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Technical Support Document, Permit Number: 13100058-101 of 8

Technical Support Document

For Draft Air Emission Permit No. 13100058-101

This technical support document (TSD) is intended for all parties interested in the draft 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 permit. 1. General information

1.1 Applicant and stationary source location:

Table 1. Applicant and source address

Applicant/Address Stationary source/Address (SIC Code: 4922)

Northern Natural Gas Co 1111 103rd St S Omaha, Nebraska 68124-1072

Northern Natural Gas Co - Faribault Compressor 21903 Canby Ave Faribault MN 55021

Contact: Kelly Henry Phone: 651-456-1712

1.2 Facility description

Northern Natural Gas Co - Faribault Compressor (NNG or Facility) is a natural gas compressor station located in Faribault, Minnesota. Compressor stations compress natural gas to a specified pressure along natural gas pipelines allowing the gas to continue moving through the pipeline to an intended recipient. The main contributing sources of air pollution include nitrogen oxides (NOX), carbon monoxide (CO), and sulfur dioxide (SO2).

1.3 Description of the activities allowed by this permit action This permit action is Major Amendment for construction of a turbine (EQUI 4), an emergency generator (EQUI 5) to replace diesel emergency engine (EQUI 1), and two process heaters (EQUI 6 and 7). With the addition of the new emission units, the facility potential to emit (PTE) for NOX, CO, and SO2 exceeds Part 70 permit thresholds. Limits on emissions of NOX, CO, and fuel sulfur content to limit SO2 have been incorporated into the permit so that NNG is a Part 70 synthetic minor source. The MPCA has a combined operating and construction permitting program under Minn. R. ch. 7007, and under Minn. R. 7007.0800. Under that authority, this permit action authorizes construction.

1.4 Facility emissions:

Table 2. Title I emissions summary

Pollutant

Unlimited potential emissions from the modification tons per year (tpy)

Limited potential emissions from the modification (tpy)

NSR/112(g) threshold for new major source (tpy)

NSR/112(g) review required? (yes/no)

PM 8.26 8.26 250 No PM10 8.26 8.26 250 No PM2.5 8.26 8.26 250 No


Pollutant

Unlimited potential emissions from the modification tons per year (tpy)

Limited potential emissions from the modification (tpy)

NSR/112(g) threshold for new major source (tpy)

NSR/112(g) review required? (yes/no)

NOX 34.8 91.5 250 No SO2 47.5 47.5 250 No CO 34.7 91.4 250 No Ozone (VOC) 19.2 19.2 250 No Lead 0.0 0.0 250 No CO2e* 66,019 66,019 75,000 No Single HAP 0.63 0.63 10 No Total HAPs 0.84 0.84 25 No

*Carbon dioxide equivalents as defined in Minn. R. 7007.0100. For CO2e, the existing minor NSR source has a CO2e PTE less than 100,000 tpy, but with the modification the facility CO2e PTE is greater than 100,000 tpy. See sections 2.1 and 2.2 in the TSD where CO2e major/minor applicability is discussed.

Table 3. Total facility potential to emit summary

PM tpy

PM10 tpy

PM2.5 tpy

SO2 tpy

NOx tpy

CO Tpy

CO2e tpy

VOC tpy

Single HAP tpy

All HAPs tpy

Total Facility Limited Potential Emissions 16.6 16.6 16.6 95.0 93.8 92.1 131,512 39.2 1.00 1.39 Total Facility Actual Emissions (2014) 0.044 0.077 0.077 37.4 77.5 19.9 * 0.832 *

* Not reported in MN emission inventory.

Table 4. Facility classification

Classification Major Synthetic minor/area Minor/area PSD X Part 70 Permit Program X Part 63 NESHAP X

1.5 Changes to permit

The MPCA has a combined operating and construction permitting program under Minnesota Rules Chapter 7007, and under Minn. R. 7007.0800, the MPCA has authority to include additional requirements in a permit. Under that authority, the following changes to the permit are made through this permit action:

· updates to reflect current MPCA templates and standard citation formatting; · completed requirements under SV 001 (STRU 1) and EU 001 (EQUI 2) including initial performance

testing have been deleted (see Attachment 6 to this TSD for performance testing report); · requirements listed under SV 001 (STRU 1) have been moved and are now listed under EQUI 2; · reoccurring performance testing for EQUI 2 is required to be completed every 60 months because

the initial performance test resulted in NOX emissions of 0.00404 % by volume at 15% oxygen, the test result is 26% of the limit, 0.0157% by volume at 15% oxygen; and

· NESHAP 40 CFR pt. 63, subp. ZZZZ requirements have been incorporated into the permit for EQUI 1.

