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~;JW.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 SO2 maintenance area for the 

three-hour, 24-hour, and annual SO2 National Ambient Air Quality Standards (NAAQS). Flint Hills 

Resources (FHR) is subject to an Administrative Order (Order) containing SO2 emission limits in order to 

ensure that the Pine Bend area continues to maintain the SO2 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 oil 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 protection necessary for ensuring safety for scenarios of 

this sort, while the Merox incinerator 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 and 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 currently 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 therefore 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 fired and therefore will result in a reduction of NOX, 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 Order 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 replacement. 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 other, only one oxidizer at a time may combust gases 

from the OSWTP equipment. When one oxidizer is combusting 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 revisions, 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 conducted for this SIP revision, in order to receive authorization to 

install a new boiler under the SIP. FHR has not yet filed 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 subject 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 SIP revision will add modeling parameters for Boiler 10.

Decoking Scenarios

In this SIP revision, FHR is also taking additional restrictions on steam-air decoking activities. Currently, 

FHR is limited to decoking operations of 432 hours per year at each of four of the facility’s heaters. The 

heaters are designated as 21H-1/EU032, 21H-2/EU033, 23H-1/EU037, and 23H-2/EU038. 
3

With this revision, FHR is taking an additional restriction reflecting current operations. The restriction 

allows 23H-1 and 23H-2 to be decoked simultaneously, 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 make some supporting monitoring and recordkeeping 

requirements in the Order consistent with those derived 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, velocity data, and SO2 emission rates for 

various other emission units. Finally, the update generally 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 parts 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 monitors” 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. These modifications have been completed. 

• Removal of language relating to retained PSD emission reductions from fuel oil combustion 

sources that no longer combust refinery fuel oil. 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 may 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 taken from the refinery gas system if the gas is 

categorically exempt or inherently low in sulfur 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 after 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 part of this project was added. 

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

• Addition of language so that the Merox incinerator monitoring will also apply to the 31H-2 

heater that will now combust the process gases, 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 SO2 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 point 1, the Merox TO facility, from 230 lbs SO2

per hour and 1007.4 tons SO2 per 12 months to 65.4 lbs SO2 per hour and 286.4 tons SO2 per 12 

months. 

• Reduction in emissions from emission point 8, the FCC facility, from 1500 lbs SO2 per hour and 

3504 tons SO2 per 12 months to 182.6 lbs SO2 per hour and 800 tons of SO2 per 12 months. 

• New emission limits for emission point 34, the 31H-2 heater, of 66.4 lbs SO2 per hour and 290.8 

tons SO2 per 12 months. 

Table 2: Limits on Diesel Powered Equipment

• Removal of hours of operation limit on five diesel engines, which are located at the cooling 

tower. These limits were originally taken to ensure 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 order to ensure compliance with the standards. 

3. Emission Changes 

The changes being made with this SIP revision result in significantly reduced SO2 emissions from the 

facility, as shown in the table below and described 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 -207.0 -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 SO2 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 predicts a slight increase in ambient concentrations, 

the predicted “after” concentrations remain well below the existing state one-hour standard and federal 

three-hour, 24-hour, and annual standards.

Table B: SIP9 Modeling Summary of SO2 Attainment Modeling Demonstration 

Before and After Merox Project (Short Term Standards) 

All Concentrations in μg/m3

 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 SO2 Attainment Modeling Demonstration 

Before and After Merox Project (Annual Standard) 

All Concentrations in μg/m3

 Standard1

μg/m3

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 model 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 modeling was conducted using 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 modeling. AERMOD is generally considered a more 

conservative model, and thereby often predicts higher concentrations. 

For informational purposes, FHR completed a modeling 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/m3 is the existing federal standard. Minnesota also has a state secondary standard of 60 

μg/m3

. 
7

revision. Table D, below, compares the ICSCT3 model 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/m3

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 maximum 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 three decoking scenarios for the short-term averaging 

periods. The annual average continues to reflect all heaters being decoked simultaneously. As noted 

previously, FHR is taking limitations 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 concentrations. In particular, using the same model and 

meteorology data, shows fairly significant decreased ambient concentrations for all the short-term 

averaging times. Predicted concentrations are well below the existing state one-hour and federal threehour, 24-hour and annual standards. More information can be found in Attachment 4. 

5. New NAAQS and Monitoring Data 

In June 2010, EPA promulgated a new, lower, federal one-hour SO2 standard. The modeling in this SIP 

revision addresses only the federal three-hour, 24-hour and annual average standards for SO2, along 

with the state one-hour standard. This modeling analysis 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 standard (a high-second-high form) rather than the 

federal one-hour standard (a 98th percentile or high-fourth-high form). 

In June 2011, the MPCA will submit to EPA a designation recommendation for the one-hour standard. 

Based on EPA guidance, the MPCA will be recommending an unclassifiable designation for Dakota 

County, which includes Flint Hills Resources. This unclassifiable designation is due to a lack of refined 

modeling conducted in the appropriate fashion 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: SO2 Monitoring Result Around Flint Hills2

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 parameters for all sources with a potential to emit or 

allowable emissions over 100 tons per year. The MPCA will then conduct modeling to determine those 

sources that may cause or contribute 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 required so that attainment with the one-hour SO2 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 SO2 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 Agency (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 “implementation, 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 sulfur 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 sulfur 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 99th 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 than 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 and enforce laws and promulgate rules to prevent 

water, air and land pollution throughout the state of Minnesota, 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 limitation, 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 atmosphere or to any other matter relevant to the 

prevention, abatement or control of air pollution.” 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 once 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) 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 (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 dioxide at 40 CFR § 81.324 (1991). The area now 

maintains the standard. 

12. In 1981, the EPA approved Minnesota’s State Implementation Plan (SIP) to control emissions of 

sulfur dioxide in the Twin Cities nonattainment 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 requirements 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 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. 

15. On September 2, 1983, the MPCA formally requested 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 monitored and modeled violations of the sulfur 

dioxide NAAQS in the Dakota County portion of AQCR 131. EPA published this notice at 49 FR 

47488 (December 5, 1984), and identified Dakota County 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 submitted a sulfur dioxide SIP revision for the Dakota County 

portion of AQCR 131 to EPA to resolve the SIP deficiency noted in the September 28, 1984, 

letter from EPA. The MPCA submitted a sulfur dioxide SIP revision for another portion of AQCR 

131 (i.e., the St. Paul Park area of Washington 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 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 General Rules” to fulfill the requirements of Part D of the Clean Air Act. 

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 for 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. 

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 and 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, Minnesota. 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 Minn. 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 amended, and as amended is in effect today. The 

Refinery’s current permit is Air Emission Permit 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 maintain 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, petroleum 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 submitted a sulfur dioxide state implementation plan to bring the 

Pine Bend area into attainment. The submittal included the original 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 request to EPA to redesignate the Pine Bend 

sulfur dioxide area from nonattainment to attainment. On May 31, 1995, EPA published a Direct 

Final Rule (60 FR 28339) indicating that it intended to redesignate the Pine Bend area from 

nonattainment for sulfur 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 “Control of Air Pollution from New Motor Vehicles: 

Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements.” This rule, 

effective April 10, 2000, required most refiners (including 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. 

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 civil penalties and injunctive 

relief against Koch Petroleum Group, 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 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 required changes to this Administrative Order. 

28. On January 18, 2001, EPA promulgated the “Control 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 amended 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 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. 

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 Action 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 its refinery in order to install one new process 

heater at the #3 Crude Unit and to account for additional SO2 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 install 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. SO2 emission rates for refinery fuel gas combustion at 

certain emission units and heater steam-air decoking 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 eliminates 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 the 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 dioxide 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 plan 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 sulfur dioxide NAAQS. Exhibit 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 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 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 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 control 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 operational 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 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 reference herein, for each emission point. The 

Company’s total facility emissions also shall not exceed 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 

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 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 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 fuel gas not taken from the Refinery 

fuel gas system provided that the Company install, operate, and 

maintain a hydrogen sulfide continuous 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 the 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 sulfide (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 with 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 simultaneously, and may not decoke either of 

these heaters while decoking heaters 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 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 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 Company 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 except: 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-41/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 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 WHCO Boiler 

(17H-2) or small WHCO Boiler (17H-4). 

B. Demonstration of Compliance With Emission 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 shall also comply with Part IV of this 

Order. 

2. Demonstration of Compliance With Fuel Gas Restrictions 

The Company shall implement the compliance 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 monitoring 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 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.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 Company 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 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 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 operate a modified unit in a 

manner contrary to the modeling parameters in Exhibit 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 dioxide 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 existing 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 emissions, 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 operate an existing sulfur dioxide emissions 

stack with a new stack if the height of the modified 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 structures, 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 additional 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 required 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 property 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, calibrate, operate and maintain each CEM and 

CMS as required by this Order, and shall 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 sulfur dioxide 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 EU245 (Merox 

TO), EU055 (31H-2), SV093 (SRU 3/4), SV042 (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 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 necessary to meet the requirement as soon as possible. 

2. Monitor Certification 

a) Sulfur Dioxide CEMs. The Company shall 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 not 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. The Company shall 

certify each hydrogen sulfide CMS as required by 40 CFR Part 60, Appendix B 

(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 

(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 assurance and quality control (QA/QC) 

program as required by 40 CFR Part 60, Appendix F (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. The Company shall operate and 

maintain each mass sulfur dioxide CEM system in accordance 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 SO2 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 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 monitor in 

accordance with an EPA-approved Alternative 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 hydrogen 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 requirement 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-continuous monitoring 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 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 test 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 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 accessibility needed for EPA and MPCA staff 

inspection. 
Page 15 of 22 

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 records 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 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 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 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 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 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 

maintenance 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 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 the emission limits referenced above. 

b) Sulfur Dioxide Emissions, Fuel Records 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, 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. 
Page 17 of 22 

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 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 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 operating 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. 

C. Record Maintenance 

The Company shall maintain all required 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 information in a form that is easily accessible for inspection by 

EPA or MPCA staff, and that is available for inspection at all reasonable times. 

VI. 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 emissions and 1989 
Page 18 of 22 

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 Certification 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 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. 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 than 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 subject 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 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 shutdown for maintenance) 

on any TGTU Unit. 

B. Quarterly Reports 

The Company shall submit to the Commissioner 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 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 

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 record 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 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. 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 Commissioner, the 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 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 assumed in the modeling presented in Exhibit 1, the 

Company shall obtain a modification of this Order. 

B. This Order is meant to delineate 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 performance standards, and laws and regulations related 

to occupational safety and health. In the event there 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 representatives shall have authority to enter all 

property of the Company in Rosemount, Minnesota, at all reasonable times for the purposes of 
inspecting 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 22
TABLE 1 – REFINERY EMISSION LIMITATIONS 

STACK VENT EMISSION UNIT 

FACILITY ID # SOURCE DESCRIPTION 3-HOUR AAQS (1) 24-HOUR AAQS (2) ANNUAL AAQS (3) D

LE

SV078 EU245 

34H-3 Merox TO Facility 65.4 pounds SO2

per hour 

 286.4 tons SO2

per 12 months 

Eo

SV093 EU111 and EU112 

45UNIT2-1 45UNIT3-1 

SRU 3 and SRU 4 Facility (SCOT) (5) 

149.0 pounds SO2

per hour 

86.5 pounds SO2

per hour 

324.3 tons SO2

per 12 months 

Eo

SV042 EU045 

26UNIT-1 SRU 5 Facility 

(TGTU #2) (5) 

170.8 pounds SO2

per hour 

93.6 pounds SO2

per hour 

409.8 tons SO2 

per 12 months 

Eo

SV019 EU228 

17UNIT1 FCC Facility 182.6 pounds SO2

per hour 

 800 tons SO2 per 

12 months 

Eo

SV049 EU055 

31H-2 #2 HDS Fractionation 

Heater 

66.4 pounds SO2

per hour 

 290.8 tons SO2

per 12 months 

Eo

SV125 SV146 EU282 EU254 

94H-1 94H-3 

OSWTP Facility (oxidizers(6)) 

50.71 pounds SO2 

per hour (4)

50.71 pounds SO2

per hour (4)

39.4 tons SO2 per 

12 months (9.0 lb/hr) 

Eo

(1) These emission limitations are based on three consecutive one-hour periods (3-hour rolling averages). To demonstrate comp

limitation, emissions shall be calculated 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 compl

emissions shall be calculated in such manner, except for EU282. (See (4).) (3) These emission limitations are based on a 12-month rolling average and to demonstrate compliance with the limitation, emi

calculated in such manner, except for Emission Point EU282. (See (4).) (4) This emission limitation is a one hour maximum value to be met for any one consecutive hour period. Compliance with these previously 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 of either the 94 H-1 oxidizer or the 94 H-3 oxidizer. 94 H-1 is the p

94 H-3 is the backup. Except when switching WWTP gases from one oxidizer to the other, only one oxidizer may combust gases 

at a time. The other oxidizer may be fired concurrently with natural gas for standby purposes. 
TABLE 2 – LIMITS ON DIESEL-POWERED UNITS

EMISSION UNIT FACILITY ID # DESCRIPTION ANNUAL LIMIT COM

EU131 93 P 160 Diesel-powered fire water 

pump 

1000 hours Dedicated fuel 

records hours o

EU198 M93 P 400 Diesel-powered fire water 

pump 

1000 hours Dedicated fuel 

records hours o

EU199 M93 P 570 Diesel-powered fire water 

pump 

1000 hours Dedicated fuel 

records hours o

EU042 EE 1657M Diesel-powered generator 1000 hours Dedicated fuel 

records hours o

EU007 EE 1852M Diesel-powered generator 1000 hours Dedicated fuel 

records hours o

EU036 M23 ME 26 Diesel-powered generator 1000 hours Dedicated fuel 

records hours o

EU100 EE 1309M Diesel-powered generator 1000 hours Dedicated fuel 

records hours o

EU024 EE 1718M Diesel-powered generator 1000 hours Dedicated fuel 

records hours o

EU130 M81 P 159 Diesel-powered cooling water pump No limit Dedicated fuel 

records hours o

EU132 M81 P 357 Diesel-powered cooling water pump No limit Dedicated fuel 

records hours o

EU128 M81 P 444 Diesel-powered cooling water pump No limit Dedicated fuel 

records hours o

EU129 M81 P 89 Diesel-powered cooling water pump No limit Dedicated fuel 

records hours o

 Wood River diesel Diesel-powered pump 2000 hours Dedicated fuel 

records hours o

EU127 71C-11 Diesel-powered plant air 

compressor 

2500 hours Dedicated fuel 

records hours o

EU133 M81 P 598 Diesel-powered cooling water pump No limit Dedicated fuel 

records hours o
Exhibit 1

FHR SIP Modeling

Merox Incinerator Shut Down

Prepared for 

Flint Hills Resources Pine Bend, LLC

May 2011
Exhibit 1 Table of Contents 

1 MPCA Technical Support Document (TSD) 

2 Model Protocol 

2A Merox Incinerator Removal Project Model Protocol 

2B Underline/Strikeout version 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 2nd 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 Resources 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 Analysis 
 

 

Flint Hills Resources Pine Bend, LLC

Justification for Air Quality Modeling Inputs (revised May 2011)

Introduction ............................................................................................................................................. 1

“K1_ #1SRU” 34H-3 Merox Off-Gas (old SRU 1/2) ................................................................................ 4

“K2_#3SRU” SRU 3, SRU 4, and TGTU (SCOT) Plant .......................................................................... 5

“K113__FG” SRU 3 Tail Gas Incinerator on Hot Standby ...................................................................... 7

“K3_#5SRU” SRU 5 and TGTU #2 ........................................................................................................ 8

“K8___FCC” Fluid Catalytic Cracking Unit ............................................................................................ 10

Fuel Combustion Devices ..................................................................................................................... 12

Stationary Diesel Engines ..................................................................................................................... 20

Portable Diesels .................................................................................................................................... 22

“K348_OXD” OSWTP Thermal Oxidizer ............................................................................................... 23

“K458_VNT” Platformer Catalyst Regenerator Vent ............................................................................. 25

“K459_VNT” Powerformer Catalyst Regeneration ................................................................................ 26

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

Sulfuric Acid Handing Emissions .......................................................................................................... 32

Insignificant Sources ............................................................................................................................. 34

 
 

1 

Introduction 

This document contains the supporting information used to determine the input parameters for the air 

quality modeling demonstration of compliance with National Ambient Air Quality Standards for Sulfur 

Dioxide (SO2) 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 meteorology files were used. Surface and upper air data 

were from the Minneapolis-St. Paul airport. This meteorological data set is from the same location as the 

previous SIP8 modeling, but the model years are more 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 smelting facility. Xcel Energy’s six turbine stack 

source modeled parameters were updated per Air Permit 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” SO2 background concentrations 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 concentration results. Receptor spacing of 10-meters was 

used along the facility fence line. Receptor spacing 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 receptors and end approximately 2-

kilometers from the facility boundary. 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 Survey (USGS) seamless elevation data. Receptor 

and elevation data information can be found in the electronic 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 were based on the February 2006 SIP Amendment 8 

modeling. With the update from ISC to AERMOD, the source locations were updated based on recent 

Title V PM10 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 PM10

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 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. 
 

4

SOURCE AERMOD_ID EMISSION RATE CHANGES MODEL SOURCE PARAMETER 

CHANGES 

33H-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 half 
 

5

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 source 
 

9

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. 
 

10

The modeling results are summarized in the table below. 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. For the annual averaging period, all decoking sources 

were included for the modeling. The results also demonstrate that the SO2 SIP modeling results pass 

with 34H-3 emissions still vented from the Merox stack and pass with 34H-3 emissions vented out of the 

31H-2 stack. 

 

The model results are shown graphically on the attached “dot-map” isopleths. These figures have 

colored dots representing the 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: 

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 Average Results for Decoking Scenarios as Percent of 

NAAQS 

Figures 10 through 12 - 5 Year Maximum 24-Hour Average 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/m3 

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 SO2 Attainment Modeling Demonstration

Modeling Results Summary - All SO2 Concentrations in ug/m3

May 2011
 

11

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

 A. Emission Point Description 

 B. Justification for Modeled SO2 Emission Rate 

 C. Consistency Between Modeled SO2 Emissions and Applicable State and Federal Regulations 

 D. Justification for Modeled Stack Parameters 
 

12

“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 mercaptans 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 and 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 34H-3 if necessary. 

B. Justification For Modeled SO2 Emission Rate

The hourly and annual SO2 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 

SO2 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 emissions will be re-routed to 31H-2. The 31H-2 emissions were modeled 

utilizing the 65.4 lb/hr SO2 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 the hourly emission rate basis for these annual rates 

(286.4 tpy and 290.9 tpy). 

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

There are no applicable state or federal SO2 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 application 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 transfer 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 conditions, 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 are used under start-up, shutdown and process upset 

conditions. SRU 3's bypass incinerator vents through “K113__FG” and SRU 4's bypass incinerator vents 

through “K2_#3SRU”. Under normal operating conditions the bypass incinerators are in hot standby mode 

and are fired on refinery fuel gas. The bypass incinerators were modeled in the hot-stand-by condition. 

SRU 4 bypass incinerator is also used as an incinerator for SRU 3 and SRU 4 sulfur degassing gases. 

B. Justification For Modeled SO2 Emission Rate

TGTU Emission Rate

A stack concentration of 500 ppmv was used to calculate emissions for the 1 and 3 hour averaging periods 

and a concentration of 250 ppmv was used to calculate 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 SO2 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 SO2 * 64.06 lb SO2 

 hr lbmol stack gas lbmol SO2 = 124.99 lb SO2/hr 

 For 24 hour average modeling @ 250 ppm: 

 3902.28 lbmol * 250.

10-6 lbmol SO2 * 64.06 lb SO2 

 hr lbmol stack gas lbmol SO2 = 62.49 lb SO2/hr 

 For annual modeling @ 200 ppm: 

 3902.28 lbmol * 200.

10-6 lbmol SO2 * 64.06 lb SO2

 hr lbmol stack gas lbmol SO2 = 50.00 lb SO2/hr 

SRU 4 Tail Gas Incinerator Emission Rates on Hot Standby

The SRU 4 bypass incinerator requires 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 SO2 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: 
 

14

 For the 1 hour averaging period: 

 15.477 MMBtu * 106

 Btu * 1 * 300 * 10-6 scf H2S * 1 lbmole H2S * 64 lb SO2 = 0.717 lb SO2

 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO2 Hr 

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

 15.477 MMBtu * 106

 Btu * 1 * 162 * 10-6 scf H2S * 1 lbmole H2S * 64 lb SO2 = 0.387 lb SO2

 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO2 Hr 

Sulfur Degassing

The emissions from sulfur degassing are calculated as follows: 

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

 300 ppm wt H2S equilibrium concentration in liquid sulfur 

 300 lb H2S * 2240 lb S * 450 LT S * 64.06 lb SO2 * 1 Day = 23.68 lb SO2 per hour 

 106

 lb S LT S Day 34.08 lb H2S 24 hr 

The total emission rates are: 

 1 hr average: 149.35 lb/hr SO2

 3 hr average: 149.04 lb/hr SO2

 24 hr average: 86.54 lb/hr SO2

 Annual average: 74.05 lb/hr SO2

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations 

Emissions from SRU 3 through the TGTU are limited to 250 ppmv SO2 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 SO2 on a dry, oxygen free basis as a 30 day rolling average due to a Lowest 

Achievable Emission Rate (LAER) limit. Under normal conditions, with both SRUs venting to the TGTU the 

limit is 150 ppmv SO2 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 Continuous 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. 

