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Technical Support Document, Permit Action Number: 14700077‐001 of 12

TECHNICAL SUPPORT DOCUMENT

For

DRAFT/PROPOSED AIR EMISSION PERMIT NO. 14700077‐001

This technical support document (TSD) is intended for all parties interested in the draft/proposed 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 preliminary

determination to issue the draft/proposed permit.

1. General Information

1.1 Applicant and Stationary Source Location

Table 1. Applicant and Source Address

Applicant/Address Stationary Source/Address

(SIC Code: 4911)

Southern Minnesota Municipal Power Agency500 First Ave SW Rochester, Minnesota 55902‐3303

Owatonna Energy StationBridge Street (Address TBD: between CR 75 & 25) Owatonna, Steele County, Minnesota 55060

Contact: Peter J. Reinarts Phone: 507‐292‐6452

1.2 Facility Description

Southern Minnesota Municipal Power Agency (SMMPA) proposes to construct a new electricity

generating station in Owatonna, MN, near County Roads 75 and 25. Natural gas will fuel four

combustion engines to produce 40 megawatts (MW) of electricity. SMMPA will operate the proposed

station and will manage its hours of operation.

One 1200 brake‐horsepower (bhp) diesel emergency generator will also be installed to provide black‐

start capabilities to the facility’s four main engines. Seven different on‐site storage tanks will hold diesel

fuel, engine coolant (ethylene glycol), and lubricating oil.

The four engines will primarily emit nitrogen oxides (NOX), carbon monoxide (CO), and certain hazardous

air pollutants (HAP). Catalytic oxidizers will reduce CO and HAP emissions from the engines. An annual

fuel limit will restrict NOX emissions and other emissions to below New Source Review (NSR) major

source thresholds. The facility will operate under an individual Part 70 permit, and will be a major source

under the National Emission Standards for Hazardous Air Pollutants (NESHAP).

1.3 Description of the Activities Allowed by this Permit Action

This permit action is a first time issuance of a Part 70 total facility air emissions permit.

The MPCA has a combined operating and construction permitting program under Minnesota Rules

Chapter 7007, and under Minn. R. 7007.0800. Under that authority, this permit action authorizes

construction and operation of the facility.


1.4 Facility Emissions

Table 2. Total Facility Potential to Emit Summary

PM tpy

PM10 tpy

PM2.5 tpy

SO2 tpy

NOx tpy

CO tpy

CO2e tpy

VOC tpy

SingleHAP tpy

AllHAPs tpy

Total Facility Limited Potential Emissions

20.06 11.03 11.03 0.39 237.50 28.52 98,072 93.02 24.43 33.40

Projected Total Facility Actual Emissions*

5.56 3.06 3.06 0.11 66.32 7.93 21,495 25.79 6.77 9.26

*No emissions inventory data is available so actual emissions are based off of predicted facility use (average of

43,265 MW‐hr of electrical production for first 10 years).

Table 3. Facility Classification

Classification Major Synthetic Minor/Area Minor/Area

PSD X

Part 70 Permit Program X

Part 63 NESHAP X

2. Regulatory and/or Statutory Basis

New Source Review

The facility is a new non‐major source under NSR regulations due to a fuel limit, operational limits, and

pollution control limits. No actions subject to NSR are authorized by this permit.

Part 70 Permit Program

The facility is major source under the Part 70 permit program.

New Source Performance Standards (NSPS)

GP 001 engines (EUs 001 – 004) are subject to 40 CFR pt. 60, subp. JJJJ, NSPS for Stationary Spark

Ignition Internal Combustion Engines.

The new black start emergency generator (EU 005) is subject to 40 CFR pt. 60, subp. IIII, NSPS for

Stationary Compression Ignition Internal Combustion Engines.

National Emission Standards for Hazardous Air Pollutants (NESHAP)

The facility is a major source of HAPs. GP 001 engines are subject to 40 CFR pt. 63, subp. ZZZZ, NESHAP

for Stationary Reciprocating Internal Combustion Engines (RICE).

Because EU 005 is an emergency generator located at a major source of HAPs and is larger than 500

brake horsepower (bhp) emission and operating limitations in 40 CFR pt. 63, subp. ZZZZ do not apply (40

CFR § 63.6600(c)).


Compliance Assurance Monitoring (CAM)

GP 001 engines are exempt from CAM at this time as they are subject to a NSPS proposed after

11/15/1990 (NSPS subp. JJJJ) and meet the applicable emission standards without an add‐on control

device.

EU 005 is also exempt as it is subject to NSPS subp. IIII and meets the emission standards without an

add‐on control device.

Minnesota State Rules

Portions of the facility are subject to Minn. R. 7011.2300, Standards of Performance for Stationary

Internal Combustion Engines.

Environmental Review

Because the total increase in electrical generation exceeds 25 MW, the project triggers a mandatory

Environmental Assessment Worksheet (EAW) under Minn. R. 4410.4300, subp. 3. Although the

Environmental Quality Board (EQB) is designated by rule as the responsible governmental unit (RGU),

the EQB requested that the MPCA accept that role; the MPCA agreed to do so.

The public comment periods for the EAW and this permit overlap. To date, the MPCA has made no

recommendation on the need for an Environmental Impact Statement for this project.

Air Emissions Risk Analysis (AERA)

An AERA was written before the Supreme Court’s Decision in Utility Air Regulatory Group v. EPA, which

ruled that a source cannot be major for PSD based on GHG emissions alone. While A PSD project would

normally trigger an AERA, the Owatonna Energy Station will no longer be a PSD major source due to the

ruling. However, an AERA was required according to MPCA guidance and forms (CK‐01) because the

project is an electric production facility greater than or equal to 25 MW.

The air toxics screen showed that all risks were below the screening value besides the acute inhalation

risk, which had a hazard quotient of 1.2 compared to a screening value of 1.0. However, it was shown

that using more refined models resulted in an acute inhalation risk less than 1.0. The AERA submittal

was reviewed and accepted by MPCA staff and the final report is attached to this TSD as Attachment 8,

AERA Report.

Source Determination

Owatonna Public Utilities (OPU), a member of SMMPA, currently operates an electrical generating

turbine adjacent to SMMPA’s proposed Owatonna Energy Station. While the two emission sources have

the same industrial classification and will be adjacent, the sources will be permitted independently

because the facilities will not be under common control. Ultimately, commercial dispatch decisions are

not made by either party, each is independently responsible for its own pollution control and

compliance activities, with no shared workforces or functions, and the facilities are not functionally

dependent on each other. OPU’s membership in SMMPA does not give them significant control of

decisions made by SMMPA, and a power purchase agreement between OPU and SMMPA commits OPU


to the control and operation of its turbine, including full compliance with any air permit issued to the

turbine.

Consistent with this decision, the sources will be permitted separately. The turbine at SMMPA will

continue to operate under its registration permit and the new Owatonna Energy Station will be issued a

Part 70 permit with enforceable conditions to keep it a minor stationary source under the Prevention of

Significant Deterioration (PSD) regulation. See Attachment 6 to this TSD, MPCA Source Determination,

for further discussion on this decision.

Table 4. Regulatory Overview of Facility

Subject Item* Applicable Regulations Rationale

Total Facility

Minn. Stat. Section 116.07, subds. 4a & 9; Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M) (Modeling Requirements)

Tier 2 NOX modeling language was recommended for the permit as a result of the refined modeling performed by the facility. Tier 1 modeling language was recommended for PM10 and Tier IV was recommended for PM2.5 due to EAW concerns.

GP 001 (Natural Gas Engines)

Title I condition – to avoid classification as a major stationary source under 40 CFR §52.21 and Minn. R. 7007.3000

A fuel consumption limit restricts annual emissions of NOX, CO, and all other pollutants to below the NSR major source thresholds.

Minn. R. 7009.0010‐7009.0080

Minimum stack heights and limiting simultaneous engine operation to two or less during the shakedown period ensures that uncontrolled emissions will not violate the NAAQS/MAAQS.

Minn. R. 7011.2300 The units are stationary internal combustion engines; therefore, Standards of Performance for Stationary Internal Combustion Engines apply.

40 CFR §72.7

Acid Rain – New Unit Exemption. The new units are exempt from the Acid Rain provisions as long as they use only gaseous fuel with an average sulfur content of 0.050 percent or less by weight. Using pipeline natural gas meets this requirement.

GP 002 (Oxidation Catalysts); CEs

001 ‐ 004

40 CFR pt. 63, subp. ZZZZ

Oxidation catalysts are used to comply with the NESHAP subp. ZZZZ.

Title I condition – to avoid classification as a major stationary source under 40 CFR §52.21 and Minn. R. 7007.3000

The minimum CO control efficiency of 93% ensures that CO emissions remain below the NSR major source threshold.

*Location of the requirement in the permit (e.g., EU, SV, GP, etc.).


Table 4. Regulatory Overview of Facility (cont.)

Subject Item* Applicable Regulations Rationale

EUs 001 ‐ 004 (Engines)

40 CFR pt. 60, subp. JJJJ

Standards of Performance for Stationary Spark Ignition Internal Combustion Engines. The following provides the basis of the applicability determination: • Units are 4 stroke lean burn spark ignition internal combustion engines • Natural gas is the only allowable fuel • Used for non‐emergency purposes • Units will be manufactured after 2010 • Each unit is rated at 13102 bhp (9770 kW)


NESHAP for Stationary Reciprocating Internal Combustion Engines. The following provides the basis of the applicability determination: • Units will be new 4 stroke lean burn stationary RICE • The facility is a major source of HAPs • Each unit is rated at 13102 bhp (9770 kW) • Units will be installed after 2014 • Used for non‐emergency, non‐black start purposes

EU 005 (Emergency Engine)

40 CFR pt. 60, subp. IIII

Standards of Performance for Stationary Compression Ignition Internal Combustion Engines. The following provides the basis of the applicability determination: • Unit is compression ignition internal combustion engine • Used for emergency purposes only • Unit will be manufactured after 2011 • Unit is rated at 1214 bhp (900 kW)


NESHAP for Stationary Reciprocating Internal Combustion Engines. The following information provides the basis of the applicability determination: • Unit will be a new, compression ignition stationary RICE • The facility is a major source of HAPs • Unit is rated at 1214 bhp (900 kW)

*Location of the requirement in the permit (e.g., EU, SV, GP, etc.).

3. Technical Information

i. Engine Shakedown Period

Each GP 001 engine will require extensive testing by the engine vendor and SMMPA before commercial

electricity dispatch. To allow the engines and control equipment to be fully tested and commissioned,

operation of control equipment will not be required during the shakedown period. According to 40 CFR

§60.8(a) and §63.7(a)(2), the Permittee will be required to demonstrate compliance when the engines

complete initial performance testing. Testing is required within 180 days of initial startup. A GP 001

permit condition further defines the shakedown period as commencing on the day each engine (EUs 001

‐ 004) goes through initial startup and terminating on the date when the engine is available for

commercial dispatch, or 180 days after the date of initial startup, whichever is earlier.


While operating control equipment will not be required during this time, the Permittee must always

remain below NSR thresholds and comply with the National/Minnesota Ambient Air Quality Standards

(NAAQS/MAAQS). The heat input limit to avoid NSR will be applicable for the engines during the

shakedown period.

ii. GP 001 (EUs 001 – 004) Requirements

GP 001 contains the requirements which apply to the group of four identical engines, including the

unique engine shakedown period requirements, annual heat input limit, acid rain exemption, minimum

stack heights, allowable fuels, and recordkeeping requirements. Because each engine requires individual

notifications, emission limits, and performance testing, most NESHAP and NSPS requirements were

placed at the individual EU level and not within GP 001.

The heat input limit to restrict the facility’s emissions to less than NSR major source thresholds is within

GP 001. This limit was applied to the group of engines and not individual engines because a group limit

could possibly motivate less startups, which cause worse emission rates. Individual engine limits could

possibly cause situations where engines were stopped and started only to maintain an engine’s limit.

GP 001 also contains a performance testing requirement to verify the NOX emission factor of 29.64 lb/hr

which was used to calculate the heat input limit. While the manufacturer guaranteed a NOX emission

rate of 26.68 lb/hr, the Permittee requested a 10% buffer to performance test against. Thus, all

calculations and permit requirements use an emission rate of 29.64 lb/hr. A one‐time test is only

required for one engine since all engines are identical, and NOX concentration testing is required for

each engine on an annual basis (see below: NESHAP subp. JJJJ Requirements).

iii. NESHAP subp. JJJJ Requirements

Initial performance tests will be required to demonstrate compliance with the NOX and VOC standards in

Table 1 of 40 CFR pt. 60, subp. JJJJ. Subsequent performance tests will then be conducted on each

engine every 8760 hours of engine operation or three years, whichever comes first. New non‐emergency

lean burn spark ignited stationary engines with a site rating of greater than 250 bhp located at a major

source of HAPs that are meeting the requirements of 40 CFR pt. 63, subp. ZZZZ, Table 2a do not have to

comply with the CO emission standards of Table 1 of 40 CFR pt. 60, subp. JJJJ.

iv. GP 002 (CEs 001 – 004): Catalytic Oxidizers Requirements

GP 002 contains the NESHAP subp. ZZZZ requirements that apply directly to the oxidation catalysts. Each

requirement applies individually to each oxidation catalyst. Extensive operating, testing, monitoring, and

recordkeeping requirements are required for GP 002 units in order to meet the NESHAP subp. ZZZZ

requirements. Because the initial startup, performance testing, and operation hours may differ for each

catalyst, the individual notifications and performance testing requirements are included at the CE level

(CEs 001 ‐ 004).


v. EU 005: Emergency Engine Requirements

There is no limit to the use of an emergency engine in emergency situations under the NESHAP subp.

ZZZZ or NSPS subp. IIII. However, the Permittee proposed an operational limit of 100 hours/year for EU

005 in order to increase the operational hours of GP 001 engines while remaining a synthetic minor

source under NSR.

Initial performance testing is not required to show compliance with the NSPS subp. IIII because EU 005 is

an emergency generator with a displacement of less than 30 liters per cylinder. The Permittee will be

required to purchase an engine certified to the standards in 40 CFR §60.4205. Emergency generators are

also not required to comply with the emission limitations of the NESHAP subp. ZZZZ (40 CFR

§63.6600(c)).

3.1 Calculations of Potential to Emit

Attachment 1 to this TSD contains a summary of the proposed PTE of the facility, calculation

spreadsheets and supporting information prepared by the MPCA and the Permittee. Based on the

calculations, the project is not subject to NSR under 40 CFR §52.21.

PTE calculations used the manufacturer guaranteed emission rates at worse‐case conditions.

Caterpillar’s Plant Performance data is contained in Attachment 4 to this TSD. SO2 emission rates were

taken from AP‐42 Table 3.2‐2. After examining the maximum controlled PTE at 8760 hours/year, NOX

emissions proved to have the highest emissions of all pollutants. Therefore, NOX emissions for the total

facility were set at 237.5 tons/year, EU 005 NOX emissions were subtracted from the total, and a GP 001

fuel limit was determined from this value (tpy):

001 237.5 0.687 2000

29.64 82.74

1322126

Where: 0.687 : Limited NOX PTE of EU 005

29.64

: Maximum emission rate of GP 001 engines

82.74 : Maximum heat input of GP 001 engines

The facility NOX limit of 237.5 tpy is consistent with the EPA’s recommended difference of 5‐10%

between a permit limit and a federal threshold, according to the March 2011 EPA Lockwood Landfill

Memorandum, which is attached to this TSD as Attachment 5. This limit corresponds to the NSR major

source threshold of 250 tpy for NOX.

3.2 Dispersion Modeling

Air dispersion modeling was required as part of Environmental Review for the project and to

demonstrate compliance with the NAAQS/MAAQS. The modeling protocol and final report were

approved by MPCA staff, and the modeling report is attached to this TSD as Attachment 7. The


dispersion models predicted that the modeled ground level concentration form the proposed facility will

be less than the Significant Impact Level (SIL) for the following pollutants and averaging periods:

CO, 1‐hr and 8‐hr averaging periods

SO2, 1‐hr, 3‐hr, 24‐hr, and annual averaging periods

PM10, annual averaging period

PM2.5, annual averaging period

The dispersion model predicted that the modeled ground level concentration from the facility will be

greater than the SIL for the following pollutants and averaging periods:

NO2, 1‐hr and annual averaging periods

PM10, 24‐hr averaging period

PM2.5, 24‐hr averaging period

The refined NO2 1‐hr and annual models and the PM10 24‐hr and annual models showed compliance with the respective NAAQS/MAAQS at the modeled parameters.

The PM2.5 24‐hr and annual models showed a concentration higher than the respective NAAQS. The

most significant contribution to this modeled concentration was from a modeled background source.

The Owatonna Energy Station does not cause a significant impact at any of the receptors showing a 24‐

hr or annual PM2.5 NAAQS violation as the contribution at the modeled violations is less than 24‐hr PM2.5

SIL of 1.2 μg/ m³. For the annual PM2.5 model, the maximum modeled contribution from the Owatonna

Energy sources is 0.080 μg/m³, compared to the annual PM2.5 Significant Impact Level of 0.30 μg/ m³.

The MPCA will further investigate the neighboring source causing an issue with the PM2.5 NAAQS

standards.

Tier 2 modeling language was recommended for the permit for NO2, while Tier 1 language was

recommended for PM10 and PM2.5. An hours of operation restriction was assumed when the modeling

was conducted and has been incorporated through permit limits in the draft/proposed Part 70 permit.

In addition, per MPCA practice, a table of the modeled parameters has been added to the permit as an

appendix. The parameters listed in Appendix A of the permit describe the operation of the facility at

maximum capacity. In other words, the flow rates and temperatures listed in Appendix II represent the

minimum parameters at the maximum emission rates. The MPCA does not require any specific

compliance demonstration with these parameters because they are worse‐case conditions. The purpose

of listing the parameters in the permit appendix is to provide a benchmark for determining if and when

additional modeling is required.

3.3 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 considered the following:

the likelihood of the facility 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.

Table 5 below summarizes the monitoring requirements.

Table 5. Monitoring

Subject Item*

Requirement (basis) Monitoring Discussion

GP 001 (Natural Gas Engines)

Heat Input: ≤ 1322126 MMBtu/yr, on a 12‐month rolling sum basis (Limit to avoid NSR)

Recordkeeping: Monthly calculations of total heat input

Calculation procedures are defined in the permit and the

permit must evaluate the NOX emission factor. The engines are not expected to be run on a daily basis, so daily recordkeeping is not appropriate.

EUs 001 ‐ 004

Opacity: ≤ 20% once operating temperatures have been attained (Minn. R. 7011.2300, subp. 1)

None Minimal opacity is expected as the engines only use pipeline natural gas by design.

SO2: ≤ 0.5 lbs/MMBtu (Minn. R. 7011.2300, subp. 2)

None The total SO2 emission rate from this unit is 0.000588 lbs/MMBtu. Non‐compliance is unlikely considering the allowable fuel.

NOX: ≤ 1.0 g/hp‐hr or 82 ppmvd (40 CFR pt. 60, subp. JJJJ)

Performance Testing

The manufacturer's guaranteed NOX emission rate from these units is 0.90 g/hp‐hr. Compliance is expected if the engines are properly maintained and operated. Performance tests are required every 3 years or 8760 hours of operation, whichever comes first, following the initial test.

VOCs: ≤ 0.70 g/hp‐hr or 82 ppmvd (40 CFR pt. 60, subp. JJJJ)

Performance Testing

The manufacturer's VOC emission rate from these units is 0.33 g/hp‐hr. Compliance is expected if the engines are properly maintained and operated. Performance tests are required every 3 years or 8760 hours of operation, whichever comes first, following the initial test.

EU 005

Operating Hours: ≤ 100 hr/yr (Limit to avoid NSR)

Hour meter on engine, recordkeeping

The Permittee shall install the hour meter prior to start up, and shall record and maintain the total hours of operation for EU 005 on each operating day, and sum the total monthly. The engine may only be operated for emergency and testing purposes only.

Sulfur Content of Fuel: ≤ 15 ppmw (40 CFR Section 60.4207(c))

Fuel supplier certification of sulfur content, recordkeeping

*Location of the requirement in the permit (e.g., EU, SV, GP, etc.)


Table 5. Monitoring (cont.)

Subject Item*

Requirement (basis) Monitoring Discussion

EU 005

SO2: ≤ 0.50 lbs/MMBtu (Minn. R. 7011.2300)

None The total SO2 emission rate from this unit is 0.00152 lbs/MMBtu. Non‐compliance is unlikely considering the diesel sulfur limit.

Opacity: variable with engine load (40 CFR pt. 60, subp. IIII, meets requirements of Minn. R. 7011.2300, subp. 1)

None Opacity limits are for the lugging mode, acceleration mode, and the peaks of either, respectively. Minimal opacity is expected considering allowable fuels.

CO: ≤ 3.5 g/kilowatt‐hr (40 CFR pt. 60, subp. IIII)

None

40 CFR §60.4202 requires stationary CI internal combustion engine manufacturers to meet the limits of 40 CFR §89.112. While a CO emission rate of 0.430 g/kw‐hr is used in PTE calculations, a weighted mass emission rate may be used to demonstrate compliance with the standard (see Appendix D of permit).

NMHC+NOX: ≤ 6.4 g/kilowatt‐hr (40 CFR pt. 60, subp. IIII)

None

40 CFR §60.4202 requires stationary CI internal combustion engine manufacturers to meet the limits of 40 CFR §89.112. While the manufacturer's worst case emission rate of 6.99 g NMHC+ NOX/kw‐hr is used in PTE calculations, a weighted mass emission rate may be used to demonstrate compliance with the standard (see Appendix D of permit).

Total PM: ≤ 0.20 g/kilowatt‐hr (40 CFR pt. 60, subp. IIII)

None

40 CFR §60.4202 requires stationary CI internal combustion engine manufacturers to meet the limits of 40 CFR §89.112. The total PM emission rate from this unit is 0.032 g/kw‐hr. Non‐compliance is unlikely considering the allowable fuels.