2. Regulatory and/or statutory basis


2.1 New source review (NSR) The existing facility potential to emit (PTE) is less than the major source thresholds for NSR (40 CFR §52.21(b)(1)). NNG has a PTE of 65,493 tpy CO2e; and a PTE after the modification of 131,512 tpy CO2e. The major source threshold is currently 100,000 tpy CO2e. In a memo dated July 24, 2014 (http://www.epa.gov/nsr/documents/20140724memo.pdf), EPA discussed the June 23, 2014 Supreme Court ruling in Utility Air Regulatory Group v. EPA, addressing the application of stationary source permitting requirements for GHG emissions. The EPA stated that it will no longer apply or enforce the requirement to obtain a Prevention of Significant Deterioration (PSD) permit solely because a facility emits or has the potential to emit GHG above major source thresholds. The facility does not require a PSD permit for any pollutant other than CO2e, therefore consistent with the Utility Air Regulatory Group decision; the MPCA will not require the Facility to obtain a PSD permit. Therefore, NNG is a minor source for NSR.

2.2 Part 70 permit program

This permit establishes limits so that NNG is a nonmajor source under the Part 70 permit program.

In the EPA memo referenced in the section above, EPA also stated that it will no longer apply or enforce the requirement to obtain a title V (Part 70) permit solely because a facility emits or has the potential to emit GHG above major source thresholds. Minn. R. 7007.0200, subps. 1 and 2 mirror the major source federal thresholds of 100,000 tpy CO2e. As a result of the June 23, 2014 Supreme Court ruling in Utility Air Regulatory Group v. EPA, the basis for requiring a Part 70 permit due solely to GHG emissions no longer applies. All other regulated pollutants are below State Permitting thresholds. Therefore, at this time the facility is allowed to maintain a State Operating Permit.

2.3 New source performance standards (NSPS)

The New Source Performance Standards for Stationary Gas Turbines (40 CFR pt. 60, subp. GG) applies to EQUI 2 which is a stationary gas turbine with a heat input at peak load equal to or greater than 10 million Btu (MMBtu) per hour, based on the lower heating value of the fuel fired, and commenced construction after October 3, 1977. The New Source Performance Standards for Stationary Combustion Turbines (40 CFR pt. 60, subp. KKKK) applies to EQUI 4 which is a stationary combustion turbine with a heat input at peak load equal to or greater than 10 MMBtu per hour, based on the higher heating value of the fuel, and commenced construction after February 18th, 2005. The New Source Performance Standards for Stationary Spark Ignition Internal Combustion Engines (40 CFR pt. 60, subp. JJJJ) applies to EQUI 5 which is an emergency stationary SI ICE with a maximum engine power greater than 19 KW (25 Hp) that commenced construction after June 12, 2006, and was manufactured on or after January 1, 2009.

2.4 National emission standards for hazardous air pollutants (NESHAP)

National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (40 CFR pt. 63, subp. ZZZZ) applies to EQUIs 1 and 5. NNG is an area source for NESHAPs.

2.5 Compliance assurance monitoring (CAM) CAM does not apply to NNG. CAM only applies at sources required to obtain a permit under 40 CFR pt. 70.

2.8 Environmental review and air emissions risk analysis (AERA)

The proposed modification is not subject to environmental review, i.e. an Environmental Assessment Worksheet (EAW), and is not required to perform an Air Emissions Risk Analysis (AERA).

http://www.epa.gov/nsr/documents/20140724memo.pdf


2.9 Minnesota state rules Portions of the facility are subject to the following Minnesota Standards of Performance:

· Minn. R. 7011.2300 Standards of Performance for Stationary Internal Combustion Engines · Minn. R. 7011.0515 Standards of Performance for Indirect Heating Fossil-Fuel-Burning Equipment

Table 5. Regulatory overview of units affected by the modification/permit amendment

Subject item* Applicable regulations Rationale

COMG 2 (Limits to avoid Part 70)