D. Justification For Modeled Stack Parameters 

The SRU 3/4 stack parameters shown below are consistent with SIP8 modeled parameters. The exit 

temperature and velocity were revised per an engineering 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 60.96 
 

15

“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 SO2 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 SO2 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 * 106

 Btu * 1 * 300 * 10-6 scf H2S * 1 lbmole H2S * 64 lb SO2 = 0.516 lb SO2

 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO2 Hr 

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

 11.141 MMBtu * 106

 Btu * 1 * 162 * 10-6 scf H2S * 1 lbmole H2S * 64 lb SO2 = 0.278 lb SO2

 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO2 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 SO2 emissions rate quantification from this 

stream is estimated from the SO2 ppm concentration maximum of 30 ppm. This value is determined from 

the actual demonstrated maximum as observed from January 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 lbsSO2 * 60 min * 2500 ft3

 * 1 lb-molSO2 = 0.747 lb SO2

 lb-molSO2 hr min 385.3 Hr

 

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

The fuel gas used to maintain the SRU 3 bypass incinerator 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 degassing 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 53.68 
 

16

“K3_#5SRU” SRU 5 and TGTU #2 

A. Emission Point Description

SRU 5 is a Claus sulfur recovery plant. Under normal 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 environmental control device designed to combust the tail gas 

from SRU 5 if TGTU #2 must be bypassed. SRU 5's tail 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 was modeled in the hot standby condition. SRU 5 bypass 

incinerator is also used as an incinerator for SRU 5 sulfur degassing gases. 

B. Justification For Modeled SO2 Emission Rate

This source has emissions limits of 170.8 lb SO2 per hour for 1-hour periods, 170.8 lb SO2 per hour 

averaged for 3-hour periods, and 93.6 lb SO2 per hour averaged for 24-hour periods. The 24-hour limit is 

also used as the annual modeled emission rate. Emissions from TGTU #2 are limited by NSPS J to 250 

ppm SO2 on a dry, oxygen free basis. A stack concentration of 500 ppmv was used to calculate emissions 

for the 1 and 3-hour average periods and a concentration of 250 ppmv was used to calculate emissions for 

24-hour and annual average periods. The TGTU #2 emission rate was determined from the design process 

flow rate and the stack gas SO2 concentrations as listed above. This source includes a contribution of 

15.80 lb SO2 per hour to account for emissions from sulfur de-gassing. MPCA staff has requested that Flint 

Hills Resources employ sulfur de-gassing to reduce H2S 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 SO2 * 64.06 lb SO2 = 154.55 lb SO2/hr 

 hr lbmol stack gas lbmol SO2 

 For 24 hour and annual average modeling @ 250 ppm: 

 4825.30 lbmol * 250.

10-6 lbmol SO2 * 64.06 lb SO2 = 77.28 lb SO2/hr 

 hr lbmol stack gas lbmol SO2

SRU 5 Bypass Incinerator Emission Rates on Hot Standby

The SRU 5 bypass incinerator requires 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 SO2 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 SO2 = 0.882 lbs SO2

 Hr MMBtu Hr 
 

17

For the 3, 24 hr and annual averaging periods: 20.0 MMBtu * 0.0238 lb SO2 = 0.476 lbs SO2

 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 H2S equilibrium concentration in liquid sulfur 

 300 lb H2S * 2240 lb S * 300 LT S * 64.06 lb SO2 * 1 Day = 15.80 lb SO2 per hour 

 106

 lb S LT S Day 34.08 lb H2S 24 hr 

The total emission rates are: 

 1 hr average: 171.23 lb/hr SO2

 3 hr average: 170.83 lb/hr SO2

 24 hr average: 93.56 lb/hr SO2

 Annual average: 93.56 lb/hr SO2

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

NSPS J limits the SO2 content from TGTU #2 to 250 ppmv on a dry, oxygen free basis for a twelve-hour 

period. Therefore, the 24-hour average stack concentration was limited to 250 ppmv. The 3-hour average 

emissions limit was kept at 500 ppmv in order to limit the potential 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 Continuous Emission Monitor (CEM) for TGTU 2 is now 

located on the SRU 5 main stack (K3_#5SRU) so that 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 consistent with SIP8 modeled parameters. The exit 

temperature was revised per an engineering review 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 65.0 

 
 

18

“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 cracking (breaking) the gas oil 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 catalyst are separated by cyclones. 

The reaction products (LPG, gasoline and fuel oil) are separated by distillation and sent on for further 

refinery processing. The coke deposits on the catalyst 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 SO2. 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 SO2 Emission Rate

This source is modeled at 182.6 lb/hr (800 tpy) (through K8__FCC) for 1, 3, 24-hour, and annual averaging 

periods. These emission rates represent the maximum 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 SO2 Emissions And Applicable State And Federal Regulations

The FCC is subject to NSPS J, which limits SO2 emissions to 50 ppmv; Flint Hills Resources monitors these 

emissions with a CEMS, per NSPS J requirements, to ensure compliance with this limit. An FCC SO2

emission rate of 182.6 lb SO2/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 consistent with SIP8 modeled parameters. The exit 

temperature and velocity were revised per an engineering 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 69.27 
 

19

Fuel Combustion Devices 

“K10...” 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. Boilers 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 gaseous 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 some cases sources may also burn natural gas directly 

from the natural gas supply system. Refinery fuel gas is a mixture of low molecular weight hydrocarbons 

that is produced as a byproduct of the refining process. PSA off gas is a byproduct of hydrogen 

production; its fuel value comes from carbon monoxide, 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 71B-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 SO2 limit of 3,770 ton/yr. 

Merox off-gas to 31H-2 Project:

The Merox Off-gas Incinerator feed stream will be routed 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 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 SO2 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 SO2 Emission Rate

Fuel Gas Combustion

SO2 emissions from fuel gas combustion are calculated 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 H2S analyzer is located on the outlet of each mix 

drum. The analyzers are used to monitor refinery fuel gas for compliance with applicable H2S limits. 

Since the 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 H2S 
 

20

concentration that correlates well with SO2 emissions from the combustion unit stacks, since there is not a 

significant concentration of non-H2S 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 (NSPS). These additional sulfur compounds in the 45 mix drum are 

associated with upstream processes, primarily the coker gas recovery units. Therefore, the calculated 

SO2 emission rate takes into account which fuel gas mix drum supplies each heater and boiler. Actual 

SO2 emission rates are now monitored via stack SO2 CEMS representative of 45 mix drum sourced 

heaters and via a reduced sulfur compound CEMS on the 41 mix drum. 

For this SIP Modification, SO2 emissions from the 45 mix drum fuel gas remain based on 500 ppm sulfur 

in fuel gas which equates to approximately 54 ppm SO2 at the heater stack on an O2 free basis using an 

F factor basis. The average annual concentration is proposed to be decreased from 500 ppm (SIP 8) to 

400 ppm with this modification. SO2 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. These input parameters remain consistent with SIP 8 

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. 

 

The SO2 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106

 Btu * 1 * CTRS scf sulfur (as predominantly H2S) * 

 Hr MMBtu FG HHV Btu/scf 106

scf Fuel Gas 

 1 lbmole sulfur (as H2S) * 64 lb SO2 * 453.59 g * 1 Hr = _____ gram SO2

 379 scf lbmole SO2 lb 3600 sec sec 

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

Heater Duty MMBtu * 8511 dscf flue gas * CSO2 scf sulfur (as SO2 @ 0% O2) * 

 Hr MMBtu 106 dscf Flue Gas 

 1 lbmole SO2 * 64 lb SO2 * 453.59 g * 1 Hr = _____ gram SO2

 379 scf lbmole SO2 lb 3600 sec sec 
 

21

The heating values were assigned to heaters and boilers as follows: 

In many cases, refinery fuel gas is used to calculate the SO2 emission rate for sources combusting 

natural gas and PSA off gas. Since the H2S content of refinery fuel gas is higher than the sulfur content 

of natural gas and PSA off gas, the modeled emission rate is conservative. 

 Commercial natural gas sulfur content is limited to 0.02 gr/dscf vs. the NSPS refinery fuel gas 

limit of 0.10 gr H2S/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 H2S. 

SO2 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 routed 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 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 SO2 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 

Description

 ISC_id HHV 

Btu/scf

Source 

Description

 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-1A 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 2010
 

22

C. Consistency Between Modeled SO2 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 H2S in fuel 

gas burned in new fuel gas combustion devices (heaters and boilers) to 0.1 gr per dscf. This 

concentration can be converted to ppm as follows: 

 0.10 gr/dscf of H2S at 1 atm, 20C 

 0.10 gr * 1 lb H2S * 1 lbmol H2S * 385.4 dscf * 106

 = 162 ppm 

 dscf 7000 gr 34.076 lb H2S lbmol H2S 

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

 dscf/lbmol: 1 lbmol = 359.05 ft3

 at 0C, 1 ATM 

 359.05 ft3

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

 273K 

Minnesota rules 7005.2110 subpart 2 and 7005.2120 subpart 3 limit the sulfur content of fuels burned in 

new and existing indirect heating equipment (heaters and boilers) to 3.0 lb SO2/MMbtu for any individual 

piece of equipment and 1.75 lb SO2/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 fired 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 converted to one carbon dioxide (CO2) atom. 

 Two hydrogen (H) atoms are converted to one water (H2O) 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 CO2 per scf fuel, scf H2O per scf fuel and scf N2 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 41 mix drumSCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF 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 45 mix drumSCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF 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
 

24

 

The modeled stack velocity is calculated as follows: 

 Stack velocity = Heater Duty MMBtu * 1 * scf flue gas * 1 Hr * 0.028317 m3 * 

 Hr 2 MMBtu 3,600 sec ft3 

 T°K * 1 = _____ exit vel m/sec 

 288.7K (D2

/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) 

#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 11,113
 

25

The actual stack height is used in the modeling except 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_DSL”, “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 the 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 extended 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. They 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 Source 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 compressor 71C-11. This diesel will operate less than 

2500 hours per year. 

B. Justification For Modeled SO2 Emission Rate 

The SO2 emission rates for the diesel engines are based on AP-42 emission factors. The AP-42 factors 

are accepted standards, which will be used frequently in the future for a variety of pollutants. These 

emission factors have been scaled down based on the sulfur 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 SO2 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 SO2/hp-hr and 0.29 lb SO2/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 emission factor is calculated to be: 

0.29 lb SO2 * 1 lb S * 1 MMBtu * 19,300 Btu * 100% = 0.280% S 

MMBtu fuel 2 lb SO2 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 SO2

 Hp-Hr 0.28%S. 1 lb 3600 Sec Hp-Hr 
 

27

ENGINES > 600 hp: 5.097E-5 g/s SO2 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 diesel fuel. Converting to g/s with 0.0015%S diesel 

fuel: 

8.09 E-3 lb SO2 * 0.0015%S * 453.59 g * 1 Hr = 1.58 E-6 g/s SO2

 Hp-Hr 1 lb 3600 S Hp-Hr 

 

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

Minnesota Rule 7005.1200 Subpart 2 limits SO2 emissions from stationary internal combustion engines to 

1.75 lb SO2 per million BTU actual heat input. These emission points will be limited to diesel fuel 

containing no more than 0.0015 % sulfur in the Clean Fuels Permit. At this sulfur content, SO2 emissions 

from combustion of diesel fuel are limited to 0.0015 lb S02 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. The 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 velocity 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 106

 Btu D2 (m) 50% D2
 

28

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 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 excludes non-road engines; therefore, the portable diesels do not need to be included 

in the SIP modeling analysis. 

The non-road definitions that apply to the portable diesels 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 diesels, 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 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 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 source 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 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 process 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 biologically 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 covered. They are connected to the Oxidizer by a duct 

system. The Oxidizer blower pulls a vacuum on the duct system to pull the treating air containing Volatile 

Organic Compounds (VOC's) and odors from the treatment tanks into the Oxidizer. The air and VOC's 

flow from the blower discharge into a heat exchanger. The heat exchanger uses hot stack gases to 

preheat the oxidizer feed. A natural gas fired burner heats the oxidizer feed up to approximately 1,400F 

and the VOC's are oxidized into CO2 and Water. The de-contaminated 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 SO2 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 when the main thermal oxidizer is out of service. Flint Hills Resources 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 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 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 oxidizer operation at the wastewater plant. 

B. Justification For Modeled SO2 Emission Rate

The wastewater feed to the OSWTP contains small amounts of odorous sulfur bearing compounds (H2S 

and mercaptans). These compounds are transferred from the wastewater to the treating air in the basins 

and are oxidized to SO2 in the oxidizer. Stack testing indicated that this source has shown emission rates 

as high as 6.2 lb/hr SO2. 

For the 1, 3 and 24 hour 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 

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 H2S * 1 lbmole H2S * 64 lb SO2 * 453.59 gm * 1 Min = 6.389 gram SO2

 Min scf Fuel Gas 385 scf lbmole SO2 lb 60 sec sec 

The annual emission rate, the oxidizer was modeled at 9.0 lb SO2/hr. This limits SO2 emissions from the 

WWTP thermal oxidizer to an emission rate which is below the PSD major modification threshold of 40 

ton/yr SO2. 
 

30

C. Consistency Between Modeled SO2 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 Subpart QQQ). This standard does not address SO2 emissions 

from VOC control devices for petroleum refinery wastewater systems. 

The Oxidizer uses only natural gas as its fuel source. There are no other applicable state or federal SO2

emissions standards. 

D. Justification For Modeled Stack Parameters

With the exception of stack temperature, the Thermal Oxidizer stack parameters are consistent with 

parameters modeled for SIP 8 and listed below. The stack 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 ft3

/min * 1 min / 60 sec * 4 / [ (5.63 ft)2] = 33.53 ft/sec = 10.36 m/sec 
 

31

Process Heater Steam-Air Decoking 

Sources “K600_DEC” through “K603_DEC”. 

A.Emission Point Description

The tubes inside of process heaters become fouled with coke during operation. The coke formation on 

the inside of the heater tubes reduces the heat transfer 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 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, steam 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 temperatures. Next, air is injected at a controlled rate 

to oxidize the coke. Water is injected 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 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. The 

21 unit heaters (21 H-1 and 21 H-2) are routed to enclosed 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 simultaneously. The 21 unit heaters are not decoked 

simultaneously with each other or the 23 unit heaters. 

B. Justification For Modeled SO2 Emission Rate 

With SIP modification 9 (2010), FHR is refining the former emission rate basis to improve the accuracy of 

both the uncontrolled and controlled emission rates. 

Uncontrolled Emission Rate Basis 

The SO2 emission rates calculated for decoking process heaters are based on the sulfur content of the 

coke, the amount of air used to decoke the heater, and the SO2 removal efficiency of the quench system. 

The coke which forms in the tubes of the delayed coking 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) + O2(g) --> CO2(g) s [=] solid, g [=] gas 

 S(s) + O2(g) --> SO2(g) 

 (Assume all carbon is completely oxidized to CO2, and all sulfur is oxidized to SO2.) 
 

32

Since 1 mole of CO2 is produced per mole of O2 consumed, and 1 mole of SO2 is produced per mole of 

O2 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 (O2) in the decoking air is consumed, heater decoking SO2

emissions are calculated for each pound of oxygen in the decoking air as follows: 

 

lb O2 = 1 lb C * 1 lbmol C * 1 lbmol O2 * 32 lb O2 + 1 lb S * 1 lbmol S * 1 lbmol O2 * 32 lb O2

 12 lb C lbmol C lbmol O2 32 lb S lbmol S lbmol O2

 which reduces to: lb O2 = 2.667 * lb C + lb S 

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

 lb O2 = 2.667*(lb coke - lb S) + lb S = 2.667 * lb coke - 1.667 lb S 

 lb O2 / 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 SO2, 2 lb O2 / lb SO2 = 2.667/ (wt frac S) - 1.667 

 Rearranging, lb SO2 = lb O2 * [(1.333/wt frac S) - 0.833]-1

The amount of O2 used in decoking can be determined from the decoking air use rate as follows: 

 lb O2 = Air SCF/min * 60 min/hr * Burn Time hr * 1 lbmol air * 29 lb air * 0.232 lb O2

 379 SCF lbmol air lb air 

This reduces to the following equation: lb O2 = Air SCF/min * Burn Time hr * 1.064 

lb SO2 = 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 (O2) addition rates metered during past heater 

decoking events to calculate worst case uncontrolled SO2 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 calculates 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 content, time required to decoke, and the stoichiometry 

detailed above, uncontrolled emission rate potentials are calculated. 

Heater Total O2

Consumption (lbs) 

Decoke Duration 

(hrs) 

Ave Uncontrolled 

SO2 rate (lb/hr) 

Peak Uncontrolled 

SO2 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 SO2 emitted = lb SO2 *(1- Quench System SO2 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 the quench pit of the 21-1 unit during a decoking event, the company 

proposes to model all heater decoking as sources with emission controls. 

Heater Decoking 

These sources are quenched in a piping 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 long 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 contracted Pace Analytical to utilize stack test methods to quantify SO2 

emission rates during a heater burn. The tests were conducted for approximately 12 hours during the 

peak air addition rate periods of the burn. An air mover 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 uncontrolled emission rate and that measured during the 21-

1 burn: 

4.0 lb SO2 emitted = 49.4 lb SO2 *(1- Quench System SO2 Removal Efficiency/100%) 

A control efficiency of 92% is estimated. However, while the air mover likely captured the vast majority of 

emissions which released with the non-condensable burn related 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 1st quarter 2011). 

(4.0) lb SO2 emitted * (2 lb emitted / 1 lb Captured) = 49.4 lb SO2 *(1- Quench System SO2 Removal 

Efficiency/100%) 

A control efficiency of 84% is therefore estimated. FHR proposes to utilize the same control efficiency at 

each of the other heaters due to the similarities 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 SO2 emissions from heater decoking are summarized in the following table: 

Heater Peak Uncontrolled 

SO2 rate (lb/hr) 

Control 

Efficiency 

Peak Hourly Controlled 

SO2 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 simultaneous burns and discharge location in the model with a 

combined emission rate of 20.2 lb/hr. 
 

34

Volume Source SO2 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) and 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) releasing from the water surface. The volume 

source emission rate for sources 601 - 603 is shown in the following table: 

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

There are no state or federal emissions standards 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 are 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.

SO2 Emissions

Heater Decoking SO2 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

Source
 

35

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 SO2. FHR has found that some of this SO2 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 Sulfuric 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 acid tank. Empty rail cars are used to ship out spent 

acid for re-processing. Spent acid is loaded into rail 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 knock 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 tank 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 SO2 Emission Rate 

SO2 emissions occur during the filling of rail cars and storage tanks. SO2 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, SO2 emissions are estimated to be 

approximately 1 lb SO2/hr from each emission point. Emission were calculated as follows: 

 Acid Loading gal * 1 ft3

 * 60 min * PPM SO2 * 1 lb-mole * 64.06 lb SO2 = lb SO2 

 min 7.48 gal hr 1E +06 379.5 scf lb-mole hr 

 

An emission rate of 2.27 lb SO2/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, SO2 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 rate from storage tanks. The other two spent acid 

tanks are not included in the SO2 emission calculation because they are either being emptied to rail 

loading or have a constant level during gravity separation of acid and hydrocarbon liquids. 
 

36

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

There are no state or federal emissions standards 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 impact 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 contents of 0 ppm – 1 ppm. At these levels, the SO2 

emission rate is 0.00015 lb SO2/MMBtu. As an example, a 100 MMBtu/hr heater would emit 0.015 lb SO2

/Hr vs. 2.38 lb SO2/Hr for refinery fuel gas at 162 ppm H2S. 

