 107) may not receive gas es from Refinery operations unless

the gases are from pressure relief, are from upsets of Re finery process equipment, or are required for equipment

maintenance. The Company shall only use commercial natural gas or nitrogen for the purge system and

commerc ial natural gas at the pilot flame for the No. 3 flare. a) (c) Nos. 5, 6, 7 Flares. These flares (Emission Point Nos. 109, 110, and 106, respectively E. Flare, W. Flare, U. Flare and N. Flare. The four flares (84ME23/EU301, 84ME24/EU302, 84ME25/EU303, and 84ME3/EU304 ) may not receive gases from Refinery operations unless the gases are from pressure relief, are from upsets of Refinery process equipment, or are required for e quipment maintenance. The Company shall only use commercial natural gas or nitr ogen for the purge system and commercial natural gas at the pilot flame for the Nos. 5, 6, and 7 flares.

b) (d) SRU 3 and SRU 4 Facility. The Company shall not emit SRU 3 (EU111) tail gas
at Emission Point No. 113 SV094 unless tail gas from SRU 3 is bypassing the SCOT /TGTU
#1 Unit

. (EU261 and EU262). The Company may use Emission Point No. 2 SV093 during periods when tail gas from SRU 4 (EU112) is bypassing the SCOT Unit

. /TGTU #1. The Company shall not shut down the SCOT Unit except as necessary for maintenance or repair. The Company shall not bypass the SCOT Unit with tailgas from SRU 3 (EU111) or SRU 4 (EU112) except:

### Page 10 of 25 (1) during periods of startup, shutdown, or breakdown of SRU 3, SRU 4, the SCOT/TGTU #1 Unit, or SCOT incinerator (EU262); or

(2) to prevent a breakdown of the SCOT Unit.

Sulfur degassing gas may be combusted in the SRU 4 startup incinerator (Emission Point No. 113). /bypass incinerator and emitted from SV094 during instances of startup, shutdown, or malfunction.

c) (e) SRU 5 Facility. The Company may use Emission Point No. 3 SV042 during periods when tail gas from SRU 5 (EU045) is bypassing the Tail Gas Recovery Unit #2 (TGTU #2 ). , 26H-40/EU236 and 26H-41/EU237). The Company shall not shut down the TGTU #2 except as necessar y for maintenance or repair. The Company shall not bypass the TGTU #2 with tail gas from SRU 5 except: 1) during periods of startup, shutdown, or breakdown (as governed by 40 CFR 60 Subp. A) of SRU 5, the TGTU No. # 2 or TGTU #2
incinerator

, (26H-41/EU237), or 2) to prevent a breakdown of the TGTU No. # 2. Sulfur degassing gas may be combusted in the SRU 5 startup incinerator (Emission Point No. 3). and emitted from SV042.
d) (f) FCC Facility. The Company shall only vent emissions from the Emission Point
No. 9 SV021 stack as follows: 1) during startup or shutdown of the FCC; 2) for an emergency at the FCC reactor or catalyst regenerator which potentially or actually requires a bypass of the large WHCO Boiler or small WHCO Boiler; 3) for an emergency shutdown of the large WHCO Boiler (17H-2) or small WHCO Boiler (17H-4); and 4) required safety inspections of the large WH CO Boiler (17H-2) or small WHCO Boiler (17H-4).

B. C. Demonstration of Compliance With Emissi on Limitations, Fuel Restrictions and Equipment Operation Requirements

1. Demonstration of Compliance with Emission Limitations

The Company shall implement the compliance methods for monitoring requirements in
Section V IV . of this Order and recordkeeping requirements in Section VI V .B.2 of this Order to determine compliance with each emission limit ation in Table 1. The Company's emission monitoring programs shall also comply with Part V IV . of this Order.

1 [Removed.]
2. Demonstration of Compliance Wi th Fuel Gas Restrictions

The Company shall implement the compliance methods in Sections V IV .A.2 and

VI V .B.2.a of this Order to dete rmine compliance with the fuel gas restrictions of Part II. B A .3 of this Order. The Company’s fuel gas monitoring programs shall also comply with Part V IV of this
Order.

3. 4. Demonstration of Compliance wi th Diesel Fuel Restrictions

### Page 11 of 25 The Company shall prepare and retain written certifications of the sulfur content of each shipment of diesel

fuel oil received at each of the Refinery's stationary diesel engines. The Company shall prepare these written

certifications at the time of delive ry of the diesel fuel to each engine. The Certification shall be signed by the

Company official responsible for ensuring the proper oil is delivered to each engine. 5. Demonstration of Compliance with Equipment Operation Requirements The Company shall monitor the start and stop times for heater decoking

For each of the Refinery’s st ationary diesel engines, the company shall retain records demonstrating sulfur content is le ss than 15 ppm (0.0015%) by wei ght. Certificates of Analysis retained onsite demonstrating that all FHR diesel s meet the federal ULSD standard satisfies this requirement. The records may be maintained in either electronic or paper format, unless either form is expressly prohibited.

4. Demonstration of Compliance with Equipment Operation Requirements

The Company shall monitor the start and stop times for heater decoking and compute the hours of heater decoking operations to determine compliance with the heater decoking requirements of Part II. B A .5 of this Order.

6. [Removed.]

III. [Removed.]

III. IV. CHANGES NOT REQUIRING A MODIFICATION OF THIS ORDER
The Company is authorized to conduct begin construction of the activities listed below at the Refinery without a modification of this Order. The Company may conduct activities not listed below without a modification of this Order, if the activities do not em it sulfur dioxide, do not affect the modeling parameters
assumed in Exhibit 8 1 , and do not affect the continuous emission monitors (CEMs) or continuous monitoring systems (CMSs) used to demonstrate compliance with this Order. The Company shall, however, obtain an air emission permit prior to commencing these activities any new activity or facility modification if one is required by Minnesota statutes, Minnesota rules or federal statutes and regulations.
After obtaining the appropriate air emission permit (if required) but prior to a modification of this Order, the Company may begin construction of a new unit or modification to an existing unit. However, the Company shall not operate a new emission unit and shall not operat e a modified unit in a manner contrary to the modeling parameters in Exhibit 8 1 for that unit until the modification to this Order is obtained and approved by EPA

.
A. The Company may install and operate any new sulf ur dioxide process or control equipment with a maximum potential sulfur dioxide em issions rate that does not exceed 2.28 pounds per hour, except as expressly allowed elsewhere in this part (Part IV III .).

The Company may modify and operate any existing sulfur dioxide process or control equipment

### Page 12 of 25 to increase the sulfur dioxide emission rate up to 2.28 lb/hr over the modeled emission rate for that
source in Exhibit 8 1

.
B. The Company may physically and operationally mo dify process and control equipment if the
modifications do not increase the modeled sulfur dioxide emissions rate above the amount allowed in paragraph A of this section, decrease the modeled stack emissions exit velocity, or decrease the modeled
heat content of the stack exit emis sions, at the emission source where the modification occurs and all other potentially affected emission points assumed in the modeling presented in Exhibit 8 1

.
C. The Company may modify or replace and operate an existing sulfur dioxide emissions stack with a new stack if the height of the modified or replacem ent stack is not less than that of the stack assumed in the modeling presented in Exhibit 8 1 , and if the exit diameter of the modified or replacement stack is not greater than that of the stack assumed in the modeling presented in Exhibit 8 1

.
D. The Company may install and operate new structur es, or modify and operate existing structures
if the new or modified structures do not increase the effective structural dimensions assumed in the modeling presented in Exhibit 8 1

.
E. The Company may replace and operate replacemen t CEMs and CMSs covered by this Order or the Company may install and operate additional CE Ms and CMSs, so long as the new or replacement CEMs and CMSs are properly certified, comply with this Order, and are operated and tested as required by this Order.

F . [Removed.]

G . [Removed.] H.
F. The Company may add additional CEMs or CMSs as needed to provide redundancy, providing the Company notifies the MPCA as required in Part VI I .A.6. The Company may modify the fuel gas delivery system if the following conditions are met: 1) fuel gas flow and hydrogen sulfide content must be continuously measured for all heat ers, either by measuring the hydrogen sulfide level in the main Refinery fuel gas system and feeding the heater directly from the system, or by separately monitoring the fuel gas to or sulfur dioxide emissions from the heater; and 2) any new fuel gas monitors added to the system must be certified within 60 days of startup, must meet 40 CFR 60 Appendix F QA/QC requirements, must have a QA/QC plan prepared an d implemented within 60 days of startup, and operate in accordance with Mi nn. Rules pt. 7017.1090 within two quarters of startup.

G. I. The boundaries of the Company-owned property may be extended and existing fencing removed provided that the property excluded from the definition of “ambient air”, as shown in Exhibit
8 1 , continues to meet the requirements in Part I.A and Part I.B of this Order.

J. [Removed.]

K. [Removed.]

L. [Removed.]

### Page 13 of 25 M. As part of the Powerforme r Unit NOX Reduction Project, the Company may install and operate ultra low NOX

burners at Emission Point No. 10 (Powerformer unit heater 32H

- 5,

- 6,

- 7). The Company will c ontinue to operate

these sources on Refinery fuel gas or na tural gas according to the requirements of Part II.B.3 of this Order.

Authority to construct under this pa rt (IV.M) expires December 31, 2006.

N. [Removed]

O. [Removed] P. The Company may make modifications which reduce the fired duty of the heaters and boilers listed below. The duty reductions are to allow FHR to comply with the NOx monitoring an d control requirements established in the Consent Decree (Civil Action No. 00

- 2 756

- PAM

- SRN). The modified modeling paramenters of these sources are described in Exhibit 8: Boilers 71B

- 1, 71B

- 2, 71B

- 3, 71B

- 4, 71B

- 6 and 71B

- 9

Heaters 11H

- 1, 11H

- 2, 12H

- 4, 19H

- 1, 21H

- 1, 21H

- 2, 25H

- 1, 25H

- 3, 27H 102, 31H

- 4, 31H

- 7, 31H

- 9,

32H

- 5,6,7, 33H

- 31, 33H

- 4 (33 H

- 1 & 2), 38H 1A, 38H

- 1B, 38H

- 2.

Q. The Company may modify the stack and structures of the sulfuric acid rail car loading and rail car

depressurization sources to install equipment to reduce SO2 emissions from these sources.

R. The Compan y may make modifications to heaters 25H

- 1 and 25H

- 3, and install a new heater 25H

- 4. The

modified modeling paramenters of thes e units are described in Exhibit 8:

H. The Company may modify its refinery in order to install a new boiler as mo deled in Exhibit 1, to improve energy efficiency of 94H-1, to decommission 34H-3 and re-route process gases to the existing 31H-2 furnace. 34H-3 may continue to operat e if Merox offgas is not routed to 31H-2.

IV. V. GENERAL MONITORING REQUIREMENTS

A. Accurate Measurements Required

1. The Company shall install, certify, calibrate , operate and maintain each CEM and CMS as required by this Order, and shall conduct all non- continuous sampling and an alysis as required by
this Order to ensure accurate measurements of the parameters to be monitored.

2. The Company shall measure the stack sulfur di oxide concentration (ppm), stack velocity and stack temperature and compute the sulfur dioxide emission rate in lb/hr to determine compliance with the emission limitations listed in Table 1 for Emission Points No. 1 EU245 (Merox TO), No. EU055 (31H- 2 ), SV093 (SRU 3/4), 3 SV042 (SRU 5), and 8 (FCC). SV019 (FCCU). The Company shall measure the Refinery fuel gas hydrogen sulfide concentration and fuel gas flow rate to determine compliance with the emission limit in Section II.B.3.c of this Order for sulfur dioxide emissions from Refinery fuel gas combustion.

B. Continuous Monitoring Requirements

### Page 14 of 25 1. General
a) Compliance with Minnesota Rules and Federal Regulations. The Company shall meet the requirements of Minn. Rules pt. 7 017.1002 – 1020 and 40 CFR Part 60.13 with each CEM and CMS. If the requirements of Minn. Rules pt. 7017.1002 – 1020 and 40 CFR Part 60.13 differ, the more stringent regulation shall apply.
b) Continuous Operation of CMS and CEM Systems. The Company shall at all times properly operate and maintain each CMS and CEM system to provide continuous, accurate, real time monitoring data for the determination of compliance with the terms and requirements of this Order. In those situations where a CMS or CEM system becomes incapable of meeting the requirement of providing continuous, accurate, real time monitoring data, the Company shall expeditiously replace or repair the CMS or CEM system and take all other measures as nece ssary to meet the requ irement as soon as possible.

2. Monitor Certification
a) Sulfur Dioxide CEMs. The Company sha ll certify each sulfur dioxide CEM as required by 40 CFR Part 60, Appendix B, Performance Specification 2 ( 1991 2010 ).

b) Emission Rate CMSs. The Company sha ll certify each continuous monitoring system as required by 40 CFR Part 60, Appendix B, Performance Specification 6 ( 1991 2010 ), except that the Compan y need not meet calibration drift requirements for those flow monitors that are not designed for conducting calibration drift tests (pitot tube or venturi type).

c) Hydrogen Sulfide CMSs for Fuel Gas Monitoring. The Company shall certify each hydrogen sulfide CMS as required by 40 CFR Part 60, Appendix B (1991 (2010 ), by using the procedures specified in Performance Specification 7.
d) Total Reduced Sulfur CMSs for Fuel Gas Monitoring. The Company shall certify each total reduced sulfur CMS as required by 40 CFR Part 60, Appendix B ( 2005 2010 ), by using the procedures specified in Performance Specification 5.
e) All CEMs and CMS. All CEMs and CMS certification shall be conducted in compliance with Minn. R. 7017.1050 – 7017.1080 (2009).

3. Quality Assurance

The Company shall conduct a quality assuranc e and quality control (QA/QC) program as required by 40 CFR Part 60, Appendix F ( 1991 2010 ), to properly maintain and calibrate each CEM
and CMS. The Company shall develop and follow the master QA/QC Plans for each CEM and CMS required by this Order.

4. Monitoring System Uptime
a) Mass Sulfur Dioxide CEM Systems. Th e Company shall operate and maintain each mass sulfur dioxide CEM system in accordance with Minn. Rules 7017.1090 (1991)

### Page 15 of 25 so that compliance with each emission limitati on of Table 1 is determined from real time certified CEM monitoring.

(b) [Removed.]

b) (c) Refinery Fuel Gas Hydrogen Sulfide CMSs. Sulfur Monitoring.

The Company shall install, calibrate, maintain and operate a CMS for the hydrogen sulfide content of the refinery fuel gas at each of the inputs to the refinery fuel gas distribution loop. The CMS shall provide a continuous record of the hydrogen sulfide content in ppm.

45 Unit Mix Drum Refinery Fuel Gas Total Reduced Sulfur Content CMS. The Company shall install, calibrate , maintain and operate a CMS for the total reduced sulfur content of the refinery fuel gas at the 45 unit mix drum input to the refine ry fuel gas distribution loop. The CMS shall provide a con tinuous record of the total reduced sulfur content in ppm. Alternatively, the Company may install The Company shall maintain an SO 2 

### CMS at a representative heater which co mbusts 45 unit mix drum fuel gas. The CMS shall provide a continuous record of the sulfur dioxide content of the heater exhaust in ppm.

The Company shall maintain a CMS which me asures reduced sulfur in the 41 unit mix drum fuel gas stream. The CMS shall provide a continuous record of the reduced sulfur content of the fuel gas in ppm.

For heaters receiving refinery fuel gas that is neither inherently low in sulfur, nor categorically exempt in accordance with NSPS J (or Ja version) 40 CFR 60.104 and/or 60.105 (40 CFR 60.102a and/or 60.107a) from sources other than the main refinery fuel gas distribution loop , the Company shall continuously measure the hydrogen sulfide content of the refinery fuel gas or moni tor in accordance with an EPA-approved Alternative Monitoring Plan (AMP) at a repr esentative point in the line supplying the heater. For heaters receiving commercial grade fuels directly, (e.g., commercial grade natural gas and propane), contract guarantee s for hydrogen sulfide and heat content shall be utilized for compliance demonstration purposes.

b) c) (d) Each CEM or CMS must be operated a nd data recorded during all periods of emission unit operation including periods of emission unit start-up, shutdown, or malfunction. This requirement to operat e the monitor applies whether or not an emission limit applies during these periods.

CEM or CMS downtime is unacceptable exce pt for reasonable periods of monitor downtime due to the following causes:
(1) damage to the CEM or CMS due to acts of God such as lightning strikes, tornadoes, or floods that render the CMS inoperative;
(2) sudden and not reasonably preven table CEM or CMS breakdowns;

### Page 16 of 25 (3) scheduled maintenance based on equipment manufacturer’s recommended schedule which cannot be reasonably be conducted when the emission unit is not operating; or
(4) unavoidable CEM or CMS downtime to conduct required checks and
audits.

C. Non-Continuous Monitoring Requirements

1. The Company shall perform non-continuous mo nitoring as required by Section II.C.4 of
this Order.

2. The Company shall conduct performance stack tests to determine compliance with the
emission limitations and fuel restrictions of th is Order as required by the Commissioner pursuant to Minn. Rules pt. 7017.2001 – 2060. Stack test s can also be required by authorized EPA personnel. All performance tests shall be conducted in accordance with the requirements of Minn. Rules pt. 7017.2001 – 2060. The Company shall submit to the MP CA performance stack test plans, protocols and schedules at least 15 da ys prior to the pretest meeting required in Part
VI I .A.5 of this Order.