Limits to avoid major source classification under 40 CFR 70.2

Part 70 Permit Limits on NOX and CO emissions to remain below 40 CFR 70.2 thresholds

EQUI 1 (Emergency Generator)

40 CFR pt. 63, subp. ZZZZ

National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE); the engine is an existing emergency compression ignition stationary RICE less than 500 Hp and construction commenced before June 12, 2006

Minn. R. 7011.2300 Standards of Performance for Stationary Internal Combustion Engines

EQUI 2 (Natural Gas Turbine)


Part 70 Permit Limits on fuel sulfur content to limit SO2 emissions to remain below 40 CFR 70.2 thresholds

40 CFR pt. 60, subp. GG New Source Performance Standards for Stationary Gas Turbines


EQUI 4 (Solar mars Turbine 100-16000S)


Part 70 Permit Limits on fuel sulfur content to limit SO2 emissions to remain below 40 CFR 70.2 thresholds

40 CFR pt. 60, subp. KKKK New Source Performance Standards for Stationary Combustion Turbines


EQUI 5 (Reciprocating IC engine)

40 CFR pt. 63, subp. ZZZZ

National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE); the engine is a new emergency spark ignition stationary RICE greater than 500 Hp and construction commenced after June 12, 2006

40 CFR pt. 60, subp. JJJJ New Source Performance Standards for Stationary Spark Ignition Internal Combustion Engines


EQUI 6 (Heater 1)

Minn. R. 7011.0515 Standards of Performance for Indirect Heating Fossil-Fuel-Burning Equipment

EQUI 7 (Heater 2)

*Location of the requirement in the permit (e.g., EQUI 1, STRU 2, etc.).

3. Technical information

3.1 Calculations of potential to emit Attachment 1 to this TSD contains a summary of the PTE of NNG and detailed spreadsheets and supporting information prepared by the MPCA and the Permittee. Emission factors for EQUIs 1 and 5 are based on AP-42 and manufacturer data. Annual PTE from EQUIs 1 and 5 are based on 500 hours per year because these


are emergency generators. Emission factors for turbines EQUIs 2 and 4 are also based on AP-42 and manufacturer data. EQUIs 2 and 4 also have separate emissions factors and capable engine capacity when the turbines are operating in ambient temperatures that are above and below 0° F. Emission factors and engine capacity when temperatures are less than 0° F are worst case and are used to calculate hourly emissions. Annual average temperatures in Minnesota are above 0° F, therefore annual emissions are calculated using emissions factors for when temperatures are above 0° F. However, because of the difference in emission factors when temperatures are above or below 0° F, emissions that could potentially exceed 100 tons per year based on yearly temperatures are limited to prevent the facility from becoming a Part 70 source (NOX and CO emissions). All manufacturer data used to calculate emissions is listed under Attachment 5 to this TSD.

The total facility emissions of SO2 in the 13100058-003 permit were calculated using the AP-42 Section 3.1, table 3.1-2a standard emission factor of 0.0034 lb/MMBtu. AP-42 also provides an emission factor equation; SO2 in lb/MMBtu = 0.94*S, where S is the sulfur content in the fuel. AP-42 states that the SO2

equation is more accurate than the standard emission factor of 0.0034 lb/MMBtu and the standard emission factor should be used if the sulfur content in the fuel is not available. EQUI 2 has a sulfur content of fuel limit of 0.8% by weight under 40 CFR pt. 60, subp. GG and is required to complete an analysis for fuel sulfur content of natural gas. EQUI 4 is also required to monitor the sulfur content of fuel under 40 CFR pt. 60, subp. KKKK. Therefore, calculating emissions using the SO2 emission factor equation in AP-42 is appropriate. To ensure SO2 emissions remain below Part 70 permitting thresholds, a sulfur content limit of 0.09% by weight is included in the permit for EQUIs 2 and 4. Previous sulfur monitoring records show that NNG will be able to meet a 0.09% by weight sulfur content limit (see Attachment 7 to this TSD).