Source Fuel Source 

 PPM H2S1

Emission Rate 

Lb/Hr SO2

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 2006 Model Protocol for 

the #3 Crude Expansion Project

Flint Hills Resources Pine Bend LLC

Ambient Air Quality Modeling Analysis
 

 

Flint Hills Resources LPPine Bend, LLC

Justification for Air Quality Modeling Inputs (revised February 2006May 2011)

Introduction ............................................................................................................................................. 1

“K1_ #1SRU” 34H-3 Merox Off-Gas (old SRU 1/2) ................................................................................ 4

“K2_#3SRU” SRU 3, SRU 4, and TGTU (SCOT) Plant .......................................................................... 5

“K113__FG” SRU 3 Tail Gas Incinerator on Hot Standby ...................................................................... 7

“K3_#5SRU” SRU 5 and TGTU #2 ........................................................................................................ 8

“K8___FCC” Fluid Catalytic Cracking Unit ............................................................................................ 10

Fuel Combustion Devices ..................................................................................................................... 12

Stationary Diesel Engines ..................................................................................................................... 20

Portable Diesels .................................................................................................................................... 22

“K348_OXD” OSWTP Thermal Oxidizer ............................................................................................... 23

“K458_VNT” Platformer Catalyst Regenerator Vent ............................................................................. 25

“K459_VNT” Powerformer Catalyst Regeneration ................................................................................ 26

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

Sulfuric Acid Handing Emissions .......................................................................................................... 32

Insignificant Sources ............................................................................................................................. 34

 
 

1 

Introduction 

This document contains the supporting information used to determine the input parameters for the air 

quality modeling demonstration of compliance with National Ambient Air Quality Standards for Sulfur 

Dioxide (SO2) for the Pine Bend, Minnesota area. The text also includes a placeholder for future 

revisions to the NOx emissions justification; no updates for NOx 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 meteorological 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 original 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. In this submittal, the restricted access 

receptors on CNRC property were added to the general receptor grid. So, this 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 image 3734), which are referenced in UTM NAD83 datum 

coordinates. Individual source coordinates were converted to UTM’s using the refinery 0,0 coordinate as 

a basis. These coordinates have all been converted to NAD83 and adjusted per the (0,0) refinery 

coordinates. The 1992 SIP modeling was conducted 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 base 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 (11 H-6, Boiler #6, and Boiler 

#9). In addition, building downwash parameters from 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 coordinates 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 Project and the #3 Crude Unit Expansion Project. The new structures include 

the heater/reactor structure for the new #4 Hydrogen Plant and the reactor structure for the 

Hydrocracking Unit. The structure inventory for the existing refinery was also upgraded to include 

building wake effects associated with the #2 Hydrogen 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 future and existing refinery structures on new ULSD 
 

2

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 SO2 Attainment Modeling Demonstration

Modeling Results Summary - All SO2 Concentrations in ug/m3

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/m3 

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 meteorology files were used. Surface and upper air data 

were from the Minneapolis-St. Paul airport. This meteorological data set is from the same location as the 

previous SIP8 modeling, but the model years are more 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 smelting facility. Xcel Energy’s six turbine stack 

source modeled parameters were updated per Air Permit 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 
 

4

from 530 lb/hr to 2,080 lb/hr. The MPCA 2008 Option 2 “Rest of TC” SO2 background concentrations 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 concentration results. Receptor spacing of 10-meters was 

used along the facility fence line. Receptor spacing 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 receptors and end approximately 2-

kilometers from the facility boundary. 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 Survey (USGS) seamless elevation data. Receptor 

and elevation data information can be found in the electronic 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 were based on the February 2006 SIP Amendment 8 

modeling. With the update from ISC to AERMOD, the source locations were updated based on recent 

Title V PM10 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 PM10

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 

CHANGES

33H-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 half 
 

8

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 source
 

12

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 below. 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. For the annual averaging period, all decoking sources 

were included for the modeling. The results also demonstrate that the SO2 SIP modeling results pass 

with 34H-3 emissions still vented from the Merox stack and pass with 34H-3 emissions vented out of the 

31H-2 stack. 

 

The model results are shown graphically on the attached “dot-map” isopleths. These figures have 

colored dots representing the high second highmaximum 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: 

crs41h3.out SIPso1hR700 - SIPso1hR704 = 1-hour average time using 19732000-2004 meteorological 

data 

crs41h4.out = 1SIPso3hR900 - SIPso3hR904 = 3-hour average time using 19742000-2004

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/m3 

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 SO2 Attainment Modeling Demonstration

Modeling Results Summary - All SO2 Concentrations in ug/m3

May 2011
 

14

crs41h5.out = 1SIPso24hR900 - SIPso24hR904 = 24-hour average time using 19752000-2004

meteorological data 

crs41h6.out = 1-hourSIPsoannR800 - SIPsoannR804 = Annual average time using 19762000-2004

meteorological data 

crs41h7.out = 1-hour average time using 1977 meteorological data

crs43h3.out = 3-hour average time using 1973 meteorological data

crs43h4.out = 3-hour average time using 1974 meteorological data

crs43h5.out = 3-hour average time using 1975 meteorological data

crs43h6.out = 3-hour average time using 1976 meteorological data 

crs43h7.out = 3-hour average time using 1977 meteorological data

crs424h3.out = 24-hour average time using 1973 meteorological data

crs424h4.out = 24-hour average time using 1974 meteorological data

crs424h5.out = 24-hour average time using 1975 meteorological data

crs424h6.out = 24-hour average time using 1976 meteorological data 

crs424h7.out = 24-hour average time using 1977 meteorological data

crs4an3.out = annual average time using 1973 meteorological data

crs4an4.out = annual average time using 1974 meteorological data

crs4an5.out = annual average time using 1975 meteorological data

crs4an6.out = annual average time using 1976 meteorological data 

crs4an7.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 SO2 Emission Rate 

C. Reserved for Updated Justification of Modeled NOx Emission Rate 

D C. Consistency Between Modeled SO2 Emissions and Applicable State and Federal 

Regulations 

ED. Justification for Modeled Stack Parameters 
 

15

“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 mercaptans 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 and 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 34H-3 if necessary.

B. Justification For Modeled SO2 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 of monitoring 

data from the period April 1999- June 2000.

 

C. Reserved for Updated Justification of Modeled NOx Emission Rate

 

DThe hourly and annual SO2 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 

SO2 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 emissions will be re-routed to 31H-2. The 31H-2 emissions were modeled 

utilizing the 65.4 lb/hr SO2 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 the hourly emission rate basis for these annual rates 

(286.4 tpy and 290.9 tpy). 

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

There are no applicable state or federal SO2 emissions standards for this source. 

ED. 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 parameters. 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 stack exit diameter by the stack 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 diameter @ probe location = 5' 5" = 5.42 ft
 

16

Measured stack velocity = 11.4 ft/sec 

Stack exit velocity = Measured velocity * 5.422 = 12.6 ft/sec

 5.172

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 emissions in the event technical issues arise that prevent the transfer 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 conditions, 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 are used under start-up, shutdown and process upset 

conditions. SRU 3's bypass incinerator vents through “K113__FG” and SRU 4's bypass incinerator vents 

through “K2_#3SRU”. Under normal operating conditions the bypass incinerators are in hot standby mode 

and are fired on refinery fuel gas. The bypass incinerators were modeled in the hot-stand-by condition. 

SRU 4 bypass incinerator is also used as an incinerator for SRU 3 and SRU 4 sulfur degassing gases. 

B. Justification For Modeled SO2 Emission Rate

TGTU Emission Rate

A stack concentration of 500 ppmv was used to calculate emissions for the 1 and 3 hour averaging periods 

and a concentration of 250 ppmv was used to calculate 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 SO2 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 SO2 * 64.06 lb SO2 

 hr lbmol stack gas lbmol SO2 = 124.99 lb SO2/hr 

 For 24 hour average modeling @ 250 ppm: 

 3902.28 lbmol * 250.

10-6 lbmol SO2 * 64.06 lb SO2 

 hr lbmol stack gas lbmol SO2 = 62.49 lb SO2/hr 

 For annual modeling @ 200 ppm: 

 3902.28 lbmol * 200.

10-6 lbmol SO2 * 64.06 lb SO2

 hr lbmol stack gas lbmol SO2 = 50.00 lb SO2/hr 

SRU 4 Tail Gas Incinerator Emission Rates on Hot Standby

The SRU 4 bypass incinerator requires 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 SO2 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 * 0.0441106

 Btu * 1 * 300 * 10-6 scf H2S * 1 lbmole H2S * 64 lb SO2 = 

0.68717 lb SO2

 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO2 Hr 

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

 15.477 MMBtu * 0.0238106

 Btu * 1 * 162 * 10-6 scf H2S * 1 lbmole H2S * 64 lb SO2 = 

0.37387 lb SO2

 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO2 Hr 

Sulfur Degassing

The emissions from sulfur degassing are calculated as follows: 

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

 300 ppm wt H2S equilibrium concentration in liquid sulfur 

 300 lb H2S * 2240 lb S * 450 LT S * 64.06 lb SO2 * 1 Day = 23.68 lb SO2 per hour 

 106

 lb S LT S Day 34.08 lb H2S 24 hr 

The total emission rates are now: 

 1 hr average: 149.35 lb/hr SO2

 3 hr average: 149.04 lb/hr SO2

 24 hr average: 86.54 lb/hr SO2

aAnnual average: 74.05 lb/hr SO2

C. Reserved for Updated Justification of Modeled NOx Emission Rate 

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations 

Emissions from SRU 3 through the TGTU are limited to 250 ppmv SO2 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 SO2 on a dry, oxygen free basis as a 30 day rolling average due to a Lowest 

Achievable Emission Rate (LAER) limit. Under normal conditions, with both SRUs venting to the TGTU the 

limit is 150 ppmv SO2 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 Continuous 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. 

ED. Justification For Modeled Stack Parameters 

The company proposes to update the SRU 3/4 stack parameters shown below are consistent with the 

following:SIP8 modeled parameters. The exit temperature and velocity were revised per an engineering 

review of historical operating data. 

Parameter Proposed Value HistoricalSIP8

Value 

Stack Exit Velocity m/sec 17.416 21.717.4
 

19

Stack Exit Temperature K 519.3578 547.04519.3

Stack Exit Diameter m 1.448 1.448 

Stack Height m 60.96 60.96 
 

20

The SRU 3/4 SO2 CEM system was recently relocated from the TGTU incinerator outlet 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 stack velocity by 20% from this value to provide a margin 

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 SO2 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 SO2 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 SO2 = 0.49106

 Btu * 1 * 300 * 10-6 scf H2S * 1 lbmole H2S * 64 lb 

SO2 = 0.516 lb SO2

 Hr MMBtu 1093 Btu/scf scf Fuel Gas 379 scf lbmole SO2 Hr 

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

 11.141 MMBtu * 0.0238106

 Btu * 1 * 162 * 10-6 scf H2S * 1 lbmole H2S * 64 lb SO2 = 

0.27278 lb SO2

 Hr MMBtu HrMMBtu 1093 Btu/scf scf Fuel Gas 379 scf 

lbmole SO2 Hr 

C. Reserved for Updated Justification of Modeled NOx Emission Rate

 

DThe 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 SO2 emissions rate quantification from this 

stream is estimated from the SO2 ppm concentration maximum of 30 ppm. This value is determined from 

the actual demonstrated maximum as observed from January 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 lbsSO2 * 60 min * 2500 ft3 * 1 lb-molSO2 = 0.747 lb SO2

 lb-molSO2 hr min 385.3 Hr

 

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

The fuel gas used to maintain the SRU 3 bypass incinerator 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 degassing are not subject to 

this restriction. 

ED. Justification For Modeled Stack Parameters
 

21

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 53.68
 

22

“K3_#5SRU” SRU 5 and TGTU #2 

A. Emission Point Description

SRU 5 is a Claus sulfur recovery plant. Under normal 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 environmental control device designed to combust the tail gas 

from SRU 5 if TGTU #2 must be bypassed. SRU 5's tail 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 was modeled in the hot standby condition. SRU 5 bypass 

incinerator is also used as an incinerator for SRU 5 sulfur degassing gases. 

B. Justification For Modeled SO2 Emission Rate

This source has emissions limits of 170.8 lb SO2 per hour for 1-hour periods, 170.8 lb SO2 per hour 

averaged for 3-hour periods, and 93.6 lb SO2 per hour averaged for 24-hour periods. The 24-hour limit is 

also used as the annual modeled emission rate. Emissions from TGTU #2 are limited by NSPS J to 250 

ppm SO2 on a dry, oxygen free basis. A stack concentration of 500 ppmv was used to calculate emissions 

for the 1 and 3-hour average periods and a concentration of 250 ppmv was used to calculate emissions for 

24-hour and annual average periods. The TGTU #2 emission rate was determined from the design process 

flow rate and the stack gas SO2 concentrations as listed above. This source includes a contribution of 

15.80 lb SO2 per hour to account for emissions from sulfur de-gassing. MPCA staff has requested that Flint 

Hills Resources employ sulfur de-gassing to reduce H2S 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 SO2 * 64.06 lb SO2 = 154.55 lb SO2/hr 

 hr lbmol stack gas lbmol SO2 

 For 24 hour and annual average modeling @ 250 ppm: 

 4825.30 lbmol * 250.

10-6 lbmol SO2 * 64.06 lb SO2 = 77.28 lb SO2/hr 

 hr lbmol stack gas lbmol SO2

SRU 5 Bypass Incinerator Emission Rates on Hot Standby

The SRU 5 bypass incinerator requires 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 SO2 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 SO2 = 0.882 lbs SO2

 Hr MMBtu Hr 
 

23

For the 3, 24 hr and annual averaging periods: 20.0 MMBtu * 0.0238 lb SO2 = 0.476 lbs SO2

 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 H2S equilibrium concentration in liquid sulfur 

 300 lb H2S * 2240 lb S * 300 LT S * 64.06 lb SO2 * 1 Day = 15.80 lb SO2 per hour 

 106

 lb S LT S Day 34.08 lb H2S 24 hr 

The total emission rates are now: 

 1 hr average: 171.23 lb/hr SO2

 3 hr average: 170.83 lb/hr SO2

 24 hr average: 93.56 lb/hr SO2

aAnnual average: 93.56 lb/hr SO2

C. Reserved for Updated Justification of Modeled NOx Emission Rate

D

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

NSPS J limits the SO2 content from TGTU #2 to 250 ppmv on a dry, oxygen free basis for a twelve-hour 

period. Therefore, the 24-hour average stack concentration was limited to 250 ppmv. The 3-hour average 

emissions limit was kept at 500 ppmv in order to limit the potential 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 Continuous Emission Monitor (CEM) for TGTU 2 is now 

located on the SRU 5 main stack (K3_#5SRU) so that 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. 

ED. Justification For Modeled Stack Parameters

The company proposes to update the SRU 53/4 stack parameters shown below are consistent with the 

following:SIP8 modeled parameters. The exit temperature was revised per an engineering review of 

historical operating data. 

Parameter Proposed Value HistoricalSIP8

Value 

Stack Exit Velocity m/sec 9.3 11.69.3

Stack Exit Temperature K 449.82464 449.82 

Stack Exit Diameter m 2.103 2.103 

Stack Height m 65.0 65.0 

 
 

24

The SRU 5 SO2 CEM system was recently relocated from the TGTU incinerator 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 stack velocity by 20% from this 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 cracking (breaking) the gas oil 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 catalyst are separated by cyclones. 

The reaction products (LPG, gasoline and fuel oil) are separated by distillation and sent on for further 

refinery processing. The coke deposits on the catalyst 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 SO2. 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 SO2, Federal GEP Guidelines require that the source be modeled for SO2 with the existing 

stack exit parameters unless the source emits less than 5000 Ton/yr of SO2. Since Flint Hills Resources

committed to this emission limit, the old stack parameters need no longer be used for SO2. 

B. Justification For Modeled SO2 Emission Rate

This source is modeled at 1,500182.6 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 periods. These emission rates are 

consistent with the current permittedrepresent 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 NOx Emission Rate 

D

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

The FCC is subject to NSPS J, which limits SO2 emissions to 50 ppmv; Flint Hills Resources monitors these 

emissions with a CEMS, per NSPS J requirements, to ensure compliance with this limit. An FCC SO2

emission rate of 1,500182.6 lb SO2/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 consistent with SIP8 modeled parameters. The exit temperature and velocity 

were revised per an engineering review of historical operating data. 

Parameter ModeledProposed

Value 

MeasuredSIP8

Value 

Stack Exit Velocity m/sec 15.5424 30.0015.54

Stack Exit Temperature K 449.8366 488.5449.8

Stack Exit Diameter m 2.94 2.94 
 

26

Stack Height m 69.27 69.27 

The stack conditions, which have generated 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 historical model inputs, it seems appropriate 

to reduce the FCC stack parameters. The proposed stack conditions include a reduction in stack velocity by 

15% from this value to provide a margin of safety in the modeled impact of the FCC. 

Note that the actual stack height 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 

“K710...” 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. Boilers 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 gaseous 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 some cases sources may also burn natural gas directly 

from the natural gas supply system. Refinery fuel gas is a mixture of low molecular weight hydrocarbons 

that is produced as a byproduct of the refining process. PSA off gas is a byproduct of hydrogen 

production; its fuel value comes from carbon monoxide, 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. 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 71B-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 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 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 SO2 limit of 3,770 ton/yr and uses 

the common stack for all boiler house SO2 modeling as allowed under PSD regulations for sources 

emitting less than 5000 Ton/yr of SO2. 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 separate 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 installed three new process heaters 

(29H-1, 29H-2 and 30H-401) and a diesel powered emergency cooling water 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 the 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 29H-2 

was used to determine the SO2 emission rate to account for the maximum potential 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 velocity associated with constructing two separate 

heaters. The locations of the two 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 heaters 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 routed 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 
 

28

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 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 SO2 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 SO2 Emission Rate

Fuel Gas Combustion

SO2 emissions from fuel gas combustion are calculated 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 

SO2sulfur 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 H2S analyzer is located on the outlet of each mix 

drum. The analyzers are used to monitor refinery fuel gas for compliance with applicable H2S limits. 

Since the make upmakeup 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 H2S concentration that correlates well with SO2 emissions from the combustion unit stacks, since there 

is not a significant concentration of non-H2S 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 (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 sulfur levels in the 45 mix drum and not in the 41 mix drum was determined by the placing and 

measurement of SO2 monitors in heaters 25H-3 (representing the 45 mix drum) and 11H-6 (representing 

the 41 mix drum). Therefore, the calculated SO2 emission rate takes into account which fuel gas mix 

drum supplies each heater and boiler. Actual SO2 emission rates are now monitored via stack SO2 CEMS 

representative of 45 mix drum sourced heaters and via a reduced sulfur compound CEMS on the 41 mix 

drum. 

For this SIP Modification, SO2 emissions from the 45 mix drum fuel gas remain based on 500 ppm sulfur 

in fuel gas which equates to approximately 54 ppm SO2 at the heater stack on an O2 free basis using an 

F factor basis. The average annual concentration is proposed to be decreased from 500 ppm (SIP 8) to 

400 ppm with this modification. SO2 emissions from the 41 mix drum fuel gas isare conservatively based 

on the H2S content reduced sulfur contents limited to 162300 ppm for the 1-hour, 3-hour, and 24-hour, 

and annual averaging periods and 300162 ppm H2Sreduced sulfur for the 1-hourannual averaging period. 

For heaters and boilers firing fuel gas from the 45 mix drum,These input parameters remain consistent 

with SIP 8 with the H2S content is conservatively assumed to be 500 ppm for allexception 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 SO2 emissions per MMbtu (106 btu) per hour of fuel burned at the fuel sulfur content limitsfrom fuel 

gas firing for each mix drum are calculated as follows: 

1 Hour Fuel Gas SO2 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106

 Btu * 1 * 30010-6CTRS scf sulfur (as predominantly H2S * 1 

lbmole H2S * 64 lb SO2) * 

 Hr MMBtu FG HHV Btu/scf 106scf Fuel Gas 379 scf 

 1 lbmole SO2

sulfur (as H2S) * 64 lb SO2 * 453.59 gmg * 1 Hr = _____ gmgram SO2

 379 scf lbmole SO2 lb 3600 sec sec 

3 Hour, 24 Hour, and Annual Fuel Gas SO2 Emissions @ 162 ppm

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

Heater Duty MMBtu * 1106 Btu * 1 * 16210-6 scf H2S * 1 lbmole H2S * 64 lb SO2 

8511 dscf flue gas * CSO2 scf sulfur (as SO2 @ 0% O2) * 

 Hr MMBtu FG HHV Btu/scf scf Fuel 106 dscf Flue Gas 

379 scf 

 1 lbmole SO2 * 64 lb SO2 * 453.59 gmg * 1 Hr = _____ gmgram SO2

 379 scf lbmole SO2 lb 3600 sec sec 

1, 3, 24 hour and Annual Fuel Gas SO2 Emissions at 500 ppm (Oxygen Free)

106 Btu * 1 scf * 500ppm * 1 MMBtu = 4.48 *10-5 ppm*MMBtu = 45 ppm*Btu

 Hr 1093 Btu 106 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 1093
 

30

Refinery
 

31

The heating values were assigned to heaters and boilers as follows: 

In many cases, refinery fuel gas is used to calculate the SO2 emission rate for sources combusting 

natural gas and PSA off gas. Since the H2S content of refinery fuel gas is higher than the sulfur content 

of natural gas and PSA off gas, the modeled emission rate is conservative. 

 Commercial natural gas sulfur content is limited to 0.02 gr/dscf vs. the NSPS refinery fuel gas 

limit of 0.10 gr H2S/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 H2S. 

SO2 Emissions from refinery fuel oil combustion

Historically, the refinery has usedEmissions from refinery fuel oil as an energy source. Thecombustion 

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 routed 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 SO2 emission reduction credits for PSD netting purposes. To ensureevent 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 SO2 emissions monitoring data from December 31, 2005 through July 31, 2009. This effectively 

reduced the modeled with an SO2hourly emission rate equalfrom 230 lb/hr to 65.4 lb/hr and the sum of its 

maximum SO2annual emission rate burning refinery fuel gas plus its historical average SO2 emission rate 

from fuel oil combustion. No SO2 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 modeled in this latest model run for PSD netting 

purposes, but they were removed from service and replaced by heater 11H-6rate. 