V. VI. RECORDKEEPING REQUIREMENTS

This Part VI V of the Order requires the Company to keep specified records so that EPA and the MPCA can evaluate the Company’s compliance with the Order. The first section requir es the Company to keep records on maintenance of property access controls . The second section requires the Company to keep records on the Refinery control plans and compliance schedules. The third section requires the Company to keep records in the form and with the accessibili ty needed for EPA and MPCA staff inspection.

A. Property Boundary Fencing and Gates

The Company shall maintain records of each inspection of the fencing and gates required by Part
I of this Order. In addition, the Company shall maintain reco rds of each maintenance activity and each repair activity required by Part I of this Order. The Company shall retain each inspection, maintenance and repair record for a period minimum of five years from the date the record was generated , despite any Company document retention policy to the contrary. These records shall be kept at the Refinery.

1. The inspection records shall include: the date of inspection; name of the person conducting the inspection; identification of each section of fence and each gate inspected; and identification of each location where repair or maintenance is required. The inspection report shall be certified as accurate in writing by the person conducting each inspection.

2. The maintenance and repair records shall include: the dates of the repairs or maintenance; a description of the repair and maintenance conducted; and the locations where they occurred. The maintenance and repair records sh all be certified as accurate by the person(s) overseeing each maintenance or repair action.

B. Recordkeeping Requirements

### Page 17 of 25 The Company shall maintain for the Refinery a copy of the records required pursuant to this Part
of the Order. Records shall be retained at the Refinery.

1. Permanent Records

The Company shall permanently maintain the following information together with all amendments, revisions, and modifications to this information.
a) Design, Construction and Operation Info rmation. The Company shall maintain information on the design, construction and op eration of each emission facility, emission source, fuel system, stack, structures pert inent to modeling for downwash in Exhibit 8 1

, and any other information required to conduct sulfur dioxide ambient air quality modeling of emissions from the Refinery. These records shall also include all information required to demonstrate that the equipment identified inExhibit 8 1 is installed as described in that exhibit. Where an activity has been undertaken pursuant
to Part IV III of this Order, the records shall include a description of each activity and all information required to demonstrate that the ac tivity complies with each applicable Part

IV III requirement. The records shall also identify and provide information on the design, construction and operation of each modification or new installation at the Refinery required by this Order.
b) Information on Sulfur Dioxide Emission Limits, Operational Requirements, and Modeling Parameters. The Company shall ma intain records at the Refinery. These
records include this Order and the Exhibits and Tables attached and incorporated by
reference in this Order.

2. Non-Permanent Records

The Company shall retain the information iden tified below for a minimum of five years following the date on which the information was obtained, despite any document retention policy to the contrary. This retention period shall be automatically extended upon the Commissioner's written request.
a) Monitoring, Testing, and Other Records. The Company shall maintain records of all measurements, including: all continuous monitoring system and continuous monitoring device measurements; all performance stack testing measurements and operating conditions during the performance stack tests; all continuous monitoring system performance evaluations; all continuous monitoring system or monitoring device calibration checks; all adjustments and ma intenance performed on these systems or devices; and all other information required or applicable to verify compliance with this Order. The Company shall prepare and maintain records of the one-hour averages for stack sulfur dioxide concentration (ppm); stack diameter, stack velocity and stack temperature; and the sulfur dioxide emission rate in lb/hr to determine compliance with
the emission limitations listed in Table 1 for Emission Points No. 1 ( SV078/EU245 (34H-3,
Merox TO ), No. ) or SV049/EU055 (31H- 2 ), SV093 (SRU 3/4), No. 3 SV042 (SRU 5), and No.
8 SV019 (FCC). The Company shall prepare and maintain records of the one-hour

### Page 18 of 25 averages of the refinery fuel gas hydrogen sulfide concentration and fuel gas flow rate to determine compliance with the emission limit in Section II. A B .3.c. Using the one-hour averages, FHR shall calculate the three-ho ur, twenty four-hour, and annual rolling averages corresponding to the emissi on limits referenced above.
b) Sulfur Dioxide Emissions, Fuel Records and Operations Records. The Company
shall maintain records to de monstrate compliance with the sulfur dioxide emissions limitations, and fuel use and quality restrictions and operational requirements of this Order. These records shall be designed, a nd the information shall be maintained in a form suitable for the Commissioner to quick ly determine compliance with each of the emission limitations, fuel restrictions, and operational requirements of this Order.
c) Startup, Shutdown, Bypass, and Breakdown Records. The Company shall
maintain records for each st artup, shutdown, bypass and breakdown for each piece of process equipment, control equipment, fuel supply system, emission stack, monitoring system and any other piece of equipment applicable to this Order. These records shall include the date and time of the start and stop of each event.
d) Excess Emissions, Exceedances of Fuel Usage and Quality Restrictions and Non-Compliance with Operational Requirements Records. The Company shall maintain
a record of each exceedance of an emission limitation, fuel use restriction and fuel quality requirement, and operational requirement at the Refinery for each emission point and fuel system subject to the emis sion limitations, fuel restrictions, and operational requirements of this Order. The record shall include for each period of exceedance a description of the exceedance, its cause, the magnitude of the exceedance, and the date and time of comme ncement and cessation of the exceedance.
e) Operations Records for CEMs and CMSs. The Company shall maintain an operations record for each CEM and CMS used to establish compliance with the terms and conditions of this Order. The operations record shall specify each date and time the CEM or CMS was inoperative and the nature of the CEM or CMS repairs or adjustments. The operations record shall include for each calendar quarter, the percent of time the CEM or CMS was operati ng and the percent of time the CEM or CMS was not operating. The Company shall also record for each calendar quarter, the amount of time the process associated with the CEM or CMS was operated.

(f) [Removed.]

C. Record Maintenance

The Company shall maintain all requi red documents, records, reports and plans in a format suitable for

determination of FHR’s compliance with this Order by EPA or MPCA staff. The Company shall maintain the info rmation in a form that is eas ily accessible for inspection by EPA or MPCA staff, and that is available fo r inspection at all reasonable times.

### Page 19 of 25 VI. VII. REPORTING REQUIREMENTS

A. Notifications

1. Notification of Process or Control Equipment Shutdown

The Company shall notify the Commissioner of shutdown of any control equipment or process equipment governed by this Order in accordance with Minn. Rules pt. 7019.1000, Subp
3.

2. Notification of Process or Control Equipment Breakdown

The Company shall notify the Commissioner of breakdowns of control equipment or process equipment governed by this Order in accordance with Minn. Rules 7019.1000, subp. 2.

3. Notification of CEM or CMS Breakdown

The Company shall notify the Commissioner of a breakdown or malfunction of any CEM or CMS used to demonstrate compliance with the terms and conditions of this Order in the next air quality quarterly report (NSPS excess emi ssions and 1989 Stipulation Agreement quarterly report ). ) following the breakdown or malfunction. The Company shall include the information
identified in Minn. Rules pt. 7017.1110, Subp. 2.B.

4. Notification of CEM or CMS Certificatio n Test and Quality Assurance Audit Test

The Company shall notify the Commissioner in writing at least 30 days prior to conducting any CEM or CMS certification test for any CEM or CMS require d to be certified pursuant to this Order. The Company may request a pretest meeting with the MPCA staff by making the request at least seven days prior to conducting any CEM or CMS certification test for the CEMs or CMS required pursuant to this Order. The Company shall notify the Commissioner in writing at least seven days prior to conducting calendar quarter quality assurance audit test procedures for those CEMs or CMSs required pursuant to this Order. Exceptions to these deadlines may be approved by MPCA on a case-by-case basis.

5. Notification of Performance Tests

The Company shall notify the Commissioner of its intent to conduct performance stack tests required pursuant to this Order not less th an 30 days prior to conducting each performance stack test as required by Minn. Rules pt. 7017.2030. The Company may request a pretest meeting with the MPCA staff by making the request at least seven days prior to conducting a performance stack test. The test date is subj ect to the Commissioner's approval and shall be approved by the Commissioner at least 15 days before the planned test date. Exceptions to these deadlines may be approved by MPCA on a case-by-case basis.

6. Notification of Changes to be Made Pursuant to Part IV of the Order

The Company shall notify the Commissioner in writing at least 15 days prior to unde rtaking an activity

allowed by Parts IV.A, D, H, and I of this Order. The written notification sha ll describe the change the Company is

proposing to make, and shall include submittal of a perm it application for the change, if required pursuant to

### Page 20 of 25 Minnesota statutes, Minnesota rules or federal statutes or regulations.

The Company shall notify the Commissioner of changes ma de pursuant to Part IV.E in the first quarterly

report required by Part VII.C following the ch ange. Each such written notification shall include all information

necessary to demonstrate the activity fully complies with Part IV of this Order.

7.

6. Notification of Regularly Scheduled Turnaround on any TGTU Unit

The Company shall notify the Commissioner in writing 30 days prior to performing regularly scheduled turnaround (scheduled unit sh utdown for maintenance) on any TGTU Unit.

B. [Removed.]

B. C. Quarterly Reports

The Company shall submit to the Commissioner each calendar quarter, a report that contains the following information: sulfur dioxide emissions for th e Emission Points of Table 1, refinery fuel gas hydrogen sulfide content (in a form that allows dire ct comparison with the requirements of the Order) on both hard copy and computer readable media; 45 mix drum fuel gas total reduced sulfur content, or equivalent stack gas SO2 concentration (in a form that allows direct comparison with the requirements of the Order); a record of data used in calculating, and ca lculations of the sulfur dioxide emissions, refinery fuel gas hydrogen sulfide content; a record of each steam-air decoke event; a record of each startup, shutdown, bypass and breakdown of proc ess and control equipment; a summary record of excess sulfur dioxide emissions, exceedances of fu el usage and quality requirements and noncompliance with operational requirements, or the Company sh all state if no exceedances or noncompliance conditions occurred in the quarter; a summary of CEM and CMS operation records including the amount of time the process equipment was operated; and, an y quality assurance test results that do not meet the requirements of 40 CFR Part 60, Appendix F ( 1991 2010 ). Quarterly reports shall be postmarked within 30 days following the end of each cale ndar quarter. Upon written notification by the Commissioner, the Company may cease including sulfur dioxide emissions, fuel usage and quality, records of data used in calculating, and calculatio ns of sulfur dioxide emissions, and fuel usage and quality in the quarterly reports. Ho wever, the Company shall submit this data within 30 days of receipt of a written request by the Commissioner.

C. D. Performance Stack Tests Reports

The Company shall submit to the Commissioner, reports of each performance stack test conducted pursuant to this order. Performance stack test reports shall be postmarked no later than 45 days following completion of the performance stack test

. , unless otherwise approved by the MPCA.

D. E. CEM Certification Test Results

The Company shall submit to the Commissioner, the results of each CEM certification test required pursuant to this Order. Certification test reports shall be postmarked no later than 45 days
after the CEM certification test date

. , unless otherwise approved by the MPCA.

### Page 21 of 25 E. F. CEM and CMS Audit Test Results

The Company shall submit to the Commissioner, th e results of quarterly cylinder gas audits and annual relative accuracy tests. Submitted results of quarterly audits and annual relative accuracy tests shall be included in the quarterly report fo r the quarter in which they were conducted.

VII. VIII. GENERAL CONDITIONS

A. Before the Company begins operation of new or modified equipment not specifically allowed by
Part IV of this Order and which results in additional sulfur dioxide emissions, or changes to sulfur dioxide emission patterns assumed in the modeling presented in Exhibit 8 1 , the Company shall obtain a
modification of this Order.

B. This Order is meant to delineate Minnesota’s stra tegy for attainment in the Pine Bend area from the present into the future, and is not an admission that the restrictions in 40 CFR § 52.24 (a) and (b) (1991) previously applied or current ly apply to the Pine Bend area.

C. [Removed.]

C. D. This Order does not relieve FHR of the obligation in undertaking all actions required by this Order, to comply with all applic able local, State and Federal laws and regulations, including, but not limited to, federal new source performance standards, and laws and regulations related to occupational safety and health. In the event there is a conflict in applic able federal or state of local laws or regulations, the more stringent of the conflicting provisions shall apply.

D. E. The MPCA, EPA or their authorized representative s shall have authority to enter all property of the Company in Rosemount, Minnesota, at all reason able times for the purposes of inspecting records, operating logs and contracts related to the Comp any's compliance with this Order; reviewing the progress of the Company in implementing this Orde r; conducting such tests as the EPA or MPCA deem necessary to determine compliance with this Order; and verifying the data submitted to the EPA and MPCA by the Company. The Company shall honor all reasonable requests for such access by the EPA or MPCA staff, conditioned only upon presentation of proper credentials. This section does not limit any other right of entry and inspection held by the EP A and MPCA pursuant to applicable federal or state laws, rules or permits.

E. F. This Order shall be binding upon the Company and its respective officers, employees, successors and assigns. FHR shall provide a copy of this Order to any successor in interest prior to transfer of that interest, and shall simultaneously inform the MPCA that this notice has been given. Should the Company sell or otherwise convey or assign any of its right, title or interest in the Refinery, such conveyance shall not release the Company from any obligation imposed by this Order, unless the party to whom the right, title or interest has been tr ansferred or assigned agrees in writing to fulfill the obligations of this Order and the MPCA finds that the new owner has the ability to fulfill the obligations of this Order, and approves such transfer or assignment.

G. [Removed.]

### Page 22 of 25 H. This Order mandates actions and establishes limits ne cessary to attain, maintain and verify compliance

with the federal sulfur dioxide NAAQS by FHR. To the extent that any federal or state statute, rule, permit,

order, stipulation agreement, consent decree or schedul e of compliance now in force or subsequently issued

imposes limits and requires actions additional to or more stringent than those required in this Order, FHR

shall also comply with the requirements
F. of the federal or state statute, rule, permit, order, stipulation agreement, consent decree or schedule of compliance.

G. I. This Order is effective upon the date that it is signed by the Chair and Commissioner of the
MPCA.

H. J. Once EPA approves this Order as part of the Minnesota SIP, this Order supersedes the requirements of the all previous SIP approved in 1981, at 46 Federal Register 20997 (April 8, 1981), revisions, as they apply to FHR

.

I T IS SO ORDERED.Page23of25TABLE 1 – REFINERY EMISSION LIMITATIONSFOR EACH APPLICABLE FEDERAL SULFURDIOXIDE AMBIENT AIR QUALITY STANDARDEMISSIONPOINTSTACK VENTEMISSION UNITFACILITY ID #FACILITY ORSOURCEDESCRIPTION3-HOUR AAQS(1)24-HOUR AAQS(2)ANNUAL AAQS(3)DATES EMISSION POINTLIMITATIONS BECOMEEFFECTIVE1SV078EU24534H-3Merox TO Facility65.4230poundsSO2per hour286.41007.4tonsSO2per 12 monthsEffective the effective date ofthis Order.2SV093EU111 andEU11245UNIT2-145UNIT3-1SRU 3 and SRU 4Facility (SCOT)(5)149.0 poundsSO2per hour86.5 pounds SO2per hour324.3 tons SO2per12 monthsEffective the effective date ofthis Order.3SV042EU04526UNIT-1SRU 5 Facility(TGTU #2)(5)170.8 poundsSO2per hour93.6 pounds SO2per hour409.8 tons SO2per12 monthsEffective the effective date ofthis Order.8SV019EU22817UNIT1FCC Facility182.61500pounds SO2perhour8003504tons SO2per 12 monthsEffective the effective date ofthis Order.SV049EU05531H-2#2 HDS FractionationHeater66.4 pounds SO2per hour290.8 tons SO2per12 monthsEffective the effective date ofthis Order.348SV125SV146EU282EU25494H-194H-3OSWTP Facility(oxidizers(6))50.71 poundsSO2per hour(4)50.71 poundsSO2per hour(4)39.4 tons SO2per12 months(9.0 lb/hr)Effective the effective date ofthis Order.(1)These emission limitations are based on three consecutive one-hour periods (3-hour rolling averages).To demonstrate compliance with the limitation, emissions shall becalculated in such manner, except for EU282.(See (4).)(2) These emission limitations are based on 24 consecutive one-hour periods (24-hour rolling averages).To demonstrate compliance with the limitation, emissions shall becalculated in such manner, except forEmission Point No. 348.EU282.(See (4).)(2)These emission limitations are based on 24 consecutive one-hour periods (24-hour rolling averages). To demonstrate compliance with the limitation, emissions shall becalculated in such manner, except for Emission Point No. 348.(See (4).)(3)These emission limitations are based on a 12-month rolling average and to demonstrate compliancewith the limitation, emissionsshall be calculated in such manner,except for Emission PointNo. 348EU282. (See (4).)(4)This emission limitation is a one hour maximum value to be metfor any one consecutive hour period. Compliance with these emission limits has previously beendemonstrated by stack tests.(5)Limits include emissions fromtheincineration ofsulfurdioxide emission reduction for netting purposes under thePrevention of Significant Deterioration (PSD) regulation (40CFR 52.21), FHR is including the annualized actual emissions (from June 1998 to May 2000) in the modelingdegassing gas.(6) This emission limit applies to the WWTP during operation of either the 94 H-1 oxidizer or the 94 H-3 oxidizer. 94 H-1 is the primary WWTP oxidizer; 94 H-3 is the backup.Except when switching WWTP gases from oneoxidizer to the other, onlyone oxidizer may combust gases from OSWTP equipment at atime. The other oxidizer may be firedconcurrently with natural gas for standby purposes.Page24of25TABLE52– LIMITS ON DIESEL-POWERED UNITSEMISSIONPOINT NO.EMISSION UNITFACILITYOR SOURCEID #DESCRIPTIONANNUAL LIMITCOMMENTS331EU13193 P 160Diesel-powered fire waterpump1000 hoursDedicated fuel storage tank;meter records hours ofoperation332EU198M93 P 400Diesel-powered fire waterpump1000 hoursDedicated fuel storage tank;meter records hours ofoperation333EU199M93 P 570Diesel-powered fire waterpump1000 hoursDedicated fuel storage tank;meter records hours ofoperation407EU042EE 1657MDiesel-powered generator1000 hoursDedicated fuel storage tank;meter records hours ofoperation408EU007EE 1852MEE1692MDiesel-powered generator1000 hoursDedicated fuel storage tank;meter records hours ofoperation435EU036M23 ME 26Diesel-powered generator1000 hoursDedicated fuel storage tank;meter records hours ofoperation453EU100EE 1309MDiesel-powered generator1000 hoursDedicated fuel storage tank;meter records hours ofoperation465EU024EE 1718MDiesel-powered generator1000 hoursDedicated fuel storage tank;meter records hours ofoperation505EU130M81 P 159Diesel-powered cooling waterpumpNo limit1000hoursDedicated fuel storage tank;meter records hours ofoperation506EU132M81 P 357Diesel-powered cooling waterpumpNo limit1000 hoursDedicated fuel storage tank;meter records hours ofoperation507EU128M81 P 444Diesel-powered cooling waterpumpNo limit1000 hoursDedicated fuel storage tank;meter records hours ofoperationPage25of25508EU129M81 P 89Diesel-powered cooling waterpumpNo limit1000 hoursDedicated fuel storage tank;meter records hours ofoperation510Wood River dieselDiesel-powered pump2000 hoursDedicated fuel storage tank;meter records hours ofoperation511EU12771C-11Diesel-powered plant aircompressor2500 hoursDedicated fuel storage tank;meter records hours ofoperation513EU133M81 P 598New 81 P 450Diesel-powered cooling waterpumpNo limit1000 hoursDedicated fuel storage tank;meter records hours ofoperations