3.2 Emission Unit Information EQUI 2 is an existing turbine. The permit and permit application for 13100058-003 list EQUI 2 capacity as 16,000 Hp. Updated manufacturer information was provided to NNG (Attachment 5 to this TSD) that when operating at or above 0 degrees Fahrenheit (F), EQUI 2 has a capacity of 16,490 Hp, and when operating below 0 degrees F, EQUI 2 has a capacity of 16,966 Hp. Because the highest capacity the emission unit can operate is at 16,966 Hp, EQUI 2’s capacity has been updated to 16,966 Hp/hr in the MPCA’s database, Tempo. EQUIs 2 and 4 are equipped with a manufacturer technology called SoLoNOx that is used to reduce NOX

emissions. The technology utilizes lean-premixed combustion to ensure uniform air to fuel mixing to prevent NOX emissions from forming. EQUIs 2 and 4 are also equipped with PACO (pilot active control option) logic controls that allow the turbines to remain in SoLoNOx mode operation from 0° F down to -20° F and also enable the turbine to run at minimum pilot. Because the SoLoNOx technology and PACO logic controls are included as part of the turbine combustion system, SoLoNOx and PACO are not included as control equipment for this permit.

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.


· The kind of monitoring found on similar units elsewhere.

The table below summarizes the monitoring requirements associated with this amendment.

Table 6. Monitoring

Subject item* Requirement (rule basis) Monitoring Discussion

COMG 2 (Limits to avoid Part 70)

CO and NOX ≤ 90 tons per year, on a 12 month rolling basis (limits to avoid pt. 70)

Recordkeeping: Daily records of hours of operation and ambient air temperature; Monthly calculations of emissions.

Records can be generated on a daily basis and can be completed using written logs. Emissions can then be calculated monthly. The likelihood of emissions exceeding limits when calculated daily is small, therefore 12-month rolling limits for NNG are reasonable.

EQUI 1 (Emergency Generator)

SO2: ≤ 0.50 lb/MMbtu; Opacity: ≤ 20 % (Minn. R. 7011.2300)

Recordkeeping: Fuel type and usage; fuel supplier certification

This unit uses diesel and the manufacturer has certified emissions. The likelihood of violating either of the emission limits is very small. Since this is a permit condition, the semi-annual deviations report will document any deviations from the applicable conditions. Design based PTE for SO2, using manufacturer data, is 0.20 lb/MMBtu compared to the rule limit of 0.50 lb/MMBtu.

Maintenance and Inspection Requirements (40 CFR pt. 63, subp. ZZZZ)

Recordkeeping: hours of operation, operation and maintenance, certifications, and reports

Monitoring based on the National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines is adequate to demonstrate compliance.

EQUI 2 (Natural Gas Turbine)

NOX: ≤ 0.0157% by volume at 15% O2; SO2: ≤ 0.015% by volume at 15% O2; Sulfur Content of Fuel: ≤ 0.8% by weight (40 CFR pt. 60, subp. GG)

Recordkeeping: Performance testing for NOX, Sample analyses and fuel records for sulfur

Monitoring based on the New Source Performance Standards for Stationary Gas Turbines is adequate to demonstrate compliance.

Sulfur Content of Fuel: ≤ 0.09% by weight (limits to avoid pt. 70)

Recordkeeping: Sample analyses and fuel records for sulfur

NNG shall comply with this limit with monitoring requirements specified in the New Source Performance Standards for Stationary Gas Turbines; previous sulfur monitoring records show that the weight percent of sulfur (H2S) in natural gas at NNG is significantly below the limit.

EQUI 4 (Solar mars Turbine 100-16000S)

NOX: ≤ 25 ppm at 15% O2; SO2: ≤ 110 nanograms per joule; (40 CFR pt. 60, subp. KKKK)

Recordkeeping: Performance testing for NOX, Sample analyses and fuel records for sulfur

Monitoring based on the New Source Performance Standards for Stationary Combustion Turbines is adequate to demonstrate compliance.

Sulfur Content of Fuel: ≤ 0.09% by weight (limits to avoid pt. 70)

Recordkeeping: Sample analyses and fuel records for sulfur

NNG shall comply with this limit with monitoring requirements specified in the New Source Performance Standards for Stationary Gas Turbines; previous sulfur monitoring records show that the weight percent of sulfur (H2S) in natural gas at NNG is significantly below the limit.

EQUI 5 (Reciprocating

NOX: ≤ 2.0 gr/Hp-hr;

Recordkeeping: Performance testing for

Monitoring based on the New Source Performance Standards for Stationary Spark Ignition Internal


Subject item* Requirement (rule basis) Monitoring Discussion

IC engine) CO: ≤ 4.0 gr/Hp-hr; VOC: ≤ 1.0 gr/Hp-hr (40 CFR pt. 60, subp. JJJJ)

NOX, CO, and VOC Combustion Engines is adequate to demonstrate compliance.