CEs 001 ‐ 004

(Oxidation Catalysts)

CO control efficiency: ≥ 93.0% (Limit to avoid NSR; 40 CFR pt. 63, subp. ZZZZ)

Performance testing, temperature and pressure drop monitoring

Performance tests are required semi‐annually on each unit following the initial tests. Tests may be annually if compliance is demonstrated in two consecutive tests.

Pressure Drop: ≤ 2.0 in. of water column from the pressure drop measured during the initial performance test (40 CFR pt. 63, subp. ZZZZ)

Performance testing

The pressure drop shall be recorded during the initial performance test which demonstrates compliance with the 93.0% CO control efficiency requirement. The test shall be conducted within 10% of the maximum engine load.

450°F ≤ Temperature ≤ 1350°F (40 CFR pt. 63, subp. ZZZZ)

Performance testing, temperature monitoring, daily checks, annual calibration

The temperature shall be recorded during the initial performance test which demonstrates compliance with the 93.0% CO control efficiency requirement. CPMS shall collect data at least once every 15 minutes, and the temperature sensors shall have a minimum tolerance of 5°F or 1% of the measurement range, whichever is larger.

VOC control efficiency: ≥ 4.0% (Minn. R. 7007.0800, subps. 2 and 14)

None

Exhaust VOC concentration is limited by the requirements of 40 CFR pt. 60, subp. JJJJ, for which performance testing is required. 4% was given as the minimum efficiency by the manufacturer considering the lowest operable temperature. Actual efficiencies are expected to be ~50%. This control efficiency is not needed to remain an NSR minor source.


3.4 Insignificant Activities

The storage tanks at the facility qualify as insignificant activities, although no limits or work practices are

applicable. The following table discusses the applicability of Minnesota rules to these units. The

Permittee has stated that there are no other operations which are classified as insignificant activities

under the MPCA’s permitting rules.

Table 6. Insignificant Activities

Insignificant Activity

General Applicable Emission Limit

Discussion

TK 001: Urea Storage

PM ≤ 0.30 gr/dscf Opacity ≤ 20% Minn. R. 7011.0715

TK 001 will contain 10,000 gallons of an aqueous urea solution. Because Urea is not a VOC or petroleum liquid and has a negligible vapor pressure; the tank will not be subject to the Standards of Performance for Storage Vessels, Minn. R. 7011.1505, subp. 3.A. No other state Standard of Performance applies. Therefore, the Industrial Process Equipment Rule applies. Any particulate emissions would be unlikely and negligible due to the low vapor pressure.

TKs 002 ‐ 003: Ethylene Glycol Storage

None Minn. R. 7011.1505, subp. 3

TK 002 and 003 will each contain up to 4,000 gallons of ethylene glycol each, an engine coolant with a vapor pressure of 0.06 mm Hg. The tanks have no requirements under Minn. R. 7011.1505, subps. 3.B and C due to the negligible vapor pressure.

TKs 004 ‐ 006: Lubricating Oil Storage


TK 004 will have a capacity of 3,000 gallons while TK 005 and TK 006 will contain up to 2,000 gallons each. No requirements apply under Minn. R. 7011.1505, subp B, as the tanks will contain lubricating oils with a very low vapor pressure and volatility.

TK 007: Diesel Fuel Storage


TK 007 will contain diesel fuel and has a capacity of 36,000 gallons. Because diesel fuel has a vapor pressure of 0.40 mm Hg, there are no requirements according to Minn. R. 7011.1505, subps. 3.B and C.

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 electronically tracked (e.g., limits, submittals, etc.), should be in Table A or B of the permit.

The main reason is that the appendices are word processing sections and are not part of the electronic

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.

This permit uses an appendix for specific calculation procedures from 40 CFR pt. 63, subps. IIII and ZZZZ,

as well as documenting the parameters used in modeling. These procedures are too complex to enter

into Delta and must go in an appendix.


3.6 Comments Received

Public Notice Period: <start date> ‐ <end date>

EPA 45‐day Review Period: <start date> ‐ <end date>

Comments were <not> received from the public during the public notice period. <The comments

received did <not> include adverse comments on any applicable requirements of the permit. Changes to

the permit were <not> made as a result of the comments. Provide summary of changes. >

4. Permit Fee Assessment

Attachment 3 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

action includes the incorporation of one NESHAP subp. ZZZZ (10 pts.), two NSPS subp. JJJJ and IIII (20

pts.), a modeling review (15 pts.), limits to remain below the NSR major source threshold (10 pts.), and

an AERA review (15 pts.). No other additional points apply to this permit action.

5. Conclusion

Based on the information provided by the Permittee, the MPCA has reasonable assurance that the

proposed operation of the emission facility, as described in the Air Emission Permit No. 14700077‐001

and this TSD, will not cause or contribute to a violation of applicable federal regulations and Minnesota

Rules.

Staff Members on Permit Team: Eric Sulita (permit engineer)

Devin Culhane (enforcement)

Ladislaus Strzok (compliance)

Amrill Okonkwo (peer reviewer)

Beckie Olson (permit writing assistant)

Laurie O’Brien (administrative support)

Kim Grosenheider/Chuck Peterson (environmental review)

Daniel Dix (modeling review)

Dorian Kvale (AERA review)

AQ File No. 4598; DQ 4934

Attachments: 1. PTE Summary and Calculation Spreadsheets 2. Facility Description and CD‐01 Forms

3. Points Calculator 4. Engine Emissions Data 5. EPA Lockwood Memo

6. MPCA Source Determination 7. Modeling Report 8. AERA Report

Attachment 1 – PTE Summary and Calculation Spreadsheets

Attachment 2 – Facility Description and CD‐01 Forms

Attachment 3 – Points Calculator

Attachment 4 – Engine Emissions Data

Attachment 5 – EPA Lockwood Memo

Attachment 6 – MPCA Source Determination

Attachment 7 – Modeling Report

Attachment 8 – AERA Report

Attachment 1 – PTE Summary and Calculation Spreadsheets

UnitekW

RatingbkW

Ratingbhp

Rating

GuaranteedHeat Rate

(BTU/kWh)

MaximumHourly Design

Rate(MMBTU/hr) Pollutant

EmissionFactor

EmissionFactor"Unit"

[Uncontrolled]Emission Rate

(lb/hr)

[Uncontrolled]EmissionRate at

8760 hrs/yr(ton/yr)

Factor Source(AP-42, ST, Other)

ControlEfficiency

(%)

[Controlled]Emission Rate

(lb/hr)

[Controlled]EmissionRate at

8760 hrs/yr(ton/yr)

[Limited]Energy Input -

Proposed(MMBTU/yr)

[Limited]Controlled

Emissions (*)(ton/yr)

EU-001 9,770 10,000 13,410 --- 82.74 PM 0.085 g/bhp-hr 2.51 10.99 Manufacturer 0.0 2.51 10.99 330,463.6 5.01(Natural Gas) PM10 0.047 g/bhp-hr 1.38 6.04 Manufacturer 0.0 1.38 6.04 2.76

SI RICE PM2.5 0.047 g/bhp-hr 1.38 6.04 Manufacturer 0.0 1.38 6.04 2.76SO2 0.001 lb/MMBTU 0.05 0.21 AP-42, Table 3.2-2 0.0 0.05 0.21 0.10NOx 1.00 g/bhp-hr 29.64 129.84 Manufacturer 0.0 29.64 129.84 59.20VOC 0.41 g/bhp-hr 12.13 53.13 Manufacturer 4.0 11.64 51.00 23.25CO 1.72 g/bhp-hr 50.94 223.12 Manufacturer 93.0 3.57 15.62 7.12







EU-005 800 --- 1,214 --- 7.91 PM 0.13 0.59 Note 1 0.0 0.13 0.59 790.7 0.01(Diesel) PM10 0.13 0.59 Note 1 0.0 0.13 0.59 0.01CI RICE (57.3 gal / hr) PM2.5 0.13 0.59 Note 1 0.0 0.13 0.59 0.01

SO2 1.52E-03 lb/MMBTU 0.01 0.05 AP-42, Table 3.4-1 0.0 0.01 0.05 0.0006NOx 13.74 60.18 Manufacturer 0.0 13.74 60.18 0.69VOC 0.11 0.48 Manufacturer 0.0 0.11 0.48 0.01CO 0.76 3.33 Manufacturer 0.0 0.76 3.33 0.04

PM 10.17 44.56 10.17 44.56 20.06PM10 5.65 24.77 5.65 24.77 11.03PM2.5 5.65 24.77 5.65 24.77 11.03SO2 0.21 0.90 0.21 0.90 0.39NOx 132.32 579.55 132.32 579.55 237.49VOC 48.63 213.00 46.69 204.50 93.02CO 204.52 895.80 15.02 65.80 28.52

PM 10.17 44.56 10.17 44.56 20.06PM10 5.65 24.77 5.65 24.77 11.03PM2.5 5.65 24.77 5.65 24.77 11.03SO2 0.21 0.90 0.21 0.90 0.39NOx 132.32 579.55 132.32 579.55 237.49VOC 48.63 213.00 46.69 204.50 93.02CO 204.52 895.80 15.02 65.80 28.52

Notes / Assumptions: 1. For calculation of particulate emissions on EU-005, the manufacturer's not-to-exceed PM rate at 50% load is summed with the AP-42, Table 3.4-2 PM condensable rate.2. 1 cubic foot natural gas = 1,026 BTU (40 CFR 98, Subp C)3. 1 gallon diesel fuel (No. 2) = 138,000 BTU (40 CFR 98, Subp C)4. For EU-001 through EU-004, SO2 emission factors from AP-42 - Natural Gas-fired Reciprocating Engines - 7/2000. Proposed emission units are 4-stroke, lean-burn engines.5. For EU-005, SO2 emission factors from AP-42 - Large Stationary Diesel and All Stationary Dual-fuel Engines - 10/1996. Sulfur content of the fuel will not exceed 15 ppm by weight (0.0015%)6. For EU-001 thru EU-004, the NOx emission rate was increased from the manufacturer's guaranteed rate of 0.9 to 1.0 g/bhp-hr. 1.0 g/bhp-hr is a requirement of 40 CFR 60, subp JJJJ.

Facility Totals (Upon Project Completion)

Owatonna Energy Station

Revision Date: 1/23/2015

Address To Be Determined, Owatonna, Minnesota

Proposed Project Totals

Construction of a New FacilityProposed / New Emission Sources - Criteria Pollutant Calculations

UnitekW

RatingGHG

Pollutant GWP

GuaranteedHeat Rate

(BTU/kWh)

MaximumHourly Design

Rate(MMBTU/hr)

EmissionFactor

(kg/MMBtu)Emission Rate

(kg/hr)

EmissionRate

(lb/hr)Factor Source

(AP-42, ST, Other)

EmissionRate at

8760 hrs/yr(ton/yr)

[Limited] Energy Input - Proposed

(MMBTU/yr)

[Limited]Controlled

Emissions (*)(ton/yr)

EU-001 9,770 CO2 1 --- 82.74 53.06 4.39E+03 9.68E+03 2013 TCR, Table 12.1 4.24E+04 330,463.6 1.93E+04(Natural Gas) CH4 25 0.5669 4.69E+01 1.03E+02 2013 TCR, Table 12.7 4.53E+02 2.07E+02

SI RICE N2O 298 0.0001 8.27E-03 1.82E-02 40 CFR 98, Subp C 7.99E-02 3.64E-02HFCs --- 0.00 0.00E+00 0.00E+00 40 CFR 98, Subp C 0.00E+00 0.00E+00PFCs --- 0.00 0.00E+00 0.00E+00 40 CFR 98, Subp C 0.00E+00 0.00E+00SF6 22,800 0.00 0.00E+00 0.00E+00 40 CFR 98, Subp C 0.00E+00 0.00E+00

CO2e --- --- 5.57E+03 1.23E+04 --- 5.37E+04 2.45E+04EU-002 9,770 CO2 1 --- 82.74 53.06 4.39E+03 9.68E+03 2013 TCR, Table 12.1 4.24E+04 330,463.6 1.93E+04

(Natural Gas) CH4 25 0.5669 4.69E+01 1.03E+02 2013 TCR, Table 12.7 4.53E+02 2.07E+02SI RICE N2O 298 0.0001 8.27E-03 1.82E-02 40 CFR 98, Subp C 7.99E-02 3.64E-02

HFCs --- 0.00 0.00E+00 0.00E+00 40 CFR 98, Subp C 0.00E+00 0.00E+00PFCs --- 0.00 0.00E+00 0.00E+00 40 CFR 98, Subp C 0.00E+00 0.00E+00SF6 22,800 0.00 0.00E+00 0.00E+00 40 CFR 98, Subp C 0.00E+00 0.00E+00







CO2e --- --- 5.57E+03 1.23E+04 --- 5.37E+04 2.45E+04

EU-005 800 CO2 1 --- 7.91 73.96 5.85E+02 1.29E+032013 TCR, Table 12.1 /

40 CFR 98, Subp C 5.65E+03 790.7 6.45E+01(Diesel) CH4 25 0.004 3.16E-02 6.97E-02 2013 TCR, Table 12.7 3.05E-01 3.49E-03CI RICE N2O 298 (57.3 gal / hr) 0.0006 4.74E-03 1.05E-02 40 CFR 98, Subp C 4.58E-02 5.23E-04


CO2e --- --- 5.87E+02 1.29E+03 --- 5.67E+03 6.47E+01

CO2 4.00E+04 175,217.89 77,377.83CH4 4.14E+02 1,812.02 826.03N2O 8.34E-02 0.37 0.15HFCs 0.00E+00 0.00 0.00PFCs 0.00E+00 0.00 0.00SF6 0.00E+00 0.00 0.00

CO2e 5.04E+04 220,627.28 98,072.15

CO2 4.00E+04 175,217.89 77,377.83CH4 4.14E+02 1,812.02 826.03N2O 8.34E-02 0.37 0.15HFCs 0.00E+00 0.00 0.00PFCs 0.00E+00 0.00 0.00SF6 0.00E+00 0.00 0.00

CO2e 5.04E+04 220,627.28 98,072.15

Facility Total [Limited] - CO2e 98,072.15 tons/yr

Notes / Assumptions: 1 cubic foot natural gas = 1,026 BTU (40 CFR 98, Subp C)1 gallon diesel fuel (No. 2) = 138,000 BTU (40 CFR 98, Subp C)No emission control equipment proposed for GHG emissions

Proposed / New Emission Sources - Criteria Pollutant CalculationsOwatonna Energy Station

Address To Be Determined, Owatonna, Minnesota

Facility Totals (Upon Project Completion)

Project Totals

Revision Date: 1/23/2015GHG Calculations

Uni

tkW

Rat

ing

bhp

Rat

ing

Gua

rant

eed

Hea

t Rat

e(B

TU

/kW

h)

Max

imum

Hou

rly

Des

ign

Rat

e(M

MB

TU

/hr)

Pol

luta

ntC

AS

Num

ber

1990

CA

AL

iste

d H

AP

?P

OM

?

Em

issi

onF

acto

r(l

b/un

it)

Em

issi

onF

acto

r"U

nit"

[Unc

ontr

olle

d]E

mis

sion

Rat

e(l

b/hr

)

[Unc

ontr

olle

d]E

mis

sion

Rat

e at

8760

hrs

/yr

(ton

/yr)

Fac

tor

Sou

rce

(AP

-42,

ST

, Oth

er)

Con

trol

Eff

icie

ncy

(%)

[Con

trol

led]

Em

issi

on R

ate

(lb/

hr)

[Con

trol

led]

Em

issi

onR

ate

at87

60 h

rs/y

r(t

on/y

r)

[Lim

ited

]E

nerg

y In

put -

P

ropo

sed

(MM

BT

U/y

r)

[Lim

ited

]M

axim

umE

mis

sion

Rat

e(t

ons/

yr)

EU

-001

9,77

013

,410

---

82.7

4A

cena

phth

ene

83-3

2-9

Yes

Yes

1.25

E-0

6M

MB

TU

1.03

E-0

44.

53E

-04

AP

-42,

Tab

le 3

.2-2

30.0

7.24

E-0

53.

17E

-04

330,

463.

61.

45E

-04

(Nat

ural

Gas

)A

cena

phth

ylen

e20

8-96

-8Y

esY

es5.

53E

-06

MM

BT

U4.

58E

-04

2.00

E-0

3A

P-4

2, T

able

3.2

-230

.03.

20E

-04

1.40

E-0

36.

40E

-04

SI

RIC

EA

ceta

ldeh

yde

75-0

7-0

Yes

8.36

E-0

3M

MB

TU

6.92

E-0

13.

03E

+00

AP

-42,

Tab

le 3

.2-2

30.0

4.84

E-0

12.

12E

+00

9.67

E-0

1A

crol

ein

107-

02-8

Yes

5.14

E-0

3M

MB

TU

4.25

E-0

11.

86E

+00

AP

-42,

Tab

le 3

.2-2

30.0

2.98

E-0

11.

30E

+00

5.95

E-0

1E

U-0

02B

enze

ne71

-43-

2Y

es4.

40E

-04

MM

BT

U3.

64E

-02

1.59

E-0

1A

P-4

2, T

able

3.2

-230

.02.

55E

-02

1.12

E-0

15.

09E

-02

(Nat

ural

Gas

)B

enzo

(b)

flu

oran

then

e20

5-99

-2Y

esY

es1.

66E

-07

MM

BT

U1.

37E

-05

6.02

E-0

5A

P-4

2, T

able

3.2

-230

.09.

61E

-06

4.21

E-0

51.

92E

-05

SI

RIC

EB

enzo

(e)

pyr

ene

192-

97-2

Yes

4.15

E-0

7M

MB

TU

3.43

E-0

51.

50E

-04

AP

-42,

Tab

le 3

.2-2

30.0

2.40

E-0

51.

05E

-04

4.80

E-0

5B

enzo

(g,

h,i)

per

ylen

e19

1-24

-2Y

esY

es4.

14E

-07

MM

BT

U3.

43E

-05

1.50

E-0

4A

P-4

2, T

able

3.2

-230

.02.

40E

-05

1.05

E-0

44.

79E

-05

EU

-003

Bip

heny

l92

-52-

4Y

es2.

12E

-04

MM

BT

U1.

75E

-02

7.68

E-0

2A

P-4

2, T

able

3.2

-230

.01.

23E

-02

5.38

E-0

22.

45E

-02

(Nat

ural

Gas

)1,

3-B

utad

iene

106-

99-0

Yes

2.67

E-0

4M

MB

TU

2.21

E-0

29.

68E

-02

AP

-42,

Tab

le 3

.2-2

30.0

1.55

E-0

26.

77E

-02

3.09

E-0

2S

I R

ICE

Car

bon

tetr

achl

orid

e56

-23-

5Y

es3.

67E

-05

MM

BT

U3.

04E

-03

1.33

E-0

2A

P-4

2, T

able

3.2

-230

.02.

13E

-03

9.31

E-0

34.

24E

-03

Chl

orob

enze

ne10

8-90

-7Y

es3.

04E

-05

MM

BT

U2.

52E

-03

1.10

E-0

2A

P-4

2, T

able

3.2

-230

.01.

76E

-03

7.71

E-0

33.

52E

-03

EU

-004

Chl

orof

orm

67-6

6-3

Yes

2.85

E-0

5M

MB

TU

2.36

E-0

31.

03E

-02

AP

-42,

Tab

le 3

.2-2

30.0

1.65

E-0

37.

23E

-03

3.30

E-0

3(N

atur

al G

as)

Chr

ysen

e21

8-01

-9Y

esY

es6.

93E

-07

MM

BT

U5.

73E

-05

2.51

E-0

4A

P-4

2, T

able

3.2

-230

.04.

01E

-05

1.76

E-0

48.

02E

-05

SI

RIC

ED

ichl

orom

etha

ne75

-09-

2Y

es2.

00E

-05

MM

BT

U1.

65E

-03

7.25

E-0

3A

P-4

2, T

able

3.2

-230

.01.

16E

-03

5.07

E-0

32.

31E

-03

1,3-

Dic

hlor

opro

pene

542-

75-6

Yes

2.64

E-0

5M

MB

TU

2.18

E-0

39.

57E

-03

AP

-42,

Tab

le 3

.2-2

30.0

1.53

E-0

36.

70E

-03

3.05

E-0

3E

thyl

benz

ene

100-

41-4

Yes

3.97

E-0

5M

MB

TU

3.28

E-0

31.

44E

-02

AP

-42,

Tab

le 3

.2-2

30.0

2.30

E-0

31.

01E

-02

4.59

E-0

3E

thyl

ene

dibr

omid

e10

6-93

-4Y

es4.

43E

-05

MM

BT

U3.

67E

-03

1.61

E-0

2A

P-4

2, T

able

3.2

-230

.02.

57E

-03

1.12

E-0

25.

12E

-03

Flu

oran

then

e20

6-44

-0Y

esY

es1.

11E

-06

MM

BT

U9.

18E

-05

4.02

E-0

4A

P-4

2, T

able

3.2

-230

.06.

43E

-05

2.82

E-0

41.

28E

-04

Flu

oren

e86

-73-

7Y

esY

es5.

67E

-06

MM

BT

U4.

69E

-04

2.05

E-0

3A

P-4

2, T

able

3.2

-230

.03.

28E

-04

1.44

E-0

36.

56E

-04

For

mal

dehy

de50

-00-

0Y

es5.

28E

-02

MM

BT

U4.

37E

+00

1.91

E+0

1A

P-4

2, T

able

3.2

-230

.03.

06E

+00

1.34

E+0

16.

11E

+00

Isom

ers

of x

ylen

e13

30-2

0-7

Yes

1.84

E-0

4M

MB

TU

1.52

E-0

26.

67E

-02

AP

-42,

Tab

le 3

.2-2

30.0

1.07

E-0

24.

67E

-02

2.13

E-0

2M

ethy

l alc

ohol

67-5

6-1

Yes

2.50

E-0

3M

MB

TU

2.07

E-0

19.

06E

-01

AP

-42,

Tab

le 3

.2-2

30.0

1.45

E-0

16.

34E

-01

2.89

E-0

12-

Met

hyl N

apht

hale

ne91

-57-

6Y

es3.

32E

-05

MM

BT

U2.

75E

-03

1.20

E-0

2A

P-4

2, T

able

3.2

-230

.01.

92E

-03

8.42

E-0

33.