Source 

Description

 ISC_id HHV 

Btu/scf

Source 

Description

 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-1A 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 2010
 

32

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 requirement 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 emission rate in gm/sec is calculated as follows:

Historical FO use Bbl * 388 lb * 0.922 % S * 2lb SO2 * 453.59 gm * 1 yr * 1 Hr = ___ gm SO2

 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 NOx Emission Rate

 

D
 

33

C. Consistency Between Modeled SO2 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 H2S in fuel 

gas burned in new fuel gas combustion devices (heaters and boilers) to 0.1 gr per dscf. This 

concentration can be converted to ppm as follows: 

 0.10 gr/dscf of H2S at 1 atm, 20C 

 0.10 gr * 1 lb H2S * 1 lbmol H2S * 385.4 dscf * 106

 = 162 ppm 

 dscf 7000 gr 34.076 lb H2S lbmol H2S 

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

 dscf/lbmol: 1 lbmol = 359.05 ft3

 at 0C, 1 ATM 

 359.05 ft3

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

 273K 

Minnesota rules 7005.2110 subpart 2 and 7005.2120 subpart 3 limit the sulfur content of fuels burned in 

new and existing indirect heating equipment (heaters and boilers) to 3.0 lb SO2/MMbtu for any individual 

piece of equipment and 1.75 lb SO2/MMbtu for the aggregate facility. Based upon the quality of the 

refinery's fuels, the SO2 emission rate per MMbtu of 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 SO2 = 1.07 lb SO2 of fuel oil burned 

6.7 MMBtu Bbl 100% lb S MMBtu

At 1.07 lb SO2/MMbtu, any Emission Point burning 100% refinery fuel oil would be in compliance with the 

individual source limit of 3.0 lb SO2/Mmbtu and with the aggregate facility limit of 1.75 lb SO2/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 fired 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 
 

34

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 converted to one carbon dioxide (CO2) atom. 

 Two hydrogen (H) atoms are converted to one water (H2O) 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 CO2 per scf fuel, scf H2O per scf fuel and scf N2 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 41 mix drumSCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF 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
 

35

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

Component 45 mix drumSCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF 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 10,883
 

36

#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 41 mix drumSCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF 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
 

37

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

Component 45 mix drumSCF N2 per SCF SCF N2 SCF CO2 per SCF SCF CO2 SCF H2O per SCF 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 10,883
 

38

 

The modeled stack velocity is calculated as follows: 

 Stack velocity = Heater Duty MMBtu * 1 * scf flue gas * 1 Hr * 0.028317 m3 * 

 Hr 2 MMBtu 3,600 sec ft3 

 T°K * 1 = _____ exit vel m/sec 

 288.7K (D2

/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 decree between EPA and FHR (Civil Action No. 00-2756-PAM-SRN), 

FHR must meet the specified NOx 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 NOx 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 used:

 If a heater or boiler’s fired duty is lowered by de-rating; its stack velocity will 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 modeled SO2 emission rate for these sources was not decreased. Current heater and boiler 

duties for these sources were used to calculate the modeled SO2 emissions. Using the original duties 

accounts for operation of these sources 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 velocity will be based on the 

heater duty burning 100% refinery fuel 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 11,113
 

39

The actual stack height is used in the modeling except 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 the1hour, 3 hour, 24 hour, and federal annual modeling. 
 

40

Stationary Diesel Engines 

“K331_DSL”, “K332_DSL”, “K333_DSL”, “K407_DSL”, “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 the 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 extended periods only in emergency situations. The 

ULSD project required 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. They 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 Source 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 compressor 71C-11. This diesel will operate less than 

2500 hours per year. 

B. Justification For Modeled SO2 Emission Rate 

The SO2 emission rates for the diesel engines are based on AP-42 emission factors. The AP-42 factors 

are accepted standards, which will be used frequently in the future for a variety of pollutants. These 

emission factors have been scaled down based on the sulfur content of the diesel fuel to account for a 

limit of 0.050015 wt % S in the fuel. 

ENGINES < 600 hp: 4.611E-5 g/s SO2 per hp-hr (AP-42 Table 3.3—1 Oct ’96 adjusted to 0.050015% S) 

AP-42 lists emission factors of 2.05 E-305E-03 lb SO2/hp-hr and 0.29 lb SO2/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 emission factor is calculated to be: 

0.29 lb SO2 * 1 lb S * 1 MMBtu * 19,300 Btu * 100% = 0.280% S 

MMBtu fuel 2 lb SO2 1 E-61E+06 Btu lb diesel 

The adjustment for 0.050015% S diesel fuel is as follows 

2.05 E-3 lb SO2 * 0.050015% S * 453.59 g * 1 Hr = 4.611.43 E-56 g/sec SO2

 Hp-Hr 0.28%S. 1 lb 3600 Sec Hp-Hr 
 

41

ENGINES > 600 hp: 5.097E-5 g/s SO2 per hphr (AP-42 Table 3.4-1 Oct ’96 adjusted to 0.050015% S) 

AP-42 lists an emission factor of 8.09 E-3 * %S in diesel fuel. Converting to g/s with 0.050015%S diesel 

fuel: 

8.09 E-3 lb SO2 * 0.050015%S * 453.59 g * 1 Hr = 5.0971.58 E-56 g/s SO2

 Hp-Hr 1 lb 3600 S Hp-Hr 

 

C. Reserved for Updated Justification of Modeled NOx Emission Rate 

D

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

Minnesota Rule 7005.1200 Subpart 2 limits SO2 emissions from stationary internal combustion engines to 

1.75 lb SO2 per million BTU actual heat input. These emission points will be limited to diesel fuel 

containing no more than 0.050015 % sulfur in the Clean Fuels Permit. At this sulfur content, SO2

emissions from combustion of diesel fuel are limited to 0.050015 lb S02 per million Btu of actual heat 

input. 

ED. 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. The 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 velocity 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 106 Btu D2 (m) 50% 

 D2

 hp hr 106 Btu D2 (m) 50% D2
 

42

Portable Diesels 

Flint Hills Resources occasionallyperiodically requires the use of portable equipment powered by diesel 

engines at various locations around the refinery (e.g. portable electric generators). Based on information 

containedThese 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 excludes non-road engines; therefore, the 

portable diesel permit application, the total capacity of portable diesels at the refinery is 13,027 

horsepower (hp) with at utilization rate of 6,369,600 hp-hours/year. do not need to be included in the SIP 

modeling analysis.

The average horsepowernon-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 mobile 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 6,369,600 hp-hours/year for the annual average. The emission rate is 

calculated using 0.05% sulfur content and the emission calculation procedure for stationary diesel 

engines 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 combined emissions from all 16,000 HP of 

diesel operation. However, the stack parameters for 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 modeled impact of portable diesel operation so that 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/m3) to be south 

of the refinery. However, the portable diesel impact at this receptor was not significant. The model 
 

43

continues to show 1-hour average concentrations (981 ug/m3

) 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 receptors, so the original siting analysis remains valid. 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 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 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 source 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 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 process 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 biologically 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 covered. They are connected to the Oxidizer by a duct 

system. The Oxidizer blower pulls a vacuum on the duct system to pull the treating air containing Volatile 

Organic Compounds (VOC's) and odors from the treatment tanks into the Oxidizer. The air and VOC's 

flow from the blower discharge into a heat exchanger. The heat exchanger uses hot stack gases to 

preheat the oxidizer feed. A natural gas fired burner heats the oxidizer feed up to approximately 1,400F 

and the VOC's are oxidized into CO2 and Water. The de-contaminated 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 SO2 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 when the main thermal oxidizer is out of service. Flint Hills Resources operatesroutes 

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 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 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 oxidizer operation at the wastewater plant. 

B. Justification For Modeled SO2 Emission Rate

The wastewater feed to the OSWTP contains small amounts of odorous sulfur bearing compounds (H2S 

and mercaptans). These compounds are transferred from the wastewater to the treating air in the basins 

and are oxidized to SO2 in the oxidizer. Stack testing indicated that this source has shown emission rates 

as high as 6.2 lb/hr SO2. 

For the 1, 3 and 24 hour 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 

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 H2S * 1 lbmole H2S * 64 lb SO2 * 453.59 gm * 1 Min = 6.389 gmgram

SO2

 Min scf Fuel Gas 385 scf lbmole SO2 lb 60 sec sec 
 

45

The annual emission rate, the oxidizer was modeled at 9.0 lb SO2/hr. This limits SO2 emissions from the 

WWTP TOthermal oxidizer to an emission rate which is below the PSD major modification threshold of 40 

ton/yr SO2. 

C. Reserved for Updated Justification of Modeled NOx Emission Rate 

DC. Consistency Between Modeled SO2 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 Subpart QQQ). This standard does not address SO2 emissions 

from VOC control devices for petroleum refinery wastewater systems. 

The Oxidizer uses only natural gas as its fuel source. There are no other applicable state or federal SO2

emissions standards. 

ED. 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 test was 

performed under normal operating conditions and the appropriate EPA reference methods were used. 

The following data were used as model inputs:

With the exception of stack temperature, the Thermal Oxidizer stack parameters are consistent with 

parameters modeled for SIP 8 and listed below. The stack 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 = 792Stack temperature = 500F = 695.2533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 ft3

/min * 1 min / 60 sec * 4 / [ (5.63 ft)2] = 33.53 ft/sec = 

10.36 m/sec 
 

46

Please note that the modeled stack velocity is conservatively 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 the 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 with coke during operation. The coke formation on 

the inside of the heater tubes reduces the heat transfer 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 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, steam is injected into the heater tubes to physically 

remove loose coke. Steam injection continues as the heater burners are fired onwith 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 injected 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 

disengagingto further condense water vapor and control sulfur dioxide emissions via submerged fill. 

QuenchFHR’s quench pits are concrete lined basins filled with water. The decoking quench line 

routeslines route the heater decoking flue gas into the water in the quench pit. Thepits. 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 theThe 21 unit heaters (21 H-1 and 21 H-2) is ventedare routed to its own 

coveredenclosed quench pitpits 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. AllThe 23 heaters may be decoked 

simultaneously. The 21 unit heaters are not decoked simultaneously with each other or the 23 unit 

heaters. 

B. Justification For Modeled SO2 Emission Rate 

With SIP modification 9 (2010), FHR is refining the former emission rate basis to improve the accuracy of 

both the uncontrolled and controlled emission rates.

Uncontrolled Emission Rate Basis 

The SO2 emission rates calculated for decoking process heaters are based on the sulfur content of the 

coke, the amount of air used to decoke the heater, and the SO2 removal efficiency of the quench system. 

The coke produced at the delayed coking units has the same sulfur content as the feed to the unit. So, 

theThe 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) + O2(g) --> CO2(g) s [=] solid, g [=] gas 

 S(s) + O2(g) --> SO2(g) 

 (Assume all carbon is completely oxidized to CO2, and all sulfur is oxidized to SO2.) 
 

50

Since 1 mole of CO2 is produced per mole of O2 consumed, and 1 mole of SO2 is produced per mole of 

O2 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 (O2) in the decoking air is consumed, heater decoking SO2

emissions are calculated for each pound of oxygen in the decoking air as follows: 

 

lb O2 = 1 lb C * 1 lbmol C * 1 lbmol O2 * 32 lb O2 + 1 lb S * 1 lbmol S * 1 lbmol O2 * 32 lb O2

 12 lb C lbmol C lbmol O2 32 lb S lbmol S lbmol O2

 which reduces to: lb O2 = 2.667 * lb C + lb S 

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

 lb O2 = 2.667*(lb coke - lb S) + lb S = 2.667 * lb coke - 1.667 lb S 

 lb O2 / 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 SO2, 2 lb O2 / lb SO2 = 2.667/ (wt frac S) - 1.667 

 Rearranging, lb SO2 = lb O2 * [(1.333/wt frac S) - 0.833]-1

The amount of O2 used in decoking can be determined from the decoking air use rate as follows: 

 lb O2 = Air SCF/min * 60 min/hr * Burn Time hr * 1 lbmol air * 29 lb air * 0.232 lb O2

 379 SCF lbmol air lb air 

This reduces to the following equation: lb O2 = Air SCF/min * Burn Time hr * 1.064 

lb SO2 = 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 (O2) addition rates metered during past heater 

decoking events to calculate worst case uncontrolled SO2 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 calculates 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 content, time required to decoke, and the stoichiometry 

detailed above, uncontrolled emission rate potentials are calculated. 

Heater Total O2

Consumption (lbs)

Decoke Duration 

(hrs)

Ave Uncontrolled 

SO2 rate (lb/hr)

Peak Uncontrolled 

SO2 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 SO2 emitted = lb SO2 *(1- Quench System SO2 Removal Efficiency/100%) 
 

51

AsAfter completing an engineering study in the original SIP modeling2010 of the quench piping and pit 

configurations as well as an emissions quantification study on the quench pit of the 21-1 unit during a 

decoking event, the company proposes to model 21 Unitall 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 uncontrolled source (0% control efficiency).

 23 H-2 heater decoking is modeled as an uncontrolled source (0% control efficiency).

21H-1 and 21H-2Heater Decoking (“K600 21H1D”, “K601 21H2D”

These sources are quenched in a piping system that maximizes flue gas/quench water mixing. The 

principle design characteristics are: 

1. It has a minimum of four (4three (3) quench water injection points. 

2. It has a “U” shaped section of piping for mixing. The “U” shaped piping section is approximately 

75greater than 50 feet long and contains at least four (4)several bends (elbows) to ensure 

completethorough mixing of the decoking flue gas with the quench water. 

3. The quench water discharge-piping exit is at least four (4) feetwell submerged below the quench pit 

water level to provide additional mixingopportunity to solubilize emissions. 

For calculation purposes, the volume of water for the SO2 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 SO2 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, absorbers, 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 the liquid at chemical equilibrium (the maximum possible) are dissolved 

on one tray. The scrubbing of SO2 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 equivalent 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% O2

1,120 SCF air * 0.21 SCF O2 * 1 lbmol O2 * 60 min * 36 hours = 1340.5 lbmol O2 per heater

 min SCF air 379 SCF O2 hr decoke decoke

1340.5 lbmol O2 * 32 lb O2 = 42,896 lb O2

 decoke lbmol

Total lbmol air = 1,340.5/Measured Control Efficiency

In October of 2010, FHR contracted Pace Analytical to utilize stack test methods to quantify SO2 

emission rates during a heater burn. The tests were conducted for approximately 12 hours during the 

peak air addition rate periods of the burn. An air mover was installed in an opening on the roof of the 21-1 
 

52

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 uncontrolled emission rate and that measured during the 21-

1 burn:

4.0 lb SO2 emitted = 49.4 lb SO2 *(1- Quench System SO2 Removal Efficiency/100%)

A control efficiency of 92% is estimated. However, while the air mover likely captured the vast majority of 

emissions which released with the non-condensable burn related 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 1st 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 O2 * [(1.333/0.065) - 0.833]-1 = 2,180.3 lb SO2

2,180.3) lb SO2 * (1 lbmol/64.06emitted * (2 lb) = 34.03 lbmol SO2

Partial pressure emitted / 1 lb Captured) = 49.4 lb SO2 *(1- Quench System SO2 = 

34.03/6,383.3*760mmHg/Atmosphere = 4.05 mmHgRemoval Efficiency/100%)

Solubility of SO2 @ stated conditions = 0.044 lb SO2 

 100 lb H2O

(Perry's Chemical Engineers Handbook, 6th Ed., p. 3-103)

Quench water rate = 400 gpm

400 gal * 8.33 lb H2O * 60 min * 36 hr * 0.044 lb SO2 * (50%A control efficiency) = 1,583.4 lb SO2

removed

 min gal hr decoke 100 lb H2O per htr decoke

Net release of SO284% is therefore estimated. FHR proposes to utilize the air per 36 hour example 

heater decoking event:

(2,180.3 – 1,583.4) lb SO2 = 596.9 lb SO2 

 decoke decoke

This results in a calculatedsame 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 calculation techniques to determine the SO2 chemical 

absorption rate in the quench system at heater decoking operating conditions (temperature, pressure SO2

concentrations and quench water rates).

The company has added a safety factor to this analysis by using a removal efficiency of 50% in the SO2 

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 SO2 emissions from heater decoking are summarized in the following table: 

Heater Decoking SO2 Emission Rate at Listed Scubbing Efficiency for All Sources

Source Description wt 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 air 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 

SO2 rate (lb/hr)

Control 

Efficiency

Peak Hourly Controlled 

SO2 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 simultaneous burns and discharge location in the model with a 

combined emission rate of 20.2 lb/hr.

Volume Source SO2 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, the21 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 wereare modeled as an area source. The 23 

Unitvolume sources. FHR believes these are appropriate to model as volume sources due to the multiple 

locations and elevations of the pit openings (21u) and 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 buoyancy of the non-condensable burn gases 

and sparge air (23u) releasing from the water surface. The volume source emission rate for sources 602 

and601 - 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 ft2 m2 g/sec g/sec-m2 g/sec g/sec-m2

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 NOx Emission Rate 

D

C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal Regulations

There are no state or federal emissions standards for steam-air decoking of process heaters. 

ED. 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 condensedpreviously noted 21H-1, 21H-2, 23H-1, and removed in 

the23H-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 temperatures used in the previous modeling 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 hatch 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 pointvolume 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 vented 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.

As 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.

SO2 Emissions

Heater Decoking SO2 Emission Rate

Source Description
 

55

Stack temperature = 120F = 48.9C

Stack Velocity = air flow (SCFM) * (120F+460)R * 4 * 1 min = Vel. (ft/s)

 520R  D2 ft2 60 s

This reduces to: Vel (ft/s) = air flow (SCFM) * 0.0237/D2

The calculated stack parameters for heater decoking are listed in the following table: below.

 

Heater Decoking Stack Velocify

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 Pit 
 

56

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

Source
 

57

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 SO2. FHR has found that some of this SO2 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 Sulfuric 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 facitilities 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 acid tank. Empty rail cars are used to ship out spent 

acid for re-processing. Spent acid is loaded into rail 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 knock 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 alkyalation 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 spendt acid storage tank must not be disturbed for a period of 24 hours to 

accomplish the acid/hdrocarbon speparation. Each tank 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 SO2 Emission Rate 

SO2 emissions occur during the filling of rail cars and storage tanks. SO2 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, SO2 emissions are estimated to be 

approximately 1 lb SO2/hr from each emission point. Emission were calculated as follows: 

 Acid Loading gal * 1 ft3

 * 60 min * PPM SO2 * 1 lb-mole * 64.06 lb SO2 = lb SO2 

 min 7.48 gal hr 1 e6 1E +06 379.5 scf lb-mole hr 

 

An emission rate of 2.27 lb SO2/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, SO2 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 rate from storage tanks. The other two spent acid 

tanks are not included in the SO2 emission calculation because they are either being emptied to rail 

loading or have a constant level during gravity separation of acid and hydrocarbon liquids. 
 

58

C. Reserved for Updated Justification of Modeled NOx Emission Rate 

D.C. Consistency Between Modeled SO2 Emissions And Applicable State And Federal 

Regulations

There are no state or federal emissions standards 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 impact 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 contents of 0 ppm – 1 ppm. At these levels, the SO2 

emission rate is 0.00015 lb SO2/MMBtu. As an example, a 100 MMBtu/hr heater would emit 0.015 lb SO2

/Hr vs. 2.38 lb SO2/Hr for refinery fuel gas at 162 ppm H2S. 