SO2: ≤ 0.50 lb/MMBtu; Opacity: ≤ 20 % (Minn. R. 7011.2300) None

This unit uses natural gas; the likelihood of violating either of the emission limits is very small. Since this is a permit condition, the semi-annual deviations report will document any deviations from the applicable conditions. Design based PTE for SO2, using AP-42, is 0.000588 lb/MMBtu compared to the rule limit of 0.50 lb/MMBtu.

EQUI 6 (Heater 1)

PM: ≤ 0.40 lb/MMBtu; Opacity: ≤ 20 % (Minn. R. 7011.0515) None

This unit uses natural gas; the likelihood of violating either of the emission limits is very small. Since this is a permit condition, the semi-annual deviations report will document any deviations from the applicable conditions. Design based PTE for PM, using AP-42, is 0.00745 lb/MMBtu compared to the rule limit of 0.50 lb/MMBtu.

EQUI 7 (Heater 2)

*Location of the requirement in the permit (e.g., EQUI 1, STRU 2, etc.).

3.4 Insignificant activities NNG does not have operations classified as insignificant activities under the MPCA’s permitting rules that are required to be listed.

3.5 Permit organization

In general, the permit meets the MPCA Tempo Guidance for ordering and grouping of requirements. One area where this permit deviates slightly from Tempo 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 the Requirements table in Tempo. 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 for limits to avoid Part 70 (COMG 2), 40 CFR pt. 60, subp. KKKK (EQUI 4), and 40 CFR pt. 60, subp. JJJJ (EQUI 5). These procedures are too complex to enter into Tempo and must go in an appendix.

3.6 Comments received

Public Notice Period: [start date] – [end date] EPA Review Period: [start date] – [end date] This section will be completed after the referenced review periods.

4. Permit fee assessment Attachment 4 to this TSD contains the MPCA’s assessment of Application and Additional Points used to determine the permit application fee for this permit action as required by Minn. R. 7002.0019. The permit action includes only one permit application which was received after the effective date of the rule (July 1, 2009)]. The action includes the incorporation of NESHAP (EQUI 5), NSPS (EQUI 5), and limits to avoid Part 70 (COMG 2) and thus additional fees apply to this permit action.


5. Conclusion Based on the information provided by Northern Natural Gas Co - Faribault Compressor the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 13100058-101 and this TSD, will not cause or contribute to a violation of applicable federal regulations and Minnesota Rules. Staff members on permit team: Andrea Walkush (permit engineer)

Sarah Sevcik (peer reviewer) Beckie Olson (permit writing assistant) Laurie O'Brien (administrative support) Jenna Ness (compliance and enforcement) Curtis Stock (performance testing)

TEMPO360 Activities: Major Amendment (IND20160001), Tracking # 5568

Attachments: 1. PTE summary calculation spreadsheets

2. Requirements development report 3. Subject item inventory/details 4. Points calculator 5. Manufacturer Information and Data to Support PTE Calculations 6. Performance testing report for EQUI 2 7. Sulfur monitoring records

Attachment 1. PTE summary calculation spreadsheets

Alternate Format GI-07 SpreadsheetFacility Emissions Summary

Air Quality Permit ProgramDoc Type: Permit Application

13100058 1b) Agency Interest ID No.:2) Facility Name: Northern Natural Gas Company - Faribault

Emissions by Source Table

3c) 3d) 3f) 3c) 3d) 3f) 3c) 3d) 3f)

Pollutant Name CAS # Lbs per Hr

Unc tpy

Limited tpy

Actual tpy Pollutant Name CAS # Lbs per

HrUnc tpy

Limited tpy


HrUnc tpy

Limited tpy

Actual tpy

NOx 21.32 53.93 90 NOx 21.32 33.31 90 NOx 4.86 1.21 1.21

VOC 8.60 18.88 18.88 VOC 8.60 19.03 19.03 VOC 0.56 0.14 0.14

CO 30.67 65.80 90 CO 30.68 33.31 90 CO 4.52 1.13 1.13

PM 1.91 8.09 8.09 PM 1.92 8.21 8.21 PM 0.08 0.02 0.02PM10 1.91 8.09 8.09 PM10 1.92 8.21 8.21 PM10 0.08 0.02 0.02PM2.5 1.91 8.09 8.09 PM2.5 1.92 8.21 8.21 PM2.5 0.08 0.02 0.02