84E

-03

N-H

exan

e11

0-54

-3Y

es1.

11E

-03

MM

BT

U9.

18E

-02

4.02

E-0

1A

P-4

2, T

able

3.2

-230

.06.

43E

-02

2.82

E-0

11.

28E

-01

Nap

htha

lene

91-2

0-3

Yes

Yes

7.44

E-0

5M

MB

TU

6.16

E-0

32.

70E

-02

AP

-42,

Tab

le 3

.2-2

30.0

4.31

E-0

31.

89E

-02

8.61

E-0

3P

hena

nthr

ene

85-0

1-8

Yes

Yes

1.04

E-0

5M

MB

TU

8.60

E-0

43.

77E

-03

AP

-42,

Tab

le 3

.2-2

30.0

6.02

E-0

42.

64E

-03

1.20

E-0

3P

heno

l10

8-95

-2Y

es2.

40E

-05

MM

BT

U1.

99E

-03

8.70

E-0

3A

P-4

2, T

able

3.2

-230

.01.

39E

-03

6.09

E-0

32.

78E

-03

PA

HY

es2.

69E

-05

MM

BT

U2.

23E

-03

9.75

E-0

3A

P-4

2, T

able

3.2

-230

.01.

56E

-03

6.82

E-0

33.

11E

-03

Pyr

ene

129-

00-0

Yes

Yes

1.36

E-0

6M

MB

TU

1.13

E-0

44.

93E

-04

AP

-42,

Tab

le 3

.2-2

30.0

7.88

E-0

53.

45E

-04

1.57

E-0

4S

tyre

ne10

0-42

-5Y

es2.

36E

-05

MM

BT

U1.

95E

-03

8.55

E-0

3A

P-4

2, T

able

3.2

-230

.01.

37E

-03

5.99

E-0

32.

73E

-03

1,1,

2,2-

Tet

rach

loro

etha

ne79

-34-

5Y

es4.

00E

-05

MM

BT

U3.

31E

-03

1.45

E-0

2A

P-4

2, T

able

3.2

-230

.02.

32E

-03

1.01

E-0

24.

63E

-03

Tet

rach

loro

etha

neY

es2.

48E

-06

MM

BT

U2.

05E

-04

8.99

E-0

4A

P-4

2, T

able

3.2

-230

.01.

44E

-04

6.29

E-0

42.

87E

-04

Tol

uene

108-

88-3

Yes

4.08

E-0

4M

MB

TU

3.38

E-0

21.

48E

-01

AP

-42,

Tab

le 3

.2-2

30.0

2.36

E-0

21.

04E

-01

4.72

E-0

21,

1,2-

Tri

chlo

roet

hane

79-0

0-5

Yes

3.18

E-0

5M

MB

TU

2.63

E-0

31.

15E

-02

AP

-42,

Tab

le 3

.2-2

30.0

1.84

E-0

38.

07E

-03

3.68

E-0

32,

2,4-

Tri

met

hylp

enta

ne54

0-84

-1Y

es2.

50E

-04

MM

BT

U2.

07E

-02

9.06

E-0

2A

P-4

2, T

able

3.2

-230

.01.

45E

-02

6.34

E-0

22.

89E

-02

Vin

yl c

hlor

ide

75-0

1-4

Yes

1.49

E-0

5M

MB

TU

1.23

E-0

35.

40E

-03

AP

-42,

Tab

le 3

.2-2

30.0

8.63

E-0

43.

78E

-03

1.72

E-0

3

Sum

of H

AP'

s5.

9726

.16

4.18

18.3

18.

35

Hig

hest

HA

P50

-00-

0(F

orm

alde

hyde

)4.

3719

.13

3.06

13.3

96.

11

Not

es/A

ssum

ptio

ns:

1. E

mis

sion

Fac

tors

fro

m A

P-4

2 -

Nat

ural

Gas

-fir

ed R

ecip

roca

ting

Eng

ines

- 7

/200

0. P

ropo

sed

engi

nes

are

4-st

roke

, lea

n-bu

rn e

ngin

es2.

Pro

pose

d ox

idat

ion

cata

lyst

inst

alla

tion

pro

vide

s 50

% c

ontr

ol o

f al

l haz

ardo

us a

ir p

ollu

tant

s

Em

issi

on U

nit T

otal

s

Ow

aton

na E

nerg

y St

atio

nC

onst

ruct

ion

of a

New

Fac

ility

Haz

ardo

us A

ir P

ollu

tant

Em

issi

on C

alcu

latio

ns (E

U-0

01 -

EU

-004

)R

evis

ion

Dat

e: 1

/23/

2015

Add

ress

To

Be

Det

erm

ined

, Ow

aton

na, M

inne

sota

Uni

tkW

Rat

ing

App

rox

Fue

l C

onsu

mpt

ion

at

full

load

(G

al/h

r)

Max

imum

Hou

rly

Des

ign

Rat

e(M

MB

TU

/hr)

Pol

luta

ntC

AS

Num

ber

1990

CA

AL

iste

d H

AP

?P

OM

?E

mis

sion

Fac

tor

Em

issi

on F

acto

r"U

nit"

[Unc

ontr

olle

d]E

mis

sion

Rat

e(l

b/hr

)

[Unc

ontr

olle

d]E

mis

sion

Rat

e at

8760

hrs

/yr

(ton

/yr)

Fac

tor

Sou

rce

(AP

-42,

ST

, Oth

er)

Con

trol

Eff

icie

ncy

(%)

[Con

trol

led]

Em

issi

onR

ate

(lb/

hr)

[Con

trol

led]

Em

issi

onR

ate

at87

60 h

rs/y

r(t

on/y

r)

[Lim

ited

]E

nerg

y In

put -

P

ropo

sed

(MM

BT

U/y

r)

[Lim

ited

]C

ontr

olle

dE

mis

sion

s (*

)(t

on/y

r)

EU

-005

800

57.3

07.

91A

cena

phth

ene

83-3

2-9

Yes

4.68

E-0

6M

MB

TU

3.70

E-0

51.

62E

-04

AP

-42,

Tab

le 3

.4-4

0.0

3.70

E-0

51.

62E

-04

790.

741.

85E

-06

Die

sel

Ace

naph

thyl

ene

208-

96-8

Yes

9.23

E-0

6M

MB

TU

7.30

E-0

53.

20E

-04

AP

-42,

Tab

le 3

.4-4

0.0

7.30

E-0

53.

20E

-04

3.65

E-0

6C

I R

ICE

Ace

tald

ehyd

e75

-07-

0Y

es2.

52E

-05

MM

BT

U1.

99E

-04

8.73

E-0

4A

P-4

2, T

able

3.4

-30.

01.

99E

-04

8.73

E-0

49.

96E

-06

Acr

olei

n10

7-02

-8Y

es7.

88E

-06

MM

BT

U6.

23E

-05

2.73

E-0

4A

P-4

2, T

able

3.4

-30.

06.

23E

-05

2.73

E-0

43.

12E

-06

Ant

hrac

ene

120-

12-7

Yes

1.23

E-0

6M

MB

TU

9.73

E-0

64.

26E

-05

AP

-42,

Tab

le 3

.4-4

0.0

9.73

E-0

64.

26E

-05

4.86

E-0

7B

enze

ne71

-43-

2Y

es7.

76E

-04

MM

BT

U6.

14E

-03

2.69

E-0

2A

P-4

2, T

able

3.4

-30.

06.

14E

-03

2.69

E-0

23.

07E

-04

Ben

zo (

a) a

nthr

acen

e56

-55-

3Y

es6.

22E

-07

MM

BT

U4.

92E

-06

2.15

E-0

5A

P-4

2, T

able

3.4

-40.

04.

92E

-06

2.15

E-0

52.

46E

-07

Ben

zo (

a) p

yren

e50

-32-

8Y

es2.

57E

-07

MM

BT

U2.

03E

-06

8.90

E-0

6A

P-4

2, T

able

3.4

-40.

02.

03E

-06

8.90

E-0

61.

02E

-07

Ben

zo (

b) f

luor

anth

ene

205-

99-2

Yes

1.11

E-0

6M

MB

TU

8.78

E-0

63.

84E

-05

AP

-42,

Tab

le 3

.4-4

0.0

8.78

E-0

63.

84E

-05

4.39

E-0

7B

enzo

(g,

h,i)

per

ylen

e19

1-24

-2Y

es5.

56E

-07

MM

BT

U4.

40E

-06

1.93

E-0

5A

P-4

2, T

able

3.4

-40.

04.

40E

-06

1.93

E-0

52.

20E

-07

Ben

zo (

k) f

luor

anth

ene

207-

08-9

Yes

2.18

E-0

7M

MB

TU

1.72

E-0

67.

55E

-06

AP

-42,

Tab

le 3

.4-4

0.0

1.72

E-0

67.

55E

-06

8.62

E-0

81,

3-B

utad

iene

106-

99-0

Yes

3.91

E-0

5M

MB

TU

3.09

E-0

41.

35E

-03

AP

-42,

Tab

le 3

.4-4

0.0

3.09

E-0

41.

35E

-03

1.55

E-0

5C

hrys

ene

218-

01-9

Yes

1.53

E-0

6M

MB

TU

1.21

E-0

55.

30E

-05

AP

-42,

Tab

le 3

.4-4

0.0

1.21

E-0

55.

30E

-05

6.05

E-0

7D

iben

z(a,

h) a

nthr

acen

e53

-70-

3Y

es3.

46E

-07

MM

BT

U2.

74E

-06

1.20

E-0

5A

P-4

2, T

able

3.4

-40.

02.

74E

-06

1.20

E-0

51.

37E

-07

Flu

oran

then

e20

6-44

-0Y

es4.

03E

-06

MM

BT

U3.

19E

-05

1.40

E-0

4A

P-4

2, T

able

3.4

-40.

03.

19E

-05

1.40

E-0

41.

59E

-06

Flu

oren

e86

-73-

7Y

es1.

28E

-05

MM

BT

U1.

01E

-04

4.43

E-0

4A

P-4

2, T

able

3.4

-40.

01.

01E

-04

4.43

E-0

45.

06E

-06

For

mal

dehy

de50

-00-

0Y

es7.

89E

-05

MM

BT

U6.

24E

-04

2.73

E-0

3A

P-4

2, T

able

3.4

-30.

06.

24E

-04

2.73

E-0

33.

12E

-05

Inde

no(1

,2,3

-cd)

pyre

ne19

3-39

-5Y

es4.

14E

-07

MM

BT

U3.

27E

-06

1.43

E-0

5A

P-4

2, T

able

3.4

-40.

03.

27E

-06

1.43

E-0

51.

64E

-07

Isom

ers

of x

ylen

e13

30-2

0-7

Yes

1.93

E-0

4M

MB

TU

1.53

E-0

36.

68E

-03

AP

-42,

Tab

le 3

.4-3

0.0

1.53

E-0

36.

68E

-03

7.63

E-0

5N

apht

hale

ne91

-20-

3Y

esY

es1.

30E

-04

MM

BT

U1.

03E

-03

4.50

E-0

3A

P-4

2, T

able

3.4

-40.

01.

03E

-03

4.50

E-0

35.

14E

-05

Phe

nant

hren

e85

-01-

8Y

es4.

08E

-05

MM

BT

U3.

23E

-04

1.41

E-0

3A

P-4

2, T

able

3.4

-40.

03.

23E

-04

1.41

E-0

31.

61E

-05

Pyr

ene

129-

00-0

Yes

3.71

E-0

6M

MB

TU

2.93

E-0

51.

28E

-04

AP

-42,

Tab

le 3

.4-4

0.0

2.93

E-0

51.

28E

-04

1.47

E-0

6T

olue

ne10

8-88

-3Y

es2.

81E

-04

MM

BT

U2.

22E

-03

9.73

E-0

3A

P-4

2, T

able

3.4

-30.

02.

22E

-03

9.73

E-0

31.

11E

-04

Sum

of H

AP'

s0.

010.

060.

010.

060.

0006

Hig

hest

HA

P71

-43-

2(B

enze

ne)

0.01

0.03

0.01

0.03

0.00

Em

issi

on U

nit T

otal

s

Ow

aton

na E

nerg

y St

atio

nC

onst

ruct

ion

of a

New

Fac

ility

Haz

ardo

us A

ir P

ollu

tant

Em

issi

on C

alcu

latio

ns (E

U-0

05)

Rev

isio

n D

ate:

1/2

3/20

15

Attachment 2 – Facility Description and CD-01 Forms

ST.

PA

UL

, MN

551

55-4

194

Sho

w:

Act

ive

and

Pen

ding

Rec

ords

Act

ion:

PE

R 0

01

AQ

D F

acili

ty ID

:14

7000

77

Fac

ility

Nam

e:MIN

NE

SOTA

PO

LL

UT

ION

CO

NT

RO

L A

GE

NC

YA

IR Q

UA

LIT

Y52

0 L

AFA

YE

TT

E R

OA

D

14 M

ay, 2

015

10:

15

FAC

ILIT

Y D

ESC

RIP

TIO

N: E

MIS

SIO

N U

NIT

(EU

)

Max

Fue

lIn

put

(mil

Btu

)

Ow

aton

na E

nerg

y S

tatio

n

Ret

ired

By

(Act

ion)

Ope

rato

r D

escr

iptio

nID

No.

Em

issi

onU

nit

Sta

tus

Add

edB

y(A

ctio

n)

Con

trol

Equ

ip.

ID N

o(s)

.

Sta

ck/

Ven

tID

No(

s).

Ope

rato

rID

for

Item

Insi

gnif-

ican

tA

ctiv

ity

SIC

Man

ufac

ture

rM

odel

Num

ber

Max

.D

esig

nC

apac

ity

Max

imum

Des

ign

Cap

acity

Mat

eria

lsU

nits

nU

nits

d

82.2

21

Eng

ine

No.

1 -

Rec

ipro

catin

gIC

Eng

ine

EU

001

Act

ive

PE

R 0

01C

E 0

01S

V 0

01 (

M)

Hr

Nat

ural

Gas

4911

Cat

erpi

llar

G20

CM

3480

141

Ft3

82.2

22

Eng

ine

No.

2 -

Rec

ipro

catin

gIC

Eng

ine

EU

002

Act

ive

PE

R 0

01C

E 0

02S

V 0

02 (

M)

Hr

Nat

ural

Gas

4911

Cat

erpi

llar

G20

CM

3480

141

Ft3

82.2

23

Eng

ine

No.

3 -

Rec

ipro

catin

gIC

Eng

ine

EU

003

Act

ive

PE

R 0

01C

E 0

03S

V 0

03 (

M)

Hr

Nat

ural

Gas

4911

Cat

erpi

llar

G20

CM

3480

141

Ft3

82.2

24

Eng

ine

No.

4 -

Rec

ipro

catin

gIC

Eng

ine

EU

004

Act

ive

PE

R 0

01C

E 0

04S

V 0

04 (

M)

Hr

Nat

ural

Gas

4911

Cat

erpi

llar

G20

CM

3480

141

Ft3

7.91

5E

ngin

e N

o. 5

(E

mer

genc

y)R

ecip

roca

ting

IC E

ngin

eE

U 0

05A

ctiv

eP

ER

001

SV

005

(M

)H

r

D

iese

l Fue

l49

11C

ater

pilla

rC

2757

.3G

al

Pag

e 1

of

1 (

a)

14 M

ay, 2

015

10:

15

FAC

ILIT

Y D

ESC

RIP

TIO

N: E

MIS

SIO

N U

NIT

(EU

)

ID N

o.E

leva

tor

Type

Bot

tlene

ckP

ct.

Fue

l/S

pace

Hea

t

Firi

ng M

etho

dA

dded

By

(Act

ion)

Rem

oval

Dat

eIn

itial

Sta

rtup

Dat

e

Com

m-

ence

Con

st.

Dat

e

Em

issi

onU

nit

Sta

tus

1E

U 0

01P

ER

001

Act

ive

2E

U 0

02P

ER

001

Act

ive

3E

U 0

03P

ER

001

Act

ive

4E

U 0

04P

ER

001

Act

ive

5E

U 0

05P

ER

001

Act

ive

Pag

e 1

of

1 (

b)

Insi

gnif-

ican

tA

ctiv

ity

Ope

rato

rID

for

Item

MIN

NE

SOTA

PO

LL

UT

ION

CO

NT

RO

L A

GE

NC

YA

IR Q

UA

LIT

Y52

0 L

AFA

YE

TT

E R

OA

DS

T. P

AU

L, M

N 5

5155

-419

4

Sho

w:

Act

ive

and

Pen

ding

Rec

ords

Act

ion:

PE

R 0

01

AQ

D F

acili

ty ID

:14

7000

77

Fac

ility

Nam

e:O

wat

onna

Ene

rgy

Sta

tion

14 M

ay, 2

015

10:

13

FAC

ILIT

Y D

ESC

RIP

TIO

N: S

TOR

AG

E T

AN

KS

(TK

)

ID N

o.C

apac

ity(1

000

gal)

Inte

rior

Hei

ght

(ft.

)

Inte

rior

Dia

met

er(f

t.)

Add

edB

y(A

ctio

n)

Con

stru

ctio

n Ty

peTa

nkS

tatu

sP

rodu

ct S

tore

dC

ontr

olE

quip

.ID

No(

s).

Ret

ired

By

(Act

ion)

1T

K 0

0110

13.8

11.8

Fix

ed R

oof

Act

ive

PE

R 0

01U

rea

2T

K 0

024

118

Fix

ed R

oof

Act

ive

PE

R 0

01E

thyl

ene

Gly

col

3T

K 0

034

118

Fix

ed R

oof

Act

ive

PE

R 0

01E

thyl

ene

Gly

col

4T

K 0

043

146

Fix

ed R

oof

Act

ive

PE

R 0

01Lu

bric

atin

g O

il

5T

K 0

052

125.

3F

ixed

Roo

fA

ctiv

eP

ER

001

Lubr

icat

ing

Oil

6T

K 0

062

125.

3F

ixed

Roo

fA

ctiv

eP

ER

001

Lubr

icat

ing

Oil

7T

K 0

073.

6F

ixed

Roo

fA

ctiv

eP

ER

001

Die

sel F

uel

Pag

e 1

of

1 (a

)

ID N

o.

FAC

ILIT

Y D

ESC

RIP

TIO

N: S

TOR

AG

E T

AN

KS

(TK

)

14 M

ay, 2

015

10:

13

Yea

rR

emov

edY

ear

Inst

alle

dS

eal T

ype

(flo

atin

g ro

of o

nly)

Add

edB

y(A

ctio

n)

Sup

port

Typ

e(f

loat

ing

roof

onl

y)C

olum

nC

ount

Col

umn

Dia

met

er(f

t.)

Dec

k Ty

pe

(flo

atin

g ro

of o

nly)

Tank

Sta

tus

1T

K 0

01P

ER

001

Act

ive

2T

K 0

02P

ER

001

Act

ive

3T

K 0

03P

ER

001

Act

ive

4T

K 0

04P

ER

001

Act

ive

5T

K 0

05P

ER

001

Act

ive

6T

K 0

06P

ER

001

Act

ive

7T

K 0

07P

ER

001

Act

ive

Pag

e 1

of

1 (

b)

MIN

NE

SOTA

PO

LL

UT

ION

CO

NT

RO

L A

GE

NC

YA

IR Q

UA

LIT

Y52

0 L

AFA

YE

TT

E R

OA

DS

T. P

AU

L, M

N 5

5155

-419

4

Sho

w:

Act

ive

and

Pen

ding

Rec

ords

Act

ion:

PE

R 0

01

AQ

D F

acili

ty ID

:14

7000

77

Fac

ility

Nam

e:O

wat

onna

Ene

rgy

Sta

tion

14 M

ay, 2

015

10:

14

FAC

ILIT

Y D

ESC

RIP

TIO

N: S

TAC

K/V

EN

TS

(SV

)

ID N

o.D

isch

arge

Dire

ctio

nF

low

Rat

e/Te

mpe

ratu

reIn

form

atio

n S

ourc

e

Exi

t G

asTe

mpe

ratu

reat

Top

(ºF

)

Des

ign

Flo

w R

ate

at T

op(A

CF

M)

Wid

th(f

eet)

Dia

met

eror

Len

gth

(fee

t)

Insi

de D

imen

sion

sH

eigh

t of

Ope

ning

Fro

mG

roun

d(f

eet)

Add

edB

y(A

ctio

n)

Ret

ired

By

(Act

ion)

Ope

rato

rID

for

Item

Ope

rato

rs D

escr

iptio

nS

tack

/V

ent

Sta

tus

1S

V 0

01U

p, N

o C

apM

anuf

actu

rer

635

5904

83.

9499

PE

R 0

01E

ngin

e N

o. 1

Act

ive

2S

V 0

02U

p, N

o C

apM

anuf

actu

rer

635

5904

83.

9499

PE

R 0

01E

ngin

e N

o. 2

Act

ive

3S

V 0

03U

p, N

o C

apM

anuf

actu

rer

635

5904

83.

9499

PE

R 0

01E

ngin

e N

o. 3

Act

ive

4S

V 0

04U

p, N

o C

apM

anuf

actu

rer

635

5904

83.