Source Fuel Source 

 PPM H2S1

Emission Rate 

Lb/Hr SO2

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 
!;N

Barr 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

5000 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 Analysis
Flint Hills Resources

NAAQS and MAAQS SO2 Attainment Modeling Demonstration

Model Input Summary -- Merox Off-Gas Project

May 2011

Descrip AERMOD_id Type UTM_E UTM_N Elv_m Ht_m GEP_m Dia_m Max. Heat 

Input 

Capacity

Duty or

Size 

Rating

De-Rated 

Duty for 

Stk Vel 

Cal's

Mix Drum HHV 

Btu/scf

Units T_K Syinit Szinit scf flue 

gas per 

MMBtu fuel 

gas

1-,3-

hr_V_m/s

SO2 ppm

SO2_1hr_ g/s S

34H-3 K1

_

MEROX POINT 496781.2 4957077.0 281.9 53.72 53.72 1.575 NA 578.0 NA 3.84 8.240 

45H-61 K2_#3SRU POINT 496906.7 4956920.9 282.7 60.96 60.96 1.448 122.0 NA 578 NA 16.00 18.822 

26H-21 K3_#5SRU POINT 496868.5 4956631.4 277.6 65.00 65.00 2.103 56.8 NA 464 NA 9.30 21.575 

71B-7

Boilers 

1,2,3,4,6 & 9

K7____BH 

FCC ESP K8___FCC POINT 496993.1 4956990.2 283.6 80.00 69.27 2.937 NA NA 366 NA 15.24 23.013 

32H-5,6,7 K10_32FG POINT 496775.9 4957022.0 281.9 62.48 62.48 2.730 160.0 160.0 135.0 41 1197 MMBtu

per Hr 

HHV

422 10,215 1.35 0.852 

19H-1 K11_19FO POINT 496585.4 4957137.0 280.4 58.52 58.52 2.134 145.6 173 146 41 1197 MMBtu

per Hr 

HHV

422 10,215 2.40 0.921 

12H-4 K13_12FG POINT 496667.2 4957137.0 280.9 60.50 60.50 2.070 138.2 150 138 41 1197 MMBtu

per Hr 

HHV

422 10,215 2.41 0.799 

33H-31 K14_33FO POINT 496981.5 4956855.0 283.5 57.52 55.78 1.969 115.7 174 116 45 1093 MMBtu

per Hr 

HHV

553 10,208 2.93 1.691 

16H-1 K15_16FG POINT 496627.7 4957108.0 280.8 58.83 58.83 3.340 236.9 236.9 41 1197 MMBtu

per Hr 

HHV

480 10,215 1.81 1.262 

11H-3 K16_11FO 11H-5 K18_11FO 

11H-1 K19_11FO POINT 496649.9 4957059.0 281.0 39.93 39.93 1.397 119.9 160 120 41 1197 MMBtu

per Hr 

HHV

466 10,215 5.08 0.852 

37H-1,2,6 K20_37FG POINT 496870.1 4956697.0 280.2 60.96 60.96 1.009 123.0 90 45 1093 MMBtu

per Hr 

HHV

422 10,208 6.61 0.875 

33H-32 K21_33FG POINT 496923.7 4956848.0 283.0 56.94 56.12 1.436 128.8 128.8 45 1093 MMBtu

per Hr 

HHV

547 10,208 6.05 1.252 

11H-2 K23_11FG POINT 496637.9 4957060.0 281.0 35.05 35.05 1.867 57.0 57 30 41 1197 MMBtu

per Hr 

HHV

508 10,215 0.77 0.304 

21H-1S FO 

fired

K27_21FO POINT 496551.5 4957092.5 280.7 38.71 38.71 1.410 66.0 66.0 40.0 41 1197 MMBtu

per Hr 

HHV

478 10,215 1.70 0.351 

21H-1N FO 

fired

K28_21FO POINT 496551.5 4957101.5 280.6 38.71 38.71 1.410 66.0 66.0 40.0 41 1197 MMBtu

per Hr 

HHV

478 10,215 1.70 0.351 

21H-2S FO 

fired

K29_21FO POINT 496550.8 4957025.2 280.9 39.93 39.93 1.410 66.0 66.0 40.0 41 1197 MMBtu

per Hr 

HHV

489 10,215 1.74 0.351 

21H-2N FO 

fired

K30_21FO POINT 496550.8 4957034.2 280.9 39.93 39.93 1.410 66.0 66.0 40.0 41 1197 MMBtu

per Hr 

HHV

489 10,215 1.74 0.351 

33H-4 (33H1&2) K31_33FG POINT 496921.1 4956899.0 282.9 30.48 30.48 1.829 182.6 182.6 144.0 45 1093 MMBtu per Hr 

HHV

550 10,208 4.19 1.775 

23H-1 FO 

fired

K32_23FO POINT 496531.7 4956882.6 272.9 57.91 57.91 1.631 165.0 165 45 1093 MMBtu

per Hr 

HHV

422 10,208 4.63 1.604 

31H-1 K33_31FG POINT 496768.3 4957087.0 281.9 20.42 20.42 1.111 23.0 23 41 1197 MMBtu

per Hr 

HHV

566 10,215 1.87 0.122 

SouSouSou

\\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 Page 1 of 4
Flint Hills Resources

NAAQS and MAAQS SO2 Attainment Modeling Demonstration

Model Input Summary -- Merox Off-Gas Project

May 2011

Descrip AERMOD_id Type UTM_E UTM_N Elv_m Ht_m GEP_m Dia_m Max. Heat 

Input 

Capacity

Duty or

Size 

Rating

De-Rated 

Duty for 

Stk Vel 

Cal's

Mix Drum HHV 

Btu/scf

Units T_K Syinit Szinit scf flue 

gas per 

MMBtu fuel 

gas

1-,3-

hr_V_m/s

SO2 ppm

SO2_1hr_ g/s S

31H-2 K34_31FG POINT 496769.0 4957077.0 281.9 18.59 18.59 0.953 23.0 23 41 1197 MMBtu

per Hr 

HHV

666 10,215 2.99 8.363 

31H-5 K36_31FG POINT 496802.9 4957102.0 282.2 17.98 17.98 0.800 10.0 10 41 1197 MMBtu

per Hr 

HHV

422 10,215 1.17 0.053 

31H-10 K37_31FG POINT 496802.9 4957112.0 282.2 30.48 30.48 1.372 29.8 30 41 1197 MMBtu

per Hr 

HHV

525 10,215 1.48 0.160 

32H-9 K41_32FG POINT 496774.0 4957037.0 281.9 21.64 21.64 0.914 9.0 9 41 1197 MMBtu

per Hr 

HHV

533 10,215 1.02 0.048 

37H-3,4,5 K42_37FG POINT 496914.2 4956703.2 279.8 81.99 71.20 3.417 391.0 390.7 45 1093 MMBtu

per Hr 

HHV

422 10,208 2.50 3.798 

38H-1A K46_38FG POINT 496952.1 4956560.5 281.5 44.50 44.50 1.803 29.0 38.2 29 45 1093 MMBtu

per Hr 

HHV

600 10,208 0.95 0.371 

38H-1B K47_38FG POINT 496952.1 4956571.3 281.5 44.50 44.50 1.803 29.0 38.2 29 45 1093 MMBtu

per Hr 

HHV

600 10,208 0.95 0.371 

38H-2 K48_38FG POINT 496979.3 4956563.4 281.7 60.96 60.96 0.838 56.0 62 30 45 1093 MMBtu

per Hr 

HHV

422 10,208 3.19 0.603 

25H-1 K50_25FG POINT 496755.4 4956642.0 274.5 77.27 65.00 3.600 253.0 253 253 45 1093 MMBtu

per Hr 

HHV

422 10,208 1.46 2.459 

25H-3 K51_25FG POINT 496786.2 4956635.0 275.8 73.71 65.00 3.500 206.0 227 227 45 1093 MMBtu

per Hr 

HHV

428 10,208 1.40 2.207 

25H-4 K52_25FG POINT 496800.5 4956636.9 276.8 60.96 60.96 1.930 163.0 163 163 45 1093 MMBtu

per Hr 

HHV

422 10,208 3.27 1.584 

23H-2 K53_23FG POINT 496532.5 4956853.8 269.8 57.91 57.91 1.335 122.0 122 45 1093 MMBtu

per Hr 

HHV

436 10,208 5.28 1.186 

27H-1 K54_27FG POINT 496725.5 4956511.4 277.1 45.72 45.72 3.132 800.0 800 45 1093 MMBtu

per Hr 

HHV

422 10,208 6.09 7.776 

27H-101 K55_27FG POINT 496811.6 4956500.1 276.6 45.72 45.72 1.113 84.0 84 45 1093 MMBtu

per Hr 

HHV

422 10,208 5.07 0.817 

27H-102 K56_27FG POINT 496813.3 4956402.9 276.0 45.72 45.72 1.113 84.0 95 84 45 1093 MMBtu

per Hr 

HHV

422 10,208 5.07 0.923 

31H-4 K57_31FG POINT 496798.1 4957001.0 282.0 32.46 32.46 1.347 71.0 71 30 41 1197 MMBtu

per Hr 

HHV

555 10,215 1.63 0.378 

31H-7 K58_31FG POINT 496798.0 4957025.0 282.0 28.65 28.65 1.067 68.4 68.4 30 41 1197 MMBtu

per Hr 

HHV

544 10,215 2.54 0.364 

31H-8 K59_31FG POINT 496799.2 4957036.0 282.1 28.80 28.80 1.049 38.6 38.6 41 1197 MMBtu

per Hr 

HHV

519 10,215 3.23 0.206 

31H-9 K60_31FG POINT 496798.8 4957018.0 282.0 24.84 24.84 0.905 50.0 50 30 41 1197 MMBtu

per Hr 

HHV

511 10,215 3.32 0.266 

28H-1 K61_28FG POINT 496837.8 4956502.2 276.9 45.72 45.72 0.787 34.0 34 45 1093 MMBtu

per Hr 

HHV

811 10,208 7.88 0.330 

71B-8 K62_BLR8 POINT 496698.3 4956542.5 277.5 9.04 9.04 1.524 185.0 185 45 1093 MMBtu

per Hr 

HHV

422 10,208 5.95 1.798 

27H-501 K63_27FG POINT 496722.3 4956358.0 275.1 35.05 35.05 3.150 475.0 475 45 1093 MMBtu

per Hr 

HHV

422 10,208 3.58 4.617 

11H-6 K67_11FG POINT 496630.1 4956988.4 280.7 56.62 54.86 2.642 390.0 390 41 1197 MMBtu

per Hr 

HHV

422 10,215 4.18 2.077 

71B-9 K68_BLR9 POINT 496569.0 4957199.8 280.0 12.19 12.19 1.829 235.0 235 135 41 1197 MMBtu

per Hr 

HHV

422 10,215 3.02 1.251 

\\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 Page 2 of 4
Flint Hills Resources

NAAQS and MAAQS SO2 Attainment Modeling Demonstration

Model Input Summary -- Merox Off-Gas Project

May 2011

Descrip AERMOD_id Type UTM_E UTM_N Elv_m Ht_m GEP_m Dia_m Max. Heat 

Input 

Capacity

Duty or

Size 

Rating

De-Rated 

Duty for 

Stk Vel 

Cal's

Mix Drum HHV 

Btu/scf

Units T_K Syinit Szinit scf flue 

gas per 

MMBtu fuel 

gas

1-,3-

hr_V_m/s

SO2 ppm

SO2_1hr_ g/s S

Boiler 10 BLR10 POINT 496568.6 4957194.3 280.0 12.19 12.19 1.829 235.0 235 135 41 1197 MMBtu

per Hr 

HHV

436 10,215 3.12 1.251 

30 H-401

#4 H2 Plant

K70_4H2 POINT 496664.6 4956414.6 274.4 35.05 35.05 2.896 900.0 900 450 45 1093 MMBtu

per Hr 

HHV

422 11,000 4.32 8.748 

29 H-1

Comb Fd& 

Dist

K71HCFD POINT 496923.0 4956351.0 277.0 40.78 40.78 2.629 241.0 220 10 45 1093 MMBtu

per Hr 

HHV

422 10,208 0.11 2.138 

71B-6 Boiler K1006_BH POINT 496566.9 4957213.0 280.1 21.34 21.34 1.372 120.0 108.0 80.0 41 1197 MMBtu

per Hr 

HHV

422 10,215 3.18 0.639 

45H-6 K113__FG POINT 496901.4 4956953.5 282.7 53.68 53.68 1.016 122.0 11.141 45 1093 MMBtu

per Hr 

HHV

422 10,208 0.81 0.202 

93P-160 K331_DSL POINT 496832.2 4956976.5 282.3 4.27 4.27 0.102 NA 175 HP 616 23.60 0.0003 

93P-400 K332

_

DSL POINT 496753.3 4957695.5 270.9 4.57 4.57 0.152 NA 624 HP 616 37.90 0.001 

93P-570 K333_DSL POINT 495957.0 4956960.1 262.2 5.49 5.49 0.305 NA 624 HP 616 9.41 0.001 

94H-1 K348_OXD POINT 496636.2 4957613.5 276.0 22.11 22.11 1.717 100.0 533 10.36 6.389 

EE-1657 K407

_

DSL POINT 496799.3 4956593.5 275.1 6.10 6.10 0.203 NA 600 HP 616 20.43 0.001 

EE-1692 K408

_

DSL POINT 496684.0 4957064.0 281.1 4.11 4.11 0.203 NA 603 HP 616 20.53 0.001 

23ME26 K435

_

DSL POINT 496526.5 4956971.5 278.6 7.01 7.01 0.152 NA 685 HP 616 41.60 0.001 

EE-1309 K453

_

DSL POINT 496910.2 4956656.0 278.4 7.92 7.92 0.152 NA 685 HP 616 41.60 0.001 

EE-1718 K465

_

DSL POINT 496908.4 4957114.5 283.0 4.57 4.57 0.203 NA 603 HP 616 20.53 0.001 

81P-159 K505

_

DSL POINT 496846.2 4956974.5 282.5 5.49 5.49 0.203 NA 546 HP 616 18.59 0.001 

81P-357 K506

_

DSL POINT 496838.3 4956933.5 282.2 6.10 6.10 0.203 NA 500 HP 616 17.02 0.001 

81P-444 K507

_

DSL POINT 496646.3 4956932.5 281.1 4.57 4.57 0.254 NA 630 HP 616 13.70 0.001 

81P-89 K508

_

DSL POINT 496639.3 4956990.5 280.9 4.57 4.57 0.102 NA 325 HP 616 43.83 0.0005 

Wood River K510

_

DSL POINT 495926.3 4957212.5 262.2 4.57 4.57 0.305 NA 1195 HP 616 18.02 0.002 

71C-11 K511

_

DSL POINT 496987.9 4956786.1 282.1 6.10 6.10 0.254 NA 705 HP 616 15.33 0.001 

Portable 

diesel cap

PORT_DSL POINT 497006.0 4957000.0 283.7 4.27 4.27 0.102 211 &

6,369,600

211 HP

HP-Hr

per Yr

616 28.46 

ULSD 

Replace 

K509DSL

81P-450

K513_DSL POINT 496672.2 4956267.3 271.9 9.75 9.75 0.305 1200 HP 477 14.02 0.002 

21H-1 dec K600_DEC VOLUME 496522.1 4957081.7 280.6 1.50 NA NA 2.24 1.4 NA 1.008 

21H-2 dec K601_DEC VOLUME 496528.9 4957028.6 280.8 1.50 NA NA 2.24 1.4 NA 1.008 

23H-1 dec K602_DEC VOLUME 496461.0 4956855.0 264.1 1.50 NA NA 2.24 1.4 NA 2.545 

23H-2 dec K603_DEC VOLUME 496461.0 4956855.0 264.1 1.50 NA NA 2.24 1.4 NA 0.000 

Acid Ld & 

Depress

K700ACDL VOLUME 496560.0 4957484.0 280.6 3.10 3.9 1.4 0.572 

Acid Stor Tks K701ACDS VOLUME 496837.0 4957122.0 282.6 7.60 5 3.5 0.572 

NSP NSP_IGH1 POINT 496686.8 4958733.5 287.5 9.75 9.75 4.212 839 1,150,000 38.95 61.550 

NSP NSP_IGH2 POINT 496686.8 4958694.9 286.9 9.75 9.75 4.212 839 1,150,000 38.95 61.550 

NSP NSP_IGH3 POINT 496676.9 4958698.7 287.1 9.75 9.75 4.212 839 1,150,000 38.95 61.550 

Source has been r71

\\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 Page 3 of 4
Flint Hills Resources

NAAQS and MAAQS SO2 Attainment Modeling Demonstration

Model Input Summary -- Merox Off-Gas Project

May 2011

Descrip AERMOD_id Type UTM_E UTM_N Elv_m Ht_m GEP_m Dia_m Max. Heat 

Input 

Capacity

Duty or

Size 

Rating

De-Rated 

Duty for 

Stk Vel 

Cal's

Mix Drum HHV 

Btu/scf

Units T_K Syinit Szinit scf flue 

gas per 

MMBtu fuel 

gas

1-,3-

hr_V_m/s

SO2 ppm

SO2_1hr_ g/s S

NSP NSP_IGH4 POINT 496677.2 4958657.2 286.3 9.75 9.75 4.212 839 1,150,000 38.95 61.550 

NSP NSP_IGH5 POINT 496686.2 4958661.4 286.4 9.75 9.75 4.212 839 1,150,000 38.95 61.550 

NSP NSP_IGH6 POINT 496686.5 4958621.5 286.3 9.75 9.75 4.212 839 1,150,000 38.95 61.550 

Gopher GOPHER POINT 490625.4 4964656.5 272.9 60.66 60.66 1.829 361 21.38 262.080 

\\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 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 - Section 6

Summary of Model Results

Flint Hills Resources Pine Bend LLC

Ambient Air Quality Modeling Analysis
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/m3 

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 SO2 Attainment Modeling Demonstration

Modeling Results Summary - All SO2 Concentrations in ug/m3

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 Parameters 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 
!!!!!!!!! !!!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!! !!!! !!!!!!!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!

!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!!!!!!!!!!!!!!!

!!!

!!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

! !!!!!!!!!!!!!!!! !!!!!!!!!!!!

! !!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr Footer: Date: 5/3/2011 4:21:34 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure2_Far_Field_Receptor_Grid.mxd User: jjm

1 0 1 2 3

Kilometers

Figure 2

Far Field Receptor Grid

SO2 SIP 9 Exhibit 1

Flint Hills Resources

Pine Bend, MN

! Receptor Grid
!!!! !!!!! !!!!!!!!!!! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! !

! !

! !

! !

! !

! !

! !

! ! !

! ! !

! ! !

! ! !

! ! !

! ! !

! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!

! !

! !

! ! !

! ! !

! !

! !

! !

! !

!

!

!

!

! !

!

!

!

!

! !

! !

! !

!

!

!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!

!!!!!!!!!!!!

!

!!!!

!

!!!!

!

!!!

!

!!!

!

!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!

!!!

!

!!!!

!!

!!

!!

!!

!

!!!

!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!

!!!!!

!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!

!! !!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!

!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!

!!!!!!!!!!!!!!!

!!!!!

!;N

Barr 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

Figure 3

Near Field Receptor Grid

SO2 SIP 9 Exhibit 1

Flint Hills Resources

Pine Bend, MN

! Receptor Grid
Exhibit 1 - Section 8 

AERMOD Model Output 

Located on CD-ROM in folder Section 8 

All Modeling Outputs are in subfolders 2000_output through 

2004_output: 

1 Hour Results: “SIPso1hR700.ado - SIPso1hR704.ado” 

3 Hour Results: “SIPso3hR900.ado – SIPso3hR904.ado” 

24 Hour Results: “SIPso24hR900.ado – SIPso4hR904.ado” 

Annual Results: “SIPsoannR800.ado – SIPsoannR804.ado”

SO2 1 hr MAAQS compliance figures are: 

“Figure 4 1 Hour SO2 Results 21H-1 Decoking Scenario.pdf” 

“Figure 5 1 Hour SO2 Results 21H-2 Decoking Scenario.pdf” 

“Figure 6 1 Hour SO2 Results 23H-1, 2 Decoking Scenario.pdf” 

SO2 3 hr NAAQS compliance 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 23H-1, 2 Decoking Scenario.pdf” 

SO2 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” 

SO2 Annual NAAQS compliance figures are: 

“Figure 13 Annual SO2 Results.pdf” 

Flint Hills Resources Pine Bend LLC 

Ambient Air Quality Modeling Analysis 
!!!!!!!!!!!!!!!! !!!! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!! !!!! !!!!!!!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!

!!!

!!!!!!! !!!!!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!

!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!!!! !!!!!!!!!!!!!!!!

!!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!! !!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!

!!!! !!!! !!!! !!!!!!!!!!!!!!!!!!! !!!!!! !

!!!!!! !!!!!

!!

!!!!!!

!

!

!!!!!

!!

!

!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !

!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!! !!!!!!!! !!!!!!!!!!!!!!!!!!!

! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!! !!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr 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

Figure 4

1 Hour SO2 Results 

21H-1 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% - 55%

MAAQS = 1,300 ug/m3

Background Concentration of 56 ug/m3 included.
!!!!!!!!!!!!!!! !!!!! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!! !!!! !!!!!!!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!!!!!!!!!!! !!!!!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!

!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!!!! !!!!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!! !!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!

!!!!! !!!!! !!!!!!!!!!!!!!!!!! !!!!!!!!!!! !!

!!!!!! !!!!!

!!

!!!!!!

!

!

!!!!!

!!

!

!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !

!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!! !!!!!!!! !!!!!!!!!!!!!!!!!!!

! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!! !!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr Footer: Date: 5/3/2011 4:24:28 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure5_1Hour_SO2_Results_21H2DecokingScenario.mxd User: jjm

1 0 1 2

Kilometers

Figure 5

1 Hour SO2 Results 

21H-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% - 55%

MAAQS = 1,300 ug/m3

Background Concentration of 56 ug/m3 included.
!!!!!!!!! !!!!!! !!!! !!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!! !!!!! !!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!! !!!! !!!! !!!!!!!!!!! !!!!!!! !!!! !!!! !!!! !!!!

!!!!!!!!! !!!!!!! !!!!!!!!!! !!!!!!

!!!! !!!! !!!! !!!!!!! !!!!!!!!!!!

!!!! !!!! !!!!!!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!!!!!!!

!!!!!!!!!!!!!!!!! !!!!! !!!!! !!!!!!!!!!!!!! !!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!

!!!!!!!!

!!!!!!!!

!

!!!!!!!!!

!!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!! !!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!

!!!!!!!!! !!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!!!!!!!!! !!!!! !!!!!!!!!!!!!!!!

!!

!!!!!!!!! !!!!!!!!!! !!!!! !!!! !!!! !!!!! !!!!! !!!!! !!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!! !!!!!!!!!!!!!! !!!!!!!!!!!!!! !!!!!!!!!!!!!!