### Attachment 3: Table of Original Order Emission Points to Current Order Emission Units

AO Emission Point # Description SIP Model Description Facility ID # MPCA EU# MPCA SV# Notes

No. 1 Merox TO Facility 34H-3 Me rox Off-Gas 34H-3 EU245 SV078 Will be shutdown upon completion of the projectto re-route the Merox offgas to 31H-2.

No. 2 SRU3 and SRU4 Facility to TGTU #1 (SCOT) SRU3, SRU4, Tail Gas Treating Unit #1 (SCOT) 45UNIT2-1 45UNIT2-1 TGTU #1 EU111 EU112 EU261 EU262 EU260 SV093 This is the 45H61 incinerator stack. EU111 is SRU3, EU112 is SRU4. Both vent to the TGTU#1 (which is the SCOT Unit) that includes the tail gas heater (EU 261) and the 45H-8 tail gas incinerator (EU 262) through the 45H61 bypass incinerator (EU 260) and vented to the SV 093 stack.

No. 3 SRU 5 Facility (TGTU#2) SRU 5 startup incinerator SRU 5, Tail Gas Treating Unit #2 (SCOT) 26UNIT-1 TGTU #2 EU045 EU236 EU237 EU235 SV042 This is the 26H21 bypass incinerator stack. EU045 is SRU5 that vents to TGTU#2 (a SCOT Unit) which includes Tail Gas Heater (EU236) and 26H41 Tail gas incinerator (EU237) through the 26H21 bypass incinerator (EU235) and vented to the SV042 stack.
No. 8 FCC Facility Fluid Catalytic Cracking Unit 17UNIT-1 EU228 SV019

No. 9 FCC Facility N/A 17UNIT-1 EU228 SV021 FCCU emergency bypass stack around the CO boilers and ESP. Rarely used, not included in modeling.

No. 34 #2 HDS Fractionation Heater Process Heater 31H-2 31H-2 EU055 SV049

No. 70 – 99 Tank Heaters N/A 86H_ EU144

– EU173, EU274, EU275 Gas fired, not included in modeling.

No. 106 No. 107 No. 109 No. 110 No. 3, 5, 6, 7 Flares N/A E. Flare – 84ME23 W. Flare – 84ME24 U. Flare – 84ME25 N. Flare – 84ME3 EU301 EU302 EU303 EU304 SV105 SV106 SV107 SV104 Flares used only during upsets and startup/ shutdown activities. Not included in the AO SO 2 modeling demonstration.AO Emission Point # Description SIP Model Description Facility ID # MPCA EU# MPCA SV# Notes

No. 113 SRU 3 SRU 4 SRU 4 startup incinerator EU111 SV094 This is the 46H-6 incinerator stack (SV094). In the event of a TGTU#1 (SCOT) upset (and start up / shut down), SRU3 gases are sent to 45H6, and SRU4 gases are sent to 45H61 for incineration.

No. 348 OSWTP Oxidizers Oil Separation & Waste Treatment Plant Thermal Oxidizer 94H-1 94H-3 EU282 EU 254

41 unit mix drum 41V33 EU256 45 unit mix drum 45V38 EU265
Decoking Process Heater 21H-1 Decoking 21H-1 EU032

Decoking Process Heater 21H-2 Decoking 21H-2 EU033

Decoking Process Heater 23H-1 Decoking 23H-1 EU037

Decoking Process Heater 23H-2 Decoking 23H-2 EU038

Large WHCO Boiler 17H-2 CE004 SV019 The waste heat CO boilers recover high temperature gas from the FCCU. Stacks for these boilers were removed in 1999. Gases from the FCCU are routed to these boilers and emitted from the main FCCU stack SV 019. Small WHCO Boiler 17H-4 CE005 SV019

Wood River Diesel Diesel Engine

– Wood River (K510 DSL) N/A Not currently in operation but included in modeling. No. 331 Diesel Engine 93P-160 93 P 160 EU131 SV101 No. 332 Diesel Engine 93P-400 M93 P 400 EU198 SV126 No. 333 Diesel Engine 93P-570 M93 P 570 EU199 SV127 No. 407 Diesel Engine EE-1657 EE 1657 M EU042 SV039 No. 408 Diesel Engine EE-1852 EE 1852M EU007 SV006 Replaced EE1692M. No. 435 Diesel Engine 23ME26 M23ME26 EU036 SV034 No. 453 Diesel Engine EE-1309 EE 1309M EU100 SV085 No. 465 Diesel Engine EE-1718 EE 1718M EU024 SV023 No. 505 Diesel Engine 81P-159 M81 P159 EU130 SV100 No. 506 Diesel Engine81P-357 M81 P 357 EU132 SV102 No. 507 Diesel Engine 81P-444 M81 P444 EU128 SV098 No. 508 Diesel Engine81P-89 M81 P 89 EU129 SV099
No. 511 Diesel Engine 71C-11 71C-11 EU127 SV096 SV097 No. 513 Diesel Engine 81P598 M81 P 598 EU133 SV171 Replaced M 81 P450.

### Attachment 4: Changes to Modeled Emission RatesDescription Model ID 1-hr 3-hr 24-hr Annual Comments [1]34H-3 K1_MEROX -28.98 -28.98 -28.98 -28.98 Source to be removed.45H-61 K2_#3SRU 0.05 0.01 0.01 0.01 Reflects sour water tank off-gas emissions.26H-21 K3_#5SRU 0.05000Slight increase in 1-hr rate to align with bypass rate.71B-7 K7____BH -6.88 -5.47 -5.47 -5.47 Source removed with corresponding historical fuel oil contribution.FCC ESP K8___FCC -165.98 -165.98 -165.98 -63.29 Emissions lowered to be more consistent with current performance.32H-5,6,7 K10_32FG 0 0.39 0.39 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.19H-1 K11_19FO -0.33 0.10 0.10 -0.33 Historical fuel oil contribution is removed. Increased 3/24-hr FG S.12H-4 K13_12FG 0 0.37 0.37 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.33H-31 K14_33FO -4.19 -3.05 -3.05 -3.39 Historical fuel oil contribution is removed. Increased 3/24-hr FG S.16H-1 K15_16FG 0 0.58 0.58 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.11H-3 K16_11FO -1.84 -1.84 -1.84 -1.84 Source removed with corresponding historical fuel oil contribution.11H-5 K18_11FO -0.83 -0.83 -0.83 -0.83 Source removed with corresponding historical fuel oil contribution.11H-1 K19_11FO -1.15 -0.76 -0.76 -1.15 Historical fuel oil contribution is removed. Increased 3/24-hr FG S.37H-1,2,6 K20_37FG 0 0 0 -0.17 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.33H-32 K21_33FG 0 0 0 -0.25 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.11H-2 K23_11FG 0 0.14 0.14 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.21H-1S FO fired K27_21FO -0.50 -0.34 -0.34 -0.50 Historical fuel oil contribution is removed. Increased 3/24-hr FG S.21H-1N FO fired K28_21FO -0.50 -0.34 -0.34 -0.50 Historical fuel oil contribution is removed. Increased 3/24-hr FG S.21H-2S FO fired K29_21FO -0.48 -0.32 -0.32 -0.48 Historical fuel oil contribution is removed. Increased 3/24-hr FG S.21H-2N FO fired K30_21FO -0.48 -0.32 -0.32 -0.48 Historical fuel oil contribution is removed. Increased 3/24-hr FG S.33H-4 (33H-1&2) K31_33FG 0 0 0 -0.35 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.23H-1 FO fired K32_23FO -0.02 0.38 0.38 0.06 Historical fuel oil contribution is removed. Increased 3/24-hr FG S.31H-1 K33_31FG 0 0.06 0.06 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.31H-2 K34_31FG 8.24 8.30 8.30 8.30 Introduction of Merox offgas for combustion due to 34H-3 shutdown.31H-5 K36_31FG 0 0.02 0.02 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.31H-10 K37_31FG 0 0.07 0.07 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.32H-9 K41_32FG 0 0.02 0.02 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.37H-3,4,5 K42_37FG 0 0 0 -0.76 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.38H-1A K46_38FG 0 0 0 -0.07 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.38H-1B K47_38FG 0 0 0 -0.07 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.Table 1. Modeled SO2 Emissions Change (grams/second) From SIP Order Amendment #8 to Proposed Amendment #9.Emissions Averaging Period (g/s)Description Model ID 1-hr 3-hr 24-hr Annual Comments [1]Table 1. Modeled SO2 Emissions Change (grams/second) From SIP Order Amendment #8 to Proposed Amendment #9.Emissions Averaging Period (g/s)38H-2 K48_38FG 0 0 0 -0.12 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.25H-1 K50_25FG 0 0 0 -0.49 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.25H-3 K51_25FG 0 0 0 -0.44 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.25H-4 K52_25FG 0 0 0 -0.32 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.23H-2 K53_23FG 0.54 0.84 0.84 0.60 Changed FG drum assignment which changes heat content (Btu/scf) basis.27H-1 K54_27FG 0 0 0 -1.56 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.27H-101 K55_27FG 0 0 0 -0.16 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.27H-102 K56_27FG 0 0 0 -0.18 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.31H-4 K57_31FG 0 0.17 0.17 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.31H-7 K58_31FG 0 0.17 0.17 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.31H-8 K59_31FG 0 0.09 0.09 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.31H-9 K60_31FG 0 0.12 0.12 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.28H-1 K61_28FG 0 0 0 -0.07 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.71B-8 K62_BLR8 0 0 0 -0.36 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.27H-501 K63_27FG 0 0 0 -0.92 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.11H-6 K67_11FG 0 0.96 0.96 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.71B-9 K68_BLR9 0 0.58 0.58 0 Increased 3-hr and 24-hr fuel gas sulfur content to be same as 1-hr.Boiler 10 BLR10 1.25 1.25 1.25 0.68 Future new source.30 H-401 #4 H2 Plant K70_4H2 0 0 0 -1.75 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.29 H-1 Comb Fd& Dist K71HCFD 0 0 0 -0.43 Reduced annual fuel gas sulfur content from 500 ppm to 400 ppm.71B-6 Boiler K1006_BH 0.06 0.33 0.33 0.03 Updated duty from 108 to 120 MMBtu/hr to reflect HHV.45H-6 K113__FG 0.09 0.09 0.09 0.07 Reduced fuel gas sulfur content; added SRU 3 tail gas analyzer exhaust.93P-160 K331_DSL -0.01 -0.01 -0.01 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.93P-400 K332_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.93P-570 K333_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.94H-1 K348_OXD0 0 0 0 Nochange.EE-1657 K407_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.EE-1692 K408_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.23ME26 K435_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.EE-1309 K453_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.Description Model ID 1-hr 3-hr 24-hr Annual Comments [1]Table 1. Modeled SO2 Emissions Change (grams/second) From SIP Order Amendment #8 to Proposed Amendment #9.Emissions Averaging Period (g/s)EE-1718 K465_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.81P-159 K505_DSL -0.02 -0.02 -0.02 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.81P-357 K506_DSL -0.02 -0.02 -0.02 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.81P-444 K507_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.81P-89 K508_DSL -0.01 -0.01 -0.01 -0.00 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.Wood River K510_DSL -0.06 -0.06 -0.06 -0.01 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.71C-11 K511_DSL -0.03 -0.03 -0.03 -0.01 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.Portable diesel cap PORT_DSL -0.74 -0.74 -0.74 -0.03 Removed from model.New K509DSL81P-450K513_DSL -0.06 -0.06 -0.06 -0.01 Fuel sulfur content reduced from 500 to 15 ppm; increased to 8760 hours.21H-1 dec K600_DEC -2.81 -2.81 -2.81 -0.1421H-2 dec K601_DEC -2.81 -2.81 -2.81 -0.1423H-1 dec K602_DEC -3.40 -3.40 -3.40 -0.1723H-2 dec K603_DEC0000Included in 23H-1 dec source.Acid Ld & Depress K700ACDL0 0 0 0 Nochange.Net Emissions Change in grams/second: -215.6 -207.0 -207.0 -106.5Net Emissions Change in lb/hr: -1,710 -1,641 -1,641Net Emissions Change in tons/year: -3,699Net Change in Refinery Emissions (%): -61% -60% -63% -52%[1] Refer to "Justification for Air Quality Modeling Inputs (revised May 2011)" for details on the emission rates used in the model.Refinery-wide modeled SO2 emissions are reduced by over half betweenAmendments #8 and #9 for all averaging periods.Emissions estimates are refined based on engineering study. For SIP9 1-hr,3-hr, and 24-hr averaging periods, each decoking activity is modeledindividually instead of concurrently as in SIP8.1-hour* 1300 52.1 56 1059 85 4032 314 664 553-hour 1300 36.5 34 690 56 1766 139 483 4024-hour 365 10.4 17 256 73 437 123 155 47Annual** 60 6.1 4 32 64 18 39 31 58[1] The NAAQS and MAAQS are the same unless otherwise specified. The more restrictive standard is listed.* SO21-hour is MAAQS.** 60 μg/m3is SO2annual MAAQS. NAAQS is 80 μg/m3.[2] Short-term averaging periods use H2H concentrations. Percent of Standard includes modeled concentration plus background.[3] In SIP8 all three decoking activities were modeled concurrently for all averaging periods. SIP9 modeled results are the maximum concentrationsout of the three individual decoking scenarios (21H-1, 21H-2, and 23H-1,2) for the 1-hr, 3-hr, and 24-hr averaging periods. The modeledconcentration and percent of standard values for the annual averaging period in this table reflects all three decoking activities occuring during theyear.Table 2. SIP Order Amendment #8 and Amendment #9 Modeling Results ComparisonPercentofStandard(%)SIP8 AERMODModeledConcentration(μg/m3)[2]PercentofStandard(%)Model Run PollutantSIP9 AERMODModeledConcentration(μg/m3)[2,3]AveragingPeriodwith Informational Modeling Run of Amendment #8 Inputs in New AERMOD Model.Approved SIP8ISC ModeledConcentration(μg/m3)[2]PercentofStandard(%)SO2NAAQS/MAAQSSIP8Background(μg/m3)Standard(μg/m3)[1]SIP9Background(μg/m3)

### Attachment 5: TSD for Related Permitting ActionTechnical Support Document, Permit Action Number: 03700011-008 Page 1 of 27 Date: 8/15/2011 

### TECHNICAL SUPPORT DOCUMENT For AIR EMISSION PERMIT NO. 03700011-008

This technical support document (TSD ) is intended for all parties interested in the permit and to meet the requirements that have been set forth by the federal and state regulations (40 CFR § 70.7(a)(5) and Minn. R. 7007.0850, subp. 1). The purpose of this document is to provide the legal and factual justification for each applicable requirement or polic y decision considered in the determination to issue the permit.