9499

PE

R 0

01E

ngin

e N

o. 4

Act

ive

5S

V 0

05U

p, N

o C

apM

anuf

actu

rer

953

6012

0.83

12.3

PE

R 0

01E

ngin

e N

o. 5

Act

ive

Pag

e 1

of

1

MIN

NE

SOTA

PO

LL

UT

ION

CO

NT

RO

L A

GE

NC

YA

IR Q

UA

LIT

Y52

0 L

AFA

YE

TT

E R

OA

DS

T. P

AU

L, M

N 5

5155

-419

4

Sho

w:

Act

ive

and

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MINNESOTA POLLUTION CONTROL AGENCYAIR QUALITY520 LAFAYETTE ROADST. PAUL, MN 55155-4194

14 May, 2015 10:15

FACILITY DESCRIPTION: Potential-to-emit (by item)

Show: Active and Pending Records

AQD Facility ID:

Facility Name:

14700077


Item UnrestrictedPotential

(tons per yr)

LimitedPotential

(tons per yr)

ActualEmissions

(tons per yr)

Pollutant AddedBy

(Action)

RetiredBy

(Action)

HourlyPotential

(lbs per hr)

EU 001

Acetaldehyde PER 001 9.67E-016.92E-01 3.03E+00

Acrolein PER 001 5.95E-014.25E-01 1.86E+00

Benzene PER 001 5.09E-023.64E-02 1.59E-01

Biphenyl PER 001 2.45E-021.75E-02 7.68E-02

1,3-Butadiene PER 001 3.09E-022.21E-02 9.68E-02

Carbon Dioxide Equivalent PER 001 2.45E+041.23E+04 5.37E+04

Methane PER 001 2.07E+021.03E+02 4.53E+02

Carbon Monoxide PER 001 7.12E+005.09E+01 2.23E+02

Carbon Dioxide PER 001 1.93E+049.68E+03 4.24E+04

Formaldehyde PER 001 6.11E+004.37E+00 1.91E+01

Hexane PER 001 1.28E-019.18E-02 4.02E-01

Methanol PER 001 2.89E-012.07E-01 9.06E-01

HAPs - Total PER 001 8.35E+005.97E+00 2.62E+01

Toluene PER 001 4.72E-023.38E-02 1.48E-01

Xylenes (mixed isomers) PER 001 2.13E-021.52E-02 6.67E-02

2,2,4-trimethylpentane PER 001 2.89E-022.07E-02 9.06E-02

Acenaphthene PER 001 1.45E-041.03E-04 4.53E-04

Acenaphthylene PER 001 6.40E-044.58E-04 2.00E-03

Benzo(ghi)perylene PER 001 4.79E-053.43E-05 1.50E-04

Nitrous Oxide PER 001 3.64E-021.82E-02 7.99E-02

Nitrogen Oxides PER 001 5.92E+012.96E+01 1.30E+02

PM < 2.5 micron PER 001 2.76E+001.38E+00 6.04E+00

PM < 10 micron PER 001 2.76E+001.38E+00 6.04E+00

Total Particulate Matter PER 001 5.01E+002.51E+00 1.10E+01

HAP-Single PER 001 6.11E+004.37E+00 1.91E+01

Sulfur Dioxide PER 001 1.00E-015.00E-02 2.10E-01

Volatile Organic Compounds PER 001 2.33E+011.21E+01 5.31E+01

EU 002


Acrolein PER 001 5.95E-014.25E-01 1.86E+00

Benzene PER 001 5.09E-023.64E-02 1.59E-01

Biphenyl PER 001 2.45E-021.75E-02 7.68E-02



Methane PER 001 2.07E+021.03E+02 4.53E+02




Hexane PER 001 1.28E-019.18E-02 4.02E-01

Methanol PER 001 2.89E-012.07E-01 9.06E-01


Toluene PER 001 4.72E-023.38E-02 1.48E-01





Page 1 of 3


14 May, 2015 10:15



AQD Facility ID:

Facility Name:

14700077



(tons per yr)

LimitedPotential

(tons per yr)

ActualEmissions

(tons per yr)

Pollutant AddedBy

(Action)

RetiredBy

(Action)

HourlyPotential

(lbs per hr)

EU 002




PM < 2.5 micron PER 001 2.76E+001.38E+00 6.04E+00

PM < 10 micron PER 001 2.76E+001.38E+00 6.04E+00





EU 003


Acrolein PER 001 5.95E-014.25E-01 1.86E+00

Benzene PER 001 5.09E-023.64E-02 1.59E-01

Biphenyl PER 001 2.45E-021.75E-02 7.68E-02



Methane PER 001 2.07E+021.03E+02 4.53E+02




Hexane PER 001 1.28E-019.18E-02 4.02E-01

Methanol PER 001 2.89E-012.07E-01 9.06E-01


Toluene PER 001 4.72E-023.38E-02 1.48E-01








PM < 2.5 micron PER 001 2.76E+001.38E+00 6.04E+00

PM < 10 micron PER 001 2.76E+001.38E+00 6.04E+00





EU 004


Acrolein PER 001 5.95E-014.25E-01 1.86E+00

Benzene PER 001 5.09E-023.64E-02 1.59E-01

Biphenyl PER 001 2.45E-021.75E-02 7.68E-02



Methane PER 001 2.07E+021.03E+02 4.53E+02


Page 2 of 3


14 May, 2015 10:15



AQD Facility ID:

Facility Name:

14700077



(tons per yr)

LimitedPotential

(tons per yr)

ActualEmissions

(tons per yr)

Pollutant AddedBy

(Action)

RetiredBy

(Action)

HourlyPotential

(lbs per hr)

EU 004



Hexane PER 001 1.28E-019.18E-02 4.02E-01

Methanol PER 001 2.89E-012.07E-01 9.06E-01


Toluene PER 001 4.72E-023.38E-02 1.48E-01








PM < 2.5 micron PER 001 2.76E+001.38E+00 6.04E+00

PM < 10 micron PER 001 2.76E+001.38E+00 6.04E+00





EU 005

Benzene PER 001 3.07E-046.14E-03 2.69E-02


Methane PER 001 3.49E-036.97E-02 3.05E-01

Carbon Monoxide PER 001 4.00E-027.60E-01 3.33E+00


Formaldehyde PER 001 3.12E-056.24E-04 2.73E-03

HAPs - Total PER 001 6.00E-041.00E-02 6.00E-02

Toluene PER 001 1.11E-042.22E-03 9.73E-03


Nitrogen Oxides PER 001 6.90E-011.37E+01 6.02E+01

PM < 2.5 micron PER 001 1.00E-021.30E-01 5.90E-01

PM < 10 micron PER 001 1.00E-021.30E-01 5.90E-01

Total Particulate Matter PER 001 1.00E-021.30E-01 5.90E-01

HAP-Single PER 001 3.07E-046.14E-03 2.69E-02


Volatile Organic Compounds PER 001 1.00E-021.10E-01 4.80E-01

Page 3 of 3

MINNESOTA POLLUTION CONTROL AGENCYAIR QUALITY520 LAFAYETTE ROADST. PAUL, MN 55155-4194 COMPLIANCE PLAN CD-01

Facility Name: Owatonna Energy Station

Permit Number: 14700077 - 001

14 May, 2015 10:28Page 1 of 28

Subject Item: Total Facility

NC/CA

Type Citation Requirement

CD hdr CONSTRUCTION AUTHORIZATION1.0

CD Minn. R. 7007.0800, subp. 2 The Permittee is authorized to install EU 001, EU 002, EU 003, EU 004, and EU005. The units shall meet all of the requirements of this permit including those listedin GP 001 and at each EU level.

The construction authorization expires 18 months after permit issuance(14700077-001). The Permittee must keep a record of the dates of installation andstart-up on site. The Permittee may apply for an extension of the constructionauthorization deadline by following the Administrative Amendment provisions inMinn. R. 7007.1400.

2.0

S/A 40 CFR Section 60.7(a)(1); 40 CFRSection 63.6590(c); Minn. R.7011.8150

Notification of the Date Construction Began: due 30 days after Start OfConstruction. The notification shall include the following information:

1) Name and address of the Permittee;2) The address of the affected source;3) Engine information including make, model, engine family, serial number, modelyear, maximum engine power, and engine displacement;4) Emission control equipment; and5) Fuel used.

3.0

CD hdr SOURCE-SPECIFIC REQUIREMENTS4.0

CD Minn. R. 7007.0800, subp. 2 Permit Appendices: This permit contains appendices as listed in the permit Table ofContents. The Permittee shall comply with all requirements contained inAppendices B, C, and D.

Modeling parameters in Appendix A are included for reference only as describedelsewhere in Table A.

5.0

CD Minn. R. 7007.0800, subp. 2 Permit Appendices: This permit contains appendices as listed in the permit Table ofContents. The Permittee shall comply with all requirements contained in theappendices.

6.0

CD Minn. R. 7007.0800, subp. 2 Application for Major Amendment Required: If any GP 001 NOx emission factorperformance test approved by the MPCA measures NOx emissions greater than29.64 lb/hr, the Permittee shall submit a complete application for a major permitamendment to adjust the GP 001 normal operating hours. The application shall besubmitted within 30 days after the Permittee's receipt of the test report (from thetesting company), indicating emissions greater than 29.64 lb/hr. The applicationshall include a fuel limit or pollution control plan to restrict Total Facility NOxemissions to a maximum of 237.5 tons per year (12-month rolling sum basis) basedon the actual emission factor that was measured greater than 29.64 lb/hr.

7.0

CD hdr OPERATIONAL REQUIREMENTS8.0

CD Minn. Stat. Section 116.07, subds.4a & 9; Minn. R. 7007.0100, subp.7(A), 7(L), & 7(M); Minn. R.7007.0800, subps. 1, 2 & 4; Minn.R. 7009.0010-7009.0080

The Permittee shall comply with National Primary and Secondary Ambient AirQuality Standards, 40 CFR pt. 50, and the Minnesota Ambient Air QualityStandards, Minn. R. 7009.0010 to 7009.0080. Compliance shall be demonstratedupon written request by the MPCA.

9.0

CD Minn. R. 7011.0020 Circumvention: Do not install or use a device or means that conceals or dilutesemissions, which would otherwise violate a federal or state air pollution control rule,without reducing the total amount of pollutant emitted.

10.0

CD Minn. R. 7007.0800, subps. 2 and16(J)

Air Pollution Control Equipment: Operate all pollution control equipment wheneverthe corresponding process equipment and emission units are operated, unlessotherwise noted in this permit.

11.0

CD Minn. R. 7007.0800, subps. 14and 16(J)

Operation and Maintenance Plan: Retain at the stationary source an operation andmaintenance plan for all air pollution control equipment. At a minimum, the O & Mplan shall identify all air pollution control equipment and control practices and shallinclude a preventative maintenance program for the equipment and practices, adescription of (the minimum but not necessarily the only) corrective actions to betaken to restore the equipment and practices to proper operation to meet applicablepermit conditions, a description of the employee training program for properoperation and maintenance of the control equipment and practices, and the recordskept to demonstrate plan implementation.

12.0




14 May, 2015 10:28Page 2 of 28

CD Minn. R. 7011.0150 Fugitive Emissions: Do not cause or permit the handling, use, transporting, orstorage of any material in a manner which may allow avoidable amounts ofparticulate matter to become airborne. Comply with all other requirements listed inMinn. R. 7011.0150.

13.0

CD Minn. R. 7030.0010 - 7030.0080 Noise: The Permittee shall comply with the noise standards set forth in Minn. R.7030.0010 to 7030.0080 at all times during the operation of any emission units.This is a state only requirement and is not enforceable by the EPA Administrator orcitizens under the Clean Air Act.

14.0

CD Minn. R. 7007.0800, subp. 9(A) Inspections: The Permittee shall comply with the inspection procedures andrequirements as found in Minn. R. 7007.0800, subp. 9(A).

15.0

CD Minn. R. 7007.0800, subp. 16 The Permittee shall comply with the General Conditions listed in Minn. R.7007.0800, subp. 16.

16.0

CD hdr PERFORMANCE TESTING17.0

CD Minn. R. ch. 7017 Performance Testing: Conduct all performance tests in accordance with Minn. R.ch. 7017 unless otherwise noted in Tables A and/or B.

18.0

CD Minn. R. 7017.2018; Minn. R.7017.2030, subps. 1-4, Minn. R.7017.2035, subps. 1-2

Performance Test Notifications and Submittals:

Performance Tests are due as outlined in Table A of the permit.See Table B for additional testing requirements.

Performance Test Notification (written): due 30 days before each Performance TestPerformance Test Plan: due 30 days before each Performance TestPerformance Test Pre-test Meeting: due 7 days before each Performance TestPerformance Test Report: due 45 days after each Performance TestPerformance Test Report - Microfiche Copy: due 105 days after each PerformanceTest

The Notification, Test Plan, and Test Report may be submitted in an alternativeformat as allowed by Minn. R. 7017.2018.

19.0

CD Minn. R. 7017.2025, subp. 3 Limits set as a result of a performance test (conducted before or after permitissuance) apply until superseded as stated in the MPCA's Notice of Complianceletter granting preliminary approval. Preliminary approval is based on formal reviewof a subsequent performance test on the same unit as specified by Minn. R.7017.2025, subp. 3. The limit is final upon issuance of a permit amendmentincorporating the change.

20.0

CD hdr MODELING REQUIREMENTS21.0

CD Title I Condition: 40 CFR Section52.21(k); Minn. R. 7007.3000;Minn. Stat. Section 116.07, subds.4a & 9; Minn. R. 7007.0100, subp.7(A), 7(L), & 7(M); Minn. R.7007.0800, subps. 1, 2 & 4; Minn.R. 7009.0010-7009.0080

Modeled Parameters for NOx, PM10, and PM2.5: The parameters used in NOx,PM10, and PM2.5 modeling for permit number 14700077-001 are listed inAppendix I of this permit. The parameters describe the operation of the facility atmaximum permitted capacity. The purpose of listing the parameters in the appendixis to provide a benchmark for future changes.

22.0


Equivalent or Better Dispersion (EBD) Modeling Triggers (Modeling Not Required)for NOx: Changes that do not require a permit amendment or that require a minoror administrative permit amendment do not trigger the EBD Modeling Submittalrequirement. The Permittee shall keep updated records on site of all modeled NOxparameters and emission rates listed in Appendix I. The Permittee shall submit anychanges to modeled NOx parameters and emission rates with the next requiredmodeling submittal.

23.0


EBD Modeling Triggers (Modeling Required) for NOx: Changes that require, orwould require, a moderate or major permit amendment due to an increase in NOxemissions and affect any modeled NOx parameter or emission rate listed inAppendix I, or an addition to the information documented in Appendix I, trigger theEBD Remodeling Submittal requirement. The Permittee shall include previouslymade changes to modeled NOx parameters and emission rates listed in Appendix Ithat did not previously trigger the EBD Modeling Submittal requirement with thismodeling submittal.

24.0


EBD Modeling Submittal for NOx: For changes meeting the criteria in the EBDModeling Triggers (Modeling Required) requirement, the Permittee shall submit anEBD modeling submittal in accordance with the current version of the MPCA AirDispersion Modeling Guidance and shall wait for written approval (for majoramendments, in the form of an issued permit amendment; for moderateamendments, in the form of a construction authorization letter) before making suchchanges.

25.0




14 May, 2015 10:28Page 3 of 28


EBD Modeling Submittal Content for NOx: The information submitted must include,for stack and vent sources, source emission rate, location, height, diameters, exitvelocity, exit temperature, discharge direction, use of rain caps or rain hats, and, ifapplicable, locations and dimensions of nearby buildings. For non-stack/ventsources, this includes the source emission rate, location, size and shape, releaseheight, and, if applicable, any emission rate scalars, and the initial lateraldimensions and initial vertical dimensions and adjacent building heights.

26.0


Outdated EBD Baseline Modeling for NOx: Prior to conducting the EBD analysis,the Permittee shall use the current version of the MPCA Air Dispersion ModelingGuidance to determine if the Baseline Modeling (the most recent refined modelingdemonstration) is outdated. If the Baseline Modeling is outdated, the Permitteeshall update the Baseline Modeling to be consistent with the current version of theMPCA Air Dispersion Modeling Guidance. The updated modeling will become thenew Baseline Modeling.

This requirement does not require the Permittee to complete a new refinedmodeling demonstration using the revisions made for the EBD demonstration.

27.0


EBD Modeling Results for NOx: The dispersion characteristics due to the revisionsof the information in Appendix I must be equivalent to or better than the dispersioncharacteristics modeled in Permit Action-001. The Permittee shall demonstrate thisequivalency in the proposal.

28.0

CD Title I Condition: 40 CFR Section52.21(k); Minn. R. 7007.3000;Minn. Stat. Section 116.07, subds.4a & 9; Minn. R. 7009.0020; Minn.R. 7007.0100, subp. 7(A), 7(L), &7(M); Minn. R. 7007.0800, subp. 2

Computer Dispersion Modeling Triggers for NOx: The Permittee shall conduct arefined remodeling analysis in accordance with the Computer Dispersion Modelingrequirements of this permit and the current version of the MPCA Air DispersionModeling Guidance if: (1) the results of the EBD modeling analysis do notdemonstrate equivalent or better dispersion characteristics; (2) a conclusion cannotreadily be made about the dispersion, or (3) the criteria in the EBD ModelingTriggers requirement are met and the Permittee has previously conducted threesuccessive EBD analyses using the same Baseline Modeling.

29.0

S/A Title I Condition: 40 CFR Section52.21(k); Minn. R. 7007.3000;Minn. Stat. Section 116.07, subds.4a & 9; Minn. R. 7009.0020; Minn.R. 7007.0100, subp. 7(A), 7(L), &7(M); Minn. R. 7007.0800, subp. 2

Computer Dispersion Modeling Protocol: due 180 days after receipt of writtenMPCA request for NOx refined modeling. The Permittee shall submit a ComputerDispersion Modeling Protocol that is complete and approvable by MPCA by thedeadline in this requirement. This protocol will describe the proposed modelingmethodology and input data, in accordance with the current version of the MPCAAir Dispersion Modeling Guidance.

30.0


Computer Dispersion Modeling Protocol: due 60 days after receipt of written MPCArequest for revisions to the submitted protocol for NOx modeling.

31.0


Computer Dispersion Modeling Results: due 180 days after receipt of written MPCAapproval Computer Dispersion Modeling Results: due 180 days after receipt ofComputer Dispersion Modeling Protocol for NOx. The Permittee shall submit a finalComputer Dispersion Modeling Report that is complete and approvable by MPCAby the deadline in this requirement. The submittal shall adhere to the currentversion of the MPCA Air Dispersion Modeling Guidance and the approvedComputer Dispersion Modeling Protocol.

32.0

CD hdr MONITORING REQUIREMENTS33.0

CD Minn. R. 7007.0800, subp. 4(D) Monitoring Equipment Calibration - The Permittee shall either:

1. Calibrate or replace required monitoring equipment every 12 months; or2. Calibrate at the frequency stated in the manufacturer's specifications.

For each monitor, the Permittee shall maintain a record of all calibrations, includingthe date conducted, and any corrective action that resulted. The Permittee shallinclude the calibration frequencies, procedures, and manufacturer's specifications(if applicable) in the Operations and Maintenance Plan. Any requirements applyingto continuous emission monitors are listed separately in this permit.

34.0




14 May, 2015 10:28Page 4 of 28

CD Minn. R. 7007.0800, subp. 4(D) Operation of Monitoring Equipment: Unless otherwise noted in this permit,monitoring a process or control equipment connected to that process is notnecessary during periods when the process is shutdown, or during checks of themonitoring systems, such as calibration checks and zero and span adjustments. Ifmonitoring records are required, they should reflect any such periods of processshutdown or checks of the monitoring system.

35.0

CD hdr RECORDKEEPING36.0

CD Minn. R. 7007.0800, subp. 5(C) Recordkeeping: Retain all records at the stationary source, unless otherwisespecified within this permit, for a period of five (5) years from the date of monitoring,sample, measurement, or report. Records which must be retained at this locationinclude all calibration and maintenance records, all original recordings forcontinuous monitoring instrumentation, and copies of all reports required by thepermit. Records must conform to the requirements listed in Minn. R. 7007.0800,subp. 5(A).

37.0

CD Minn. R. 7007.0800, subp. 5(B) Recordkeeping: Maintain records describing any insignificant modifications (asrequired by Minn. R. 7007.1250, subp. 3) or changes contravening permit terms (asrequired by Minn. R. 7007.1350, subp. 2), including records of the emissionsresulting from those changes.

38.0

CD Minn. R. 7007.1200, subp. 4 If the Permittee determines that no permit amendment or notification is requiredprior to making a change, the Permittee must retain records of all calculationsrequired under Minn. R. 7007.1200. For expiring permits, these records shall bekept for a period of five years from the date the change was made or until permitreissuance, whichever is longer. The records shall be kept at the stationary sourcefor the current calendar year of operation and may be kept at the stationary sourceor office of the stationary source for all other years. The records may be maintainedin either electronic or paper format.

39.0

CD hdr REPORTING/SUBMITTALS40.0

CD Minn. R. 7019.1000, subp. 3 Shutdown Notifications: Notify the Commissioner at least 24 hours in advance of aplanned shutdown of any control equipment or process equipment if the shutdownwould cause any increase in the emissions of any regulated air pollutant. If theowner or operator does not have advance knowledge of the shutdown, notificationshall be made to the Commissioner as soon as possible after the shutdown.However, notification is not required in the circumstances outlined in Items A, Band C of Minn. R. 7019.1000, subp. 3.

At the time of notification, the owner or operator shall inform the Commissioner ofthe cause of the shutdown and the estimated duration. The owner or operator shallnotify the Commissioner when the shutdown is over.

41.0

CD Minn. R. 7019.1000, subp. 2 Breakdown Notifications: Notify the Commissioner within 24 hours of a breakdownof more than one hour duration of any control equipment or process equipment ifthe breakdown causes any increase in the emissions of any regulated air pollutant.The 24-hour time period starts when the breakdown was discovered or reasonablyshould have been discovered by the owner or operator. However, notification is notrequired in the circumstances outlined in Items A, B and C of Minn. R. 7019.1000,subp. 2.

At the time of notification or as soon as possible thereafter, the owner or operatorshall inform the Commissioner of the cause of the breakdown and the estimatedduration. The owner or operator shall notify the Commissioner when the breakdownis over.

42.0

CD Minn. R. 7019.1000, subp. 1 Notification of Deviations Endangering Human Health or the Environment: As soonas possible after discovery, notify the Commissioner or the state duty officer, eitherorally or by facsimile, of any deviation from permit conditions which could endangerhuman health or the environment.

43.0

CD Minn. R. 7019.1000, subp. 1 Notification of Deviations Endangering Human Health or the Environment Report:Within 2 working days of discovery, notify the Commissioner in writing of anydeviation from permit conditions which could endanger human health or theenvironment. Include the following information in this written description:1. The cause of the deviation;2. The exact dates of the period of the deviation, if the deviation has been corrected3. Whether or not the deviation has been corrected;4. The anticipated time by which the deviation is expected to be corrected, if not yetcorrected; and5. Steps taken or planned to reduce, eliminate, and prevent reoccurrence of thedeviation.