!!!!!!!!!! !!!!!!!!!!!!! !!!!!!!!!

!!!!! !!!!!!! !!!!!!!!!! !!!

!!!!!!!!!!!!!!!!!!

!!

!!!!! !!!!!!

!

!

!!!!!

!!

!

!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!

!!!!!!!!!!!!!!!!!!

!!!!!!!!!!!!

!!!!!!!!!!!! !!!!!!!!!! !!!! !!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!! !!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!! !!!!!!!!!!!! !!!!!!!!! !!!!!!

! !!!!!!!!!!!!!!!!!!!! !!!!! !!!!!! !!!!!! !!!!!!!!!! !!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr 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

Figure 6

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%

MAAQS = 1,300 ug/m3

Background Concentration of 56 ug/m3 included.
!!!!!!!!!!!!!!!!!!! !!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! ! !!!! !!!! !!!!!!!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!!!

!!!!!

!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !

!!!!!

!!!!!!!!!!

!!!!!!! !!!!!!! !!!!!! !!!!! !!!!! !!!!!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!

!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!! !!!

!!!!!!! !!!!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!! !!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!! !!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!

! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! ! !!!!!!!!!!!! !!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr 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

Figure 7

3 Hour SO2 Results 

21H-1 Decoking Scenario

SO2 SIP 9 Exhibit 1

Flint Hills Resources

Pine Bend, MN

Percent of 3 Hour NAAQS

! 8% - 20%

! 21% - 25%

! 26% - 30%

! 31% - 35%

! 36% - 40%

NAAQS = 1,300 ug/m3

Background Concentration of 34 ug/m3 included.
!!!!!!!!!!!!! !! !!!! !!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!

!!!!!!!!!!!!!!! !!!! !!!! !!!!!!!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!! !!!!!!! !!!!!! !!!!! !!!!! !!!!!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!

!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!! !!!

!!!!!!! !!!!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!

! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!! !!!!!!!!!! !!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr 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

! 8% - 20%

! 21% - 25%

! 26% - 30%

! 31% - 35%

! 36% - 39%

NAAQS = 1,300 ug/m3

Background Concentration of 34 ug/m3 included.
!!!!!!! !!!! ! !!!!!!!! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!! !!!!!

!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!!!!!!!!! !!!!!!!!!!! !!!! !!!! !!!!!!!!!!!!! !!!!! !!!! !!!! !!!!!!!!! !!!!!!!! !!!!

!!!! !!!!!!!! !!!!!!!!!! !!!! !!!! !!!! !!!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!! !!!!!! !!!!!!!

!!!!! !!!!! !!!!!!!!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!

!!!!!!!!!!!!!!! !!!!!! !!!!! !!!!!!!!!! !!!!!!!!

!!!!!!!!!! !!!!!!!! !!!!!!!!!! !!!!! !!!!! !!!!!! !!!!!!!! !!

!!!!!!!! !!!!!!!!!!

!!!!!!! !!!!! !!!!!!!!!!!! !!!!!! !!!!! !!!!! !!!!!

!!!!!! !!!!!! !!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!!!!

!!!!!!!!!! !!!!!! !!!!!! !!!! !!!! !!!!!!! !!!!!!!!!!!!!!! !!!!!!!!!!!!! !!!!!! !!!!!!

!!!!!!!!

!!!!!!!!!!!

! !!

!!!!!!! !!!!!! !!!!!! !!!!!!!!!!! !!!!!!!!!!!!!!!! !!!!! !!!! !!!!!!!!!!!!!!! !!!!!! !!!!!! !!!!!!

!!!!!!!!!!!! !!!!! !!!!!!!!!!!!!!!!!!!! !!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!! !!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!! !!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!! !!!!! !!!!!!!!!!!! !!!!!!!!!!!!

!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!! !!!!!!!! !!!!!! !!!! !!!!!! !!!!!!!!

!!!!! !!!!!!!!!!!

!!!!!!

!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!!!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!! !!!!!! !!!! !!!! !!!!! !!!! !!!!!

! !!!!!!!!!!!!!!!!! !!!!!!!!! !!!!! !!!!!!!!!!!!!!!!!!! !!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr 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

Figure 9

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%

! 16% - 20%

! 21% - 25%

! 26% - 30%

! 31% - 33%

NAAQS = 1,300 ug/m3

Background Concentration of 34 ug/m3 included.
!!!!!!!!!!!!!!!!!!!! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!! !!!! !!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!!! !!!!!!!!!! !!!!! !!!!! !!!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!!!!!!!!! !!

!!!!!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!!

!!!!!!!!!!!!!! !!!!!!!!!! !!!!!!! !!!!!!! !!!!

!!!!!!!!!!!! !!!!! !!!!! !!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!!!! !!!!!!!!!!! !!!!! !!!!!! !!!!! !!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!! !!!!!! !!!

!!!!!! !

!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!! !!!!!!

!!!!!

!!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!! !!!!!! !!!!!! !!!!!! !!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!! !!!!!!!!! !!!!! !!!!!!!!!!!!!!

! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr Footer: Date: 5/3/2011 4:31:34 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure10_24Hour_SO2_Results_21H1DecokingScenario.mxd User: jjm

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%

! 31% - 35%

! 36% - 40%

! 41% - 45%

! 46% - 47%

NAAQS = 365 ug/m3

Background Concentration of 17 ug/m3 included.
!!!!!!!!!!!!!!!!!!!! !

!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!! !!!! !!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!! !!!!! !!!!!!!!!! !!!!! !!!!! !!!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!!!!!!!!! !!

!!!!!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!!

!!!!!!!!!!!!! !!!!!!!!!! !!!!!!!!!!! !!!! !!!!

!!!!!!!!!!!! !!!!! !!!!! !!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!!!!!!!! !!!!!!!

!!!!!! !!!!!!!!!! !!!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!! !!!!!! !!!!!!!!!

!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!! !!!!!! !!!!!!

!!!!! !!!!! !!!!!

!!!!! !!!!!

!!!!!!!!!!!!!

!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!! !!!!!! !!!!!! !!!!!! !!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!! !!!!!!!!! !!!!!! !!!!!!!!!!!!

! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr Footer: Date: 5/3/2011 4:38:17 PM File: I:\Client\FlintHills\PineBend\AirModeling\Projects\23191034_SIP9\Report_Figures\May2011\Figure11_24Hour_SO2_Results_21H2DecokingScenario.mxd User: jjm

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

! 10% - 30%

! 31% - 35%

! 36% - 40%

! 41% - 45%

! 46% - 47%

NAAQS = 365 ug/m3

Background Concentration of 17 ug/m3 included.
!!!!!! !!!!! ! !!!! !!!! !

!!!!!!!!!!!!!!!!!!!!!! !!!!!!!! !!!! !!!! !

!!!!!!!!!!!!!!!!!!!!!

!!!

!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!

!!!!!!!!!! !!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!! !!!!!!!! !!!!!!! !!!!!!!!!!!! !!!! !!!! !!!!!!!!

!!!! !!!

!!!!!!!! !!!!!! !!!!! !!!!!

!!!!! !!!!!!!!!!!!!

!!! !!!!!!!!!!

!!!!!

!!!!!!!!!!!!! !!!! !!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!! !!!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!!!

!!!!! !!!! !!!!!!!!!!!!!!!! !!!!!!!!!!! !!!!! !!!!! !!!!! !!!!!! !!!!!! !!!!!!!!!!!!!!!

!!!!! !!!! !!!!!

!!!! !!!!! !!!!!

!! !!!!!!

!!!! !!!!

!!!!!!!

!

!!!!

!!!!!!

!!!!!! !!!!!! !!!!! !!!!! !!!! !!!!! !!!!!!!!! !!!!!!!!!! !!!!! !!!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!! !!!!!!!! !!!!!!!!

!!!!!!! !!!! !!!! !!!!!!!!!!!!!

!!

!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!! !!!!!!!!!!!! !!!!! !!!!! !!!!!!!! !!!! !!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!! !!!!

!!!!!! !!!!!! !!!!!! !!!!!! !!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!! !!!!!!!

!

!!!!!! !!!!!!! !!!!

!!!!!

!!!!!!! !!!!!!!!!!!!

!!!!!

!!!!!!!!!!!!!!!!!!! !!!!!!! !!!!! !!!!!! !!!!!! !!!!!!!!!!

!!!!! !!!!! !!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!!!! !!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!!! !!!!!!!!!!!!!!

!

!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!!!!!!!!!! !!!!!!! !!!!!!!!!!

! !!!!!!!!!!!!!!! !!!!!!!!!!!!! ! !!!!!!!!!!! !!!!!!!!!! !!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr 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

! 11% - 25%

! 26% - 30%

! 31% - 35%

! 36% - 40%

! 41% - 46%

NAAQS = 365 ug/m3

Background Concentration of 17 ug/m3 included.
!!!!!!!!!!!!!!!!!!!! !

!!!!!!

!!!!!!!!!!!!!!!!!! !

!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!

!!!!!!!!!!!!!!!!! !! !!!!!!!!!!!!!

!!!!!!! !!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!

!!!!!!!! !!!!!!!!!! !!!!!!!!!!!! !!!! !!!! !!!! !!!!!

!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!!!!!!! !!!!!

!!!!

!!!! !!!! !!!! !!!! !!!! !!!!! !!!!! !!!!!! !!!!!!!! !!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!!

!!!!!

!!!!! !!!!! !!!!! !!!!!

!!!!!!!!!!!!!!!!!!

!!!! !!!! !!!! !!!! !!!!! !!!!! !!!!! !!!!!! !!!!!!

!!!!!

!!!!!! !!!!! !!!!! !!!! !!!! !!!! !!!! !!!!!!!!!!!!!!! !!!!! !!!!! !!!!! !!!!!!!! !!!!! !!!!! !!!!! !!!!!! !!!!! !!!!! !!!!! !!!!! !!!!! !!!!!

!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!! !!!!!!! !!!!! !!!!! !!!!!!!!!!!! !!!!! !!!!! !!!!!!!!!!!!!!!!! !!!!!!

!

!!!!! !!!!! !!!!! !!!!! !!!!! !!!! !!!!!! !!!!!! !!!!!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!! !!!!!! !!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!! ! !!!! !!!!! !!!!!!!!! !!!!!! !!!!!! !!!!!! !!!!!! !!!!! !!!!! !!!!! !!!!!!

!!! !!!! !!!! !!!!!!!!!! !!!!!!!!! !!!! !!!! !!!!! !!!!!!

!!!!!!!!!!!!!! !!!!! !!!!! !!!!!!!! !!!!!!! !!!!!!!!!!!

!

! !

! !

!

! !

! !

! !

! !

!

!

!

! ! ! ! ! ! ! ! ! ! ! !

!!!

!!!!!

!

!!!!!!!!!!!!!

!!!

!

!!

!!!

!

!!!!!!

!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

!!! !!!!!!!!!!!!!!!!!!!!!!!!!!!

! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! !!!!

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

! ! ! ! ! !

!;N

Barr 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

1 0 1 2

Kilometers

Figure 13

Annual SO2 Results 

SO2 SIP 9 Exhibit 1

Flint Hills Resources

Pine Bend, MN

Percent of Annual NAAQS

! 11% - 20%

! 21% - 30%

! 31% - 40%

! 41% - 50%

! 51% - 58%

NAAQS = 60 ug/m3

Background Concentration of 4 ug/m3 included.
Exhibit 1 - Section 9 

Background 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/m3

for the listed averaging times: 

1 - Hour Averages 56 ug/m3 (MPCA 2008 Option 2 values for “Rest of TC”) 

3 - Hour Averages 34 ug/m3 (MPCA 2008 Option 2 values for “Rest of TC”) 

24 - Hour Averages 17 ug/m3 (MPCA 2008 Option 2 values for “Rest of TC”)

Annual Averages 4 ug/m3 (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 version 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 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 the followingthis

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 “implementation, 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 (19912010) (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 concentration, not to be exceeded 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 for sulfur dioxide of 75 parts per billion (ppb) 

one-hour annual average, met when the three-year average of the annual 99th percentile of the daily 

maximum one-hour concentration is less than 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 (19912010). 

5.6. The MPCA is a statutory agency of the state of Minnesota, Minn. Stat. § 116.02, subp. 1 (19902010), 

charged with the responsibility to administer and enforce laws and promulgate rules to prevent water, 

air and land pollution throughout the state of Minnesota, Minn. Stat. chs. 115, 115B and 116 (19902010). 
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 limitation, 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 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 (19902010). 

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 concentration, not to be exceeded more than once 

per year. Minn. Rules pt. 70057009.0080 (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. 70057009.0080 

(19912010). 

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 enforcing “reasonable orders, schedules of compliance and 

stipulation agreements.” Minn. Stat. § 116.07, subp. 9 (19902010). 

9.10. Minn. Stat. § 115.071 (19902010) 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 (19902010). 

10.11. The seven-county Twin Cities metropolitan area Air Quality Control Region (AQCR) is defined at 

40 CFR § 81.27 (19912010) 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 Implementation Plan (SIP) to control emissions of 

sulfur dioxide in the Twin Cities nonattainment area, AQCR 131. 46 Federal Register 20997 (April 8, 

1981). See 40 CFR § 52.12201222(c)(16) (199117) (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 Air Act, 42 U.S.C. §§ 7501-7508. 47 Federal Register 32,74232742

(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 redesignate 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 Federal 

Register 47488 (December 5, 1984), and identified Dakota County as one of the areas in the country with 

fully or partially approved Part D plans 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 athe 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 Washington 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 the 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 comments inEPA’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 General 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 for 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 Petroleum 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 the state of Minnesota at the junction of Highways 52 

and 55 in Dakota County, Minnesota. 

19.20. The Company owns and operates a petroleum refinery (Refinery), in the Pine Bend area of 

Rosemount, Dakota County, Minnesota. The refineryfacility 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. Rules 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. 106A-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 this 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 contained in this Administrative Order regarding 

FHR’s Sulfuric Acid Units (SAU). The issuance of that permit removed the need to include SO2 

requirements for the FHR SAU in this Administrative Order. 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 VIIIVII. below) that will achieve and maintain compliance with the annual, 24-hour and 

three-hour NAAQS for sulfur dioxide. 

21.22. The Refinery iswas found to be a potential 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)] it 

iswas 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 facilities which contain emission sources 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 thisthe 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 request to EPA to redesignate the Pine Bend 

sulfur dioxide area from nonattainment to attainment. On May 31, 1995, the EPA published a Direct Final 

Rule (60 FR 28339) indicating that it intended to redesignate the Pine Bend area from nonattainment for 

sulfur 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. 

25.26. On February 10, 2000, EPA promulgated the “Control of Air Pollution from New Motor Vehicles:

Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements.” This rule, 

effective April 10, 2000, required most refiners (including 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 civil penalties and injunctive relief against 

Koch Petroleum Group, 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 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 requiresrequired changes to 

this Administrative Order. 

27.28. On January 18, 2001, EPA promulgated the “Control 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 mustwere required to be available 

by June 1, 2006. 

28.29. On March 11, 2003, the MPCA amended this Administrative 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 willwould maintain compliance with 

the NAAQS for sulfur dioxide in the Pine Bend area of AQCR 131, and willwould 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 Administrativethis 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 the Consent Decree (Civil Action 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 allowwhich 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 SO2 emissions from refinery fuel gas 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 install a new boiler, to decommission 34H-3 (Merox Thermal Oxidizer) and 

re-route 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. SO2

emission rates for refinery fuel gas combustion at certain emission units and heater steam-air decoking 

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 eliminates previously completed or obsolete provisions from 

earlier Administrative Orders and amendments issued to FHR and included in Minnesota’s State 

Implementation Plan. 

31.34. This Order is needed to maintain the 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 dioxide as set forth in 40 CFR §§ 50.4 and 50.5 (19912010), 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 the property from the definition of “ambient air” 

subject to the sulfur dioxide NAAQS. Exhibit 81 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 81, attached and incorporated by reference. 

The Company shall meet the following requirements for the property shown in Exhibit 81: 

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 is present controllingpatrols 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 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 control plan will attain compliance with NAAQS. Exhibit 81 is 

the modeling technical support document. The sulfur dioxide modeling parameters for this equipment 

are contained in Exhibit 81. The emission limits and operational requirements of this Order apply to the 

units identified in Exhibit 81. 

The remainder of this Part is divided into threetwo sections. The first section contains the 

required Refinery modifications and compliance schedules. The second section contains the 

Refinery'sRefinery’s sulfur dioxide emission limitations, fuel restrictions, and operational requirements. 

The thirdsecond section contains the Refinery’s compliance 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.BA and shall demonstrate compliance as described in Part II.CB. 

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 reference herein, for each emission point. The Company's total 

facility emissions also shall not exceed 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 fuel 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 included in the ambient air quality modeling (in Exhibit 8). 

Reductions achieved by eliminating 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 Oily Separationwer Waster 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. 70Units EU144 through 99EU 

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 sources 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 IIIV.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 thosethe units identified in 

(a)(1), above, may burn Refinery fuel gas not taken from the Refinery fuel gas 

system provided that the Company install, operate, and maintain a hydrogen 

sulfide continuous monitoring system (CMS) and flow meter at the heaterfuel gas 

combustion unit in accordance with the requirements of Part II.CB.23 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-gas; soil-vapor extraction off-gas; wastewater treatment process vapors; and 

reformer lock hopper and switch valve 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 version) 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 4541 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 

than 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 any time which contains greater than 162 parts 

per million (ppm) of hydrogen sulfide (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 with a sulfur content not in excess of 15 ppm 

(0.05 percent0015%) by weight at each of the Refinery’s stationary diesel engines. Limits on 

hours of operation for selected stationary diesels are shown in Table 52, 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 gases from Refinery operations unless 

the gases are from pressure relief, are from upsets of Refinery process equipment, or are required for equipment 

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 No. 3 flare. 

a) (c) Nos. 5, 6, 7 Flares. These flares (Emission Point Nos. 109, 110, and 106, 

respectivelyE. 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 equipment 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 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. 113SV094 unless tail gas from SRU 3 is bypassing the SCOT/TGTU 

#1 Unit. (EU261 and EU262). The Company may use Emission Point No. 2SV093 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. 3SV042 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 necessary 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. 9SV021 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 WHCO Boiler (17H-2) or small WHCO Boiler 

(17H-4). 

B. C. Demonstration of Compliance With Emission 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 VIV. of this Order and recordkeeping requirements in Section VIV.B.2 of this Order to 

determine compliance with each emission limitation in Table 1. The Company's emission 

monitoring programs shall also comply with Part VIV. of this Order. 

1 [Removed.] 

2. Demonstration of Compliance With Fuel Gas Restrictions 

The Company shall implement the compliance methods in Sections VIV.A.2 and 

VIV.B.2.a of this Order to determine compliance with the fuel gas restrictions of Part II.BA.3 of 

this Order. The Company’s fuel gas monitoring programs shall also comply with Part VIV of this 

Order. 

3. 4. Demonstration of Compliance with 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 delivery 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 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 

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.BA.5 of this Order. 

6. [Removed.] 

III. [Removed.] 

III. IV. CHANGES NOT REQUIRING A MODIFICATION OF THIS ORDER 

The Company is authorized to conductbegin 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 emit sulfur dioxide, do not affect the modeling parameters 

assumed in Exhibit 81, 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 activitiesany 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 operate a modified unit in a manner contrary to the modeling 

parameters in Exhibit 81 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 dioxide emissions rate that does not exceed 2.28 pounds per hour, except as 

expressly allowed elsewhere in this part (Part IVIII.). 

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 81. 

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 emissions, at the emission source where the modification occurs and all 

other potentially affected emission points assumed in the modeling presented in Exhibit 81. 

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 replacement stack is not less than that of the stack assumed 

in the modeling presented in Exhibit 81, 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 81. 

D. The Company may install and operate new structures, 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 81. 

E. The Company may replace and operate replacement CEMs and CMSs covered by this Order or 

the Company may install and operate additional 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. [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 VII.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. 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 

81, 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 Powerformer 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 continue to operate 

these sources on Refinery fuel gas or natural gas according to the requirements of Part II.B.3 of this Order. 

Authority to construct under this part (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 and control requirements established in 

the Consent Decree (Civil Action No. 00-2756-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, 27H102, 31H-4, 31H-7, 31H-9, 

32H-5,6,7, 33H-31, 33H-4 (33 H-1 & 2), 38H1A, 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 Company may make modifications to heaters 25H-1 and 25H-3, and install a new heater 25H-4. The 

modified modeling paramenters of these units are described in Exhibit 8: 

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 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 analysis as required by 

this Order to ensure accurate measurements of the parameters to be monitored. 

2. The Company shall measure the stack sulfur dioxide 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. 1EU245 (Merox 

TO), No. EU055 (31H-2), SV093 (SRU 3/4), 3SV042 (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. 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 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 necessary to meet the requirement as soon as 

possible. 