1. General Information
1.1 Applicant and Stationary Source Location:
Table 1. Applicant and Source Address
Applicant/Address Stationary Source/Address (SIC Code: 2911)
Flint Hills Resources Pine Bend LLC
PO Box 64596 St. Paul, MN 55164-0596 Flint Hills Resources Pine Bend Refinery 13775 Clark Road Rosemount, Dakota County, MN 55068
Contacts: Ms. Sue Anderson 651-438-1214 Ms. Kari Lorch 651-437-0806 Ms. Dzung Farell 651-480-3865 Mr. Michael Krautkremer 651-480-3914

1.2 Facility Description
Flint Hills Resources Pine Bend, LLC (hereafter refe rred to as “FHR” or “Permittee”) owns and operates the Pine Bend Refinery (“refinery” or “facility”) in the city of Rosemount, Dako ta County, Minnesota. The refinery primarily processes heavy, sour crude oil fr om Western Canada, although it may also process oil from other parts of the world. Pipelines currently de liver all of the crude oil to the refinery, where FHR processes it to produce a wide variety of products. These products include gasoline, diesel fuel, heating oil, jet fuel, petroleum coke, asphalt, elemental su lfur, and carbon dioxide. FHR distributes these products to customers in Minnesota and the surro unding Upper Midwest states via pipelines, trucks, barges and rail cars. 1.3 Description of the Activities Allowed by this Permit Action
1. A major amendment to revise the No. 5 Sulfur Re covery Unit (SRU) (also known as the 26 Unit; vents through SV 042) Nitrogen Oxides (NO X 

### ) Best Available Control Tec hnology (BACT) limit due to identification of additional NO X 

### emissions from No. 5 SRU not accounted for in the original December 1991 BACT analysis for the Clean Fuels Permit (No. 106A-92-I/O-32) (DQ #989).
2. A major amendment to incorporate into th e permit the outstanding Hydrogen Sulfide (H 2 

### S) Minnesota Ambient Air Quality Standard (MAAQS) compliance requirements from the December 10, 2007, Schedule of Compliance (DQ #2499) and November 11, 2010, schedule extension approval.
3. A major amendment to shutdown the Merox Incine rator (EU245) and reroute the off gas to the 31H-2 heater (EU055) (DQ #3153). This amendment also changes the SO 2 

### SIP limits on the FCCU (EU228) to less than 182.6 lb/hr and less than 800 tpy (see Table 10).Technical Support Document, Permit Action Number: 03700011-008 Page 2 of 27 Date: 8/15/2011 

### 4. A minor amendment to install two temporary portab le coke crushers (EU325 & EU326) to be operated no more than 6 months per year (DQ #3352).
5. An administrative amendment to change the facilit y name to Flint Hills Resources Pine Bend Refinery and the owner name to Flint Hills Resources Pine Bend LLC (DQ #3287).
6. Reopenings to reflect new permit limits for #3 Coker Heater (EU035) of less than 115.3 mmBtu/hr (DQ #3354), Steam Boiler #8 (EU204) of less than 139.4 mmBtu/hr (DQ #3355, #3366) and Naphtha Hydrotreater Reactor Charge Heater (EU 053) of less than 34.0 mmBtu/hr (DQ #3374).

1.4 Facility Emissions: Table 2. Title I Emissions Increase Summary (SV042 NO X 

### BACT)

Pollutant Emissions Increase from the Modification (tpy) Limited Emissions Increase from the Modification (tpy) PSD/112(g) Significant Thresholds for major sources (tpy) NSR/ 112(g) Review Required? (Yes/No)

PM 25

PM 10 

### 15

PM 2.5 

### 10

NO X 

### 42.5 * 

### 42.5 * 

### 40 Yes

SO 2 

### 40

CO 100 Ozone (VOC) 40

Lead 0.6

* Emissions increase is due to revision of the SV 042 NO X 

### BACT limit established by the 1992 Clean

Fuels New Source Review permit. The value shown in this column is the revised total SV 042 NO X 

### emissions for the 1992 Clean Fuels permit.Technical Support Document, Permit Action Number: 03700011-008 Page 3 of 27 Date: 8/15/2011 

### Table 3. Title I Emissions Increase Summary (Merox)

Pollutant Projected Actual Emissions * 

### (tpy) Baseline Actual Emissions **


### (tpy) Baseline Period (years) Excludable Emissions *** 

### (tpy) Emissions Increase

(tpy) NSR Significant Thresholds for major

sources

(tpy) NSR Review Required? (Yes/No)

PM 25

PM 10 

### 15

PM 2.5 

### 10

NO x 

### 40

SO 2 

### 39.3 33.5 07-08 None 5.8 40 No

CO 100

Ozone (VOC) 40

Lead 0.6

CO 2 

### e **** 

### 75,000 * Projected Actual Emissions as defined in 40 CFR § 52.21(b)(41). ** Baseline Actual Emissions as defined in 40 CFR § 52.21(b)(48). *** Emissions that can be excluded as detailed in 40 CFR § 52.21(b)(41(ii)(c). **** Carbon dioxide equivalents as defined in Minn. R. 7007.0100. 

### Merox Incinerator (EU245) Emissions Reductions

Following completion of the shutdown requirements for EU245 the PTE will be zero for all pollutants. The reductions in potential emissions are listed below.

CO -9.52 tpy PM -0.86 tpy
CO 2 

### -7904.4 tpy PM 10 

### -0.86 tpy
NO X 

### -31.74 tpy VOC -6.18 tpy
SO 2 

### -1007 tpy
The 31H-2 (EU055) heater is rated at 23 mmBtu/hr. Us ing the fuel gas combustion emission factor from EPA AP-42 of 127.55 lb/mmBtu, this yields 12,849 tpy CO 2 

### e. The heater rating before and after the project will remain 23 mmBtu/hr; therefore the CO 2 

### e increase from the project is 0 tpy; however, one of the three burners of 31H-2 will be redesigned to accommodate the Merox o ffgas stream formerly combusted at 34H-2/3 (EU245). 31H-2 burning fuel gas on ly is considered worst case since fuel gas has a higher carbon content than the Merox offgas. 31H-2 combusting a mixture of fuel gas and Merox offgas will result in a decrease of approximately 490 tpy in potential CO 2 

### e emissions.Technical Support Document, Permit Action Number: 03700011-008 Page 4 of 27 Date: 8/15/2011 

### Table 4. Non-Title I Emissions Increase Summary (Portable Coke Crushers)

Pollutant After Change (lb/hr) Before Change (lb/hr) Net Change (lb/hr) Insignificant Modification Thresholds

(lb/hr <) Minor and Moderate Amendment Thresholds (lb/hr < or > ) Type of Amendment

(Minor or Moderate)

PM 10 

### 1.5 0 1.5 0.855 3.42 Minor
NO x 

### 2.28 9.13
SO 2 

### 2.28 9.13
CO 5.70 22.80
VOC 2.28 9.13 Lead 0.025 0.11
Table 5. Facility Classification
Classification Major/Affected Source Synthetic Minor Minor PSD PM, PM 10 

### , PM 2.5 

### , SO 2 

### , NO X 

### , CO, VOC,
GHG N/A Pb

Part 70 Permit Program PM 10 

### , PM 2.5 

### , SO 2 

### , NO X 

### , CO, VOC, GHG N/A N/A Part 63 NESHAP Single and Total HAPs 2. Regulatory and/or Statutory Basis

New Source Review
The facility is an existing major source under federal New Source Review regulations. This permit action does not change this status.
This permit revises the 1992 Clean Fuels No. 5 Sulfur Recovery Unit (No. 5 SRU) SV 042 Prevention of Significant Deterioration (PSD) permit including the NO X 

### BACT limit due to the identification of additional
NO X 

### emissions from No. 5 SRU. The Permittee submitted a revised permit application including BACT and ambient air analyses to address the additional emi ssions. An Endangered Species Act (ESA) consultation was required as well. The consultation determined th at the proposed permit modification for the No. 5 SRU at the facility would have no effects on any th reatened or endangered species present in Dakota County and no further consultation was requi red for the project. See attachment No. 4.

Part 70 Permit Program
The facility is a major source under the Part 70 permit program. This permit action does not change this

status.
New Source Performance Standards (NSPS)
40 CFR pt. 60, subp. J: NSPS for Petroleum Refine ries for which Construction, Reconstruction, or Modification commenced after June 11, 1973, and on or before May 14, 2007
40 CFR pt. 60, subp. Ja: NSPS for Petroleum Refine ries for which Construction, Reconstruction, or Modification Commenced After May 14, 2007Technical Support Document, Permit Action Number: 03700011-008 Page 5 of 27 Date: 8/15/2011 

### The 31H-2 heater (EU055) is already subject to the fuel gas limit of 230 mg H 2 

### S/dscm from NSPS subp. J. EU055 is triggering the fuel gas combustion device (F GCD) standards in NSPS subp. Ja, which has more restrictive limits than in subp. J and Minn. R. 7011.1410, subp. 2. Compliance demonstration with Subpart Ja will be deemed compliance with this less stringent standard.
National Emission Standards for Hazardous Air Pollutants (NESHAP)
40 CFR pt. 63, subp. CC: National Emission Standa rds for Hazardous Air Pollutants from Petroleum Refineries
40 CFR pt. 63, subp. UUU: National Emission Sta ndards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units
Compliance Assurance Monitoring (CAM)
Since no control equipment is utilized to meet applic able emission limits for this modification, CAM does not apply.

Environmental Review & AERA
The changes authorized by this permit amendmen t do not trigger requirements for environmental
review or an AERA.

Minnesota State Rules
Portions of the facility are subject to:

• Minn. R. 7011.1400 - 7011.1435 Standards of Perfor mance for Petroleum Refineries (EU055, Fuel Gas Combustion Device)

• Minn. R. 7011.0700 - 7011.0735 Standards of Perfor mance for Industrial Process Equipment (EU325 and EU326, Portable Coke Crushers)

• Minn. R. 7009.0080 State Ambient Air Quality Standards Table 6. Regulatory Overview of Units Affected by the Modification/Permit Amendment
Subject

Item* Applicable Regulations Comments:

Total Facility Minn. Stat. Sec. 116.07, subds. 4a and 9; Minn. R. 7007.0100, subps. 7M; Minn. R. 7007.0800, subps. 1, 2, and 4; Minn. R. 7009.0010-
7009.0080 Total Facility H2S ambient air co mpliance demonstration. This is a state-only requirement not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act.

EU055 40 CFR pt. 60, subp. Ja The 31H-2 heater (EU055) triggers the fuel gas combustion device (FGCD) standards of NSPS subp, Ja. Since the capacity of the unit is below 40 mmBtu/hr, it is not subject to the NO X 

### standard at 40 CFR Section 60.102a(g)(2). Increase in SO 2 

### emissions are due to the Merox offgas higher sulfur content than fuel gas. GP055 40 CFR pt. 60, subp. J (constructed before 6/11/73); Minn. R. 7011.1405 Remove EU055 from GP055. Effective upon completion of this project.Technical Support Document, Permit Action Number: 03700011-008 Page 6 of 27 Date: 8/15/2011 

### Subject

Item* Applicable Regulations Comments:

GP057 40 CFR pt. 60, subp. Ja (constructed after 6/11/73);
Minn. R. 7011.1410 Add EU055 to GP057. Effective upon completion of this project.

GP106 40 CFR pt. 63, subp. CC;
Minn. R. 7011.7280 Add EU055 as an associated item to GP106 and remove Control Equipment (CE013) from GP106 upon completion of this project. GP118 Minn. R. 7011.0715, subps. 1 (A) and (B); Minn. R. 7007.0800, subp. 2 Post-1969 Industrial Process Equipment Rule (IPER) for particulate emissions and opacity. Limited to 6 months of operation per year. EU055/
EU245 Title I Condition: SIP for SO2 NAAQS, 40 CFR pt. 50; MN State Implementation Plan (SIP)
40 CFR pt. 60, subp. Ja
Minn. R. 7011.1410, subp. 3 Requirements for emissions control of the Merox miscellaneous process vent (MPV) are being moved from
EU245 to EU055.

SV042 Title I Condition: 40 CFR Section 52.21 BACT limit;
Minn. R. 7007.3000 Revision of No. 5 SRU SV042 NO X 

### BACT limit. Limits revised from 0.122 lb/mmBtu and 2.44 lb/hr to 9.7 lb/hr and 50 ppm by volume dry on a 24 hour rolling average (corrected to 7%
O 2 

### ) to account for additional NO X 

### emissions from No. 5 SRU

process. *Location of the requirement in the permit (e.g., EU, SV, GP, etc.).


### The language 'These are state-only requirements not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clea n Air Act' refers to permit requirements that are mandated by state law rather than by the federal Clea n Air Act. The language is to clarify the distinction between permit conditions that are required by federal law and those that are required by state law. State law requirements are not enforceable by the EPA or by citizens under the federal Clean Air Act, but are fully enforceable by the MPCA and citizens under provisions of state law.

3. Technical Information

3.1 Individual Project Descriptions

3.1.1 Major Amendment for Merox Incinerator Shutdo wn and Off-gas Reroute to 31H-2 Furnace (DQ# 3153)

This major permit amendment application for the Merox Incinerator Shutdown is comprised of the following:

• Install piping and related equipment (possibly including a knock out pot, control systems, coalescer, flame arrestors, heater stack ports, Continuous Emissions Monitoring System (CEMS), and flare and sewer connections) to utilize an existing process heater (31H-2; EU055) as a control device for a process vent stream curre ntly regulated under 40 CFR pt. 63, subp. CC from a vessel (42V-41) in the Merox treating unit;Technical Support Document, Permit Action Number: 03700011-008 Page 7 of 27 Date: 8/15/2011 

### • Incorporate 42V-12A (Backup Caustic Regenerato r) offgas into the new vent gas equipment routed to 31H-2 during 42V-41 (skim pot mo unted above caustic settler 42V-16, EU109) maintenance outages. (42V-12A is in identical se rvice to 42V-41 as part of a full backup system that is used when the primary sy stem is down for maintenance.);

• Shutdown the Merox incinerator (34H-2/3);

• Upgrade power supply for CEMS building that cu rrently houses the 34H-2/3 (EU245) CEMS unit so that it can be used for the 31H-2 (EU055) CEMS;

• Update and obtain approval for State Implementati on Plan (SIP) modeling of both affected fuel gas combustion devices 31H-2 (EU055) and 34H-2 /3 (EU245) (to be submitted under separate cover);

• Clarify plans to submit an Alternative Monitoring Plan (AMP) for meeting NSPS Subpart Ja for the 31H-2 (EU055) heater due to the additional Merox stream; and

• Two other scope items to be completed outside of turnaround, but included here for completeness. They are not considered as scop e items needing permit support, since they are not required nor dependent on the primary project, but will result in emissions decreases:

o Recycle a sour water tank (31V-77) vent stream formerly controlled by the Merox Incinerator (34H-2/3) back into the satura tes gas plant (14 unit) for further sulfur recovery; however, it is included here for completeness; and,

o Implement a change from naphtha to #1 fu el oil as a wash for the Merox unit to minimize emissions generated from this material used to remove the disulfide oils out of the process (regenerated caustic). General Schedule for Project Completion
Construction of the Merox project is projected to begin in 2012. Construc tion should not take more than six months and the 31-2 unit (No. 2 Desulfurizer Unit) will need to be shut down to complete the final tie-ins to the unit. Physical changes to route the sour water tank vent into the 14 unit gas plant and connecting the #1 fuel oil line to the existing naphtha wash line do not require a permit amendment and will result in reduced SO 2 

### emissions from the existing Merox Incinerator. These two projects are expected to be completed prior to September 2011. Summary of Regulatory Applicability and Compliance
The following paragraphs detail applicability of a nd compliance with federal and state air quality regulations for the project.

2001 Consent Decree
The Merox Incinerator (34H-2/3) is not subject to the Consent Decree as noted in the Annual Update to the Heater and Boiler Plan submitted to EPA on Ma rch 27, 2003. The #2 distillate desulfurizer reboiler (31H-2) is also not subject to any upgrades or monitoring requirements under the Consent Decree, based on the size of the heater. The heat input ca pacity of this heater is 23 MMBtu/hr which is well below the 40 MMBtu/hr threshold that would have triggered requirements for installation of ultra low
NO X 

### burners (ULNB) under Consent Decree requirements.

New Source Performance Standards for Re fineries - 40 CFR pt. 60, subp. J/Ja
Fuel Gas Combustion Device (FGCD) as Affected Facility Under J/JaTechnical Support Document, Permit Action Number: 03700011-008 Page 8 of 27 Date: 8/15/2011 

### The Merox Incinerator (34H-2/3) is not current ly subject to 40 CFR pt. 60, subp. J for SO 2 

### emissions because it is considered a grandf athered unit (since it has not been modified or reconstructed since promulgation of the rule). The 31H-2 (EU055) heater is currently subject to 40 CFR pt. 60, subp. J as a fuel gas combustion device for SO 2 

### emissions. On June 24, 2008, the EPA promulgated the final rule related to NSPS Subpart Ja. In order for 31H-2 to be subject to Subpart Ja, the physical changes occurring would need to meet the definition of modification or reconstruction as described in the Subpart Ja rulemaking below: Existing affected facilities that commence modification or reconstruction after May 14, 2007, are subject to the final standards in 40 CFR part 60, subpart Ja. A modification is any physical or operational change to an existing affected facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies (see 40 CFR Section 60.14). Changes to an existing affected facility that do not result in an increase in the emission rate, as well as certain changes that have been exempted under the General Provisions (see 40 CFR Section 60.14(e)), are not considered modifications...
...Petroleum refinery process units are subject to the final standards in 40 CFR part 60, subp. Ja if they meet the criteria under the reconstruction provisions, regardless of changes in emission rate. Reconstruction means the replacement of components of an existing facility such that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility; and (2) it is technologically and economically feasible to meet the applicable standards (40 CFR Section 60.15).