SO2 10.78 47.22 47.22 SO2 10.85 47.52 47.52 SO2 0.005 0.001 0.001

1,3-Butadiene 0.00 0.00 0.00 1,3-Butadiene 0.00 0.00 0.00 1,3-Butadiene -- -- --

Acetaldehyde 0.002 0.001 0.001 Acetaldehyde 0.005 0.022 0.022 Acetaldehyde 0.07 0.02 0.02

Acrolein 0.000 0.000 0.000 Acrolein 0.001 0.004 0.004 Acrolein 0.04 0.01 0.01

Benzene 0.003 0.001 0.001 Benzene 0.002 0.007 0.007 Benzene 0.003 0.001 0.001

Biphenyl -- -- -- Biphenyl -- -- -- Biphenyl 0.002 0.000 0.000

Carbon Tetrachloride -- -- -- Carbon Tetrachloride -- -- -- Carbon Tetrachloride 0.000 0.000 0.000

Chlorobenzene -- -- -- Chlorobenzene -- -- -- Chlorobenzene 0.000 0.000 0.000

Chloroform -- -- -- Chloroform -- -- -- Chloroform 0.000 0.000 0.000

Ethylbenzene 0.004 0.017 0.017 Ethylbenzene 0.004 0.018 0.018 Ethylbenzene 0.000 0.000 0.000

Ethylene Dibromide -- -- -- Ethylene Dibromide -- -- -- Ethylene Dibromide 0.000 0.000 0.000

Formaldehyde 0.090 0.383 0.383 Formaldehyde 0.091 0.389 0.389 Formaldehyde 0.923 0.231 0.231

n-Hexane -- -- -- n-Hexane -- -- -- n-Hexane 0.009 0.002 0.002

Methanol -- -- -- Methanol -- -- -- Methanol 0.02 0.00 0.00

Methylene Chloride -- -- -- Methylene Chloride -- -- -- Methylene Chloride 0.00 0.00 0.00

Naphthalene 0.000 0.001 0.001 Naphthalene 0.000 0.001 0.001 Naphthalene 0.00 0.00 0.00

Phenol -- -- -- Phenol -- -- -- Phenol 0.00 0.00 0.00

POM 0.000 0.001 0.001 POM 0.000 0.001 0.001 POM 0.00 0.00 0.00

Propylene Oxide 0.004 0.016 0.016 Propylene Oxide 0.004 0.016 0.016 Propylene Oxide -- -- --

Styrene -- -- -- Styrene -- -- -- Styrene 0.00 0.00 0.00

Toluene 0.02 0.07 0.07 Toluene 0.02 0.07 0.07 Toluene 0.003 0.001 0.001

Vinyl Chloride -- -- -- Vinyl Chloride -- -- -- Vinyl Chloride 0.00 0.00 0.00

Xylene 0.01 0.03 0.03 Xylene 0.01 0.04 0.04 Xylene 0.001 0.000 0.000

Total HAP 0.13 0.55 0.55 Total HAP 0.13 0.56 0.56 Total HAP 1.07 0.27 0.27CO2 14,908 65,296 65,296 CO2 15,001 65,702 65,702 CO2 910 227 0

Methane 0.28 1.23 1.23 Methane 0.28 1.24 1.24 Methane 0.02 0.00 0.00N2O 0.03 0.12 0.12 N2O 0.03 0.12 0.12 N2O 0.00 0.00 0.00CO2e 14,923 65,364 65,364 CO2e 15,016 65,770 65,770 CO2e 911 228 228

5)

1a) AQ Facility ID No.:

You may use and submit this spreadsheet in place of Form GI-07. Follow the instructions for Form GI-07 to complete this spreadsheet. This spreadsheet can be copied into a tab for your emissions spreadsheet and must be submitted on a CD with your application. If you need to provide emissions information for more emissions units, add more sets of columns (3a through 3f) to the right as needed in the Emissions by Source table. If you need to provide information for more pollutants, add rows as needed.