2. Monitor Certification 

a) Sulfur Dioxide CEMs. The Company shall certify each sulfur dioxide CEM as 

required by 40 CFR Part 60, Appendix B, Performance Specification 2 (19912010). 

b) Emission Rate CMSs. The Company shall certify each continuous monitoring 

system as required by 40 CFR Part 60, Appendix B, Performance Specification 6 

(19912010), except that the Company 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 (20052010), 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 assurance and quality control (QA/QC) program as 

required by 40 CFR Part 60, Appendix F (19912010), 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. The 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 limitation 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 refinery fuel gas 

distribution loop. The CMS shall provide a continuous record of the total reduced sulfur 

content in ppm. Alternatively, the Company may installThe Company shall maintain an 

SO2 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 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 monitor in accordance with an EPA-approved 

Alternative Monitoring Plan (AMP) at a representative point in the line supplying the 

heater. For heaters receiving commercial grade fuels directly, (e.g., commercial grade 

natural gas and propane), contract guarantees for hydrogen sulfide and heat content 

shall be utilized for compliance demonstration purposes. 

b)c) (d) 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 requirement 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; 
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 monitoring 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 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 

test plans, protocols and schedules at least 15 days prior to the pretest meeting required in Part 

VII.A.5 of this Order. 

V. VI. RECORDKEEPING REQUIREMENTS 

This Part VIV 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 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 accessibility 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 records 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 periodminimum 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 shall 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 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 81, 

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 81 is 

installed as described in that exhibit. Where an activity has been undertaken pursuant 

to Part IVIII 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 

IVIII 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 maintain 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 identified 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 maintenance 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. 3SV042 (SRU 5), and No. 

8SV019 (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.AB.3.c. Using the one-hour 

averages, FHR shall calculate the three-hour, twenty four-hour, and annual rolling 

averages corresponding to the emission limits referenced above. 

b) Sulfur Dioxide Emissions, Fuel Records 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, 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 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 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 operating 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 required 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 information in a form that is easily accessible for inspection by 

EPA or MPCA staff, and that is available for 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 emissions 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 Certification 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 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. 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 than 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 subject 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 undertaking an activity 

allowed by Parts IV.A, D, H, and I of this Order. The written notification shall describe the change the Company is 

proposing to make, and shall include submittal of a permit 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 made pursuant to Part IV.E in the first quarterly 

report required by Part VII.C following the change. 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 shutdown 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 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 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 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 record 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 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 (19912010). 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. 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, the 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 for 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 81, the Company shall obtain a 

modification of this Order. 

B. This Order is meant to delineate 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. [Removed.] 

C. D. 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 performance standards, and laws and regulations related to occupational 

safety and health. In the event there is a conflict in applicable 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 representatives shall have authority to enter all property 

of the Company in Rosemount, Minnesota, at all reasonable times for the purposes of inspecting 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. 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 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. 

G. [Removed.] 
Page 22 of 25

H. 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 

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 theall previous SIP approved in 1981, at 46 Federal Register 20997 (April 8, 

1981),revisions, as they apply to FHR.

IT IS SO ORDERED.
TABLE 1 – REFINERY EMISSION LIMITATIONS FOR EACH APPLICABLE FEDERAL SULFUR DIOXIDE AMBIENT A

EMISSIONPOINT

STACK VENTEMISSION UNIT 

FACILITY ID # FACILITY OR 

SOURCE DESCRIPTION

3-HOUR AAQS (1) 24-HOUR AAQS 

(2)

ANNUAL AAQS 

1 SV078

EU245

34H-3 Merox TO Facility 65.4 230 pounds 

SO2 per hour

286.4 1007.4 tSO2 per 12 mo

2 SV093

EU111 and EU112

45UNIT2-145UNIT3-1

SRU 3 and SRU 4 Facility (SCOT) (5) 

149.0 pounds SO2 per hour 

86.5 pounds SO2

per hour 

324.3 tons SO

12 months 

3 SV042

EU045

26UNIT-1 SRU 5 Facility 

(TGTU #2) (5) 

170.8 pounds SO2 per hour 

93.6 pounds SO2

per hour 

409.8 tons SO

12 months 

8 SV019

EU228

17UNIT1 FCC Facility 182.6 1500

pounds SO2 per 

hour

800 3504 tons per 12 months 

SV049

EU055

31H-2 #2 HDS Fractionation 

Heater

66.4 pounds SO2per hour 

290.8 tons SO12 months 

348 SV125

SV146EU282EU254

94H-194H-3

OSWTP Facility (oxidizers(6)) 

50.71 pounds SO2 per hour (4)

50.71 pounds SO2 per hour (4)

39.4 tons SO2 

12 months (9.0 lb/hr) 

(1) These emission limitations are based on three consecutive one-hour periods (3-hour rolling averages). To demonstrate compliance with tcalculated 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 thcalculated in such manner, except for Emission 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 

calculated 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 compliance with the limitation, emissions shexcept for Emission Point No. 348EU282. (See (4).) (4) This emission limitation is a one hour maximum value to be met for any one consecutive hour period. Compliance with these emissdemonstrated by stack tests. (5) Limits include emissions from the incineration of sulfur dioxide emission reduction for netting purposes under the Prevention of Significant DCFR 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 WWTExcept when switching WWTP gases from one oxidizer to the other, only one oxidizer may combust gases from OSWTP equipment at a time. concurrently with natural gas for standby purposes.
 TABLE 5 2 – LIMITS ON DIESEL-POWERED UNITS

EMISSION 

POINT NO.

EMISSION UNIT FACILITY OR SOURCE ID # DESCRIPTION ANNUAL LIMIT 

331 EU131 93 P 160 Diesel-powered fire water 

pump 

1000 hours 

332 EU198

M93 P 400 Diesel-powered fire water 

pump

1000 hours 

333 EU199

M93 P 570 Diesel-powered fire water 

pump 

1000 hours 

407 EU042 EE 1657M Diesel-powered generator 1000 hours 408 EU007 EE 1852M EE1692M Diesel-powered generator 1000 hours 435 EU036

M23 ME 26 Diesel-powered generator 1000 hours 

453 EU100 EE 1309M Diesel-powered generator 1000 hours 465 EU024 EE 1718M Diesel-powered generator 1000 hours 505 EU130

M81 P 159 Diesel-powered cooling water 

pump

No limit 1000 hours 

506 EU132

M81 P 357 Diesel-powered cooling water 

pump

No limit 1000 hours 

507 EU128

M81 P 444 Diesel-powered cooling water 

pump

No limit 1000 hours 
508 EU129 M81 P 89 Diesel-powered cooling water 

pump

No limit 1000 hours 

510 Wood River diesel Diesel-powered pump 2000 hours 511 EU127 71C-11 Diesel-powered plant air 

compressor 

2500 hours 

513 EU133 M81 P 598 New 81 P 450 Diesel-powered cooling water 

pump 

No limit 1000 hours 
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 Merox Off-Gas 34H-3 EU245 SV078 

Will be shutdown upon 

completion of the project 

to 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 SO2

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 operationbut 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 Rates 

 
Description Model ID 1-hr 3-hr 24-hr Annual Comments [

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 0.05000 Slight increase in 1-hr rate to align with byp71B-7 K7____BH -6.88 -5.47 -5.47 -5.47 Source removed with corresponding historicFCC ESP K8___FCC -165.98 -165.98 -165.98 -63.29 Emissions lowered to be more consistent wi32H-5,6,7 K10_32FG 0 0.39 0.39 0 Increased 3-hr and 24-hr fuel gas sulfur con19H-1 K11_19FO -0.33 0.10 0.10 -0.33 Historical fuel oil contribution is removed. I12H-4 K13_12FG 0 0.37 0.37 0 Increased 3-hr and 24-hr fuel gas sulfur con33H-31 K14_33FO -4.19 -3.05 -3.05 -3.39 Historical fuel oil contribution is removed. I16H-1 K15_16FG 0 0.58 0.58 0 Increased 3-hr and 24-hr fuel gas sulfur con11H-3 K16_11FO -1.84 -1.84 -1.84 -1.84 Source removed with corresponding historic11H-5 K18_11FO -0.83 -0.83 -0.83 -0.83 Source removed with corresponding historic11H-1 K19_11FO -1.15 -0.76 -0.76 -1.15 Historical fuel oil contribution is removed. I37H-1,2,6 K20_37FG 0 0 0 -0.17 Reduced annual fuel gas sulfur content from 33H-32 K21_33FG 0 0 0 -0.25 Reduced annual fuel gas sulfur content from 11H-2 K23_11FG 0 0.14 0.14 0 Increased 3-hr and 24-hr fuel gas sulfur con21H-1S FO fired K27_21FO -0.50 -0.34 -0.34 -0.50 Historical fuel oil contribution is removed. I21H-1N FO fired K28_21FO -0.50 -0.34 -0.34 -0.50 Historical fuel oil contribution is removed. I21H-2S FO fired K29_21FO -0.48 -0.32 -0.32 -0.48 Historical fuel oil contribution is removed. I21H-2N FO fired K30_21FO -0.48 -0.32 -0.32 -0.48 Historical fuel oil contribution is removed. I33H-4 (33H-1&2) K31_33FG 0 0 0 -0.35 Reduced annual fuel gas sulfur content from 23H-1 FO fired K32_23FO -0.02 0.38 0.38 0.06 Historical fuel oil contribution is removed. I31H-1 K33_31FG 0 0.06 0.06 0 Increased 3-hr and 24-hr fuel gas sulfur con31H-2 K34_31FG 8.24 8.30 8.30 8.30 Introduction of Merox offgas for combustio31H-5 K36_31FG 0 0.02 0.02 0 Increased 3-hr and 24-hr fuel gas sulfur con31H-10 K37_31FG 0 0.07 0.07 0 Increased 3-hr and 24-hr fuel gas sulfur con32H-9 K41_32FG 0 0.02 0.02 0 Increased 3-hr and 24-hr fuel gas sulfur con37H-3,4,5 K42_37FG 0 0 0 -0.76 Reduced annual fuel gas sulfur content from 38H-1A K46_38FG 0 0 0 -0.07 Reduced annual fuel gas sulfur content from 38H-1B K47_38FG 0 0 0 -0.07 Reduced annual fuel gas sulfur content from 

Table 1. Modeled SO2 Emissions Change (grams/second) From SIP Order Amendment #8 to Proposed 

Emissions Averaging Period (g/s)
Description Model ID 1-hr 3-hr 24-hr Annual Comments [

Table 1. Modeled SO2 Emissions Change (grams/second) From SIP Order Amendment #8 to Proposed 

Emissions Averaging Period (g/s)

38H-2 K48_38FG 0 0 0 -0.12 Reduced annual fuel gas sulfur content from 25H-1 K50_25FG 0 0 0 -0.49 Reduced annual fuel gas sulfur content from 25H-3 K51_25FG 0 0 0 -0.44 Reduced annual fuel gas sulfur content from 25H-4 K52_25FG 0 0 0 -0.32 Reduced annual fuel gas sulfur content from 23H-2 K53_23FG 0.54 0.84 0.84 0.60 Changed FG drum assignment which chang27H-1 K54_27FG 0 0 0 -1.56 Reduced annual fuel gas sulfur content from 27H-101 K55_27FG 0 0 0 -0.16 Reduced annual fuel gas sulfur content from 27H-102 K56_27FG 0 0 0 -0.18 Reduced annual fuel gas sulfur content from 31H-4 K57_31FG 0 0.17 0.17 0 Increased 3-hr and 24-hr fuel gas sulfur con31H-7 K58_31FG 0 0.17 0.17 0 Increased 3-hr and 24-hr fuel gas sulfur con31H-8 K59_31FG 0 0.09 0.09 0 Increased 3-hr and 24-hr fuel gas sulfur con31H-9 K60_31FG 0 0.12 0.12 0 Increased 3-hr and 24-hr fuel gas sulfur con28H-1 K61_28FG 0 0 0 -0.07 Reduced annual fuel gas sulfur content from 71B-8 K62_BLR8 0 0 0 -0.36 Reduced annual fuel gas sulfur content from 27H-501 K63_27FG 0 0 0 -0.92 Reduced annual fuel gas sulfur content from 11H-6 K67_11FG 0 0.96 0.96 0 Increased 3-hr and 24-hr fuel gas sulfur con71B-9 K68_BLR9 0 0.58 0.58 0 Increased 3-hr and 24-hr fuel gas sulfur conBoiler 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 29 H-1 Comb Fd& Dist K71HCFD 0 0 0 -0.43 Reduced annual fuel gas sulfur content from 71B-6 Boiler K1006_BH 0.06 0.33 0.33 0.03 Updated duty from 108 to 120 MMBtu/hr to 45H-6 K113__FG 0.09 0.09 0.09 0.07 Reduced fuel gas sulfur content; added SRU 93P-160 K331_DSL -0.01 -0.01 -0.01 -0.00 Fuel sulfur content reduced from 500 to 15 p93P-400 K332_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 p93P-570 K333_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 p94H-1 K348_OXD 0 0 0 0 No change.EE-1657 K407_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 pEE-1692 K408_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 p23ME26 K435_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 pEE-1309 K453_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 p
Description Model ID 1-hr 3-hr 24-hr Annual Comments [

Table 1. Modeled SO2 Emissions Change (grams/second) From SIP Order Amendment #8 to Proposed 

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 p81P-159 K505_DSL -0.02 -0.02 -0.02 -0.00 Fuel sulfur content reduced from 500 to 15 p81P-357 K506_DSL -0.02 -0.02 -0.02 -0.00 Fuel sulfur content reduced from 500 to 15 p81P-444 K507_DSL -0.03 -0.03 -0.03 -0.00 Fuel sulfur content reduced from 500 to 15 p81P-89 K508_DSL -0.01 -0.01 -0.01 -0.00 Fuel sulfur content reduced from 500 to 15 pWood River K510_DSL -0.06 -0.06 -0.06 -0.01 Fuel sulfur content reduced from 500 to 15 p71C-11 K511_DSL -0.03 -0.03 -0.03 -0.01 Fuel sulfur content reduced from 500 to 15 pPortable diesel cap PORT_DSL -0.74 -0.74 -0.74 -0.03 Removed from model.New K509DSL81P-450 K513_DSL -0.06 -0.06 -0.06 -0.01 Fuel sulfur content reduced from 500 to 15 p21H-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_DEC 0000 Included in 23H-1 dec source.Acid Ld & Depress K700ACDL 0 0 0 0 No change.

Net Emissions Change in grams/second: -215.6 -207.0 -207.0 -106.5

Net Emissions Change in lb/hr: -1,710 -1,641 -1,641

Net Emissions Change in tons/year: -3,699

Net 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 rAmendments #8 and #9 for all averaging peEmissions estimates are refined based on en3-hr, and 24-hr averaging periods, each decoindividually instead of concurrently as in SI
1-hour* 1300 52.1 56 1059 85 4032 314 

3-hour 1300 36.5 34 690 56 1766 139 

24-hour 365 10.4 17 256 73 437 123 

Annual** 60 6.1 4 32 64 18 39 

[1] The NAAQS and MAAQS are the same unless otherwise specified. The more restrictive standard is listed. * SO2 1-hour is MAAQS.

** 60 μg/m3 is SO2 annual 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 maximu out 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  concentration and percent of standard values for the annual averaging period in this table reflects all three decoking activities o year. 

Table 2. SIP Order Amendment #8 and Amendment #9 Modeling Results Comparison

SIP8 AERMOD 

Modeled 

Concentration 

(μg/m3

) [2]

Percent 

of 

Standard 

Model Run Pollutant (%)

Averaging 

Period

with Informational Modeling Run of Amendment #8 Inputs in New AERMOD Model.

Approved SIP8 

ISC Modeled 

Concentration 

(μg/m3

) [2]

Percent 

of 

Standard 

(%)

NAAQS/ SO2

MAAQS

SIP8 

Background 

(μg/m3

)

Standard 

(μg/m3) 

[1]

SIP9 

Background 

(μg/m3

)
Attachment 5: TSD for Related Permitting Action 
Technical 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 policy 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 referred to as “FHR” or “Permittee”) owns and operates 

the Pine Bend Refinery (“refinery” or “facility”) in the city of Rosemount, Dakota County, Minnesota. The 

refinery primarily processes heavy, sour crude oil from Western Canada, although it may also process oil 

from other parts of the world. Pipelines currently deliver 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 sulfur, and carbon dioxide. FHR distributes these 

products to customers in Minnesota and the surrounding 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 Recovery Unit (SRU) (also known as the 26 Unit; vents 

through SV 042) Nitrogen Oxides (NOX) Best Available Control Technology (BACT) limit due to 

identification of additional NOX 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 the permit the outstanding Hydrogen Sulfide (H2S) 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 Incinerator (EU245) and reroute the off gas to the 31H-2 

heater (EU055) (DQ #3153). This amendment also changes the SO2 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 portable coke crushers (EU325 & EU326) to be operated 

no more than 6 months per year (DQ #3352). 

5. An administrative amendment to change the facility 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 (EU053) of less than 34.0 mmBtu/hr (DQ #3374). 

1.4 Facility Emissions:

Table 2. Title I Emissions Increase Summary (SV042 NOX 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 

PM10 15 

PM2.5 10 

NOX 42.5* 42.5* 40 Yes 

SO2 40 

CO 100 

Ozone (VOC) 40 

Lead 0.6 

*Emissions increase is due to revision of the SV 042 NOX BACT limit established by the 1992 Clean 

Fuels New Source Review permit. The value shown in this column is the revised total SV 042 NOX

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 

PM10 15 

PM2.5 10 

NOx 40 

SO2 39.3 33.5 07-08 None 5.8 40 No 

CO 100 

Ozone 

(VOC) 

 40 

Lead 0.6 

CO2e**** 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 

CO2 -7904.4 tpy PM10 -0.86 tpy 

NOX -31.74 tpy VOC -6.18 tpy 

SO2 -1007 tpy 

The 31H-2 (EU055) heater is rated at 23 mmBtu/hr. Using the fuel gas combustion emission factor from 

EPA AP-42 of 127.55 lb/mmBtu, this yields 12,849 tpy CO2e. The heater rating before and after the 

project will remain 23 mmBtu/hr; therefore the CO2e increase from the project is 0 tpy; however, one of 

the three burners of 31H-2 will be redesigned to accommodate the Merox offgas stream formerly 

combusted at 34H-2/3 (EU245). 31H-2 burning fuel gas only 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 CO2e 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) 

PM10 1.5 0 1.5 0.855 3.42 Minor 

NOx 2.28 9.13 

SO2 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, PM10, PM2.5, SO2, NOX, CO, VOC, 

GHG 

N/A Pb 

Part 70 Permit Program PM10, PM2.5, SO2, NOX, 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 NOX BACT limit due to the identification of additional 

NOX emissions from No. 5 SRU. The Permittee submitted a revised permit application including BACT and 

ambient air analyses to address the additional emissions. An Endangered Species Act (ESA) consultation 

was required as well. The consultation determined that the proposed permit modification for the No. 5 

SRU at the facility would have no effects on any threatened or endangered species present in Dakota 

County and no further consultation was required 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 Refineries 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 Refineries for which Construction, Reconstruction, or 

Modification Commenced After May 14, 2007 
Technical 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 H2S/dscm from NSPS subp. J. 

EU055 is triggering 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 

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 Standards for Hazardous Air Pollutants from Petroleum 

Refineries 

40 CFR pt. 63, subp. UUU: National Emission Standards 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 applicable emission limits for this modification, CAM does 

not apply. 

Environmental Review & AERA

The changes authorized by this permit amendment 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 Performance for Petroleum Refineries (EU055, 

Fuel Gas Combustion Device) 

• Minn. R. 7011.0700 - 7011.0735 Standards of Performance 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 compliance 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 NOX

standard at 40 CFR Section 60.102a(g)(2). Increase in SO2

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 NOX 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% 

O2) to account for additional NOX 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 Clean Air Act' refers to permit requirements that are 

mandated by state law rather than by the federal Clean 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 Shutdown 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 currently 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 Regenerator) offgas into the new vent gas equipment 

routed to 31H-2 during 42V-41 (skim pot mounted above caustic settler 42V-16, EU109) 

maintenance outages. (42V-12A is in identical service to 42V-41 as part of a full backup system 

that is used when the primary system is down for maintenance.); 

• Shutdown the Merox incinerator (34H-2/3); 

• Upgrade power supply for CEMS building that currently 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 Implementation 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 scope 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 saturates gas plant (14 unit) for further sulfur 

recovery; however, it is included here for completeness; and, 

o Implement a change from naphtha to #1 fuel 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. Construction 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 SO2 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 and 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 March 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 capacity 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 

NOX burners (ULNB) under Consent Decree requirements. 

New Source Performance Standards for Refineries - 40 CFR pt. 60, subp. J/Ja 

 Fuel Gas Combustion Device (FGCD) as Affected Facility Under J/Ja
Technical Support Document, Permit Action Number: 03700011-008 

Page 8 of 27 

Date: 8/15/2011

The Merox Incinerator (34H-2/3) is not currently subject to 40 CFR pt. 60, subp. J for SO2 emissions 

because it is considered a grandfathered 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 SO2 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 include physical modifications to the heater that will 

result in increased SO2 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 device 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 H2S 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 project, 31H-2 will now utilize the Merox vent offgas 

as an additional fuel gas source; however, this fuel gas will be routed directly to the heater firebox rather 

than being monitored through the mix drum and therefore will not be monitored via the analyzer at the 

refinery fuel gas mix drum analyzers. 