The project includes utilization of a fuel gas stream that the heater was designed to accommodate (i.e., fuel gas stream) prior to rule promulgation, which is not a modification by itself as noted in 40 CFR Section 60.14(e)(4). However, the project does incl ude physical modifications to the heater that will result in increased SO 2 

### emissions from use of this alternate fuel gas stream. Therefore, as a result of this project, the 31H-2 heater as a fuel gas combustion de vice is considered to undergo modification as a fuel gas combustion device and will be subject to NSPS Subpart Ja instead of Subpart J.
Currently the H 2 

### S limit in the fuel gas under 40 CFR Section 60.104(a)(1) is met for 31H-2 (EU055) by monitoring the 41 unit fuel gas mix drum supplying this heater, which is compliant with 40 CFR Section 60.105(a)(4). With the proposed changes under this pr oject, 31H-2 will now utilize the Merox vent offgas as an additional fuel gas source; however, this fuel ga s will be routed directly to the heater firebox rather than being monitored through the mix drum and theref ore will not be monitored via the analyzer at the refinery fuel gas mix drum analyzers.
Although an SO 2 

### CEMS will be installed (MR069) on this heater to ensure compliance with the SIP requirements, it will not be used to demonstrate compliance with NSPS Subpart Ja given the non-H 2 

### S sulfur compounds present in the fuel gas that would not be representative of fuel gas H 2 

### S. Given the inherently low H 2 

### S expected in the fuel gas from the Merox offgas stream, FHR requested and received approval for an exemption from H 2 

### S monitoring of the Merox Treating Un it offgas stream. Approval of the exemption request to EPA Region V was mailed to Ms. Kari Lorch (FHR) dated November 15, 2010, and a copy of this letter is atta ched to this TSD (attachment 3).
Process Heater as Affected Facility Under Ja
Subpart Ja also regulates NO X 

### emissions from “process heaters”, wh ich are separate affected facilities from “fuel gas combustion devices” above. Emissions of NO X 

### from this heater 31H-2 (EU055) areTechnical Support Document, Permit Action Number: 03700011-008 Page 9 of 27 Date: 8/15/2011 

### attributable to the burner design and corresponding heat input capacity. The heat input capacity of 31H2 is not increasing as a function of this projec t. The physical changes being made to the unit will accommodate the Merox stream but otherwise are not designed to increase the firing rate or NO X 

### emissions rate.
Notwithstanding that the 31H-2 is not undergoing an NSPS modification as a process heater, please note the following with respect to Subpart Ja:

• This rule is currently stayed for the process heater NO X 

### provisions. The EPA is currently considering changes to the rule during this st ay of effectiveness (73 FR 78552; December 22, 2008).

• As the rule is currently written at 40 CFR Section 60.102a(g)(2), only process heaters with a rated capacity greater than 40 MMBtu/hr are subject to a NO X 

### emissions standard. The 31H-2 has a rated capacity less than 40 MMBtu/hr (23 MMBtu/hr).

Flare as Affected Under Ja
The project will result in new connections to the flar e header as noted previously. On June 24, 2008, new standards under NSPS subp. Ja were promulgated. On December 22, 2008, these provisions were stayed from February 24, 2009, until further notice. Since the original NSPS subp. Ja rule was proposed with subsequent changes to the applicability date, FHR al ready has completed a number of flare connections that would result in a flare modification under 40 CF R Section 60.100a(c)(1), if those provisions remain unchanged and the stay was to be removed; therefore, these specific flare connect ions will not, in and of themselves, trigger applicability. FHR will meet appropriate requirements (including permitting) for the flare affected facility under this subpart when the stay is removed and the regulation is clarified. Until then, no additional conditions are being proposed as part of this project for the flare affected facility under Subpart Ja. New Fugitive Equipment - 40 CFR pt. 60, subp. GGGa
A number of components in VOC service are being a dded that will be subject to 40 CFR Section 60.590a (Subp. GGGa) and by reference some sections of 40 CF R Section 60.480a (Subp. VVa) to which all units in the refinery are currently subject. These componen ts will be managed under existing fugitive source groups within the 31 and 42 process units. No addi tional permit conditions are required for these components.

National Emission Standard for Benzene Wast e Operations - 40 CFR pt. 61, subp. FF
The Pine Bend refinery is already an affected facility subject to 40 CFR pt. 61, subp. FF. Any flare connections or tie-ins needed for the proj ect will comply with subp. FF requirements.
Although the Title V permit currently contains requi rements for the Merox incinerator (34H-2/3) being regulated as a control device under subp. FF, no re gulated streams are currently being routed to 34H2/3. The primary stream that was formerly routed to this incinerator was a vent from a spent caustic tank (TK312) that has since been removed and replaced with a different vessel (11V-6) that is controlled by the flare gas recovery system rather than 34H-2/3.
Additionally, FHR confirmed that the 42V-41 vent gas from the Merox unit is no t subject to the control requirements under subp. FF since the streams in 42V-41 are upstream of the subp. FF waste stream point of generation for spent caustic. To provide fu rther detail, 42V-41 is a skim pot off 42V-16 caustic settler. The caustic settler (42V-16, EU109) contains regenerated caustic and disulfide oil. The point ofTechnical Support Document, Permit Action Number: 03700011-008 Page 10 of 27 Date: 8/15/2011 

### generation for the spent caustic waste stream, which is subject to subp. FF contro ls is located at a vessel downstream of the caustic settler at the outlet of 11V-6. Additionally, the point of generation for the disulfide oil stream is located at the exit of the outl et of 42V-16 caustic settler. This stream is piped to the slop oil system which is managed under subp. FF; therefore, no additional requirements under subp. FF will apply to 31H-2.

National Emissions Standards for Hazardous Air Pollutants (NESHAPs) for Petroleum Refineries 40 CFR pt. 63, subp. CC (MACT CC)
The vent stream from 42V-41 (skim pot mounted abov e caustic settler 42V-16) is considered a Group 1 miscellaneous process vent pursuant to 40 CFR Sect ion 63.640(a) (Subp. CC). This vent stream will be combusted in 31H-2 during normal operation, or alte rnatively vented to the flare system during times when 31H-2 is down (e.g. maintena nce turnarounds). Either of these options comply with 40 CFR Section 63.643(a)(1) and (2) which require combustion in a flare meeting the requirements of 40 CFR Section 63.11(b) (MACT subp. A) or venting to a control devi ce which reduces organic HAP emissions by 98 wt % (or to 20 ppmv, dry basis, corrected to 3% O 2 

### ). The vent stream will be introduced in the flame zone of 31H-2 process heater as required by 63.643(b) and is therefore exempt from firebox temperature monitoring per 40 CFR Section 63.644(a)(4).
With this change, the Startup/Shutdown/Malfunc tion Plan (SSMP) required under 40 CFR Section 63.6(e)(3) will be updated to reflect the alternative control device (31H-2 rather than 34H-2/3) being used to meet the destruction efficiency requirements referenced in 40 CFR Section 63.643. Prevention of Significant Deterioration
The project will result in significantly reduced overall emissions from shutting down the Merox Incinerator (34H-2/3). Increased SO 2 

### emissions from the 31H-2 heater will occur due to utilization of a higher sulfur fuel gas stream (vent gas from 42V-41). Ot her than routing this vent stream into a separate burner within the firebox of 31H-2 and adding the SO 2 

### CEMS (MR069), no physical changes are being made to the heater. A new monitor (31H2 Flow Mete r for Exhaust Gases, MR184) for stack vent (SV049) flow associated with EU055 will be added. This moni tor is anticipated to be an upgraded design (pitot tube).
FHR evaluated the “replacement unit” provisions of 40 CFR Section 52.21 (as referenced by Minn. R. 7007.3000) to determine if the baseline actual emission s of the Merox incinerator are to be applied to the 31H-2 in its new service as the combustion de vice for the Merox process offgas. A “replacement unit” is defined in 40 CFR Section 52.21(b)(33) as:

“...an emissions unit for which all the criteria liste d in paragraphs (b)(33)(i ) through (iv) of this section are met. No creditable emission reductions shall be generated from shutting down the existing emissions unit that is replaced. (i) The emissions unit is a reconstructed unit within the meaning of 40 CFR Section 60.15(b)(1) of this chapter, or the emissions unit completely takes the place of an existing
emissions unit. (ii) The emissions unit is identical to or functionally equivalent to the replaced emissions
unit. (iii) The replacement does not alter the basic design parameters (as discussed in paragraph (cc)(2) of this section) of the process unit.Technical Support Document, Permit Action Number: 03700011-008 Page 11 of 27 Date: 8/15/2011 

### (iv) The replaced emissions unit is permanently removed from the major stationary source, otherwise permanently disabled, or perman ently barred from operation by a permit that is enforceable as a practical matter. If the replaced emissions unit is brought back into operation, it shall constitute a new emissions unit.”
The 31H-2 emissions unit meets the definition of a replacement unit as well as the regulatory intent of the replacement unit provisions, as follows:
(i) The 31H-2 completely takes the place of the Merox incinerator. (ii) The 31H-2 serves in the same function for th e Merox offgas as the Merox incinerator; that is, as a combustion device to oxid ize compounds in this stream. (iii) The “process unit” as defined in 40 CFR Section 52.21(b)(55) is not altered, whether it be the 42 Unit Merox fuel gas treatment process or the 31 Unit distillate desulfurizer process. As noted above, the heat input capacity of the 31H-2 is not increasing and no other changes are being made to the 31 or 42 Units, so the basic desi gn parameters (i.e., process throughput) are not altered. (iv) The Merox incinerator will be permanently disabl ed as an inherent element of this project to meet the objectives of this effort: reduce ener gy needs and costs, reduce emissions, mitigate future reliability and maintenance costs. FHR has proposed on Form CD-01 a federally enforceable condition to shut down the Merox incinerator.
In accordance with 40 CFR Section 52.21(b)(7)(ii), a replacement unit is an existing emissions unit, meaning that the baseline actual emissions from both the Merox incinerator and the refinery fuel gas combustion at 31H-2 are compared to projected actu al emissions from 31H-2 firing both gases. Because
SO 2 

### emissions from the Merox system/incinerator have been measured by a CEMS for the last several years and because the Merox process is not othe rwise altered except in ways that may reduce combustion SO 2 

### emissions, projected actual emissions at 31H-2 can be readily estimated. The 31H-2 is a more energy efficient unit than the Merox incinerato r. Combustion emissions from the 31H-2 other than
SO 2 

### will inherently not result in an increase from this project. Therefore, only SO 2 

### emissions are quantified in the PSD applicability analysis.

Other than PM 10 

### as noted below, no changes to emission factors are expected for other pollutants, including PM 2.5 

### , as a result of this additional fuel gas be ing routed to 31H-2. Pr eviously, FHR confirmed that increased SO 2 

### generation can lead to increased PM 10 

### , however, as noted in June 29, 2007, correspondence to the MPCA following testing of PM 10 

### from multiple sources of fuel gas, FHR continues to use the most recent AP-42 emission factor for PM 10 

### (that includes condensable PM 10 

### ) for fuel gas firing. In this case, FHR has some reason to believe that, as a result of increased non-H 2 

### S sulfur compounds in this fuel gas, PM 10 

### emissions may be higher. For purposes of emissions inventory, FHR conducted performance testing of EU245 in the fa ll of 2010 to determine a more representative emission factor for PM 10 

### pursuant to Minn. R. 7019.3100 which will be used for the Merox incinerator until this permit is issued and the project is implemen ted (at which time this data will be used for 31H-2 emission reporting). Because this is a replacement unit as set forth above, this emission factor does not affect the permit determination since the quantity of PM 10 

### emissions resulting from the fuel gas sulfur in the Merox offgas being routed to 31H-2 is the sa me as what formerly was routed to the Merox incinerator. Based on these results, FHR is not at th is point proposing to perform any additional testing for PM 10 

### on this heater.Technical Support Document, Permit Action Number: 03700011-008 Page 12 of 27 Date: 8/15/2011 

### The 2007 and 2008 calendar years are used to calculate baseline actual emissions. Year 2009 was not used due to the poor economic and market condi tions and the corresponding lower processing rates. The two-year baseline actual SO 2 

### emissions for 31H-2 are 0.4 tpy and from the 34H-2/3 are 33.1 tpy, taken from the refinery’s annual emission inventory reports. The total baseline actual emissions for the 31H-2 replacement unit are 33.5 tpy SO 2 

### . Projected actual annual emissions for the 31H-2 unit are 39.3 tpy for SO 2 

### , estimated as follows:

• SO 2 

### from refinery fuel gas burned from the mix dr um is conservatively based on the current Title V PTE of 2.3 tpy as calculated in the May 2010 Title V reissuance application.

• SO 2 

### from Merox offgas combustion is based on the highest 180-day rolling average emissions from the last four years of operation. This value (37.0 tpy annualized for the 180-day period ending March 26, 2008) is about five percent higher than the highest 365-day rolling average.
The project’s emissions increase is 5.8 tpy SO 2 

### , calculated as the difference in projected actual emissions of 39.3 tpy and baseline actual emissions of 33.5 tpy. The project is not a major modification based on an increase in emissions that remain below significant emission rates (SERs), as defined in 40 CFR Section 52.21(b)(2); therefore, this permit pr oject is not subject to PSD review.
The reasonable possibility recordkeeping requirements of PSD will be met if applicable. As the rule is currently written, the project’s emissions increase is less than 50 percent of the significant emissions increase threshold (20 tpy for SO 2 

### ); therefore, tracking of future actual emissions is not mandated.
FHR has proposed shutdown on the Merox incinerato r within 180 days after the date that the 31H-2 resumes normal operation combusting the full Merox offgas stream. The 180-day timeline is consistent with the PSD replacement unit provision at 40 CF R Section 52.21(b)(3)(viii). Consistent with the definition of replacement unit, the baseline actual emissions from the Merox incinerator will not be creditable emission reductions for future PSD netting purposes. Minnesota Standards for Stationary Sources
Minnesota Rules 7011.1400 through 7011.1435 contains sta ndards of performance for existing and new affected facilities at petroleum refineries. The 31H-2 heater is currently considered a new affected facility and is subject to the emission limits in Minn. R. 7011.1410, subp. 2, which emulate those in 40 CFR pt. 60, subp, J. FHR will conti nue to comply with these existing standards of performance using the same methods of demonstration as refere nced above for 40 CFR pt. 60, subp. Ja. National Ambient Air Quality Standards (NAAQS) and Administrative Order (AO) under the State Implementation Plan (SIP) for Sulfur Dioxide
Rerouting the Merox stream to the 31H-2 (EU055) tri ggers a change to the AO. FHR submitted proposed alterations to the current AO and SO 2 

### dispersion model and managed concurrently with this permit amendment. Consistent with past practice, the mode led SIP potential to emit rate will be higher than the projected actual emissions under NSR as a conser vative estimate. To ensure compliance with the SIP modeled emission rates, FHR proposed to install an SO 2 

### continuous emission monitor (CEM) (MR069) on the 31H-2 stack (SV049). Greenhouse Gas (GHG) RequirementsTechnical Support Document, Permit Action Number: 03700011-008 Page 13 of 27 Date: 8/15/2011 

### FHR is currently complying with the Mandatory GHG Reporting Rule. Although EPA has determined that the GHG reporting rule requirements are not applic able requirements for Title V purposes, MPCA is noting them here for completeness. No additional Ti tle V condition is being added to the CD-01 forms.
This project will result in significant GHG reductions as a result of shutting down the Merox incinerator. Additionally, the reporting rule does not require monitori ng fuel gas flow that is <10% of the total fuel to the heater. The Merox offgas contribution (previousl y estimated at 1.1-2.4 MMBtu/hr) should remain below this threshold for 31H-2, and therefore no a dditional monitoring will be required. This past estimate included the sour water tank emissions wh ich will not be routed to 31H-2 and also included naphtha as a disulfide oil diluents which is being cha nged to a less volatile distillate product (#1 fuel oil). EPA Response to FHR Letter Regarding H 2 

### S Monitoring Exemption
FHR sent a letter to U.S. Environmental Protection Agency (EPA) October 12, 2010, requesting exemption from H 2 

### S monitoring of the Merox treating unit offgas stream. USEPA produced a response to this letter on November 15, 2010. A copy of USEP A’s response letter was received by MPCA on November 23, 2010. See attachment 3 to this TSD. Administrative Order and State Implementation Plan (SIP) Amendments

Because the SO 2 

### emissions at 31H-2 (EU055) will increase due to rerouting the offgas from the Merox incinerator, an amendment to the Minnesota State Impl ementation Plan (SIP) is required to continue to demonstrate attainment of the National Am bient Air Quality Standards (NAAQS) for SO 2 