3a) Delta ID No.: EU 001 3a) Delta ID No.: 3a) Delta ID No.:

3b) Tempo SI ID No.: EQUI 2 3b) Tempo SI ID No.: EQUI 4 3b) Tempo SI ID No.: EQUI 5

3e) Potential 3e) Potential 3e) Potential

Application is being submitted on paper, and editable calculation spreadsheet(s) are included on an enclosed CD.

Application is being submitted on a compact disc (CD), and the editable calculation spreadsheet(s) are included on the CD.

Page 1 of 3

Alternate Format GI-07 SpreadsheetFacility Emissions Summary

Air Quality Permit ProgramDoc Type: Permit Application

13100058 1b) Agency Interest ID No.: 0 1a) AQ Facility ID No.: 13100058

2) Facility Name: Northern Natural Gas Company - Faribault 2) Facility Name: Northern Natural Gas Company - Faribault

Emissions by Source Table

Emissions Summary Table

3c) 3d) 3f) 3c) 3d) 3f) 3c) 3d) 3f) 4a) Potential (lb/hr) 4c) Actual

Pollutant Name CAS # Lbs per Hr

Unc tpy

Limited tpy


HrUnc tpy

Limited tpy


HrUnc tpy

Limited tpy

Actual tpy Pollutant Name Hourly Unrestricted Limited tons/year

NOx NOx NOx NOx 47.5 88.5 91.2

VOC 0.18 0.78 0.78 VOC 0.07 0.31 0.31 VOC 0.003 0.014 0.014 VOC 18.0 39.1 39.1

CO CO CO CO 65.9 100.2 91.1

PM PM PM PM 3.9 16.3 16.3

PM10 PM10 PM10 PM10 3.9 16.3 16.3

PM2.5 PM2.5 PM2.5 PM2.5 3.9 16.3 16.3

SO2 SO2 SO2 SO2 21.6 94.7 94.7

1,3-Butadiene 0.00 0.00 0.00Acetaldehyde 0.07 0.04 0.04

Acrolein 0.04 0.01 0.01Benzene 0.01 0.01 0.01Biphenyl 0.00 0.00 0.00

Carbon Tetrachloride 0.00 0.00 0.00Chlorobenzene 0.00 0.00 0.00

Chloroform 0.00 0.00 0.00Ethylbenzene 0.01 0.03 0.03

Ethylene Dibromide 0.00 0.00 0.00Formaldehyde 1.10 1.00 1.00

n-Hexane 0.01 0.00 0.00Methanol 0.02 0.00 0.00

Methylene Chloride 0.00 0.00 0.00Naphthalene 0.00 0.00 0.00

Phenol 0.00 0.00 0.00POM 0.00 0.00 0.00

Propylene Oxide 0.01 0.03 0.03Styrene 0.00 0.00 0.00Toluene 0.04 0.14 0.14

Vinyl Chloride 0.00 0.00 0.00Xylene 0.02 0.07 0.07

Total HAP 1.33 1.38 1.38CO2 30,818 131,226 130,999

Methane 0.58 2.47 2.47N2O 0.06 0.25 0.25CO2e 30,850 131,362 131,362

1a) AQ Facility ID No.:

3a) Delta ID No.: FS 001 3a) Delta ID No.: FS 002

3b) Tempo SI ID No.: FUGI 3 3b) Tempo SI ID No.: FUGI 2

3e) Potential 3e) Potential 4b) Potential (tons/year)