44.0




14 May, 2015 10:28Page 5 of 28

S/A Minn. R. 7007.0800, subp. 6(A)(2) Semiannual Deviations Report: due 30 days after end of each calendar half-yearfollowing Permit Issuance. The first semiannual report submitted by the Permitteeshall cover the calendar half-year in which the permit is issued. The first report ofeach calendar year covers January 1 - June 30. The second report of eachcalendar year covers July 1 - December 31. If no deviations have occurred, thePermittee shall submit the report stating no deviations.

45.0

CD Minn. R. 7007.1150 - 7007.1500 Application for Permit Amendment: If a permit amendment is needed, submit anapplication in accordance with the requirements of Minn. R. 7007.1150 throughMinn. R. 7007.1500. Submittal dates vary, depending on the type of amendmentneeded.

46.0

S/A Minn. R. 7007.0400, subp. 2 Application for Permit Reissuance: due 180 days before expiration of ExistingPermit No. 14700077-001.

47.0

CD Minn. R. 7007.1400, subp. 1(H) Extension Requests: The Permittee may apply for an Administrative Amendment toextend a deadline in a permit by no more than 120 days, provided the proposeddeadline extension meets the requirements of Minn. R. 7007.1400, subp. 1(H).Performance testing deadlines from the General Provisions of 40 CFR pt. 60 andpt. 63 are examples of deadlines for which the MPCA does not have authority togrant extensions and therefore do not meet the requirements of Minn. R.7007.1400, subp. 1(H).

48.0

S/A Minn. R. 7007.0800, subp. 6(B) Report: due 30 days before end of each calendar half-year following PermitIssuance The Compliance Schedule Progress Report shall contain the informationspecified in Minn. R. 7007.0800, subp. 6(B) and shall be submitted on a formapproved by the Commissioner in accordance with the Compliance Schedulecontained in Table C. Progress Reports will not be needed upon completion of allactivities contained in the Compliance Schedule.

49.0

S/A Minn. R. 7007.0800, subp. 6(C) Compliance Certification: due 31 days after end of each calendar year followingPermit Issuance (for the previous calendar year). The Permittee shall submit this tothe Commissioner on a form approved by the Commissioner. This report covers alldeviations experienced during the calendar year.

50.0

CD Minn. R. 7019.3000 - 7019.3100 Emission Inventory Report: due on or before April 1 of each calendar year followingpermit issuance, to be submitted on a form approved by the Commissioner.

51.0

CD Minn. R. 7002.0005 - 7002.0095 Emission Fees: due 30 days after receipt of an MPCA bill.52.0




14 May, 2015 10:28Page 6 of 28

Subject Item: GP 001 Natural Gas Engines

Associated Items: EU 001 Engine No. 1 - Reciprocating IC Engine

EU 002 Engine No. 2 - Reciprocating IC Engine



NC/CA


CD hdr ENGINE SHAKEDOWN PERIOD REQUIREMENTS1.0

CD Title I Condition: Avoid majorsource under 40 CFR52.21(b)(1)(i) and Minn. R.7007.3000

The engine generator shakedown period for each individual GP 001 engine (EUs001 - 004) is defined as the period of time commencing on the date of initial startupof the engine and terminating on the date that the engine engages in commercialdispatch or 180 days after the start of that engine's shakedown period, whichever isearlier. Commercial dispatch occurs when the Midwest Independent SystemOperator is notified that the engine is available for commercial electric powergeneration.

2.0

CD Minn. Stat. Section 116.07, subps.4a & 9; Minn. R. 7007.0100,subps. 7A, 7L, & 7M; Minn. R.7007.0800, subps. 1, 2, & 4; Minn.R. 7009.0010-7009.0080

No more than two GP 001 engines may be operated simultaneously during theengine shakedown period.

3.0

CD Minn. R. 7007.0800, subp. 2 Control Equipment Operation During Engine Shakedown Period: Operation ofcontrol equipment is not required during the engine shakedown period, but shall beinitiated prior to the commencement of normal operation.

This requirement applies individually to EU 001, EU 002, EU 003, and EU 004.

4.0

CD Minn. R. 7007.0800, subps. 4 and5

The Permittee shall maintain records of engine usage and the natural gasconsumption upon initial startup of each engine. The GP 001 heat input limit andcorresponding recordkeeping requirements shall be applicable at all times,including the engine shakedown period.

5.0

CD hdr OPERATIONAL REQUIREMENTS6.0

LIMIT Title I Condition: Avoid majorsource under 40 CFR52.21(b)(1)(i) and Minn. R.7007.3000; Minn. R. 7007.0800,subps. 4 and 5

Heat Input: less than or equal to 1321854 million Btu/year of natural gas based ona 12-month rolling sum to be calculated by the 15th day of each month.

This requirement applies to the combined heat input to EU 001, EU 002, EU 003,and EU 004.

7.0

CD Minn. Stat. Section 116.07, subps.4a & 9; Minn. R. 7007.0100,subps. 7A, 7L, & 7M; Minn. R.7007.0800, subps. 1, 2, & 4; Minn.R. 7009.0010-7009.0080

Minimum Stack Height: The Permittee shall not install and vent emissions througha stack on any GP 001 engine that is less than 99 feet above grade.

8.0

CD Minn. R. 7007.0800, subp. 2 Fuel type: Pipeline natural gas only, by design.9.0

CD 40 CFR Section 72.7(f)(4)(i); Minn.R. 7007.1075

An exempt unit shall be treated as an affected unit under the Acid Rain Program onthe earliest of the following dates:

1) The date on which the unit first serves one or more generators with totalnameplate capacity in excess of 25 MWe;2) The date on which the unit burns any coal or coal derived fuel except forcoal-derived gaseous fuel with a total sulfur content no greater than natural gas; or3) January 1 of the year following the year in which the annual average sulfurcontent for nongaseous fuel burned at the unit exceeds 0.050 percent by weight (asdetermined under 40 CFR Section 72.7(d)).

10.0

CD 40 CFR Section 72.7(f)(3); Minn.R. 7007.1075

For a period of 5 years from the date the records are created, the Permittee shallretain at the source records demonstrating that the requirements of 40 CFR Section72.7(a) are met. The 5-year period for keeping records may be extended for cause,at any time prior to the end of the period, in writing by the Administrator or thepermitting authority. Such records shall include, for each delivery of fuel to the unit,the type of fuel, the sulfur content, and the sulfur content of each sample taken.The Permittee bears the burden of proof that the requirements of 40 CFR Section72.7(a) are met.

11.0

CD hdr PERFORMANCE TESTING REQUIREMENTS12.0




14 May, 2015 10:28Page 7 of 28

S/A Title I Condition: Avoid majorsource under 40 CFR52.21(b)(1)(i) and Minn. R.7007.3000

Initial Performance Test: due 180 days after Initial Startup of the first GP 001engine, or after the first GP 001 engine commences normal operation (terminatesthe engine shakedown period), whichever comes first, to evaluate the NOxemission factor of 29.64 lb/hr.

All four engines shall be tested. The performance test shall be conducted at worstcase conditions as defined at Minn. R. 7017.2005, subp. 8, using EPA ReferenceMethod 7E or 20, or another method approved by MPCA in the performance testplan approval.

Refer to Total Facility Performance Test Notifications and Submittals for additionalperformance testing requirements.

13.0


Protocol for Re-Setting the Emission Factor Used For Calculating NOx Emissions:The Permittee shall report the test result in pounds per hour (lb/hr) in theperformance test report required by Minn. R. 7017.2035, subp. 1.

The emission factor used for calculating NOx emissions shall be re-set to the3-hour average emission rate in lb/hr, measured during the most recentMPCA-approved NOx emission factor performance test.

The new emission factor used for calculating NOx emissions determined using thisProtocol shall be effective upon receipt of the Notice of Compliance (NOC) letterthat approves the test results and shall be incorporated into the permit during thenext permit amendment.

14.0

CD Minn. R. 7007.1500, subp. 1 The Permittee must apply for and obtain a major permit amendment if thePermittee wishes to deviate from the Protocol for Re-setting the Emission FactorUsed for Calculating NOx Emissions established by this permit.

15.0

CD Minn. R. 7017.2025 Notwithstanding the Protocol detailed above, the MPCA reserves the right to setoperational limits and requirements as allowed under Minn. R. 7017.2025. If theMPCA sets limits, the new limits shall be implemented upon receipt of the NOCletter that notifies the Permittee of preliminary approval. The limits set according toMinn. R. 7017.2025 are final upon issuance of a permit amendment incorporatingthe change.

16.0

CD hdr RECORDKEEPING REQUIREMENTS17.0


Heat Input Calculation: By the 15th day of each month, the Permittee shall:

1) Record the natural gas consumption in cubic feet for EU 001, EU 002, EU 003,and EU 004 individually for the previous month. Using the energy content (Btu/ft3)provided by the natural gas supplier (if available) or the default value of 1028Btu/ft3, the Permittee shall convert this value to MMBtu. This provides the heatinput for each emission unit for the month.

2) Sum the total heat input to each individual emission unit (EU 001, EU 002, EU003, and EU 004) for the most recent 12 months. This provides the 12-monthrolling sum heat input for each emission unit.

3) Sum the 12-month rolling sum total heat inputs for EU 001, EU 002, EU 003,and EU 004.

18.0




14 May, 2015 10:28Page 8 of 28

Subject Item: GP 002 Oxidation Catalysts

Associated Items: CE 001 Catalytic Oxidizer

CE 002 Catalytic Oxidizer



NC/CA


CD Minn. R. 7007.0800, subp. 2 The following requirements of GP 002 apply individually to CE 001, CE 002, CE003, and CE 004.

1.0

CD hdr MONITORING AND RECORDKEEPING2.0

CD Minn. R. 7007.0800, subp. 4 Monitoring Equipment: The Permittee shall install and maintain thermocouples formeasuring the temperatures as required by this permit. The monitoring equipmentmust be installed, in use, and properly maintained whenever the monitored controlequipment is required to be operated.

3.0

CD 40 CFR Section 63.6600(b); 40CFR pt. 63, subp. ZZZZ, Table2b(2.a); Minn. R. 7011.8150;Minn. R. 7007.0800, subps. 4 and5

The Permittee shall maintain and operate thermocouple monitoring devices thatcontinuously indicate and record both the inlet and outlet temperatures of eachcatalytic oxidizer. Each monitoring device shall have a margin of error less than thegreater of +/- 0.75 percent of the temperature being measured or +/- 4.5 degreesFahrenheit. The recording devices shall also calculate the three-hour rolling averageinlet temperatures.

4.0


Daily Monitoring: The Permittee shall physically verify the operation of eachtemperature recording device at least once each operating day to verify that it isworking and recording properly. The Permittee shall maintain a written record of thedaily verifications.

5.0

CD Minn. R. 7007.0800, subps. 4, 5,and 14

Monthly Monitoring: At least once each month during normal operation, thePermittee shall record the temperature rise across each catalyst (outlet temp. - inlettemp.) while the process is running. If it is determined that the catalyst reactivityhas been impaired, by comparison of the observed temperature rise to the pasttemperature rise records, the Permittee shall follow the corrective actions in theOperation and Maintenance Plan. The Permittee shall maintain written records ofthe monitoring and any corrective actions taken.

6.0


Quarterly Inspections: At least once per calendar quarter, or more frequently ifrequired by the manufacturer specifications, the Permittee shall inspect the controlequipment internal and external system components, including but not limited to therefractories, heat exchangers, and electrical systems. The Permittee shall maintaina written record of the inspection and any corrective actions taken resulting fromthe inspection.

7.0


Annual Calibration: The Permittee shall calibrate each temperature monitor at leastannually and shall maintain a written record of the calibration and any actionresulting from the calibration.

8.0


For periods when the catalytic oxidizer is operated above the minimum inlettemperature, the Permittee shall use either one of the following when completingcalculations as required elsewhere in this permit:

The overall CO control efficiency limit specified in this permit for this equipment(93.0%); or the overall control efficiency determined during the most recent MPCAapproved performance test. If the tested efficiency is less than the efficiency limit inthis permit, the Permittee must use the tested value in all calculations until theefficiency is demonstrated to be above the permit limit through a new test.

9.0


Corrective Actions: If the temperature is below the minimum specified by this permitor if a catalytic oxidizer or any of its components are found during the inspections toneed repair, the Permittee shall take corrective action as soon as possible.Corrective actions shall return the temperature to at least the permitted minimumand/or include completion of necessary repairs identified during the inspection, asapplicable. Corrective actions include, but are not limited to, those outlined in theO&M Plan for the catalytic oxidizers. The Permittee shall keep a record of the typeand date of any corrective action taken.

10.0

CD Minn. R. 7007.0800, subp. 14 The Permittee shall operate and maintain each catalytic oxidizer in accordance withthe Operation and Maintenance (O & M) Plan. The Permittee shall keep copies ofthe O & M Plan available onsite for use by staff and MPCA staff.

11.0

CD hdr NESHAP SUBPART ZZZZ REQUIREMENTS12.0




14 May, 2015 10:28Page 9 of 28

CD 40 CFR Section 63.6630(a); 40CFR pt. 63, subp. ZZZZ, Table5(1); Minn. R. 7011.8150

The Permittee shall demonstrate initial compliance with the requirements of 40CFR pt. 63, subp. ZZZZ by:

1) Reducing the average emissions of CO by 93.0% or greater, as determinedfrom the initial performance tests;2) Installing CPMS to continuously monitor catalyst inlet temperatures according tothe requirements of 40 CFR Section 63.6625(b); and3) Recording the catalyst pressure drops and catalyst inlet temperatures during theinitial performance tests.

See Total Facility and Control Equipment requirements for further performancetesting procedures.

13.0

CD 40 CFR Section 63.6620(e); Minn.R. 7011.8150

The Permittee shall determine compliance with the percent reduction requirementaccording to the procedures in 40 CFR Section 63.6620(e)(1) and as described inAppendix B of this permit.

The Permittee shall normalize the carbon monoxide concentrations at the inlet andoutlet of the control device to a dry basis and to 15 percent oxygen, or anequivalent percent carbon dioxide. If pollutant concentrations are to be corrected to15 percent oxygen and carbon dioxide concentration is measured in lieu of oxygenconcentration measurement, a carbon dioxide correction factor is needed. ThePermittee shall calculate the carbon dioxide correction factor as described inparagraphs (e)(2)(i) through (iii) of 40 CFR Section 63.6620 and in Appendix B ofthis permit.

14.0

CD 40 CFR Section 63.7(e); Minn. R.7017.2015

Performance tests shall be conducted under normal operating conditions.Operations during periods of startup, shutdown, and malfunction shall not constituterepresentative conditions for the purpose of a performance test, nor shall emissionsin excess of the level of the relevant standard during periods of startup, shutdown,and malfunction be considered a violation of the relevant standard.

15.0

CD 40 CFR Section 63.6620(b); Minn.R. 7011.8150

Each performance test must be conducted according to the requirements of 40CFR pt. 63, subp. ZZZZ, Table 4. If you own or operate a non-operationalstationary RICE that is subject to performance testing, you do not need to start upthe engine solely to conduct the performance test. Owners and operators of anon-operational engine can conduct the performance test when the engine isstarted up again. The test must be conducted at any load condition within plus orminus 10 percent of 100 percent load.

16.0

CD 40 CFR Section 63.6620(i); Minn.R. 7011.8150

The engine percent load during a performance test shall be determined bydocumenting the calculations, assumptions, and measurement devices used tomeasure or estimate the percent load in a specific application. A written report ofthe average percent load determination shall be included in the notification ofcompliance status. The following information shall be included in the written report:the engine model number, the engine manufacturer, the year of purchase, themanufacturer's site-rated brake horsepower, the ambient temperature, pressure,and humidity during the performance test, and all assumptions that were made toestimate or calculate percent load during the performance test shall be clearlyexplained. If measurement devices such as flow meters, kilowatt meters, betaanalyzers, strain gauges, etc. are used, the model number of the measurementdevice and an estimate of its accuracy in percentage of true value shall beprovided.

17.0

CD 40 CFR Section 63.7(c); Minn. R.7017.2015

Performance testing quality assurance program and submission of site-specific testplan: Before conducting a required performance test, the Permittee shall developand, if requested by the Administrator, shall submit a site-specific test plan to theAdministrator for approval. The test plan shall include a test program summary, thetest schedule, data quality objectives, and both an internal and external qualityassurance (QA) program. Data quality objectives are the pretest expectations ofprecision, accuracy, and completeness of data.

18.0




14 May, 2015 10:28Page 10 of 28

Subject Item: EU 001 Engine No. 1 - Reciprocating IC Engine


GP 001 Natural Gas Engines

SV 001 Engine No. 1

NC/CA


S/A 40 CFR Section 60.7(a)(3); 40CFR Section 60.4245(d); 40 CFRSection 63.6590(c); Minn. R.7011.8150

Notification of the Actual Date of Initial Startup: due 15 days after Initial Startup ofEU 001. This is the day that emissions are first generated and commences theshakedown period of EU 001. See GP 001 for further shakedown periodrequirements.

1.0

CD hdr STARTUP AND SHUTDOWN REQUIREMENTS2.0

CD 40 CFR Section 63.6625(h); Minn.R. 7011.8150

The Permittee shall minimize the engine's time spent at idle and minimize theengine's startup time to a period needed for appropriate and safe loading of theengine, not to exceed 30 minutes, after which time the non-startup emissionlimitations and standards apply.

3.0

CD Minn. R. 7007.0800, subp. 2 Control Equipment Operation During Startup and Shutdown: Operation of controlequipment is not required during EU 001 startup but shall be initiated prior to theoxidation catalyst (CE 001) outlet duct gas temperature reaching 450 degrees F, orwithin 30 minutes of commencing operation, whichever comes first. Duringshutdown, the control equipment shall continue to operate as long as is physicallypossible.

4.0

CD 40 CFR Section 60.7(b); 40 CFRSection 60.4245(d); Minn. R.7011.8150

Maintain records of the occurrence and duration of any startup, shutdown, ormalfunction on the operation of the unit, any malfunction of air pollution controlequipment, or any periods during which a continuous monitoring system ormonitoring device is inoperative.

5.0

CD hdr EMISSION LIMITS6.0

LIMIT Minn. R. 7011.2300, subp. 1 Opacity: less than or equal to 20 percent once operating temperatures have beenattained.

7.0

LIMIT Minn. R. 7011.2300, subp. 2 Sulfur Dioxide: less than or equal to 0.50 lbs/million Btu heat input .

Compliance with this limit is demonstrated by the use of pipeline natural gas.

8.0

LIMIT 40 CFR Section 60.4233(e); 40CFR pt. 63, subp. JJJJ, Table 1;Minn. R. 7011.8150

Nitrogen Oxides: less than or equal to 1.0 grams/horsepower-hour or 82 parts permillion volumetric dry (ppmvd) at 5% oxygen.

9.0


Volatile Organic Compounds: less than or equal to 0.70 grams/horsepower-hour or60 ppmvd at 15% oxygen.

10.0

CD hdr NSPS SUBPART JJJJ REQUIREMENTS11.0

CD 40 CFR Section 60.4243(b)(2)(ii) The Permittee shall keep a maintenance plan and records of conductedmaintenance and shall, to the extent practicable, maintain and operate the enginein a manner consistent with good air pollution control practice for minimizingemissions. In addition, the Permittee shall conduct an initial performance test andconduct subsequent performance testing every 8760 hours of operation or 3 years,whichever comes first, thereafter to measure NOx and VOC emissions. The testingshall follow the procedures in 40 CFR Section 60.4244, as applicable.

12.0

S/A 40 CFR Section 60.8; 40 CFRSection 60.4245(d); Minn. R.7011.8150

Initial Performance Test: due 180 days after Initial Startup of EU 001 to determinecompliance with the Nitrogen Oxides emission limitation.

The performance test shall be conducted at worst case conditions as defined atMinn. R. 7017.2005, subp. 8, using EPA Reference Method 7E or 20, or anothermethod approved by MPCA in the performance test plan approval.

13.0


Initial Performance Test: due 180 days after Initial Startup of EU 001 to determinecompliance with the VOC emission limitation.

The performance test shall be conducted at worst case conditions as defined atMinn. R. 7017.2005, subp. 8, using EPA Reference Method 25, or another methodapproved by MPCA in the performance test plan approval.

14.0

CD 40 CFR Section 60.4243(b)(2)(ii);Minn. R. 7017.2020, subp. 1

Conduct subsequent performance testing every 8760 operating hours or threeyears (whichever comes first) thereafter, to measure NOx and VOC emissions.

15.0




14 May, 2015 10:28Page 11 of 28

CD 40 CFR Sections 60.4244(a) - (g);Minn. R. 7011.8150

Each performance test shall be conducted within 10 percent of 100 percent peak(or the highest achievable) load and according to the requirements in 40 CFRSection 60.8 and under the specific conditions that are specified by Table 2 of 40CFR pt. 60, subp. JJJJ.

The performance tests shall not be conducted during periods of startup, shutdown,or malfunction, as specified in 40 CFR Section 60.8(c). If the stationary SI internalcombustion engine is non-operational, you do not need to startup the engine solelyto conduct a performance test; however, you shall conduct the performance testimmediately upon startup of the engine.

Each performance test shall consist of three separate test runs, as specified in 40CFR Section 60.8(f). Each test run shall be conducted within 10 percent of 100percent peak (or the highest achievable) load and last at least 1 hour. ThePermittee shall use the equations in Appendix C of this permit to calculate theemission rates from performance test data.

16.0

CD 40 CFR Section 60.4245(d); Minn.R. 7011.8150

The Permittee shall submit a copy of each performance test as conducted in 40CFR Section 60.4244 within 60 days after the test has been completed.

17.0




14 May, 2015 10:28Page 12 of 28




SV 002 Engine No. 2

NC/CA




1.0



The Permittee shall minimize the engine's time spent at idle and minimize theengine's startup time to a period needed for appropriate and safe loading of theengine, not to exceed 30 minutes, after which time the non-startup emissionlimitations and standards apply.