### . In addition to amending the SIP, FHR submitted air dispersion mode ling to assess how this project will impact ambient
SO 2 

### concentrations. See attachment 5 to this TS D for the modeling memo from Ruth Roberson.
Unrelated to the Merox offgas project, several other updates to the dispersion model are included in this amendment. Specifically, FHR has proposed changes to a few of the fuel gas sulfur representations in the model to better reflect actual emissions as measured via CEMS installed in the period following the previous SIP modification. Short term SO 2 

### emissions from the 45 mix drum fuel gas remain based on 500 ppm sulfur. The average annual concentration is prop osed to be decreased from 500 ppm (SIP8) to 400 ppm with this modification. SO 2 

### emissions from the 41 mix drum fuel gas are conservatively based on reduced sulfur contents limited to 300 ppm for th e 1-hour, 3-hour, and 24-hour averaging periods and 162 ppm reduced sulfur for the annual averaging period. These input parameters remain consistent with SIP8 with the exception of the 3-hour and 24-hour averaging periods which are proposed to be increased from 162 to 300 ppm to provide consistency with the 1-hour standard and account for inherent process variability during low rate operation.
Other changes to the SIP modeling include updating the diesel sulfur content from 0.05% by weight to 0.0015% by weight (15 ppm) for stationary diesel engines listed in permit Appendix B. The fuel oil component was removed for some heaters (EU005, 026, 028, 030, 034, 084) as it is no longer used. Also changes in permit limits and heat input rates contribut ed to changes in the SIP modeling. Units that have been removed from the facility will be removed from the modeling. FHR included Boiler #10 in the revised SIP modeling though no permit application to add this boiler has been received to date. Additionally FHR plans to improve the energy effici ency of the 94H-1 Thermal Oxidizer (EU282) which results in lower stack temperature and thus is in cluded in the dispersion model. Operation of the decoking units (EU032, 033, 037, 038) shall be one of the three scenarios modeled during any 1-, 3- or 24-hour period based on modeling for Amendment 9 to the State Implementation Plan (SIP9). Limits for
SO 2 

### have been revised for EU055, EU228 and EU245 with SIP9. The new lb/hr and ton/yr limits are listedTechnical Support Document, Permit Action Number: 03700011-008 Page 14 of 27 Date: 8/15/2011 

### in Table 10 below. The steps taken by FHR with SI P9 including shutting down the Merox incinerator and rerouting the offgas to the more effi cient 31H-2 incinerator and reducing SO 2 

### SIP limits in the permit along with other changes described above make s ubstantial progress in reducing the modeled 1-hour ambient SO 2 

### impacts from FHR. More information including a comprehensive discussion regarding the modeling results are contained in the Background Information document accompanying the proposed administrative order, both of which are located in Appendix C of the permit.

3.1.2 Major Permit Amendment For Revision Of No . 5 Sulfur Recovery Unit 1992 PSD Permit NO X 

### BACT Limit (DQ# 989)
The No. 5 Sulfur Recovery Unit (SRU; EU 045) or ‘26 Unit’, was a new processing unit originally permitted in 1992 as part of the Clean Fuels Project. The 1992 Clean Fuels Project was permitted in 1992 as a PSD major modification for NO X 

### emissions. Although the Clean Fuels Project air permit addressed NO X 

### emissions from the 26H-21 standby incinerator (E U 235/SV 042), the upstream Tail Gas Treatment Unit (TGTU-2; EU 237/SV 042) NO X 

### emissions were not considered during the original No. 5 SRU BACT analysis. The 26H-21 standby incinerator and the TGTU -2 (including the 26H-41 incinerator in the TGTU2) are part of the No. 5 SRU and both vent thro ugh the No. 5 SRU stack SV 042. Although NOx from these sources was not specifically anticipated or consid ered as part of the original PSD permitting, as set forth below, a revised BACT analysis confirms that these sources already are equipped with burners that meet BACT requirements.
A July 2005 stack test measured 7.40 lb/hr of NO X 

### compared to the 2.44 lb/hr SV 042 NO X 

### BACT limit (due to additional emissions from the TGTU-2 not acco unted for in the original BACT analysis). FHR then used a NO X 

### analyzer to collect NO X 

### measurements at various points in the No. 5 SRU process and at the main stack (SV 042). The measurements showed additional NO X 

### was generated upstream of 26H-21 from combustion of SRU waste gas and refinery fuel gas in the 26H-41 TGTU-2 incinerator (EU 237). Figure 1. No. 5 SRU General Configuration

In response to the higher NO X 

### SV 042 emissions, FHR submitted an application for a major permit amendment that included a revised SV 042 PSD analysis that included both TGTU-2 and 26H-21 NO X 

### emissions. No. 5 SRU Tail Gas Treating TGTU-2

Ref Fuel Gas Nat Gas S 3

S

2 S

1 No. 5 SRU 26H-40 26H-41



### 26H-21
Incinerator SV 042

NOx

Sample Locations S

1 = Zero NOx S

2 = NOx present S

3 = NOx presentTechnical Support Document, Permit Action Number: 03700011-008 Page 15 of 27 Date: 8/15/2011 

### FHR used the “top down” BACT method for evaluating currently available NO X 

### control technologies and determining BACT for SV 042.
26H-21 Standby Incinerator (EU 235) : The 26H-21 unit is an incinerator with low-NO X 

### duct burners (according to the manufacturer, John Zi nk) and is an integral part of a nd located in the #5 SRU stack (SV 042). This design precludes routing these emissions to add-on controls, and there is no addition technically feasible low NO X 

### combustion technology to further reduce 26H-21 NO X 

### . TGTU-2 Incinerator (EU 237) : The Tail Gas Treatment Unit (TGTU-2) co nsists of four sections - reaction, absorption, quench, and incineration (EU 237 is the incineration section). NO X 

### is created by combustion of process gas entering TGTU-2, as well as combustion of refinery gas in the 26H-41 incinerator burners.
The BACT analysis identified two technically feasib le add-on control technologies that could reduce NO X 

### at the TGTU-2 outlet, as well as one low NO X 

### combustion control technolo gy control option. Add-on controls would control NO X 

### from process gas combustion as well as from refinery gas combustion in the 26H-41 burners, whereas combusti on controls such as low NO X 

### burners would only reduce NO X 

### from fuel combustion in the 26H-41 burners.
Low temperature oxidation and SCR were identifi ed as technically feasible post-combustion technologies. Low NO X 

### staged air burners and Low NO X 

### staged fuel burners were identified as a technically feasible combus tion control technologies.
FHR estimated baseline uncontrolled 26H-41 burner emissions using an emission factor of 0.20 lb/mmBtu. This is the uncontrolled NO X 

### emissions factor for mechanical draft heaters without air preheat from the 1991 BACT analysis, and represents the midpoint of uncontrolled emission factors for such heaters in American Petroleu m Institute Publication No. 4311 “NO X 

### Emissions from Petroleum Industry Operations”.
At 0.20 lb/mmBtu, potential uncontrolled baseline NO X 

### emissions for the 26H-41 incinerator are
0.20 lb/mmBtu * 36.8mmBtu/hr = 7.36 lb/hr x [8760 hr/yr x ton/2000 lb] = 32.2 tpy.Technical Support Document, Permit Action Number: 03700011-008 Page 16 of 27 Date: 8/15/2011 

### Table 7. Technically Feasible NO X 

### Control Technologies for 26H-41

Control Technology Control Efficiency Emission Reduction tpy Installed Capital Cost Annualized Operating

Cost/yr Pollution Control Cost/ton Adverse Environmental Impacts? Energy Impact?

Low Temperature

Oxidation 65% of all NO X 20.5 $1,559,158 $1,095,108 $53,329 N N

SCR 65% of all
NO X 20.5 $8,643,050 $1,985,745 $96,701 Y N

Low NO X Staged Fuel
Burner 50% of uncontrolled burner NO X 15.8 $2,499,800 $364,170 $23,055 Y N

Low NO X Staged Air

Burner 30% of uncontrolled burner NO X 9.5 $172,141 $32,574 $3,437 N N



### Table 7 shows that only the Low NO X 

### Staged Air Burner option is cost effective. The staged fuel Low
NO X 

### burner option is considerably more costly than the staged air technology due to required fuel preparation systems, incinerator design, bur ner redundancies to ensure 26H-41 incinerator reliability, and retrofit costs.
As part of this assessment, FHR confirmed with John Zink (26H-41 burner manufacturer), that the existing 26H-41 burners are low NO X 

### staged air burners, and therefore were BACT in 1992. FHR proposed a revised NO X 

### BACT limit of 9.7 lb/hr (365-day rolling ave rage) and 50 ppmvd at 7% oxygen (24-hour rolling average) as part of this updated BACT revision. These BACT limits were proposed based on a review of the BACT Clearinghouse data and recent BACT determinations.

FHR also revised the NO X 

### ambient air analysis for SV 042 through the use of a Screen model. Table 8 shows the model inputs.

Table 8. SV 042 NO X 

### Modeling Inputs

NAD 83 Easting (X) NAD 83 Northing (Y) Base Elevation Stack Height Temp Exit Velocity Stack
Diameter Short
Term Annual

Stack
ID EU ID Description (m) (m) (m) (m) (K) (m/s) (m) (g/s) (g/s)

SV
042 EU 045

EU 235

EU 237 K3_#5SRU
SRU #5

26H-21
Incinerator

26H-41
Incinerator 496851.4 4956630.3 282.9 65 449.8 9.3 2.103 1.222 1.222



### The maximum annual NO X 

### concentration from No. 5 SRU NO X 

### emissions is 0.509 μg/m 3 

### , which is 50.9% of the significant impact level (SIL) of 1 μg/m 3 

### . This concentration was calculated from the 1 hour modeling concentration result of 6.357 μg/m 3 

### and a conversion factor of 0.08. This analysis demonstrates that the revised SV 042 NO X 

### emission limit does not exceed the SIL threshold andTechnical Support Document, Permit Action Number: 03700011-008 Page 17 of 27 Date: 8/15/2011 

### therefore, ambient air quality impacts from the revised emission rate are insignificant and a cumulative air quality impacts analysis is unnecessary.
Additional Impacts Analysis - No additional impacts are expected due to the revision of the SV 042 NO X 

### BACT limit.

3.1.3 Major Amendment To Incorporate Outstanding Requirements From the December 10, 2007 H 2



### S Schedule Of Compliance, Subsequent May 2008 Proposed Schedule (DQ# 2499), and November 11, 2010 Schedule Extension Request
This action incorporates into the operating perm it the commitments made by FHR pursuant to the December 2007 Asphalt Emissions Schedule of Comp liance (SOC) and the November 2010 SOC extension approved by MPCA staff.
In 2006 FHR began to realize that asphalt tank and load out H 2 

### S and VOC emissions were likely higher than previously understood. As a result, FHR initiated a series of discussions with the MPCA leading to the December 2007 SOC. The proposed compliance requirements specified the dates that outstanding project milestones were to be achieved and establis hed emission limitations prior to project completion. In 2010, after completing the projects committed to in the original SOC requirements (including the May 2008 schedule actions submitted in response to the SOC), FHR identified delayed coker unit operations as an additional H 2 

### S source not previously known or eval uated. FHR subsequently requested an extension to the SOC to allow FHR to evaluate and, if necessary, reduce the coker-related H 2 

### S emissions in order to demonstrate compliance with the Minnesota ambient air quality standard for H 2 

### S.
FHR has completed a capital project to significantly reduce H 2 

### S emissions from asphalt tanks as identified in the original effort in 2007. This project has resu lted in reductions of over 95% of the asphalt related emissions. Additionally, while computer dispersion modeling inputs are being evaluated for potential issues, ambient monitoring stations surrounding the facilit y continue to show actual emissions are in full compliance with the standards.
As originally proposed, the SOC addressed both VOC and H 2 

### S emissions, establishing interim limits until final corrective actions could be implemented. For VO C emissions, FHR will continue to adhere to the existing limits established in the previously issu ed #3 Crude Unit Project Permit (Permit No. 03700011- 002) and is not proposing to replace these limits.
The following table lists the status of all SOC re quirements, the May 2008 schedule actions, and the November 2010 schedule extension request actions. Table 9. December 2007 Schedule of Compliance Requirements

Permit Citation Requirement (All are state-only requirements not enforceable by the U.S. EPA Administrator and citizens under the Clean Air Act.) Requirement

source Status

NA The regulated party shall complete a study that will define process or physical changes needed to ensure compliance with the MAAQS for H 2 S by April 30, 2008. 12/2007 SOC
Part 7.a CompletedTechnical Support Document, Permit Action Number: 03700011-008 Page 18 of 27 Date: 8/15/2011 Permit Citation Requirement (All are state-only requirements not enforceable by the U.S. EPA Administrator and citizens under the Clean Air Act.) Requirement

source Status

NA The regulated party shall submit by May 30, 2008, a proposed schedule (and permit application making the proposed schedule enforceable) for initiating and completing physical or process changes (defined by the study) to ensure compliance with the MAAQS for H 2 S and shall undertake those changes pursuant to the proposed schedule. The proposed schedule shall include, but not be limited to, project milestones (engineering, construction, if needed, etc), date for any additional application for permit amendment (if necessary), post project ambient air dispersion modeling completion date, and emission testing date to confirm reductions. 12/2007 SOC Part 7.b Completed

NA The regulated party shall submit by October 30, 2007, an amended permit application, including the relevant portions of this (SOC) agreement, as well as the corrected emission factors and proposed conditions for VOCs and H 2 S. 12/2007 SOC
Part 7.c Completed

NA The Regulated Party shall abide by the existing future actual VOC emission tracking requirements established in Air Permit No. 03700011-002 and shall ensure that VOC emissions from the #3 Crude Unit Project (project), including VOC emissions from increased asphalt production resulting from the project, do not exceed PSD major modification thresholds, until such time as an amended permit with differing conditions is issued. 12/2007 SOC Part 7.d.i Completed

Minn. Stat. Sec. 116.07, subds. 4a and 9; Minn. R. 7007.0100, subps. 7M; Minn. R. 7007.0800, subps. 1, 2, and 4; Minn. R.
7009.0010-7009.0080 MAAQS compliance: The Regulated Party shall ensure that calendar year H2S emissions do not increase as a result of the No. 3 Crude Unit Project over the annualized average emission rates from Sept 05 through Aug 07 (baseline emission rate), until such time as an amended permit with differing conditions is issued. This requirement shall terminate upon total facility modeled compliance with the H 2 S MAAQS. 12/2007 SOC Part 7.d.ii Completed; note
SOC extension includes requirement for total facility H2S modelingincluding decoking NA By September 1, 2008, the permittee shall complete an engineering study and dispersion modeling for hydrogen sulfide (H 2 S) on asphalt barge loading operations 12/2007 SOC Part 7.b & 05/2008 proposed schedule Completed

NA By February 1, 2009, the permittee shall propose any additional corrective actions with a schedule for implementation, that may be necessary to demonstrate ongoing MAAQS compliance for hydrogen sulfide (H 2 S) associated with asphalt barge loading operations 12/2007 SOC Part 7.b & 05/2008 proposed schedule CompletedTechnical Support Document, Permit Action Number: 03700011-008 Page 19 of 27 Date: 8/15/2011 Permit Citation Requirement (All are state-only requirements not enforceable by the U.S. EPA Administrator and citizens under the Clean Air Act.) Requirement

source Status

NA MAAQS compliance: by February 1, 2010, the permittee shall complete the engineering on the permanent chemical scavenger project and any secondary measures needed to ensure compliance with the MAAQS for hydrogen sulfide (H 2 S). 12/2007 SOC Part 7.b & 05/2008 proposed schedule Completed

NA MAAQS compliance: by July 1, 2010, the permittee shall complete the construction (mechanical completion) of the permanent chemical scavenger project and any secondary measures needed to ensure compliance with the MAAQS for hydrogen sulfide (H 2 S). 12/2007 SOC Part 7.b & 05/2008 proposed schedule Completed

NA MAAQS compliance: by December 1, 2010, the permittee shall complete the asphalt tank emissions quantification study (utilizing stack test methods) necessary to confirm ongoing compliance with the MAAQS for hydrogen sulfide (H 2 S). 12/2007 SOC Part 7.b & 05/2008 proposed schedule Completed

NA MAAQS compliance: by December 31, 2010, the permittee shall complete and submit the computer dispersion modeling on asphalt tanks necessary to confirm ongoing compliance with the MAAQS for hydrogen sulfide (H 2 S). 12/2007 SOC Part 7.b & 05/2008 proposed schedule Completed; Model shows compliance for previously identified H 2 S

sources

Minn. Stat. Sec. 116.07, subds. 4a and 9; Minn. R. 7007.0100, subps. 7M; Minn. R. 7007.0800, subps. 1, 2, and 4; Minn. R.
7009.0010 Implement Compliance Plan: due before 04/30/2011. By April 30, 2011, the Permittee shall complete an emissions quantification study on recently identified H 2 S sources associated with the delayed coking unit operations that will serve as the basis to define process or physical changes potentially needed to ensure compliance for the H 2 S MAAQS.