Although an SO2 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-H2S 

sulfur compounds present in the fuel gas that would not be representative of fuel gas H2S. Given the 

inherently low H2S expected in the fuel gas from the Merox offgas stream, FHR requested and received 

approval for an exemption from H2S monitoring of the Merox Treating Unit 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 attached to this TSD (attachment 3). 

Process Heater as Affected Facility Under Ja

Subpart Ja also regulates NOX emissions from “process heaters”, which are separate affected facilities 

from “fuel gas combustion devices” above. Emissions of NOX from this heater 31H-2 (EU055) are 
Technical 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 project. The physical changes being made to the unit will 

accommodate the Merox stream but otherwise are not designed to increase the firing rate or NOX

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 NOX provisions. The EPA is currently 

considering changes to the rule during this stay 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 NOX 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 flare 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 already has completed a number of flare connections 

that would result in a flare modification under 40 CFR Section 60.100a(c)(1), if those provisions remain 

unchanged and the stay was to be removed; therefore, these specific flare connections 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 added that will be subject to 40 CFR Section 60.590a 

(Subp. GGGa) and by reference some sections of 40 CFR Section 60.480a (Subp. VVa) to which all units in 

the refinery are currently subject. These components will be managed under existing fugitive source 

groups within the 31 and 42 process units. No additional permit conditions are required for these 

components. 

National Emission Standard for Benzene Waste 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 project will comply with subp. FF requirements. 

Although the Title V permit currently contains requirements for the Merox incinerator (34H-2/3) being 

regulated as a control device under subp. FF, no regulated 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 not 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 further 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 of 
Technical 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 controls 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 outlet 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 above caustic settler 42V-16) is considered a Group 1 

miscellaneous process vent pursuant to 40 CFR Section 63.640(a) (Subp. CC). This vent stream will be 

combusted in 31H-2 during normal operation, or alternatively vented to the flare system during times 

when 31H-2 is down (e.g. maintenance 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 device which reduces organic HAP emissions by 98 wt % 

(or to 20 ppmv, dry basis, corrected to 3% O2). 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/Malfunction 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 SO2 emissions from the 31H-2 heater will occur due to utilization of a 

higher sulfur fuel gas stream (vent gas from 42V-41). Other than routing this vent stream into a separate 

burner within the firebox of 31H-2 and adding the SO2 CEMS (MR069), no physical changes are being 

made to the heater. A new monitor (31H2 Flow Meter for Exhaust Gases, MR184) for stack vent (SV049) 

flow associated with EU055 will be added. This monitor 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 emissions of the Merox incinerator are to be applied to 

the 31H-2 in its new service as the combustion device 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 listed 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 permanently 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 the Merox offgas as the Merox incinerator; that is, 

as a combustion device to oxidize 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 design parameters (i.e., process throughput) are not 

altered. 

(iv) The Merox incinerator will be permanently disabled as an inherent element of this project to 

meet the objectives of this effort: reduce energy needs and costs, reduce emissions, mitigate 

future reliability and maintenance costs. FHR has proposed on Form CD-01 a federally 

enforceable condition to shutdown 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 actual emissions from 31H-2 firing both gases. Because 

SO2 emissions from the Merox system/incinerator have been measured by a CEMS for the last several 

years and because the Merox process is not otherwise altered except in ways that may reduce 

combustion SO2 emissions, projected actual emissions at 31H-2 can be readily estimated. The 31H-2 is a 

more energy efficient unit than the Merox incinerator. Combustion emissions from the 31H-2 other than 

SO2 will inherently not result in an increase from this project. Therefore, only SO2 emissions are 

quantified in the PSD applicability analysis. 

Other than PM10 as noted below, no changes to emission factors are expected for other pollutants, 

including PM2.5, as a result of this additional fuel gas being routed to 31H-2. Previously, FHR confirmed 

that increased SO2 generation can lead to increased PM10, however, as noted in June 29, 2007, 

correspondence to the MPCA following testing of PM10 from multiple sources of fuel gas, FHR continues 

to use the most recent AP-42 emission factor for PM10 (that includes condensable PM10) for fuel gas 

firing. In this case, FHR has some reason to believe that, as a result of increased non-H2S sulfur 

compounds in this fuel gas, PM10 emissions may be higher. For purposes of emissions inventory, FHR 

conducted performance testing of EU245 in the fall of 2010 to determine a more representative 

emission factor for PM10 pursuant to Minn. R. 7019.3100 which will be used for the Merox incinerator 

until this permit is issued and the project is implemented (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 PM10 emissions resulting from the fuel gas sulfur in 

the Merox offgas being routed to 31H-2 is the same as what formerly was routed to the Merox 

incinerator. Based on these results, FHR is not at this point proposing to perform any additional testing 

for PM10 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 conditions and the corresponding lower processing rates. 

The two-year baseline actual SO2 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 SO2. 

Projected actual annual emissions for the 31H-2 unit are 39.3 tpy for SO2, estimated as follows: 

• SO2 from refinery fuel gas burned from the mix drum is conservatively based on the current Title 

V PTE of 2.3 tpy as calculated in the May 2010 Title V reissuance application. 

• SO2 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 SO2, 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 project 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 SO2); therefore, tracking of future actual emissions is not mandated. 

FHR has proposed shutdown on the Merox incinerator 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 CFR 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 standards 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 continue to comply with these existing standards of performance using the 

same methods of demonstration as referenced 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) triggers a change to the AO. FHR submitted proposed 

alterations to the current AO and SO2 dispersion model and managed concurrently with this permit 

amendment. Consistent with past practice, the modeled SIP potential to emit rate will be higher than 

the projected actual emissions under NSR as a conservative estimate. To ensure compliance with the SIP 

modeled emission rates, FHR proposed to install an SO2 continuous emission monitor (CEM) (MR069) on 

the 31H-2 stack (SV049). 

Greenhouse Gas (GHG) Requirements
Technical 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 applicable requirements for Title V purposes, MPCA is 

noting them here for completeness. No additional Title 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 monitoring fuel gas flow that is <10% of the total fuel to 

the heater. The Merox offgas contribution (previously estimated at 1.1-2.4 MMBtu/hr) should remain 

below this threshold for 31H-2, and therefore no additional monitoring will be required. This past 

estimate included the sour water tank emissions which will not be routed to 31H-2 and also included 

naphtha as a disulfide oil diluents which is being changed to a less volatile distillate product (#1 fuel oil). 

EPA Response to FHR Letter Regarding H2S Monitoring Exemption 

FHR sent a letter to U.S. Environmental Protection Agency (EPA) October 12, 2010, requesting 

exemption from H2S monitoring of the Merox treating unit offgas stream. USEPA produced a response to 

this letter on November 15, 2010. A copy of USEPA’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 SO2 emissions at 31H-2 (EU055) will increase due to rerouting the offgas from the Merox 

incinerator, an amendment to the Minnesota State Implementation Plan (SIP) is required to continue to 

demonstrate attainment of the National Ambient Air Quality Standards (NAAQS) for SO2. In addition to 

amending the SIP, FHR submitted air dispersion modeling to assess how this project will impact ambient 

SO2 concentrations. See attachment 5 to this TSD 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 SO2 emissions from the 45 mix drum fuel gas remain based on 500 

ppm sulfur. The average annual concentration is proposed to be decreased from 500 ppm (SIP8) to 400 

ppm with this modification. SO2 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. 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 contributed 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 efficiency of the 94H-1 Thermal Oxidizer (EU282) which 

results in lower stack temperature and thus is included 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 

SO2 have been revised for EU055, EU228 and EU245 with SIP9. The new lb/hr and ton/yr limits are listed 
Technical 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 SIP9 including shutting down the Merox incinerator and 

rerouting the offgas to the more efficient 31H-2 incinerator and reducing SO2 SIP limits in the permit 

along with other changes described above make substantial progress in reducing the modeled 1-hour 

ambient SO2 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 NOX

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 NOX emissions. Although the Clean Fuels Project air permit addressed NOX

emissions from the 26H-21 standby incinerator (EU 235/SV 042), the upstream Tail Gas Treatment Unit 

(TGTU-2; EU 237/SV 042) NOX 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 through the No. 5 SRU stack SV 042. Although NOx from 

these sources was not specifically anticipated or considered 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 NOX compared to the 2.44 lb/hr SV 042 NOX BACT limit 

(due to additional emissions from the TGTU-2 not accounted for in the original BACT analysis). FHR then 

used a NOX analyzer to collect NOX measurements at various points in the No. 5 SRU process and at the 

main stack (SV 042). The measurements showed additional NOX 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 NOX 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 NOX

emissions. 

No. 5 SRU Tail Gas 

Treating TGTU-2 

Ref Fuel Gas 

Nat Gas 

S3

S1 S2

No. 5 SRU 

26H-40 26H-41 

26H-21 

Incinerator 

SV 042 

NOx 

Sample Locations 

S1 = Zero NOx 

S2 = NOx present 

S3 = NOx present 
Technical 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 NOX control technologies and 

determining BACT for SV 042. 

26H-21 Standby Incinerator (EU 235): The 26H-21 unit is an incinerator with low-NOX duct burners 

(according to the manufacturer, John Zink) and is an integral part of and 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 NOX combustion technology to further reduce 26H-21 NOX. 

TGTU-2 Incinerator (EU 237): The Tail Gas Treatment Unit (TGTU-2) consists of four sections - reaction, 

absorption, quench, and incineration (EU 237 is the incineration section). NOX 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 feasible add-on control technologies that could reduce NOX

at the TGTU-2 outlet, as well as one low NOX combustion control technology control option. Add-on 

controls would control NOX from process gas combustion as well as from refinery gas combustion in the 

26H-41 burners, whereas combustion controls such as low NOX burners would only reduce NOX from fuel 

combustion in the 26H-41 burners. 

Low temperature oxidation and SCR were identified as technically feasible post-combustion 

technologies. Low NOX staged air burners and Low NOX staged fuel burners were identified as a 

technically feasible combustion control technologies. 

FHR estimated baseline uncontrolled 26H-41 burner emissions using an emission factor of 0.20 

lb/mmBtu. This is the uncontrolled NOX 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 Petroleum Institute Publication No. 4311 “NOX Emissions from Petroleum 

Industry Operations”. 

At 0.20 lb/mmBtu, potential uncontrolled baseline NOX 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 NOX 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 NOX

20.5 $1,559,158 $1,095,108 $53,329 N N 

SCR 65% of all 

NOX

20.5 $8,643,050 $1,985,745 $96,701 Y N 

Low NOX

Staged Fuel 

Burner 

50% of 

uncontrolled 

burner NOX

15.8 $2,499,800 $364,170 $23,055 Y N 

Low NOX

Staged Air 

Burner

30% of 

uncontrolled 

burner NOX

9.5 $172,141 $32,574 $3,437 N N 

Table 7 shows that only the Low NOX Staged Air Burner option is cost effective. The staged fuel Low 

NOX burner option is considerably more costly than the staged air technology due to required fuel 

preparation systems, incinerator design, burner 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 NOX staged air burners, and therefore were BACT in 1992. FHR proposed 

a revised NOX BACT limit of 9.7 lb/hr (365-day rolling average) 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 NOX ambient air analysis for SV 042 through the use of a Screen model. Table 8 

shows the model inputs.

Table 8. SV 042 NOX 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 NOX concentration from No. 5 SRU NOX emissions is 0.509 μg/m3, which is 50.9% 

of the significant impact level (SIL) of 1 μg/m3

. This concentration was calculated from the 1 hour 

modeling concentration result of 6.357 μg/m3

 and a conversion factor of 0.08. This analysis 

demonstrates that the revised SV 042 NOX emission limit does not exceed the SIL threshold and 
Technical 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 NOX

BACT limit. 

3.1.3 Major Amendment To Incorporate Outstanding Requirements From the December 10, 2007 

H2S Schedule Of Compliance, Subsequent May 2008 Proposed Schedule (DQ# 2499), and 

November 11, 2010 Schedule Extension Request

This action incorporates into the operating permit the commitments made by FHR pursuant to the 

December 2007 Asphalt Emissions Schedule of Compliance (SOC) and the November 2010 SOC extension 

approved by MPCA staff. 

In 2006 FHR began to realize that asphalt tank and load out H2S 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 established 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 H2S source not previously known or evaluated. FHR subsequently requested an 

extension to the SOC to allow FHR to evaluate and, if necessary, reduce the coker-related H2S emissions 

in order to demonstrate compliance with the Minnesota ambient air quality standard for H2S. 

FHR has completed a capital project to significantly reduce H2S emissions from asphalt tanks as identified 

in the original effort in 2007. This project has resulted 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 facility continue to show actual emissions are in full 

compliance with the standards. 

As originally proposed, the SOC addressed both VOC and H2S emissions, establishing interim limits until 

final corrective actions could be implemented. For VOC emissions, FHR will continue to adhere to the 

existing limits established in the previously issued #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 requirements, 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 H2S by April 30, 2008. 

12/2007 SOC 

Part 7.a 

Completed 
Technical 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 H2S 

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 H2S. 

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 H2S MAAQS. 

12/2007 SOC 

Part 7.d.ii 

Completed; note 

SOC extension 

includes 

requirement for 

total facility H2S 

modeling 

including decoking 

NA By September 1, 2008, the permittee shall complete an 

engineering study and dispersion modeling for hydrogen 

sulfide (H2S) 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 (H2S) 

associated with asphalt barge loading operations 

12/2007 SOC 

Part 7.b & 

05/2008 

proposed 

schedule 

Completed 
Technical 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 (H2S). 

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 (H2S). 

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 (H2S). 

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 (H2S). 

12/2007 SOC 

Part 7.b & 

05/2008 

proposed 

schedule 

Completed; 

Model shows 

compliance for 

previously 

identified H2S 

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 H2S 

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 H2S 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 

permit 
Technical 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 H2S 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 replacement, 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 the calculated emissions increases were determined 

to be insignificant utilization increases (less than 1 tpy) 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 was 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 received on December 22, 2010 for operation of two 

temporary portable coke crushers that were projected to be on site for approximately six (6) months 

after January 1, 2011. 

The two coke crushers in the permit application were 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/hr 
Technical Support Document, Permit Action Number: 03700011-008 

Page 21 of 27 

Date: 8/15/2011

• PM10 1.50 lb/hr 

• PM2.5 1.50 lb/hr 

The increases in emissions from the temporary portable coke crushers did not increase emissions 

beyond SERs under PSD rules as defined in 40 CFR Section 52.21(b)(2); therefore, the project was not 

considered a major modification and was not subject to PSD review. 

Also, the addition of the portable coke crushers were above insignificant modification PM10 thresholds 

per Minn. R. 7007.1250, subp. 1, but below moderate amendment PM10 thresholds per Minn. R. 

7007.1450, subp. 2; therefore, requiring a minor permit amendment. 

The combustion emissions were not subject to permitting 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 directly 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 standards promulgated under section 111 (Standards of 

Performance for New Stationary Sources) or section 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 this definition, a nonroad engine is any internal 

combustion engine: 

(i) In or on a piece of equipment that is self-propelled 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 intended 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 New 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 source 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 location 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 approximately 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 considered portable equipment, and the equipment will not remain at a 

location for more than 12 consecutive months or through an entire season of operation. Therefore, the 

portable coke crushers’ engines were not regulated 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 - Pine 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 O2% 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 added to the facility description as 71B9. SV data 

included with the SO2 modeling parameters that was not previously contained in the facility description 

was added for SV131, 164, 165, 166 and 173. 

3.2 Emissions Calculations

This amendment will account for additional NOX emissions (31.8 tpy) due to the No. 5 Sulfur Recovery 

Unit SV 042 NOX BACT revision. This amendment will also use projected actual emissions to estimate a 

5.8 tpy SO2 increase with the Merox project. (See Table 3 and discussion above. (DQ# 3153)) 

EU055 PTE for SO2

All PTE values for EU055 (in the Facility Description) were taken from the May 2010 Title V permit 

reissuance application, except for SO2 which are changed due to the addition of the Merox offgas 

stream. The hourly and annual SO2 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 SO2 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. 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 SO2 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 responsibility 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 requirement 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) 

NOX CEMS NOX is monitored on the SRU #5 stack with 

a CEMS. This includes NOX 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 

SO2 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 SO2 NAAQS standards. 

Scenarios: 

1. EU032 only; 

2. EU033 only; 

3. EU037 and EU038. 

EU055 SO2: < 66.4 lb/hr using 

3-hr rolling average 

Title I Condition: SIP for 

SO2 NAAQS, 40 CFR pt. 

50; MN State 

Implementation Plan 

(SIP) 

SO2 CEMS (MR069) to 

show compliance with 

SIP requirements 

Recordkeeping: keep 

records of SO2

emissions of hourly 

averages of total SO2

emissions in lb/hr. 

This value is subject to change pending 

the SIP Administrative Order action. 

EU055 SO2: < 290.8 tpy using 

365-day rolling average 

Title I Condition: SIP for 

SO2 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 

SO2 NAAQS, 40 CFR pt. 

50; MN State 

Implementation Plan 

(SIP) 

Recordkeeping: keep 

records of SO2

emissions of total SO2

in tons per year. 

EU055 SO2: < 20 ppmv (dry 

basis, corrected to 0% 

excess air, determined 

hourly) on a 3-hr rolling 

average 

and 

SO2: < 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 SO2

emission limit of 40 CFR Section 

60.102a(g)(1)(i) or the H2S fuel gas 

concentration limit of 40 CFR Section 

60.102a(g)(1)(ii). 

EU055 H2S: < 162 ppmv hourly 

on a 3-hr rolling 

average 

and 

H2S: < 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 SO2

emission limit of 40 CFR Section 

60.102a(g)(1)(i) or the H2S fuel gas 

concentration limit of 40 CFR Section 

60.102a(g)(1)(ii). 

EU055 H2S: ≤ 230 mg 

H2S/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 SO2: < 182.6 lb/hr using 

1- and 3-hr rolling 

Monitoring: use SO2

CEMS to measure SO2

emissions from SV019 

Revised SO2 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 

SO2 NAAQS, 40 CFR pt. 

50; MN State 

Implementation Plan 

(SIP); and SO2 MAAQS, 

Minn. R. 7009.0080 

and SV021 

EU228 SO2: < 800 tpy using 12-

month rolling average 

Title I Condition: SIP for 

SO2 NAAQS, 40 CFR pt. 

50; MN State 

Implementation Plan 

(SIP) 

Monitoring: use SO2

CEMS to measure SO2

emissions from SV019 

and SV021 

Revised SO2 limit for FCCU based on 

updated Amendment 9 to the SIP. 

EU245 SO2: < 65.4 lb/hr using 

3-hr rolling average 

Title I Condition: SIP for 

SO2 NAAQS, 40 CFR pt. 

50; MN State 

Implementation Plan 

(SIP) 

Monitoring: use SO2

CEMS to measure SO2

emissions from SV042 

Revised SO2 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 SO2: < 286.4 tpy using 

12-month rolling 

average 

Title I Condition: SIP for 

SO2 NAAQS, 40 CFR pt. 

50; MN State 

Implementation Plan 

(SIP) 

Monitoring: use SO2

CEMS to measure SO2

emissions from SV042 

Revised SO2 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 insignificant activities. These are listed in Appendix A 

to the permit. There are no insignificant activities 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.), should be in Table A or B. The main reason is that the 

appendices are word processing sections and are not part of the tracking system. Violation of the 

appendices can be enforced, but the computer system 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 assessment 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.; minor, 4 pts.; administrative, 1 pt.). Additional points 

fees include: modeling review (15 pts.) for SO2 regarding the SIP, NSPS review (10 pts.) of subpart Ja, and 

a BACT review (15 pts.) for SV042 NOX. 

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 contribute 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 (SO2 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 H2S 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 MPCA 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 Tcchnology (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).

Asummary 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 ~ccommodatelhe 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. ASIP 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, 5S1-757-2404 - 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

Acopy 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 CFR pt. 51, Appendix V, Part 2.1) 

The EPA’s Criteria for Determining the Completeness 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 Hedman. 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 any and all requirements of such federal law or 

such rules and regulations promulgated thereunder 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 ‘document’) 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 authority under State law to adopt and implement the 

plan.” 

This SIP revision request is an update to MPCA’s Pine Bend SO2 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 for 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 proposed 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 government 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 accordance with the information provided in the public 

notice and the State’s laws and constitution, if applicable.” 

The public notice states: “A public information meeting 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 selected meeting date. The public information meeting will 

provide information, receive public input, and answer questions about both the proposed permit and 

SIP revision.” 

No public meeting was requested. 

7) Public Comments and State Response: 

“Compilation of the public comments 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 SO2. 

 
2) Source Identification 

Identification of the locations of affected sources 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 Bend portion of the AQCR131/Twin Cities SO2 maintenance area is 

Flint Hills Resources. Further information on the facility 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 SO2 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, prevention of significant deterioration increments, 

reasonable further progress demonstration, and visibility, as applicable, are protected if the plan is 

approved and implemented.” 

Modeling of the proposed changes at the facility show that the 3-hour, 24-hour and annual SO2 NAAQS 

will be maintained, and that the facility’s impact on the one-hour standard will be decreased.