3.0


4.0



5.0



7.0



8.0



9.0



10.0


CD 40 CFR Section 60.4243(b)(2)(ii);Minn. R. 7011.8150

The Permittee shall keep a maintenance plan and records of conductedmaintenance and shall, to the extent practicable, maintain and operate the enginein a manner consistent with good air pollution control practice for minimizingemissions. In addition, the Permittee shall conduct an initial performance test andconduct subsequent performance testing every 8760 hours of operation or 3 years,whichever comes first, thereafter to measure NOx and VOC emissions. The testingshall follow the procedures in 40 CFR Section 60.4244, as applicable.

12.0




13.0




14.0

CD 40 CFR Section 60.4243; Minn. R.7017.2020, subp. 1; Minn. R.7011.8150


15.0




14 May, 2015 10:28Page 13 of 28




Each performance test shall consist of three separate test runs, as specified in 40CFR Section 60.8(f). Each test run shall be conducted within 10 percent of 100percent peak (or the highest achievable) load and last at least 1 hour. ThePermittee shall use the equations in Appendix C to calculate the emission ratesfrom performance test data.

16.0



17.0




14 May, 2015 10:28Page 14 of 28




SV 003 Engine No. 3

NC/CA




1.0



The Permittee shall minimize the engine's time spent at idle and minimize theengine's startup time at startup to a period needed for appropriate and safe loadingof the engine, not to exceed 30 minutes, after which time the non-startup emissionlimitations and standards apply.

3.0


4.0


Maintain records of the occurrence and duration of any startup, shutdown, ormalfunction on the operation of the engine, any malfunction of air pollution controlequipment, or any periods during which a continuous monitoring system ormonitoring device is inoperative.

5.0



7.0

LIMIT Minn. R. 7011.2300, subp. 2 Sulfur Dioxide: less than or equal to 0.50 lbs/million Btu heat inputCompliance with this limit is demonstrated by the use of pipeline natural gas.

8.0



9.0



10.0


CD 40 CFR Section 60.4243(b)(2)(ii) The Permittee shall keep a maintenance plan and records of conductedmaintenance and shall, to the extent practicable, maintain and operate the enginein a manner consistent with good air pollution control practice for minimizingemissions. In addition, the Permittee shall conduct an initial performance test andconduct subsequent performance testing every 8760 hours of operation or 3 years,whichever comes first, thereafter to measure NOx and CO emissions. The testingshall follow the procedures in 40 CFR Section 60.4244, as applicable.

12.0




13.0




14.0

CD 40 CFR Section 60.4243; Minn. R.7017.2020, subp. 1


15.0




14 May, 2015 10:28Page 15 of 28





16.0



17.0




14 May, 2015 10:28Page 16 of 28




SV 004 Engine No. 4

NC/CA




1.0



The Permittee shall minimize the engine's time spent at idle and minimize theengine's startup time at startup to a period needed for appropriate and safe loadingof the engine, not to exceed 30 minutes, after which time the non-startup emissionlimitations and standards apply.

3.0


4.0



5.0



7.0



8.0



9.0



10.0


CD 40 CFR Section 60.4243(b)(2)(ii) The Permittee shall keep a maintenance plan and records of conductedmaintenance and shall, to the extent practicable, maintain and operate the enginein a manner consistent with good air pollution control practice for minimizingemissions. In addition, the Permittee shall conduct an initial performance test andconduct subsequent performance testing every 8760 hours of operation or 3 years,whichever comes first, thereafter to measure NOx and VOC emissions. The testingshall follow the procedures in 40 CFR Section 60.4244, as applicable.

12.0




13.0




14.0

CD 40 CFR Section 60.4243; Minn. R.7017.2020, subp. 1


15.0




14 May, 2015 10:28Page 17 of 28





16.0



17.0




14 May, 2015 10:28Page 18 of 28

Subject Item: EU 005 Engine No. 5 (Emergency) Reciprocating IC Engine

Associated Items: SV 005 Engine No. 5

NC/CA



1.0

LIMIT Minn. R. 7011.2300, subp. 2 Sulfur Dioxide: less than or equal to 0.50 lbs/million Btu heat input . The potential toemit from this unit is 0.00152 lbs/MMBtu due to equipment design and allowablefuels.

2.0

CD hdr OPERATING REQUIREMENTS3.0

LIMIT Title I Condition: Avoid majorsource under 40 CFR52.21(b)(1)(i) and Minn. R.7007.3000

Operating Hours: less than or equal to 100 hours/year using 12-month Rolling Sumto be calculated by the 15th day of each month.

4.0

CD Minn. R. 7007.0100, subp. 35a Permitted Fuel type: Diesel fuel only5.0

LIMIT 40 CFR Section 60.4207(b); 40CFR Section 80.510(b); Minn. R.7011.2305

Sulfur Content of Fuel: less than or equal to 15 parts per million by weight. Dieselfuel shall meet the requirements of 40 CFR Section 80.510(b). Diesel fuel shallhave a maximum annual average sulfur content of 0.0015 percent or 15 parts permillion by weight, and either a minimum cetane index of 40 or a maximum aromaticcontent of 35 volume percent.

6.0

CD hdr 40 CFR PT. 60, SUBP. IIII REQUIREMENTS7.0

CD 40 CFR Section 60.4206; Minn. R.7011.2305; Minn. R. 7011.8150

The Permittee shall operate and maintain EU 005 so that it achieves theseemission limits over the entire life of the engine.

8.0

CD 40 CFR Section 60.4205(b); 40CFR Section 60.4202(a)(2); 40CFR Section 89.113(a); Minn. R.7011.2305

Exhaust opacity shall not exceed:

1) 20 percent during the acceleration mode;2) 15 percent during the lugging mode; and3) 50 percent during the peaks in either the acceleration or lugging modes.

9.0

LIMIT 40 CFR Section 60.4205(b); 40CFR Section 60.4202(a)(2); 40CFR Section 89.112(a); Minn. R.7011.2305

Carbon Monoxide: less than or equal to 3.5 grams/kilowatt-hour .10.0


NMHC+NOx: less than or equal to 6.4 grams/kilowatt-hour11.0


Total Particulate Matter: less than or equal to 0.20 grams/kilowatt-hour12.0

CD 40 CFR Section 60.4206; 40 CFRSection 60.4211(a); Minn. R.7011.2305

The Permittee shall operate and maintain the engine according to themanufacturer's written instructions or procedures developed by the Permittee thatare approved by the engine manufacturer, over the entire life of the engine. ThePermittee shall only change those settings that are permitted by the manufacturer.The Permittee shall also meet the requirements of 40 CFR pts. 89, 94 and/or 1068,as applicable.

13.0

CD 40 CFR Section 60.4211(c); Minn.R. 7011.2305

The Permittee shall demonstrate compliance by purchasing an engine certified toconform with the emission standards listed in the emission limits above for thesame model year and maximum engine power. The engine shall be installed andconfigured according to manufacturer's specifications.

14.0

CD 40 CFR Section 60.4211(f); Minn.R. 7011.2305

The Permittee shall operate the emergency stationary ICE according to therequirements in 40 CFR Section 60.4211(f)(2) through (3). In order for the engine tobe considered an emergency stationary ICE under 40 CFR pt. 60, subp. IIII, anyoperation other than emergency operation, maintenance and testing, emergencydemand response, and operation in non-emergency situations for 50 hours peryear, as described below, is prohibited. If the Permittee does not operate theengine according to the requirements in 40 CFR Section 60.4211(f)(2) through (3),the engine shall not be considered an emergency engine under 40 CFR pt. 60,subp. IIII and shall meet all requirements for non-emergency engines.

15.0




14 May, 2015 10:28Page 19 of 28

LIMIT 40 CFR Section 60.4211(f)(2);Minn. R. 7011.2305

Operating Hours: less than or equal to 100 hours/year for any combination of thepurposes specified in paragraphs 40 CFR Section 60.4211(f)(2)(i)through (iii). Anyoperation for non-emergency situations as allowed by 40 CFR Section60.4211(f)(3) counts as part of the 100 hours per calendar year allowed by thispermit as well as 40 CFR Section 60.4211(f)(3).

16.0

LIMIT 40 CFR Section 60.4211(f)(3);Minn. R. 7011.2305

Operating Hours: less than or equal to 50 hours/year in non-emergency situations.The 50 hours of operation in non-emergency situations are counted as part of the100 hours per calendar year limit provided in this permit. Except as provided in 40CFR Section 60.4211(f)(3)(i), the 50 hours per calendar year for non-emergencysituations cannot be used for peak shaving or non-emergency demand response,or to generate income for a facility to an electric grid or otherwise supply power aspart of a financial arrangement with another entity.

17.0

CD 40 CFR Section 60.4211(f)(2)(i);Minn. R. 7011.2305

Emergency stationary ICE may be operated for maintenance checks and readinesstesting, provided that the tests are recommended by federal, state or localgovernment, the manufacturer, the vendor, the regional transmission organizationor equivalent balancing authority and transmission operator, or the insurancecompany associated with the engine. Any such usage shall be counted in the12-month Rolling Sum Operating Hours Limit for EU 005.

18.0

CD 40 CFR Section 60.4211(f)(2)(ii);Minn. R. 7011.2305

Emergency stationary ICE may be operated for emergency demand response forperiods in which the Reliability Coordinator under the North American ElectricReliability Corporation (NERC) Reliability Standard EOP-002-3, Capacity andEnergy Emergencies (incorporated by reference, see 40 CFR Section 60.17), orother authorized entity as determined by the Reliability Coordinator, has declaredan Energy Emergency Alert Level 2 as defined in the NERC Reliability StandardEOP-002-3.

19.0

CD 40 CFR Section 60.4211(f)(2)(iii);Minn. R. 7011.2305

Emergency stationary ICE may be operated for periods where there is a deviationof voltage or frequency of 5 percent or greater below standard voltage or frequency.

20.0


The 50 hours per year for non-emergency situations can be used to supply poweras part of a financial arrangement with another entity if all of the followingconditions are met:1) The engine is dispatched by the local balancing authority or local transmissionand distribution system operator;2) The dispatch is intended to mitigate local transmission and/or distributionlimitations so as to avert potential voltage collapse or line overloads that could leadto the interruption of power supply in a local area or region.3) The dispatch follows reliability, emergency operation or similar protocols thatfollow specific NERC, regional, state, public utility commission or local standardsor guidelines.

(continued below)

21.0


(continued from above)4) The power is provided only to the facility itself or to support the localtransmission and distribution system.

5) The Permittee identifies and records the entity that dispatches the engine andthe specific NERC, regional, state, public utility commission or local standards orguidelines that are being followed for dispatching the engine. The local balancingauthority or local transmission and distribution system operator may keep theserecords on behalf of the Permittee.

22.0

CD hdr RECORDKEEPING REQUIREMENTS23.0

CD Title I Condition: Avoid majorsource under 40 CFR52.21(b)(1)(i) and Minn. R.7007.3000; 40 CFR Section60.4209; Minn. R. 7011.2305

The engine shall contain a non-resettable hour meter prior to startup of engine.24.0


Daily Recordkeeping: On each day of operation, the Permittee shall calculate,record, and maintain the total hours of operation for EU 005. This shall be based ona non-resettable hour meter and maintained in a written log or electronic format.

25.0


Monthly Recordkeeping: By the 15th of the month, the Permittee shall calculate andrecord the following:

1) The total hours of operation for the previous calendar month using the dailyhours of operation records; and2) The 12-month rolling sum hours of operation for the previous 12-month period bysumming the monthly hours of operation data for the previous 12 months.

26.0




14 May, 2015 10:28Page 20 of 28


Diesel Fuel Sulfur Content Certification: The Permittee shall obtain a certificationfor each diesel fuel delivery from the fuel supplier specifying the actual sulfurcontent in percent by weight, or guaranteeing that the sulfur content does notexceed 0.0015 percent or 15 parts per million by weight.

27.0




14 May, 2015 10:28Page 21 of 28

Subject Item: CE 001 Catalytic Oxidizer


GP 002 Oxidation Catalysts

NC/CA


CD hdr EMISSION AND OPERATIONAL LIMITS1.0


The Permittee shall operate and maintain the engine oxidation catalyst (CE 001)any time that EU 001 is in operation, unless otherwise noted in this permit. ThePermittee shall document periods of non-operation of the control equipment.

2.0

LIMIT Title I Condition: Avoid majorsource under 40 CFR52.21(b)(1)(i) and Minn. R.7007.3000; 40 CFR Section63.6600(b); 40 CFR pt. 63, subp.ZZZZ, Table 2b(2.a); Minn. R.7011.8150

During normal operation the Permittee shall operate and maintain CE 001 such thatit achieves an overall control efficiency for Carbon Monoxide: greater than or equalto 93.0 percent control efficiency

3.0

LIMIT Minn. R. 7007.0800, subps. 2 and14

The Permittee shall operate and maintain CE 002 such that it achieves an overallcontrol efficiency for Volatile Organic Compounds: greater than or equal to 4.0percent control efficiency

4.0

LIMIT 40 CFR Section 63.6600(b); 40CFR pt. 63, subp. ZZZZ, Table2b(1.a); Minn. R. 7011.8150

Pressure Drop: less than or equal to 2.0 inches of water column at 100 percentload plus or minus 10 percent from the pressure drop across CE 001 that wasmeasured during the initial performance test.

5.0

CD 40 CFR Section 63.6600(b); 40CFR pt. 63, subp. ZZZZ, Table2b(1.a); Minn. R. 7011.8150

The Permittee shall maintain CE 001 so that the pressure drop across the catalystdoes not change by more than 2.0 inches of water column at 100 percent load plusor minus 10 percent from the pressure drop across the catalyst that was measuredduring the initial performance test.

6.0

LIMIT 40 CFR Section 63.6600(b); 40CFR pt. 63, subp. ZZZZ, Table2b(1.b); Minn. R. 7011.8150

Temperature: greater than or equal to 450 degrees F and less than or equal to1350 degrees F at the inlet of CE 001 using a 4-hour rolling average.

7.0


If the Permittee changes the oxidation catalyst, the values of the operatingparameters measured during the initial performance test shall be reestablished. Toreestablish the values of the operating parameters, the Permittee shall alsoconduct a performance test to demonstrate that the emission unit is meeting therequired emission limitations as specified in this permit.

8.0


S/A 40 CFR Section 63.6610(a); Minn.R. 7011.8150

Initial Performance Test: due 180 days after Initial Startup of EU 001 to measurethe CO at the inlet and outlet of CE 001, according to the requirements of Table 5of 40 CFR pt. 63, subp. ZZZZ. Measure the O2 and CO concentration at the inletand the outlet of CE 002 at the same time. The test shall be conducted at any loadcondition within plus or minus 10 percent of 100 percent load.

The performance test shall use EPA Reference Method 10, or another methodapproved by MPCA in the performance test plan approval.

10.0


During the initial performance test, the Permittee shall establish each operatinglimitation in Table 2b of 40 CFR pt. 63, subp. ZZZZ that applies.

11.0

S/A 40 CFR Sections 63.6620(a), (b),(d), and (e); 40 CFR Section63.6640(a); 40 CFR pt. 63, subp.ZZZZ, Tables 3, 4, and 6; Minn. R.7011.8150; Minn. R 7017.2020,subp. 1

Performance Test: due before end of each half-year following Initial PerformanceTest or the date of the last performance test, not to exceed 6 months, to determineCO reduction. Measure the oxygen and CO concentration at the inlet and the outletof CE 002 at the same time. The test shall be conducted at any load conditionwithin plus or minus 10 percent of 100 percent load.

12.0

CD 40 CFR pt. 63, subp. ZZZZ, Table3; Minn. R. 7011.8150

After the Permittee has demonstrated compliance for two consecutive tests, thefrequency of subsequent tests may be reduced to annually, not to exceed 12months between tests. If the results of any subsequent annual performance testindicate EU 001 is not in compliance with the CO reduction limitation, or thePermittee deviates from any of the operating limitations, the Permittee shall resumesemiannual performance tests.

13.0




14 May, 2015 10:28Page 22 of 28

CD 40 CFR Sections 63.6620(b);Minn. R. 7011.8150

Compliance with the numerical emission limitations established in 40 CFR pt. 63,subp. ZZZZ is based on the results of testing the average of three 1-hour runsusing the testing requirements and procedures in 40 CFR Section 63.6620 and 40CFR pt. 63, subp. ZZZZ, Table 4.

14.0




14 May, 2015 10:28Page 23 of 28




NC/CA





2.0



3.0



4.0



5.0



6.0



7.0


If the Permittee changes the oxidation catalyst, the values of the operatingparameters measured during the initial performance test must be reestablished. Toreestablish the values of the operating parameters, the Permittee must alsoconduct a performance test to demonstrate that the emission unit is meeting therequired emission limitations as specified in this permit.

8.0



Initial Performance Test: due 180 days after Initial Startup of EU 002 to measurethe CO at the inlet and outlet of CE 002, according to the requirements of Table 5of 40 CFR pt. 63, subp. ZZZZ. Measure the O2 and CO concentration at the inletand the outlet of CE 002 at the same time. The test must be conducted at any loadcondition within plus or minus 10 percent of 100 percent load.


10.0



11.0


Performance Test: due before end of each half-year following Initial PerformanceTest or the date of the last performance test, not to exceed 6 months, to determineCO reduction. Measure the oxygen and CO concentration at the inlet and the outletof CE 002 at the same time. The test must be conducted at any load conditionwithin plus or minus 10 percent of 100 percent load.

12.0


After the Permittee has demonstrated compliance for two consecutive tests, thefrequency of subsequent tests may be reduced to annually, not to exceed 12months between tests. If the results of any subsequent annual performance testindicate EU 002 is not in compliance with the CO reduction limitation, or thePermittee deviates from any of the operating limitations, the Permittee must resumesemiannual performance tests.

13.0




14 May, 2015 10:28Page 24 of 28



14.0




14 May, 2015 10:28Page 25 of 28




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8.0





10.0



11.0



12.0



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14 May, 2015 10:28Page 26 of 28



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14 May, 2015 10:28Page 27 of 28




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14 May, 2015 10:28Page 28 of 28



14.0

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Attachment 4 – Engine Emissions Data

Maximum Hourly Emissions and Modelling Parameters for Each Engine, Lbs/Hr

and Tons per Year (TPY) Emissions for Each Engine @ 8,760 Operating Hours

Parameter 100% Load 80% Load 60% Load 25% Load Startup ^ Shutdown ^^

Maximum Output and Heat Input (Per Engine Basis):

Max. Engine Output bkW 10,000 8,000 6,000 2,500

Engine efficiency (77 C, 5% tolerance) 48.1% 47.7% 46.4% 40.5%

Engine Heat Rate (LHV, 5% tolerance) BTU/bkWh 7,094 7,168 7,370 8,425

Generator HR (LHV, 0% tolerance) BTU/kWh 7,698 7,779 7,997 9,143

Generator HR (HHV, 0% tolerance) BTU/kWh 8,530 8,619 8,861 10,130

Heat Input (LHV basis) MMBTU/hr 70.94 57.35 44.22 21.06Heat Input (HHV basis) MMBTU/hr 78.60 63.54 48.99 23.34

Engine Emissions Data (Per Engine Basis): 24

g/kWh 1.21 1.21 1.21 1.21 1.21 1.21

NOx g/bhp-hr 0.90 0.90 0.90 0.90 0.90 0.90

lb/hr 26.68 21.34 16.01 6.67 25.79 25.35

TPY 117

g/kWh 2.31 2.31 2.31 3.31 3.31 3.31

CO g/bhp-hr 1.72 1.72 1.72 2.47 2.47 2.47

lb/hr 50.94 40.75 30.56 18.25 70.55 69.34

TPY 223

g/kWh 0.11 0.11 0.11 0.11 0.11 0.11

PM (Total) g/bhp-hr 0.085 0.085 0.085 0.085 0.085 0.085

lb/hr 2.51 2.01 1.51 0.63 2.43 2.39

TPY 11.0

g/kWh 0.063 0.063 0.063 0.063 0.063 0.063

PM 10 g/bhp-hr 0.047 0.047 0.047 0.047 0.047 0.047

lb/hr 1.38 1.11 0.83 0.35 1.34 1.31

TPY 6.1 4.8 3.6 1.5 5.9 5.8

g/kWh 0.063 0.063 0.063 0.063 0.063 0.063

PM 2.5 g/bhp-hr 0.047 0.047 0.047 0.047 0.047 0.047

lb/hr 1.38 1.11 0.83 0.35 1.34 1.31

TPY 6.1 4.8 3.6 1.5 5.9 5.8

g/kWh 0.006 0.006 0.006 0.006 0.006 0.006

SO2 g/bhp-hr 0.004 0.004 0.004 0.004 0.004 0.004

lb/hr 0.13 0.11 0.08 0.03 0.13 0.13

TPY 0.58

g/kWh 0.55 0.55 0.55 0.55 0.55 0.55

VOC (as NMNEHC) g/bhp-hr 0.41 0.41 0.41 0.41 0.41 0.41

lb/hr 12.13 9.70 7.28 3.03 11.72 11.52

TPY 53.1

g/kWh 450 450 450 450 450 450

CO2 g/bhp-hr 336 336 336 336 336 336

lb/hr 9,923 7,938 5,954 2,481 9,592 9,426

TPY 43,461

g/kWh 0.19 0.19 0.19 0.19 0.19 0.19

Formaldehyde g/bhp-hr 0.14 0.14 0.14 0.14 0.14 0.14

lb/hr 4.28 3.42 2.57 1.07 4.14 4.06TPY 18.7

Maximum Emissions Reductions (with SCR and Oxidation Catalysts - BACT):

NOx % Reduction 92% 92% 92% 92% 92% 92%

CO % Reduction 93% 93% 93% 93% 93% 93%

PM (Total) % Reduction 20% 20% 20% 20% 20% 20%

SO2 % Reduction 0% 0% 0% 0% 0% 0%

VOC (as NMNEHC) % Reduction 4% 4% 4% 4% 4% 4%

CO2 % Reduction 0% 0% 0% 0% 0% 0%

Formaldehyde % Reduction 50% 50% 50% 50% 50% 50%

Post-treatment Emissions Data (Per Engine Basis - BACT):

g/kWh 0.10 0.10 0.10 0.10 0.65 0.10

NOx * g/bhp-hr 0.07 0.07 0.07 0.07 0.49 0.07

lb/hr 2.13 1.71 1.28 0.53 13.93 2.03

TPY 9.3

g/kWh 0.16 0.16 0.16 0.23 1.77 0.23

CO * g/bhp-hr 0.12 0.12 0.12 0.17 1.32 0.17

lb/hr 3.57 2.85 2.14 1.28 37.75 4.85

TPY 15.6

g/kWh 0.091 0.091 0.091 0.091 0.103 0.09

g/bhp-hr 0.068 0.068 0.068 0.068 0.077 0.068

lb/hr 2.01 1.61 1.21 0.50 2.19 1.91

TPY 8.8

g/kWh 0.006 0.006 0.006 0.006 0.006 0.01

SO2 g/bhp-hr 0.004 0.004 0.004 0.004 0.004 0.00

lb/hr 0.13 0.11 0.08 0.03 0.13 0.13

TPY 0.58

g/kWh 0.53 0.53 0.53 0.53 0.54 0.53

VOC (as NMNEHC) * g/bhp-hr 0.39 0.39 0.39 0.39 0.40 0.39

lb/hr 11.64 9.31 6.99 2.91 11.49 11.06

TPY 51.0

g/kWh 450 450 450 450 450 450

CO2 g/bhp-hr 336 336 336 336 336 336

lb/hr 9,923 7,938 5,954 2,481 9,592 9,426

TPY 43,461

g/kWh 0.10 0.10 0.10 0.10 0.15 0.10

Formaldehyde * g/bhp-hr 0.07 0.07 0.07 0.07 0.11 0.07

lb/hr 2.14 1.71 1.28 0.53 3.10 2.03

TPY 9.4

g/kWh 0.020 - - - - -

g/bhp-hr 0.015 - - - - -

lb/hr 0.44 - - - - -TPY 0.07

Exhaust Gas Data @ 49 oF average ambient air temperature ( 9.4

oC) :

Exhaust Gas Flow kg/hr 56,152 47,981 42,666 29,473

(+/- 10% tolerance) Nm3/hr 44,922 38,385 34,133 23,578

m3/hr 97,248 84,784 77,018 56,571

Stack TemperatureoF 604 626 649 720

(+/- 10 C tolerance)oC 318 330 343 382

Stack Diameter ft 4 4 4 4

m 1.200 1.200 1.200 1.200

Exhaust Gas Data @ 93 oF maximum ambient air temperature ( 34

oC) :

Exhaust Gas Flow kg/hr 53,597 46,075 40,982 28,200

(+/- 10% tolerance) Nm3/hr 42,878 36,860 32,786 22,560

m3/hr 92,980 81,011 73,137 54,375

Stack TemperatureoF 606 621 637 725

(+/- 10 C tolerance)oC 319 327 336 385

(Guaranteed)

(Guaranteed)

(Guaranteed)

(Guaranteed)

(Indicative)

(Indicative)

(Indicative)

(Indicative)

(Indicative)

PM (TOTAL) *

^ 1-Hour Startup emissions include 30-minutes of startup emissions plus 30-minutes of full load operation emissions.