This is a state-only requirement not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act. 12/2007 SOC Part 7.b & 11/2010 SOC schedule
extension Completed; however needs incorporation into permitTechnical Support Document, Permit Action Number: 03700011-008 Page 20 of 27 Date: 8/15/2011 Permit Citation Requirement (All are state-only requirements not enforceable by the U.S. EPA Administrator and citizens under the Clean Air Act.) Requirement

source Status

Minn. Stat. Sec. 116.07, subds. 4a and 9; Minn. R. 7007.0100, subps. 7M; Minn. R. 7007.0800, subps. 1, 2, and 4; Minn. R.
7009.0010 Implement Compliance Plan: due before 07/30/2011. By July 30, 2011, the Permittee shall submit a proposed schedule (and permit application making the proposed schedule enforceable) for initiating and completing any physical or process changes (defined by the delayed coking unit study) to ensure compliance with the MAAQS for H 2 S and shall undertake those changes pursuant to the proposed schedule. The proposed schedule shall include, but not be limited to, project milestones (engineering, construction, if needed, etc), date for any additional application for permit amendment (if necessary), post project ambient air dispersion modeling completion date (if necessary), and emission testing date to confirm reductions (if necessary).

This is a state-only requirement not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act. 12/2007 SOC Part 7.b & 11/2010 SOC schedule
extension Pending; needs incorporation into permit



### 3.1.4 Minor Amendment to Install Two Temporary Portable Coke Crushers (DQ# 3352)

Two temporary portable coke crushers were proposed for use in the 21 Unit due to turnaround staging issues associated with the A and B coke drum replacement project that occurred during spring 2011 hindering normal coke crushing operations in the unit. While the portable crushers project could arguably be aggregated with the 21 Unit drum replac ement, the permit applicability for that project or this one would not change if the projects were aggregated. The 21 Unit drum replacement project involved same-size replacement of existing drums. From a New Source Review perspective, FHR determined that no permit was necessary because th e calculated emissions increases were determined to be insignificant utilization increases (less than 1 tp y) below significant emission rates (SERs) on a past actual to future actual basis. From a state permitting perspective, FHR determined that no permit was necessary because there was no emissions increase on a maximum hourly emissions rate basis. From an NSPS perspective, FHR determined that no permit wa s necessary because reconstruction or modification was not triggered. Thus, even if the portable coke crushers project was evaluated in conjunction with the 21 Unit drum replacement, the only emissions to be evaluated would be the emissions from crushing, leading to the same permit analysis.
A minor permit amendment application was receiv ed on December 22, 2010 for operation of two temporary portable coke crushers that were projecte d to be on site for approximately six (6) months after January 1, 2011.
The two coke crushers in the permit application we re evaluated at capacities of 150 and 100 tons per hour (tph) for a total capacity of 250 tph. The estimated increases in potential emissions were based on both crushers operating during crushing operations:

• PM 5.00 lb/hrTechnical Support Document, Permit Action Number: 03700011-008 Page 21 of 27 Date: 8/15/2011 

### • PM 10 

### 1.50 lb/hr

• PM 2.5 

### 1.50 lb/hr
The increases in emissions from the temporary port able coke crushers did not increase emissions beyond SERs under PSD rules as defined in 40 CFR Se ction 52.21(b)(2); therefore, the project was not considered a major modification a nd was not subject to PSD review.
Also, the addition of the portable coke crus hers were above insignificant modification PM 10 

### thresholds per Minn. R. 7007.1250, subp. 1, but below moderate amendment PM 10 

### thresholds per Minn. R. 7007.1450, subp. 2; therefore, requiring a minor permit amendment.
The combustion emissions were not subject to pe rmitting requirements because the temporary coke crushers qualify as nonroad engines. The Clean Air Act, as amended through the 1990 Clean Air Act amendments, defines “stationary source” such that nonroad engines are not regulated as stationary

sources. CAA Title III [¶ 2302] Sec. 302 - Definitions: (z) STATIONARY SOURCE - The term “stationary source” means generally any source of an air pollutant except those emissions resulting di rectly from an internal combustion engine for transportation purposes or from a nonroad engine or nonroad vehicle as defined in section 216. CAA Title II [¶ 2216] Sec. 216 - Definitions for Part A: (10) NONROAD ENGINE - The term “nonroad engine” means an internal combustion engine (including the fuel system) that is not used in a motor vehicle or a vehicle used solely for competition, or that is not subject to st andards promulgated under section 111 (Standards of Performance for New Stationary Sources) or se ction 202 (Establishment of Standards for motor vehicle emissions).


### This definition of nonroad engine is codified in 40 CFR Section 89.2 as:

NONROAD ENGINE means: (1) Except as discussed in paragraph (2) of th is definition, a nonroad engine is any internal combustion engine: (i) In or on a piece of equipment that is self-p ropelled or serves a dual purpose by both propelling itself and performing another function (such as garden tractors, off-highway mobile cranes and bulldozers); or (ii) In or on a piece of equipment that is in tended to be propelled while performing its function (such as lawnmowers and string trimmers); or (iii) That, by itself or in or on a piece of equipment, is portable or transportable meaning designed to be and capable of being carried or moved from one location to another. Indicia of transportability include, but are not limited to, wheels, skids, carrying handles, dolly, trailer, or platform. (2) An internal combustion engine is not a nonroad engine if: (i) The engine is used to propel a motor vehicle or a vehicle used solely for competition, or is subject to standards promulgated under section 202 of the Act; or (ii) The engine is regulated by a federal Ne w Source Performance Standard promulgated under section 111 of the Act; or (iii) The engine otherwise included in paragraph (1)(iii) of this definition remains or will remain at a location for more than 12 consecutive months or a shorter period of time for an engine located at a seasonal source. A location is any single site at a building, structure, facility, or installation. Any engine (or engines) that replaces an engine at a location and that is intended to perform the same or similar function as the engine replaced will be included in calculating the consecutive time period. An engine located at a seasonal s ource is an engine that remains at a seasonal source during the full annual operating period of the seasonal source. A seasonal source is a stationary source that remains in a single locati on on a permanent basis (i.e., at least two years)Technical Support Document, Permit Action Number: 03700011-008 Page 22 of 27 Date: 8/15/2011 and that operates at that single location approxim ately three months (or more) each year. This paragraph does not apply to an engine after the engine is removed from the location.


### The portable coke crushers are co nsidered portable equipment, and the equipment will not remain at a location for more than 12 consecutiv e months or through an entire seas on of operation. Therefore, the portable coke crushers’ engines were not regulat ed under the Clean Air Act and air quality permitting regulations were not applicable to the engines, though FHR must still comply with the NAAQS.

3.1.5 Administrative Facility and Ownership Name Change (DQ# 3287)

FHR submitted an administrative amendment changing the facility name to Flint Hills Resources Pine Bend Refinery (formerly Flint Hills Resources LP - Pi ne Bend Refinery) and the ownership name to Flint Hills Resources Pine Bend LLC (formerly Flint Hills Resources LP). This change became effective November 1, 2010.

3.1.6 Permit Reopenings (DQ# 3354, 3355, 3366, 3374)
3354: A reopening of EU035 (No. 3 Coker Heater, 23H-2) will add a heat input limit of less than or equal to 115.3 mmBtu/hr based on the results of a performance test conducted November 2, 2010.
3355: A reopening of EU204 (Steam Boiler No. 8, 71B-8) will add a heat input limit of less than or equal to 139.4 mmBtu/hr based on the results of a performance test conducted May 19-20, 2010.
3366: A reopening of EU204 (Steam Boiler No. 8, 71B-8). This is an exact copy of DQ 3355, except the CO emissions for O 2 

### % greater than 4.9% was corrected to 0.0010 lb/mmBtu.
3374: A reopening of EU053 (28H-1) will add a heat input limit of less than or equal to 34.0 mmBtu/hr based on the results of a performance test conducted November 16, 2010.

3.1.7 Facility Description
The operator ID for Steam Boiler No. 9 (EU313) was a dded to the facility description as 71B9. SV data included with the SO 2 

### modeling parameters that was not previous ly contained in the facility description was added for SV131, 164, 165, 166 and 173.

3.2 Emissions Calculations

This amendment will account for additional NO X 

### emissions (31.8 tpy) due to the No. 5 Sulfur Recovery
Unit SV 042 NO X 

### BACT revision. This amendment will also use projected actual emissions to estimate a 5.8 tpy SO 2 

### increase with the Merox project. (See Table 3 and discussion above. (DQ# 3153))

EU055 PTE for SO 2 

### All PTE values for EU055 (in the Facility Descriptio n) were taken from the May 2010 Title V permit reissuance application, except for SO 2 

### which are changed due to the addition of the Merox offgas stream. The hourly and annual SO 2 

### PTE values are estimated from the maximum expected fuel sulfur from the Merox offgas stream using CEMS data at the Merox incinerator. The highest hourly and 365- day rolling SO 2 

### CEMS reading from the Merox incinerator since 2006 is 45.2 lb/hr and 35.4 tpy, respectively. Three standard deviations from th e 2006-2009 data and a 20% safety factor for CEMS accuracy are added to these maximu ms to yield 65.4 lb/hr and 50.4 tpy. Adding the refinery fuel gas PTE values from the Title V reissuance application (0.97 lb /hr and 2.3 tpy) yields a total estimated PTE of 66.4 lb/hr and 290.8 tpy. These SO 2 

### values and methodology are subject to change pending the SIP Administrative Order amendment submitted under separate cover.Technical Support Document, Permit Action Number: 03700011-008 Page 23 of 27 Date: 8/15/2011 

### 3.3 Periodic Monitoring
In accordance with the Clean Air Act, it is the respon sibility of the owner or operator of a facility to have sufficient knowledge of the facility to certify that the facility is in compliance with all applicable requirements.
In evaluating the monitoring included in the permit, the MPCA considers the following:

• The likelihood of violating the applicable requirements;

• Whether add-on controls are necessary to meet the emission limits;

• The variability of emissions over time;

• The type of monitoring, process, maintenance, or control equipment data already available for the emission unit;

• The technical and economic feasibility of possible periodic monitoring methods; and

• The kind of monitoring found on similar units elsewhere.
The table below summarizes the periodic monitoring requirements for those emission units for which the monitoring required by the applicable re quirement is nonexistent or inadequate. Table 10. Periodic Monitoring Level* Requirement (rule basis) Additional Monitoring Discussion

SV042 Title I Condition: 40 CFR Section 52.21(j) NO X 

### CEMS NO X 

### is monitored on the SRU #5 stack with a CEMS. This includes NO X 

### from EU 237
26H-41 TGTU-2 incinerator.
EU032
EU033
EU037
EU038 Decoking units shall be operated in one of the three scenarios modeled for any 1-, 3- or 24-hr period

Title I Condition: SIP for
SO 2 

### NAAQS, 40 CFR pt. 50; MN State Implementation Plan (SIP) Recordkeeping: hours of operation of the decoking units This requirement was placed at the EU level for the decoking units based on SIP modeling limitations for the 1-, 3- and 24- hour SO 2 

### NAAQS standards.
Scenarios: 1. EU032 only; 2. EU033 only; 3. EU037 and EU038.

EU055 SO 2 

### : < 66.4 lb/hr using 3-hr rolling average

Title I Condition: SIP for
SO 2 

### NAAQS, 40 CFR pt. 50; MN State Implementation Plan (SIP) SO 2 

### CEMS (MR069) to show compliance with SIP requirements
Recordkeeping: keep records of SO 2 

### emissions of hourly averages of total SO 2 

### emissions in lb/hr. This value is subject to change pending the SIP Administrative Order action.

EU055 SO 2 

### : < 290.8 tpy using 365-day rolling average

Title I Condition: SIP for SO 2 

### CEMS (MR069) to show compliance with SIP Requirements This value is subject to change pending the SIP Administrative Order action.Technical Support Document, Permit Action Number: 03700011-008 Page 24 of 27 Date: 8/15/2011 

### Level* Requirement (rule basis) Additional Monitoring Discussion

SO 2 

### NAAQS, 40 CFR pt. 50; MN State Implementation Plan (SIP) Recordkeeping: keep records of SO 2 

### emissions of total SO 2 

### in tons per year.
EU055 SO 2 

### : < 20 ppmv (dry basis, corrected to 0% excess air, determined hourly) on a 3-hr rolling

average

and

SO 2 

### : < 8 ppmv (dry basis, corrected to 0% excess air, determined daily) on a 365 successive day rolling

average

40 CFR Section 60.102a(g)(1)(i) None (Exempt; NSPS subp. Ja monitoring exemption approved by EPA Region V on 11/15/10) FHR shall comply with either the SO 2 

### emission limit of 40 CFR Section 60.102a(g)(1)(i) or the H 2 

### S fuel gas concentration limit of 40 CFR Section 60.102a(g)(1)(ii).

EU055 H 2 

### S: < 162 ppmv hourly on a 3-hr rolling

average

and

H 2 

### S: < 60 ppmv on a
365 successive calendar day rolling

average

40 CFR Section 60.102a(g)(1)(ii) None (Exempt; NSPS subp. Ja monitoring exemption approved by EPA Region V on 11/15/10) FHR shall comply with either the SO 2 

### emission limit of 40 CFR Section 60.102a(g)(1)(i) or the H 2 

### S fuel gas concentration limit of 40 CFR Section 60.102a(g)(1)(ii).

EU055 H 2 

### S: ≤ 230 mg
H 2 

### S/dscm in fuel gas

Minn. R. 7011.1410, subp. 2 None The 31H-2 heater is already subject to these conditions and are in the Title V permit as NSPS subp. J requirements. This heater triggered the fuel gas combustion device (FGCD) standards in NSPS subp. Ja, which has more restrictive limits than in subp. J and Minn. R. 7011.1410, subp. 2. Compliance demonstration with subp. Ja will be deemed compliance with this less stringent standard.
EU228 SO 2 

### : < 182.6 lb/hr using 1- and 3-hr rolling Monitoring: use SO 2 

### CEMS to measure SO 2 

### emissions from SV019 Revised SO 2 

### limit for FCCU based on updated Amendment 9 to the SIP.Technical Support Document, Permit Action Number: 03700011-008 Page 25 of 27 Date: 8/15/2011 

### Level* Requirement (rule basis) Additional Monitoring Discussion

average

Title I Condition: SIP for
SO 2 

### NAAQS, 40 CFR pt. 50; MN State Implementation Plan (SIP); and SO 2 

### MAAQS,
Minn. R. 7009.0080 and SV021

EU228 SO 2 

### : < 800 tpy using 12- month rolling average

Title I Condition: SIP for
SO 2 

### NAAQS, 40 CFR pt. 50; MN State Implementation Plan (SIP) Monitoring: use SO 2 

### CEMS to measure SO 2 

### emissions from SV019 and SV021 Revised SO 2 

### limit for FCCU based on updated Amendment 9 to the SIP.

EU245 SO 2 

### : < 65.4 lb/hr using 3-hr rolling average

Title I Condition: SIP for
SO 2 

### NAAQS, 40 CFR pt. 50; MN State Implementation Plan (SIP) Monitoring: use SO 2 

### CEMS to measure SO 2 

### emissions from SV042 Revised SO 2 

### limit for Merox incinerator based on updated Amendment 9 to the SIP. Following Merox shutdown, emissions from EU245 will be zero and offgas will be routed to 31H-2 (EU055).

EU245 SO 2 

### : < 286.4 tpy using 12-month rolling

average

Title I Condition: SIP for
SO 2 

### NAAQS, 40 CFR pt. 50; MN State Implementation Plan (SIP) Monitoring: use SO 2 

### CEMS to measure SO 2 

### emissions from SV042 Revised SO 2 

### limit for Merox incinerator based on updated Amendment 9 to the SIP. Following Merox shutdown, emissions from EU245 will be zero and offgas will be routed to 31H-2 (EU055).

GP118 PM: < 38.59 lb/hr based on 1-hr average (for EU325)

PM: < 36.11 lb/hr based on 1-hr average (for EU326)

Minn. R. 7011.0715, subp. 1(A) None Compliance is inherent to the design of the equipment. Based on published emission factors (AIRS, March 1990, EPA 450/4-90-003) and the maximum design of the equipment, emissions will be well below the industrial process equipment rule.

GP118 Opacity: < 20% opacity

Minn. R. 7011.0715, subp. 1(B) None Limit applies to each associated item individually.Technical Support Document, Permit Action Number: 03700011-008 Page 26 of 27 Date: 8/15/2011 

### Level* Requirement (rule basis) Additional Monitoring Discussion

GP118 Hours of Operation:

< 4380 hrs/year based on 12-mo. rolling sum

Minn. R. 7007.0800, subp. 2 Recordkeeping: record hours of operation and 12-month rolling sum each month Limit applies to each associated item individually.

*Where the requirement appears in the permit (e.g., EU, SV, GP, etc.).

3.4 Insignificant Activities
FHR has several operations which are classified as in significant activities. These are listed in Appendix A to the permit. There are no insignificant acti vities associated with this permit action.

3.5 Permit Organization
In general, the permit meets the MPCA Delta Guidance for ordering and grouping of requirements. One area where this permit deviates slightly from Delta guidance is in the use of appendices. While appendices are fully enforceable parts of the permit, in general, any requirement that the MPCA thinks should be tracked (e.g., limits, submittals, etc.), shou ld be in Table A or B. The main reason is that the appendices are word processing sections and are no t part of the tracking system. Violation of the appendices can be enforced, but the computer syst em will not automatically generate the necessary enforcement notices or documents. Staff must generate these.

3.6 Comments Received
Public Notice Period: July 1, 2011 - August 1, 2011 EPA 45-day Review Period: July 1, 2011 - August 15, 2011
No comments related to the permit were received from the public during the public notice period. No comments were received from EPA during their review period.

4. Permit Fee Assessment

Attachment 7 to this TSD contains the MPCA’s assessm ent of Application and Additional Points used to determine the permit application fee for this permit action as required by Minn. R. 7002.0019. The permit action includes five permit applications, three of which were received after the effective date of the rule (July 1, 2009) and are paid (major, 25 pts.; mino r, 4 pts.; administrative, 1 pt.). Additional points fees include: modeling review (15 pts.) for SO 2 

### regarding the SIP, NSPS review (10 pts.) of subpart Ja, and a BACT review (15 pts.) for SV042 NO X 

### . 5. Conclusion
Based on the information provided by Flint Hills Resources Pine Bend LLC, the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 03700011-008 and this TSD, will not cause or cont ribute to a violation of applicable federal regulations and Minnesota Rules.
Staff Members on Permit Team: Tarik Hanafy (permit writer/engineer) Marshall Cole (permit writer/engineer) Brent Rohne (enforcement) Curtis Stock (stack testing)Technical Support Document, Permit Action Number: 03700011-008 Page 27 of 27 Date: 8/15/2011 

### Ruth Roberson (modeling) Catherine Neuschler (SO 2 

### SIP revision) Amrill Okonkwo (peer reviewer)

AQ File No. 106A; DQ 989, incorporates 2499, 3153, 3287, 3352, 3354, 3355, 3366, 3374

Attachments: 1. Facility Description and CD-01 Forms
2. Calculation Spreadsheets
3. EPA Response to FHR Letter Regarding H 2 

### S Monitoring Exemption
4. SV042 ESA Consult
5. Modeling Review
6. PER 008 CD-01 Changes
7. Points Calculator

### Attachment 6: Public Notice

### PM**Particul~l~** 

### M,tter PM, , • PM <mailer**th~n** 

### 2.5 microm NO .• Nitrogen O"de< CO· Carbon Monoxide MINNESOTA POLLUTION CONTROL AGENCY PUlIlIC NOTICE ON ORAFT/PROPOSED AIR EMISSION FACIlITY PERMIT

NOTICE IS HEREBY GIVEN, that the Commi"ione, olthe Minnesota Pollution Contrel Agency lMPCA) p<opole, to 

### i<sue
Air Emission Permit No. 03700011·008, to Flint Hills Re,ources Pine Bend llC for thei' facility located at 13775 dark Road, Rosemount, Oakota County,**MlnneIOl~.**



### In addition, NOTICE IS HEREBY GIVEN that the Commissioner has determined that the State Implementation Plan (SIP) cond'tion' for this facility should be amended. The facility is subje<tto an Admlnistratioe Order (Orde'), which i' included
in Minnesota', SIP and contains conditions that are nece«ary to demonstrate**compli~nce** 

### with the**Nation~1** 

### Ambient Air Quality Standard {NMQS) for ,ulfu, d,oxide, Under itl Tille I authority, Ihe MPCA I, ,evising the Order and will be formally requelting that the U.s. Enyironmental P,otectlon Agenoy (EPA) amend Minnesota', SIP to include the ,evi,ed O,der,

II Proposed Permit The permit act,on 

### ,s for con,truction and operation of the facility The permit "ctlon is a major amendment;**Iher~fore,** 

### the draft/propo,ed permit**h~,** 

### been placed on public notice. The M PCA i' seeking the U.S. Environrnenlal Protp.ction Agency" (EPA) concurrent review of this d,ah/proposed permit and the EPA 4S-day review period will begin with the 30-day public 'ev,ew period.

Th"**m~jor** 

### amendment is fo' a combination of permit application, for unrelatcd changes al the la"IiW. The**~hange,** 

### are the reYision oflhe SV 042 NO, Besl Available Control T cchnology (BACT) limit, the inclusion of outstanding Decembe'
2007 Hydrogen Sulfide (H,s) compliance schedule reqUirementS, and the shutdown of the Mero< In(ifleralor (EU24S) and

reroute of otfga, to the 31H-2 furnace (EUOSSI. There I' al<o a minor amendment to in,laUtwo temporary coke crushers lEU32S & 

### EU326) and an adminlSt'ative amendment for a facilily and ownersh<p name change. Re-opening, are al'o included that revise heat input limit, on EU03S (23H-2j, WOS3 (2SH-l) and EU2D4171B·S).

A summary of the (mission' Increa,e in lOn, per year i' as foliowI:

Pollutant 

### eM PM" PM" 

# '"' '", 

# "" " CO,e 

# ,,'
,mh,len,lnorea,e 10.95 3.29 3.29 

# ,. 42.5 

# , , , 

# ,
trem new and m<>dltied emission umtl Emission,Oe,,""," -D86 -0.86 

# " -1007 _3174 ·618 

### -952 _7,904 

# , from Mew, 

### shutdown

PM,.' PM smaller than 10 microns 50,' 5ultur Olo<ide VOC,. Volatile Organio Compound' CO,e. Carb"" Dioxld" Equi"alent' a, detined in Minn. R 70070100
Th" Permmee has ,ubmltted a pollution pre"enlion pragre« report pursuant to 

### Minn. Stat. § 

### 1150.08.

2) Propo<ed SIP Changes Changes to the SIP condition for thi< facility are needed to**~ccommodate** 

### lhe lhuldown of the Merox Incinerator**~nd** 

### reroute of of/gas to the 31H-, furnace, improve the energy efficiency of the 94H_l Wa,teW"ler Treatment**PI~nt** 

### (WWTP) Thermal O,.d"er, and provide the abil,ty to install a new boiler In the future. The main emission changes are reducllon, in SO, em",ion, from die'el engine, due to lowe, sulfur luel, reduction' in emis"ons from the Merox and FCC emission unil<, and new emission limits for the 31H-, hc"ler. In addition, the SIP revisl.", updales em"'ion' and modeling parameters from ,arious 10urCe' within the facility, and remove, 'eferences to requirements that have been completed. Overall the (hange, re,ult in iower SO, emissions from the facility and generally lowe, ambient Impact>

Flint Hills Re,ource$ i< localed in a maintcnance area for the annual and 24_hour sulfur dio"de $tandard The MPCA believe' that the SIP changes proposed will not have an adverse impact on compliance wiU, Ih"se $t>ndardl. EPA ha$ recently pfomulgated a new one·hour standard lor ,ullur dlo,;de. A SIP tor the new <tandard is not yel due to EPA

### 3) Public Parti<ipatlon
The prelimiMry dctcrmlnation to 

### i"ue the air emi"ion permit and submit the SIP revi"on iltentati"e. Ihere are four formal procedures for public participatron In the MPCA's consideration of the per mit application and decision to submit the SIP. Intere'ted persons may (1) subm,t wnttcn comment, on the draft/propo,ed permit and proposed SIP revision; (2) request that the MPCA hold a public information meeting; 131 rCQue.t the MPCA hold a contested ca.e hearing; and/or (4) submit a petition to 

### the Commi"ioner reQue'ting that the MPCA Citilens' Board (Board) consider the permit matter and propo'ed SIP ,eViS'M.

The deci,ion whether to issue the permit and submit the SIP ,evision and. If '0, under what te,m,. will be pre'ented to the Board for deci"on if: (1) the Commi"ioner grantslhe pel,llon reque.llng the malte' be pr",ented to the Board; (2) an Board member requests to hear the matter prior to the time the Commissioner**ma~es.** 

### final decision on the permit; Or (3) a request for. conte,ted case hearing Is pending. Otherwi,e. the Commi"ioner will make the decision

Pe"ons who submit comments Of petitions to 

### the MPCA must ,tate (1) 

### therr intere't in the permit application or the draft permit and proposed SIP re"islon; (2lthe aCllon they wish the MPCA to take, indudmg specific rer.,erlce, to the section of the draft permit and proposed SIP revi,ion they beHeve .houid be changed: and (3) the reasom ,upporting their pOSition. 'tated with sumeient 'pecificiW as to allow the MPCA to 

### investigate the merits of the po,ition



### A> delcrrbed in Minn. R. 7000.1800, perlonl who submit ,eque,ts fo; a contested case hearing must also ,tate the issues they propose to addre" in a contcsted**CaS~** 

### healing. the**~peCllic** 

### rel,eI requested or resolution olthe matter, and the

reasons {which may be in the form of propoSCd findings) supporting an MPCA decision to hold a conte'ted case hearing, Failure to comply w'th**the~e** 

### ,ulcs exactly may rcsult in a denial of the reque,\. The decision whether to hold a conte.ted

case hearing will be made under Minn. R. 7000,1900, Most public Iibfaries throughout the state have copies of the

current Minnesota Rules. They are al,o available on the Internet at '""'-' rev,sor**I~,,,** 

### te, mn u',

Ihe public comment period commence, July 1. 2011. and te,minates Augmt 1, ,011. Comments. including reQue<1< for a public meet'ng, mult be received in writing at the MPCA by 4:30 p.m, on August I, 2011, Evidence of timely receipt includes a date/time stamp imprinted on the first page of the written comment< by the flm floor inlormation and reception arc<' 0/ the MPCA or bv the Ind,,,tri.1 Divi,ion or EAO ,upport ,tafl. or recCipt by fax,

A public inform.tion**meetin~** 

### will only be held if one i, requested by the dose of the public comment penod, If such a meeting is requested. a sep"ate Mtice 01 the meeting will be published at least 30 days prior to the selected meetrng date, The publ,c information meeting, ,f reque'ted, wiil provide information, receive public Input, and 'nswer Queltion, about both the proposed**~rmit** 

### and SIP revi<lon.

Comment<. reque'ts. and petitions should be sont to:



### • Perm't Contact: Tank Hanaly, Air Quality Permits Section, InduWlal Division.**Minne~ota** 

### Pollut,on Contr<'1 Agency. S20 la/a vette Road North, St. Paul, Minnesota SSlSS, 5S1-75 7 -2404

- voice 0; 

### 651-296-8717 fa..

• Permit Contact: Marshall Cole. Ai, Quality Pe,mits Section, Industllal Divi,ion, Minnesota Pollution Control Agency. 18 Wood lake Drive Soulheast. MiMesota 55904, 507-206·25S3

- voice or 507·280·S513

- fax,

• SiP R""i,ion: Catherine Neu"hler, fAW Division, Minnesota Pollution Control Agency 5LO 

### La/avette Road North. 51. Paul. Minncsota 55155, 651·757·2507

- ,oree or 551·297·8324

- fax or bye-mail at ratl'e I 'neu 'rrL

A copy 01 the draft/proposed permit will a\lailable on the MPCA·s website at Imp 1!'·M"'.,J!1,l 

# ,"'t ' mC'..ll. jn,·w,jd,"

. ,nde', rfm 'PN_-l, or w,lI alw be 

### mailed to any**inte,elt~d** 

### person upon the MPCA', ,ecelpt of a written reque,t. Information on the SIP revi,ion will al,o be available on the MPCA', website at httpili"-'/w¥as<ate.m".u,la<rI<·p.hlml. Copics of the publ,c notice, draft/proposed permit, technical 'upport dowmenl, Information on the SIP revi,io" a"d permit application material, will .Iso be avaifable at,**~oben** 

### Trail Ubrary, 14395 South Robert Trail, Rosemount, MN 55068, Additionai material, relat,ng to the is,uJn'e Olth

.. permit and the proposed SIP re",S'On are "vailable for impection by appointment at 

### the MiMcsota PoUution Control Agency. 520 lafayette Road North. St. Paul. Minne.ota S5155. phone 6S1·757·2404, and at 18 Wood lake Dtive Southea,t, Roche'ter, Minnesota 55904. 

### phone 507-106-2653. 

### between the hours of 8,00 a,m, and 4:30 p.m., Monday through Fflday. All MP{A offrces may be reached by call,ng 1 SOO 657 3864

DATED: June 1l.10n

Air Quality Permit' Section Indu,!rlal Divi,ion

### Attachment 7: Completeness Review

A. Administrative Materials (40 CF R pt. 51, Appendix V, Part 2.1)

The EPA’s Criteria for Determining the Complete ness of Plan Submittals, published at 40 CFR pt. 51, Appendix V, requires states to provide the basic documents that show that the State has properly followed the administrative requirements called for by the CAA for the adoption of SIPs. The requirements, and how this SIP revision complies with these requirements, are discussed here:

1) Formal Letter of Submittal:

“A formal letter of submittal from the Governor or his designee, requesting EPA approval of the plan or revision thereof.”

Attached to this SIP revision request is a formal letter of submittal from the MPCA Commissioner, Paul Aasen, to the EPA Region V Administrator, Susan He dman. The office of the Commissioner of the MPCA is statutorily created at Minnesota Statute § 116.03, subd. 1 (a) (2010). The Commissioner is appointed by the Governor, and the duties of the position include acting as the state agent to “apply for, receive, and disburse federal funds made available to the state by federal law or rule and regulations promulgated thereunder for any purpose related to the power and duties of the MPCA or the Commissioner. The Commissioner shall comply with an y and all requirements of such federal law or such rules and regulations promulgated thereunde r to facilitate application for, receipt, and disbursement of such funds.” Minn. Stat. § 116.03 subd. 3 (2010).

2) Evidence of State Adoption of Plan and Issuance of Orders in Final Form

“Evidence that the State has adopted the plan in the State code or body of regulations; or issued the permit, order, consent agreement (hereafter ‘documen t’) in final form. That evidence shall include the date of adoption or final issuance as well as the effective date of the plan, if different from the adoption/issuance date.”

Attachment 1 contains the Administrative Order issued to Flint Hills Resources. The Order became effective as soon as it was signed.

3) Legal Authority Documentation:

“Evidence that the State has the necessary legal au thority under State law to adopt and implement the plan.”

This SIP revision request is an update to MPCA’s Pine Bend SO 2 

### SIP. This SIP was submitted by the MPCA in July 1992 and approved by EPA in the Federal Register on September 9, 1994. EPA’s approval of a redesignation request for the area was published on May 31, 1995 (60 FR 28339). Attachment C of the initial submittal documents MPCA’s legal authority to submit SIP revisions and to issue Administrative Orders.

### 4) Compliance with State Procedures:

“Evidence that the state followed all of the procedural requirements of the State’s laws and constitution in conducting and completing the adoption/issuance of the plan.”

MPCA complied with all relevant state procedures fo r issuing the permit as well as the SIP Revision, including a public notice period and the opportunity to request a hearing.

5) Public Notice:

“Evidence that public notice was given of the pr oposed change consistent with the procedures approved by the EPA, including the date of the publication of the notice.”

The public notice for the permit and associated SIP revision was published in the Apple Valley/Rosemount/Eagan Sun Current on June 30, 2011, with the public comment period commencing on July 1 and ending on August 1. The public notice was also published on the MPCA’s website. During the public comment period, a copy of the permit and SIP revision was made available at Dakota County’s Robert Trail Library, due to a Minnesota state gove rnment service interruption from July 1 through July 21. After the service interruption, the materials were also available on the MPCA’s website and at the MPCA offices located in St. Paul and Rochester. A copy of the public notice is attached. (Attachment 6).

6) Public Hearing Certification

“Certification that public hearing(s) were held in ac cordance with the informatio n provided in the public notice and the State’s laws and constitution, if applicable.”

The public notice states: “A public information m eeting will only be held if one is requested during the public comment period. If such a meeting is requested, a separate notice of the meeting will be published at least 30 days prior to the select ed meeting date. The public information meeting will provide information, receive public input, and answ er questions about both the proposed permit and SIP revision.”

No public meeting was requested.

7) Public Comments and State Response:

“Compilation of the public comment s and State’s response thereto.”

No public comments on the SIP were received.

B. Technical Support:

1) Pollutants Regulated:

“Identification of all regulated pollutants affect by the plan.”

The regulated pollutant subject to this SIP revision request is SO 2


### .

### 2) Source Identification

Identification of the locations of affected so urces including the EPA attainment/nonattainment designation of the locations and the state of the Attainment Plan for the affected area(s).”

The affected source within the Pine Be nd portion of the AQCR131/Twin Cities SO 2 

### maintenance area is Flint Hills Resources. Further information on the facili ty is included in Exhibit 1 of the Administrative Order.

3) Emissions Quantification:

“Quantification of the changes in the plan; allowable emissions from the affected sources; estimates of changes in current actual emissions from affected sources or, where appropriate, quantification of the changes in actual emissions through calculations of the differences between certain baseline levels and allowable emissions anticipated as a result of the revision.”

The changes allowed in this SIP revision result in a decrease in SO 2 

### emissions of 3250 tons per year. Further details on emission reductions are shown in the Background Document.

4) NAAQS Protections:

“The State’s demonstration that the NAAQS, prev ention of significant deterioration increments, reasonable further progress demonstration, and visibi lity, as applicable, are pr otected if the plan is approved and implemented.”

Modeling of the proposed changes at the facili ty show that the 3-hour, 24-hour and annual SO 2 

### NAAQS will be maintained, and that the facility’s impact on the one-hour standard will be decreased.