^^ 1-Hour Shutdown emissions include 30-minutes of shutdown emissions plus 30-minutes of full load operation emissions.

Ammonia Slip *

Owatonna Project - Performance Criteria_2015 01 14

Attachment 5 – EPA Lockwood Memo

Attachment 6 – MPCA Source Determination

MPCA Source Determination: Owatonna Energy Station

Summary Although the new Owatonna Energy Station and the existing turbine owned by Owatonna Public Utilities (OPU) have the same industrial classification and will be adjacent, the MPCA determined that the facilities are separate sources because the facilities will not be under common control. Ultimately, commercial dispatch decisions are not made by either party, each is independently responsible for its own pollution control and compliance activities, with no shared workforces or functions, and the facilities are not functionally dependent on each other. OPU’s membership in SMMPA does not give them significant control of decisions made by SMMPA, and the power purchase agreement between OPU and SMMPA commits OPU to the control and operation of its turbine, including full compliance with any air permit issued to the turbine.

Consistent with this decision, the sources will be permitted separately. The turbine will continue to operate under its registration permit and the new Owatonna Energy Station will be issued a Part 70 permit with enforceable conditions to keep it a minor stationary source under the Prevention of Significant Deterioration (PSD) regulation.

Descriptions of Facilities Southern Minnesota Municipal Power Agency (SMMPA) proposes to construct a new electricity generating station in Owatonna, MN, near County Roads 75 and 25. Natural gas will fuel four reciprocating internal combustion engines (RICE) to generate and sell up to 40MWe to the regional grid. OPU owns and operates a 17.1 MWe natural gas fired turbine under a Registration Permit (Option D) number 14700040 which is located directly across the street from the proposed Owatonna Energy Station.

Single Source Determination Criteria According to 40 CFR §§51.166(b)(5) & (6), three criterion are used to determine what a single stationary source is. Pollutant emitting activities are a single stationary source if they:

1. Belong to the same industrial grouping, according to their Standard Industrial Classification,

2. Are located on one or more contiguous or adjacent properties, and

3. Are under the control of the same person or persons.

In this case, the facilities have the same SIC code (4911: Electric services). Both the MPCA and SMMPA agree that the properties could be considered adjacent. The extent of common control and ownership will therefore determine if the facilities could be considered a single stationary source.

SMMPA and OPU SMMPA is a non-profit, joint-action agency governed by and for its member municipalities. Joint-action agencies allow individual members (municipalities) to buy wholesale electricity as a group while still being responsive to the needs of local customers. They do not constrain the independence of members, who maintain control over their own power generation and assets. OPU is a member of SMMPA and

holds a position on the SMMPA Board of Trustees. This share in control over SMMPA would amount to far less than 50%, as it is only one of eighteen members. OPU’s role in SMMPA does not give them significant control over the decisions made by SMMPA, nor does SMMPA have control over the decisions made by OPU.

Common Control

Common ownership establishes common control, but common ownership is not the only evidence of control. Several source determinations centered on the common control criterion involve a proposed source locating on land owned by an existing source. A new source locating on another’s land often establishes a control relationship. In this instance, both properties will be separately owned and SMMPA’s facility will be located on land previously owned by a farming company and not the existing source, OPU’s turbine.

A criterion that often demonstrates common control is a functional dependence between each facility. In this instance, the Owatonna Energy Station and OPU’s existing turbine will have zero dependence on each other and will share no common resources, products, or by-products. Because OPU and SMMPA will each be responsible for its own compliance and operation, either facility could easily exist in the absence of the other.

Another important aspect of control in this case is how each power station will be dispatched, as neither SMMPA nor OPU decide when to commercially operate their facilities. Similar to all power stations in the region, the Midcontinent Independent System Operator (MISO) is responsible for deciding which power generators will be operated at a given time. MISO is a Regional Transmission Organization and assures regional grid management, unbiased access to the transmission facilities, and also determines electricity market prices. MISO assures reliability and grid management partly by dispatching only the most economical generators at the time. SMMPA pays MISO the market price for the energy needed to serve its customer load each hour, and are paid the market price by MISO each time one of its generators are used to serve a load. Through a current Power Purchase Agreement, SMMPA is entitled to the electrical generation of OPU’s turbine.

Power Purchase Agreement A Power Purchase Agreement (PPA) currently exists that entitles SMMPA to the use of 100% of the net electric generating capability of OPU’s turbine. In return, SMMPA reimburses OPU for operational costs, fuel, and insurance. OPU maintains 100% of the ownership of the facility with the exception of the additions paid for by SMMPA. As of 2015, SMMPA has made $480,603 worth of upgrades to the $18.1 million facility. The agreement may be terminated with a 60 day notice by SMMPA if the facility becomes uneconomical for SMMPA. In this case, OPU would keep any improvements made by SMMPA. SMMPA possesses dozens of PPAs with municipalities across the state. Five different PPAs with similar parties have been terminated by SMMPA since 2008.

In addition to fully owning the turbine, OPU is the explicit operator of the facility and is responsible for all O&M including the following:

Obtaining the necessary personnel and, in cooperation with SMMPA, provide for such training as may be required to qualify them to perform the O&M

Maintaining quick-start capability for the Plant

Operate the Member Plant with sufficient qualified personnel

Assist SMMPA with any renewals and replacements SMMPA elects to perform, including the replacement, modification, renewal, and disposal and salvaging of any part of the property included in the Member Plant

Comply with all any and all laws applicable to the performance of O&M and R&R for the Member Plant, including all applicable Environmental Laws

Comply with the terms and conditions of any contract, permit or license relating to the Member Plant

Purchase and procure equipment, apparatus, machinery, tools , materials, and supplies and contract for services of third parties to perform O&M

In the event of an operating emergency, take such action as Member to terminate such operating emergency, so as to minimize any adverse environmental effects.

SMMPA reimburses OPU monthly O&M Costs for routine services in the amount of the annual base salaries of each designated staff person, divided by 12 months. SMMPA also has the right to perform any R&R it elects to perform at the plant, and shall be responsible for such costs. Furthermore, SMMPA has sole authority under the current agreement to procure all fuel for and deliver all fuel to the facility.

MISO’s Control With the fact that MISO makes commercial dispatch decisions for both facilities, an argument could be made that MISO would have a certain amount of control over both facilities. However, MISO has no involvement in the operation or ownership of any facility under its supervision; it only manages the end-product of electric generators. A central command making dispatch decisions such as MISO is necessary to manage the delivery of such a complicated product and to constantly balance the load and supply of electricity. This level of control has no effect on the operational decisions of an individual generator or its compliance requirements.

Similar Control Determinations In a 1979 PSD applicability determination, a paper mill owned by International Paper Company and a chemical plant owned by Arizona Chemical Company were both located on property owned by International Paper. EPA concluded that if an entity such as International Paper had as much as a 50% voting interest in another, it could be considered “in control” of that entity. This could be compared to OPU’s current position as a board member in SMMPA, which gives OPU far less than a 50% voting interest in the decisions made by SMMPA. Similarly, the PPA is the extent of SMMPA’s control over OPU and does not give them voting interest within Owatonna or OPU.

In EPA’s 1999 KN Power Determination, the Agency addressed whether a proposed peaking station constructed by Front Range Energy and an existing PSD major generating facility owned by Public Service Company of Colorado (PSCo) constituted a single PSD source. The two facilities belonged to the same SIC code and were located on adjacent properties, thus the issue was whether the two plants were under common control. The Front Range facility was owned by KN Power and Quixx Corp, a subsidiary of New Century Energy Inc., which also held PSCo. Thus, a common corporate control existed between the two

facilities. Front Range also had a PPA with PSCo to provide all net generation of the facility available at any time to PSCo, and PSCo agreed to pay Front Range for the operational costs of the facility, including procuring fuel. PSCo had the sole right under the agreement to determine startup, shutdown, and operational levels at the Front Range plant. EPA concluded that PSCo controlled the essential function of the Front Range facility via the PPA between the two, and that control was “indicated by ownership interest in the Facility held by PSCo’s parent company, New Century Energies, Inc”. EPA determined that the Front Range facility was a modification to the existing PSCO plant.

While this PPA was very similar to the one that exists between OPU and SMMPA, there are several differences which make it challenging to directly apply this Colorado determination to SMMPA’s. PSCo and Front Range were both subsidiaries of New Century Energy, Inc., showing a clear corporate link which SMMPA and OPU lack. PSCo was also the RTO in much of Colorado, whereas the third-party MISO is the RTO within Minnesota.

Front Range Energy and PSCo were both subsidiaries of the investor owned New Century Energies, Inc. (which has since been acquired by Xcel Energy, Inc.), showing common corporate control. This means that New Century owned 50% of the Front Range plant and could make significant decisions for both plants, including the PPA. OPU owns 100% of its turbine and OPU’s membership in SMMPA does not give them significant control of SMMPA as they are only one of 18 members.

Unlike Minnesota and MISO, there is no Regional Transmission Organization in Colorado, so utilities have the responsibility for planning their respective transmission systems, administering their own energy market, and balancing generation with customer load at all times. This means that the equivalent functions of MISO in Minnesota are performed by PSCo, greatly increasing PSCo’s control over the Front Range facility. Instead of MISO, all dispatch decisions are made by PSCo. Without the presence of an RTO and energy market such as MISO, PSCo would have no obligation to dispatch the Front Range facility without the PPA. This demonstrates the functional dependence between the two in this case; if the Front Range facility were built entirely independently of PSCo and its resources, there would have be no guarantee of it ever being able to operate, even if it were to be the most economical generator at the time. If OPU did not have a PPA with SMMPA, it could still dispatch it’s generator to the grid via MISO.

Future Permit Actions In determining that the two sources are not functionally dependent and do not exert significant control on each other, the sources will be permitted separately. The turbine will continue to operate under its registration permit and the new Owatonna Energy Station will be issued a Part 70 permit with enforceable conditions to keep it a minor stationary source under the Prevention of Significant Deterioration (PSD) regulation.

Although the sources will continue to be permitted as two separate sources, there are obvious interactions between SMMPA and OPU. Once both facilities are operating there may be certain actions that would lead the MPCA to reevaluate this decision. These would include, but are not necessarily limited to:

SMMPA acquiring 50% or more of the ownership of the OPU turbine SMMPA relying on OPU’s workforce to operate the Owatonna Energy Station

A significant increase in OPU’s share and control of SMMPA in which it could solely control the decisions of SMMPA

SMMPA accepting responsibility for compliance activities or pollution fees on behalf of OPU’s turbine

Either facility functionally relying on the other for purposes such as ancillary services or black-start capabilities

SMMPA assuming the role of RTO in the Owatonna/Southern Minnesota region

Attachment 7 – Modeling Report

“When a violation of any NAAQS or increment is predicted at one or more receptors in the impact area, the application can determine whether the net emissions increase from the proposed source will results in a significant ambient impact at the point (receptor) of each predicted violation, and at the time the violation is predicted to occur. The source will not be considered to cause or contribute to the violation if its own impact is not significant at any violating receptor at the time of the predicted violation. In such case, the permitting agency, upon verification of the demonstration, may approve the permit.”

AQDM-06Air Quality Dispersion Modeling Report

Protocol Form for Criteria Pollutant Modeling(Previously AQDMR-01)

Doc Type: Air Dispersion Modeling

Facility Information

*This should be the central location of the facility/source.

Project Description

Files to Accompany Modeling Report

www.pca.state.mn.us • 651-296-6300 • 800-657-3864 • TTY 651-282-5332 or 800-657-3864 • Available in alternative formatsaq2-48 • 7/10/13 Page 1 of 7

*Provide the final spreadsheet (i.e. AQDM-02) and indicate/highlight changes.

Section 1. Modeling Protocol

*This is the date given on AQDM-04 form

Section 2. Changes to Modeling Protocol

Purpose for Air Dispersion Modeling and Related Information

EPA Pre-Processors and EPA Post-Processors

Model Selection and Options (Key CO Pathway Inputs)

Emission Source Characterizations and Parameters (Key SO Pathway Inputs)

Paved Roads Fugitive Dust (as per MPCA April 25, 2011 Policy)

Receptors (RE Pathway)

Meteorological Data (ME Pathway)

SIL Analysis and Results

Background Values

Nearby Sources

Pollutant-based Considerations


Section 2.1: Detailed Changes to Modeling Protocol


Section 3. Paved Roads Fugitive Dust (Optional)

Section 4. Modeling Results


*SO2 3-hr for Northern Minnesota is 915 ug/m3.


Section 5. Discussion

Please see attached memorandum for a discussion of why the PM2.5 models predict concentrations above the NAAQS.

Section 6. Modeling Results Figures/Maps


AERMOD View - Lakes Environmental Software

SCALE:

0 0.1 km

1:2,637

PROJECT TITLE:

Owatonna Energy StationFacility Layout

COMMENTS:

Green crosses represent receptors.Blue represents buildings.Red crosses represent point sources.

COMPANY NAME:

Golder Associates Inc.

MODELER:

Ryan Birkenholz, PE

DATE:

4/10/2015

PROJECT NO.:

1401787

SOURCES:

5

RECEPTORS:

169

FIGURE 1


SCALE:

0 0.3 km

1:8,684

PROJECT TITLE:

Owatonna Energy StationNO2 1-hr 98th Percentile

COMMENTS:


COMPANY NAME:


MODELER:

Ryan Birkenholz, PE

DATE:

4/12/2015

PROJECT NO.:

1401787

SOURCES:

5

RECEPTORS:

4745

OUTPUT TYPE:

Concentration

MAX:

162.9 ug/m^3

FIGURE 2


SCALE:

0 0.3 km

1:8,684

PROJECT TITLE:

Owatonna Energy StationNO2 Annual Average

COMMENTS:


COMPANY NAME:


MODELER:

Ryan Birkenholz, PE

DATE:

4/12/2015

PROJECT NO.:

1401787

SOURCES:

5

RECEPTORS:

4745

OUTPUT TYPE:

Concentration

MAX:

20.75 ug/m^3

FIGURE 3


SCALE:

0 0.2 km

1:5,290

PROJECT TITLE:

Owatonna Energy StationPM10 24-hr Highest Sixth High

COMMENTS:


COMPANY NAME:


MODELER:

Ryan Birkenholz, PE

DATE:

4/10/2015

PROJECT NO.:

1401787

SOURCES:

5

RECEPTORS:

169

OUTPUT TYPE:

Concentration

MAX:

90.97 ug/m^3

FIGURE 4


SCALE:

0 0.2 km

1:5,333

PROJECT TITLE:

Owatonna Energy StationPM10 Annual Average

COMMENTS:


COMPANY NAME:


MODELER:

Ryan Birkenholz, PE

DATE:

4/10/2015

PROJECT NO.:

1401787

SOURCES:

5

RECEPTORS:

169

OUTPUT TYPE:

Concentration

MAX:

31.380 ug/m^3

FIGURE 5


SCALE:

0 0.3 km

1:8,614

PROJECT TITLE:

Owatonna Energy StationPM2.5 24-hr 98th Percentile

COMMENTS:


COMPANY NAME:


MODELER:

Ryan Birkenholz, PE

DATE:

4/10/2015

PROJECT NO.:

1401787

SOURCES:

5

RECEPTORS:

4745

OUTPUT TYPE:

Concentration

MAX:

56.5 ug/m^3

FIGURE 6


SCALE:

0 0.3 km

1:8,684

PROJECT TITLE:

Owatonna Energy StationPM2.5 Annual Average

COMMENTS:


COMPANY NAME:


MODELER:

Ryan Birkenholz, PE

DATE:

4/10/2015

PROJECT NO.:

1401787

SOURCES:

5

RECEPTORS:

4745

OUTPUT TYPE:

Concentration

MAX:

13.64 ug/m^3

FIGURE 7

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AQDM-04AQDM Protocol Approval Notification Form

Air Quality Dispersion Modeling (AQDM)(Previously AQDM PAN-01)



Protocol Approval Notification

Reviewer Information


AQDM-01Air Quality Dispersion Modeling Protocol

Protocol Form for Criteria Pollutant Modeling(Previously AQDMP-01)




Use the checkboxes to indicate that the following required files are included with the completed protocol form (unless otherwise noted).

Please do not use spaces or special characters in the file names and pathways.

Examples include

SIL models provided.


Section A. Purpose for Air Dispersion Modeling and Related Information

25 MW operating capacity

Daniel reviewed a prior version of this protocol (unknown date).

Installation of four natural gas fired internal combustion engines to generate electricity. One diesel generator will be installed to provide emergency power.

PM2.5

(PM2.5 trigger date will be on Oct. 20, 2011, 1 year after F.R. publication date.)PM2.5

N/A


Section B. EPA Pre-Processors and EPA Post-Processors

All UTM coordinates must be in NAD83, Zone 15 Extended (not NAD27).

Tiering of buildings must follow MPCA’s modeling guidance from the “How To Model” section of the April 2013 “MPCA Air Dispersion Modeling Guidance For Minnesota Title V Modeling Requirements And Federal Prevention of Significant Deterioration (PSD) Requirements.” (aq2-58)

AERSURFACE version 08009 (or version 13016) is used to determine surface characteristics using 1992 LULC data.Yearly-averaged moisture conditions (wet, dry, or average) based on historical ranks are accounted for in AERSURFACE to aid in the determination of Bowen ratio values. Default 1.0 km radius for surface roughness and 10 km by 10 km domain for albedo and Bowen ratio used in AERSURFACE

*If no, skip to question 4 and provide additional information in question 6.

(Default is “Yes”)



N/A


Section C. Model Selection and Options (Key CO Pathway Inputs)

Please refer to Tables App.1 and App.2 in the Appendix for averaging times and form of standard for each criteria pollutant(s). Refer to the most recent version of the EPA’s AERMOD User’s Guide for correct pollutant IDs to use. Use EPA’s most recent modeling guidance’ methods for PM2.5.

AERMOD User’s Guide Addendum

For Tier 3 options, please fill-out the NO2 questions in Section K: Pollutant-based Considerations.

We propose to use the default ambient ratio of 0.80 which is readily accepted by US EPA.

e. “Finally, for condition (3) in paragraph (b) of this subsection…an alternative refined model may be used provided that:The model has received a scientific peer review;The model can be demonstrated to be applicable to the problem on a theoretical basis;The data bases which are necessary to perform the analysis are available and adequate;Appropriate performance evaluations of the model have shown that the model is not biased toward underestimates; andA protocol on methods and procedures to be followed has been established.”


Section D. Emission Source Characterizations and Parameters (Key SO Pathway Inputs)

MPCA’s Modeling Parameters Spreadsheet

“N/A” = Source-type not present; “Yes” = Source-type present and will model; “No” = Source-type present but will not model.

*Please provide justification for use of non-default option in question ii, below.If using third-party software, please check with the vendor to determine if there are any issues with the use of BETA options POINTCAP and POINTHOR.

*

*Volume source should then be converted to an area source of commensurate size (per section 6.2 of EPA’s AERMOD Implementation Guide (03/19/2009) or be further refined. Also see EPA’s Haul Road Workgroup Guidance (03/02/2012).


* Please provide justification for excluding any fugitive emission sources within the modeling, including the use of the Paved Roads Fugitive Dust Policy.

Note: If modeling for paved road fugitive dust, please read and complete Section E.

The insignificant activities identified in the air permit application do not emit NOx, CO, SO2, PM10/PM2.5.

The emergency generator is an intermittent unit that will be operated only for maintenance and readiness testing as well as in the event of an emergency.

The emergency generator is not being included in the 1-hr NO2 model because it is not required to be considered in the AERA and it is an intermittent source that is not expected to operate under normal operation. This unit will be considered in other models.

The following sclars are used: 0.75 and 0.80 to represent NOx to NO2 conversion for annual and 1-hr NO2 models respectively. A scalar of 0.0114 is used for SV05 for annual models to account for the 100 hr/yr limit. A scalar of 0.4559 is used for SV01-04 for annual models to account for the 3,994 hr/yr limit. A "0" scalar is used for SV05 for 1-hr NO2 and 1-hr SO2 models because it is an intermittent source.


*If yes, please provide the hourly emission file(s) with the submittal of this form and list file in question 6 under the “Files To Accompany Protocol” section.

N/A

Section E. Paved Roads Fugitive Dust

*If neither, policy does not apply. Please answer questions 2 – 4, and proceed to the next section (F) without filling in Table E-01.

N/A


Note: If completing Table E-01, modeling output files must then be submitted.

NAAQS/MAAQSResult(s) w/ Background and Nearby Sources (%)

PSD Class II Result(s)(%)

# < 60% 60% < # < 95% 95% < # # < 35% 35% < # < 75% 75% < #

# < 80% 80% < # < 95% 95% < # # < 40% 40% < # < 80% 80% < #

Section F. Receptors (RE Pathway)MPCA Air Dispersion Modeling Guidance for Minnesota Title V

Modeling Requirements and Federal Prevention of Significant Deterioration (PSD) Requirements” (aq2-58)


N/A

Section G. Meteorological Data (ME Pathway)

The surface and upper air data were suggested for use at this site by MPCA due to proximity to the proposed facility.


N/A

Section H. SIL Analysis and Results

*As of 10/26/20101-hr3-hr

24-hrAnnual24-hr

Annual24-hr

Annual1-hr

Annual1-hr8-hr

PM10 radius is "120 meters" The formatting of this form does not allow anything less than 1 km to be entered.

Section I. Background ValuesAERMOD User’s Guide, Addendum”


N/A

PM2.5 (annual) : average monitored value (2010-2012) = 7 ug/m3; Rochester MonitorPM2.5 (24-hr) : 98th percentile of daily average (2010-2012) = 25 ug/m3; Rochester MonitorPM10 (annual) : highest annual concentration (2010-2012) = 31 ug/m3 (FHR 470 monitor)PM10 (24-hr) : 2nd highest daily maximum (use highest of three years). 2010 = 74 ug/m3, 2011 = 84 ug/m3, 2012 = 67 ug/m3; CHOOSE 84 ug/m3; St Paul MonitorNO2 (annual) : average monitored value (2010-2013) = 10 ppb; FHR 420 monitorNO2 (1 hr): average of the annual 98th percentile daily maximum 1-hr concentrations = 46 ppb; FRH 420 monitorThese background values were proposed in a previous version of this modeling protocol and were approved at that time.

(BGflag can be defined as ANNUAL, SEASON, MONTH, etc. See Table B-4, Appendix B, of the AERMOD User’s Guide Addendum)

Section J. Nearby Sources


*Contact MPCA air dispersion modeling staff for MPCA-generated products. Also, refer to the “How to model, Part II” section, “Step four – Compliance demonstration” subsection in the MPCA’s Air Dispersion Modeling Guidance.

*If no, please skip ahead to Section K: Pollutant-based Considerations.

This is the MPCA-generated GIS Tool

*Nearby sources out to 50 km away from the subject source should be examined.*Please include facility ID’s and/or names in the modeling input files of all nearby sources.The MPCA's GIS Nearby Source Tool was used to determine all sources within 50 km of the proposed facility.

Emissions listed in the MPCA's GIS lookup tool will be used.NO2 sources to include are: Northern Natural Gas- Albert Lea (ID 4700065), Crown Cork & Seal Co Inc - Owatonna (ID 1470001), and Owatonna Public Utilities - West Owatonna (ID 1470004). PM10 & PM2.5 sources to include are: Viracon Inc - Owatonna (ID 1470006).

Permitted valueIf problems arise with permitted rates, we propose to use actual rates with MPCA approval.

See attached figures for a map showing sources considered and sources included for NO2 and PM2.5 models.

Section K. Pollutant-based Considerations


MPCA guidance on estimatting Secondary Formation of PM2.5 located in the MPCA Dispersion Modeling Guidance will be used to estimate secondary PM2.5.

If no, skip the rest of the NO2-related questions.

(Please check all option(s) proposed to be used):

Example

Tier 3 NO2 methodologies that require approval by Region 5 modeling staff need to have said approval before submission of the AQDM-06 report form and attach approval.

N/A


Appendix

CONO2Pb

PM10PM2.5SO2

NO2PM10PM2.5SO2

Criteria pollutants modeled for SIL analyses should be modeled as H1H’s.

Helpful Webpages, Documents/Guidance, and Modeling Tips


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Attachment 8 – AERA Report

TECHNICAL MEMORANDUM

Golder Associates Inc. (Golder) prepared a dispersion modeling analysis for the proposed Owatonna Energy

Station (Facility) which will be owned by Southern Minnesota Municipal Power Agency (SMMPA). A complete

air modeling analysis and Air Emissions Risk Analysis (AERA) were submitted to MPCA on March 12, 2015.

SMMPA proposes to reduce the stack heights for SV01-04 from the previously modeled 100 ft to 99 ft. This

technical memorandum describes the revised results for the modeling and AERA due to the change in stack

height.

Changes to Air Model Results

The reduction in stack height from 100 ft to 99 ft for SV01-04 caused modeled ground level concentrations to

increase slightly. None of the increased concentrations exceed the National Ambient Air Quality Standards or

Minnesota Ambient Air Quality Standards with the exception of PM2.5. The concentration of PM2.5 is elevated

due to a modeled background source. The discussion presented in the March 12, 2015 analysis still applies to

this revised analysis; no additional discussion is being presented.

A revised modeling report form (AQDM-06) is attached to this memorandum and contains the revised ground

level concentrations. Revised modeling files are submitted electronically.

Changes to AERA Results

The reduction in stack height caused the modeled source contributions used in the Risk Assessment Screening

Spreadsheet (RASS) to increase. The RASS predicts an acute risk of 1.2 with the new stack height; all other

risks remain below the screening levels. A revised RASS summary sheet is included in Attachment . The

RASS is included with this submission electronically.

Date: March 25, 2015 Project No.: 1401787To: Travis Zipf Company: Emanualson-Podas Inc.

From: Ryan Birkenholz

cc: Email:

RE: UPDATED AIR DISPERSION MODELING & AERA– OWATANNA ENERGY STATION

\\minneapolis\projects\golder projects\140 projects\1401787 - ep - smmppa owatonna-mn\working\modeling\report\modelingmemo-2015-03-25 update.docx

Golder Associates Inc.1751 W. County Road B, Suite 105

Roseville, MN 55113 USA Tel: (651) 697-9737 Fax: (651) 697-9735 www.golder.com

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ATTACHMENT A

MPCA Model Report Form

AQDM-06Air Quality Dispersion Modeling Report

Protocol Form for Criteria Pollutant Modeling(Previously AQDMR-01)


Acronym Information on Page 7

Instructions: Permit applicants required to conduct air dispersion modeling should submit two paper copies of the completed Air Quality Dispersion Modeling Report form (AQDM-06) and all accompanying files to:

Air Quality Permit Document CoordinatorMinnesota Pollution Control Agency520 Lafayette Road NorthSt. Paul, MN 55155-4194

Applicants may also submit an electronic version in addition to the two paper copies. This is highly recommended. Please note that all assumptions made in the air dispersion modeling analysis could result in air permit requirements.

Electronic copies of the forms and accompanying files should be sent to: [email protected].


AQ tracking no.: AQ facility/permit ID no.: TBD Today’s date (mm/dd/yyyy): 03/25/2015

Three-letter modeling facility ID (ex., XEK = Xcel Energy Allen S. King, MEC = Mankato Energy Center, etc.):

Facility name: Owatonna Energy Station

Facility street address: TBD

City: Owatonna County: Steele Zip code: 55060 State: MN

Facility contact: Peter J. Reinarts, P.E. Protocol prepared by: Ryan Birkenholz, P.E.

Facility contact phone: 507-292-6452 Preparer phone: 651-697-9737

Facility contact e-mail address: [email protected] Preparer e-mail address: [email protected]

*UTM coordinates of facility (NAD83, zone 15 extended ONLY): x = 478,983.00 m East, y = 4,881,376.00 m North


This report is associated with (check all that apply):

Permit application

Permit requirement

SIL-only analysis

Other: AERA

Project Description (50 words or less)

The Owatonna Energy Station will generate electricity using four internal combustion engines fueled by natural gas.

Files to Accompany Modeling ReportInclude the following files with the completed modeling report form. Use checkbox to indicate that all applicable files are included.

1. AERMOD input files (*.inp, *.adi, *.ami) AERMOD output files (*.out, *.ado, *.amo)AERMOD plot files (*.plt)AERMOD post files (*.pst) (If applicable)AERMOD event files (*.evi, *.evo) (If applicable)AERMOD miscellaneous/other files (MAXDCONT, ?, ?, etc.) (If applicable)


2. AERMET files: *.sfc *.pfl

3. BPIP-PRIME files: Input (*.bpi) Output (*.bpo, *.sum) (If applicable)

4. AERMAP files: Terrain (*.dem(s), *.tif (NED files)), Input (*.ami), Output (*.rou, *.sou, etc.) (If applicable)

5. Background data files: Background concentrations for applicable pollutants (seasonal, monthly, daily, hourly, etc.)

(If applicable)

6. Modeling Results: Figures (*.jpeg, *.pdf), GIS Maps (*.shp)

7. AQDM-02 spreadsheet*:

8. Other files and supporting documents (paved roads fugitive dust modeling output files, etc.):

*Provide the final spreadsheet (i.e. AQDM-02) and indicate/highlight changes.

Section 1. Modeling Protocol

1. The Air Dispersion Modeling presented in this report is based on a Protocol that has been:

Approved Conditionally approved *MPCA approval date (mm/dd/yyyy): 03/02/2015

*This is the date given on AQDM-04 form

2. Does this Modeling submittal completely follow the Approved Protocol? Yes No

If yes, proceed to Section 3.

If no, proceed to Section 2.

Section 2. Changes to Modeling Protocol

Table 1: Protocol Changes (Please indicate which sections in Approved Protocol contain changes.)

Modeling protocol by sections

Section and section name Change/No change

Files to accompany protocol No ChangeSection APurpose for Air Dispersion Modeling and Related Information No ChangeSection BEPA Pre-Processors and EPA Post-Processors No ChangeSection CModel Selection and Options (Key CO Pathway Inputs) No ChangeSection DEmission Source Characterizations and Parameters (Key SO Pathway Inputs) No ChangeSection EPaved Roads Fugitive Dust (as per MPCA April 25, 2011 Policy) No ChangeSection FReceptors (RE Pathway) No ChangeSection GMeteorological Data (ME Pathway) No ChangeSection HSIL Analysis and Results ChangeSection IBackground Values No ChangeSection JNearby Sources No ChangeSection KPollutant-based Considerations No Change


Section 2.1: Detailed Changes to Modeling Protocol

Please provide specific information corresponding to those sections in Table 1 where changes are indicated.

Section A. Purpose for air dispersion modeling and related information

MPCA approved change: Yes No Date (mm/dd/yyyy):

Describe changes and/or indicate section item number(s):

Section B. EPA pre-processors and EPA post-processors



Section C. Model selection and options (Key CO pathway inputs)



Section D. Emission source characterizations and parameters (Key SO pathway inputs)



Section E. Paved roads fugitive dust



Section F. Receptors (RE pathway)



Section G. Meteorological data (ME pathway)



Section H. SIL analysis and results



The protocol indicated that the Radius of Impact for 1-hr NO2 is 50 km. This was an estimate. The actual Radius of Impact is


approximately 22 km and the refined receptor grid reflects this. Some of the SIL results changed due to a change in stack diameter and stack velocity for EU01-EU04.

Section I. Background values



Section J. Nearby sources



Section K. Pollutant-based Considerations



Section 3. Paved Roads Fugitive Dust (Optional)

Facilities that have indicated in AQDM-01 form the exclusion of paved roads in the air dispersion modeling should provide the results of that modeling in Table 1, whether results were or were not provided in the AQDM-01 form. Results should not include fugitive dust from paved roads. (See the AQDM-01 form for further details and tiers.)

Table 1: Model results for paved roads fugitive dust exemption policy

Averaging Period

NAAQS 3)

Total Modeled NAAQS Concentration (includes Background and Nearby Sources) (ug/m3) % of NAAQS

PSD Class II Increments

3)

Modeled Class II Increment Impact Concentrations

3)% of Class II Increments

PM1024-hour 150 0.00% 30 0.00%

Annual 50 0.00% 17 0.00%

PM2.524-hour 35 0.00% 9 0.00%

Annual 15 0.00% 4 0.00%

Section 4. Modeling Results

Table 2: Pollutants and averaging periods (Check all the boxes for each pollutant and averaging period(s) modeled.)

Pollutant Averaging PeriodStandard

Increment SIL-onlyNAAQS MAAQS

CO1-hr

8-hr

LeadRolling 3 mo. Avg

Quarterly Avg

NO21-hr

Annual

SO2

1-hr

3-hr

24-hr

Annual

PM1024-hr

Annual


PM2.524-hr

Annual

Table 3: NAAQS/MAAQS modeling results (Enter modeling results along with the percent of standard.)

Pollutant Averaging period

NAAQSstandard(ug/m3)

MAAQSstandard(ug/m3)

Total modeled concentration (includes background and nearby sources)(ug/m3)

Percent of standard (%)

NAAQS MAAQS

CO1-hr 40,000 35,000 N/A

8-hr 10,000 10,000 N/A

LeadRolling 3 mo. Avg 0.15 *** N/A

Quarterly Avg 1.5 1.5 N/A

NO21-hr 188 *** 156.0 83%

Annual 100 100 20.6 21% 21%

SO2

1-hr 196 1300 N/A

3-hr *** 1300/*915 N/A

24-hr 365 365 N/A

Annual 80 60 N/A

PM1024-hr 150 150 107.2 71% 71%

Annual *** 50 32.2 64%

PM2.524-hr 35 65 747.5 2136% 1150%

Annual 12 15 132.4 1103% 883%*SO2 3-hr for Northern Minnesota is 915 ug/m3.

Table 4: Increment modeling results (Provide the increment modeling results along with the percent of standard.)

Pollutant Averaging Period

Class II Increment(ug/m3)

Total Modeled Concentration(includes other increment sources) (ug/m3)

Percent of Standard(%)

NO21-hr *** N/A

Annual 25 N/A

SO2

1-hr *** N/A

3-hr 512 N/A

24-hr 91 N/A

Annual 20 N/A

PM1024-hr 30 N/A

Annual 17 N/A

PM2.524-hr 9 N/A

Annual 4 N/A

Table 5: SIL-only modeling results (Provide the SIL modeling results along with the percent of standard.)

Pollutant Averaging PeriodSIL(ug/m3)

Total Modeled Concentration (ug/m3)

Percent of Standard(%)

NO21-hr 7.52 156 2074%

Annual 1 1.11 111%

SO2

1-hr 7.83 1.1 14%

3-hr 25 0.8 3%

24-hr 5 0.3 6%

Annual 1 0.002 0.2%

PM1024-hr 5 6.10 122%

Annual 1 0.06 6%

PM2.524-hr 1.2 7.79 649%

Annual 0.3 0.08 27%


CO1-hr 2000 355 18%

8-hr 500 316 63%

Section 5. DiscussionEnter any discussion or comments on the information provided in this form (this can be used as a substitute for a written report):

Please see attached memorandum for a discussion of why the PM2.5 models predict concentrations above the NAAQS.

Section 6. Modeling Results Figures/MapsInsert a figure or map showing the facility emission sources, receptors, and the location of the modeled maximum concentration(s) for each applicable pollutant, corresponding averaging periods, and operating scenarios. Figures or maps should correspond to Section 3 NAAQS and Increment results.

[Paste here]


Acronyms

AERMAP AERMOD Terrain Preprocessor

AERMET AERMOD Meteorological Preprocessor

AERMOD AMS/EPA Regulatory Model

AQ Air Quality

AQDMP-01 Air Quality Dispersion Modeling Protocol form

AQDMPS-01 Air Quality Dispersion Modeling Protocol Spreadsheet

BPIP-PRIME Building Profile Input Program for PRIME

CO Carbon Monoxide

EPA U.S. Environmental Protection Agency

FAC 3-letter facility ID

MAAQS Minnesota State Ambient Air Quality Standard

MPCA Minnesota Pollution Control Agency

NAAQS National Ambient Air Quality Standard

NO2 Nitrogen Dioxide

OU Operable Unit

Pb Lead

PM10 Particulate Matter less than 10 um in size

PM2.5 Particulate Matter less than 2.5 um in size

PRIME Plume Rise Model Enhancements

PSD Prevention of Significant Deterioration Program

SIL Significant Impact Level

SO2 Sulfur Dioxide

SIP State Implementation Plan

SMS Standardized Mobile Source 3 Micrograms per cubic meter ( g/m3)

UTM Universal Transverse Mercator


ATTACHMENT B

RASS Summary Sheet

Summary

\\minneapolis\Projects\Golder Projects\140 PROJECTS\1401787 - EP - SMMPPA Owatonna-MN\WORKING\AERA\REPORT (no CT - with emergency gen - no SCR)-2015-03\62-APPX A - AERA-22 (POST).xlsx1 of 1 3/25/2015 11:01 AM

RASS version number = 20130304- 25 stacksNo Inputs Allowed on this Page

Screening Date:AQ Facility ID No.:AQ File No.:Facility Name:Facility Location:SIC Code (Required):

AcuteSubchronic Noncancer

Chronic Noncancer

CancerFarmer

NoncancerFarmer Cancer

Urban Gardener

Noncancer

Urban Gardener Cancer

Resident Noncancer

Resident Cancer

Farmer Noncancer

Farmer Cancer

Urban Gardener Noncancer

Urban Gardener Cancer

Resident Noncancer

Resident Cancer

1.E+00 1.E-01 7.E-02 8.E-07 5.E-06 6.E-07 2.E-07 7.E-02 6.E-06 7.E-02 1.E-06 7.E-02 9.E-07

1.E+00 1.E+00 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05

REFINE OK OK OK OK OK OK OK OK OK OK OK OK

1.2E+00 1.0E-01 7.0E-02 7.6E-07 5.3E-06 6.5E-07 1.6E-07 7.0E-02 6.0E-06 7.0E-02 1.4E-06 7.0E-02 9.2E-07

Endpoint AcuteSubchronic Noncancer

Chronic Noncancer

Respiratory/ Olfactory

1.2E+00 1.0E-01 6.9E-02

Developmental/Reproductive/Endocrine/Fetotoxicity

3.6E-04 0.0E+00 3.7E-04

Hemetological (e.g. Hematopoietic, blood,lymphsystem, immune system)

0.0E+00 0.0E+00 5.5E-04

Neurological (e.g. central nervous system)

6.4E-05 0.0E+00 1.7E-03

Eyes 8.8E-01 0.0E+00 0.0E+00

Alimentary (e.g. digestive)

0.0E+00 9.0E-06

Bone & teeth 0.0E+00 0.0E+00

Cardiovascular 0.0E+00 0.0E+00 1.7E-07

Kidney (e.g. renal) 0.0E+00 8.8E-06

Hepatic (e.g. liver) 0.0E+00 1.7E-05

Skin 0.0E+00

Ethanol specific 0.0E+00 0.0E+00 0.0E+00

9.9E-01 9.9E-01 9.9E-01<<<Guidance

Level

REFINE OK OK<<<OK or REFINE?

ChemicalFraction of 1-hr

stdFraction of 3-hr

stdFraction of 24-

hr stdFraction of

qtrly stdFraction of annual std

SO2 0.002 0.000 0.001 0.000

PM10 0.038 0.001

PM2.5 0.162 0.005

NOx 0.860 0.010

CO 0.005

Pb

Fraction of VOCs assessed 0.516

Fraction of HAPs assessed 1.000

Total Criteria Pollutant Emissions (tpy) 322.354

Total HAP Emissions (tpy) 45.831

Total VOC Emissions (tpy) 93.019

Benzene no

Bromopropane, 1- no

Carbon disulfide no

Cellosolve Acetate no

Chloroform no

2-ethoxyethanol no

Ethylbenzene no

Ethyl chloride no

2-methoxyethanol no

Trichloroethylene no

Arsenic no

Carbon tetrachloride no

Mercury no

Propylene oxide no

Owatonna, MN

4911

3/25/2015


Ceiling Values Exceeded?

Total Inhalation Screening Hazard Indices and Cancer Risks

PTE

Criteria Pollutant Screen

Total Indirect Pathway Screening Hazard Indices and Cancer Risks

The Criteria pollutant screen is for informational purposes only, not for demonstration of attainment or violation of ambient air quality standards. This information may be used to assess whether further analysis is warranted.

Many pollutants have more than a single endpoint and thus are included in multiple endpoints totals

Air Toxics Screen

Note: The hazard index (HI) against which facility risks are compared for acute, sub-chronic and chronic non-cancer risks is 1. The cancer risk against which facility risks are compared is 1 E-5 (or 1 chance in 100,000). These facility risk guidelines are risk management-based. They are not discrete indicators of observed adverse effect. If a risk estimate falls below facility risk guidelines, the MPCA may conclude that the assessed health effects from the proposed action are unlikely to occur, or will be negligible. A risk estimate that exceeds a guideline triggers further careful consideration.

Air Toxics Endpoint Refinement

Total Inhalation Screening Hazard Indices and Cancer Risks

Total Multipathway Screening Hazard Indices and Cancer Risks

Emissions type (PTE, Future Actual):