3a) Delta ID No.: FS 003

3b) Tempo SI ID No.: FUGI 1

3e) Potential

Page 2 of 3

FACILITY-WIDE POTENTIAL EMISSIONS SUMMARYFARIBAULT COMPRESSOR STATION

NORTHERN NATURAL GAS COMPANY

Emission GHGUnit NOx VOC CO SO2 CO2e

Emissions Source ID (lb/hr) (tpy)Limited

(tpy) (lb/hr) (tpy)Limited








(tpy)Caterpiller 3406B Emergency Generator EQUI 1 9.31 2.33 2.33 0.16 0.04 0.04 2.77 0.69 0.69 0.82 0.21 0.21 -- -- -- 0.64 0.16 0.16 515 129 129 -- -- -- 1.22E-02 3.05E-03 3.05E-03Solar Mars 100-T15000S Turbine EQUI 2 21.3 53.9 8.60 18.9 18.9 30.7 66 1.91 8.09 8.09 -- -- -- 10.8 47 47 14,923 65,364 65,364 -- -- -- 1.31E-01 5.54E-01 5.54E-01Solar Mars 100-16000S Turbine EQUI 4 21.3 33.3 8.60 19.0 19.0 30.7 33 1.92 8.21 8.21 -- -- -- 10.8 48 48 15,016 65,770 65,770 -- -- -- 1.32E-01 5.62E-01 5.62E-01Caterpillar G3512 Emergency Generator EQUI 5 4.86 1.21 1.21 0.56 0.14 0.14 4.52 1.13 1.13 0.08 0.02 0.02 -- -- -- 0.005 0.001 0.001 911 228 228 -- -- -- 1.07 2.67E-01 2.67E-01Heater 1 EQUI 6 0.04 0.15 0.15 0.00 0.01 0.01 0.03 0.13 0.13 0.00 0.01 0.01 0.00 0.00 0.00 0.000 0.001 0.001 42 10 10 -- -- --Heater 2 EQUI 7 0.04 0.15 0.15 0.00 0.01 0.01 0.03 0.13 0.13 0.00 0.01 0.01 0.00 0.00 0.00 0.000 0.001 0.001 42 10 10 -- -- --Fugitive VOC Emissions - Valves FUGI 3 -- -- -- 0.18 0.78 0.78 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Compressor Seal FUGI 2 -- -- -- 0.07 0.31 0.31 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Flanges FUGI 1 -- -- -- 0.003 0.01 0.01 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --

Total Facility Emissions 56.9 91.1 93.8 18.2 39.2 39.2 68.7 101 92.1 4.74 16.6 16.6 0.0 0.0 0.0 22.3 95 95 31,449 131,512 131,512 1.11 1.00 1.00 1.34 1.39 1.39

Title I Emission Increases 34.83 91.52 19.19 34.70 91.39 8.26 47.52 66,019 6.25E-01 8.35E-01Emission

Unit 1,3-Butadiene Acetaldehyde Beryllium Biphenyl Cadmium Carbon Tetrachloride










(tpy)

Caterpiller 3406B Emergency Generator EQUI 1 1.23E-04 3.08E-05 3.08E-05 2.42E-03 6.04E-04 6.04E-04 2.91E-04 7.28E-05 7.28E-05 -- -- -- 2.94E-03 7.35E-04 7.35E-04 -- -- -- -- -- -- -- -- -- -- -- --Solar Mars 100-T15000S Turbine EQUI 2 5.48E-05 2.32E-04 2.32E-04 5.10E-03 2.16E-02 2.16E-02 8.16E-04 3.45E-03 3.45E-03 -- -- -- 1.53E-03 6.47E-03 6.47E-03 -- -- -- -- -- -- -- -- -- -- -- --Solar Mars 100-16000S Turbine EQUI 4 5.51E-05 2.35E-04 2.35E-04 5.13E-03 2.19E-02 2.19E-02 8.21E-04 3.50E-03 3.50E-03 -- -- -- 1.54E-03 6.57E-03 6.57E-03 -- -- -- -- -- -- -- -- -- -- -- --Caterpillar G3512 Emergency Generator EQUI 5 -- -- -- 6.50E-02 1.63E-02 1.63E-02 4.00E-02 1.00E-02 1.00E-02 -- -- -- 3.42E-03 8.56E-04 8.56E-04 -- -- -- 1.65E-03 4.12E-04 4.12E-04 -- -- -- 2.85E-04 7.14E-05 7.14E-05Heater 1 EQUI 6 -- -- -- -- -- -- -- -- -- 7.03E-08 3.08E-07 3.08E-07 7.38E-07 3.23E-06 3.23E-06 4.22E-09 1.85E-08 1.85E-08 -- -- -- 3.86E-07 1.69E-06 1.69E-06 -- -- --Heater 2 EQUI 7 -- -- -- -- -- -- -- -- -- 7.38E-07 3.23E-06 3.23E-06 7.03E-08 3.08E-07 3.08E-07 4.22E-09 1.85E-08 1.85E-08 -- -- -- 4.92E-07 1.69E-06 2.15E-06 -- -- --Fugitive VOC Emissions - Valves FUGI 3 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Compressor Seal FUGI 2 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Flanges FUGI 1 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --

Total Facility Emissions 0.00 0.00 0.00 0.08 0.06 0.06 0.04 0.02 0.02 0.01 0.01 0.01 0.00 0.000 0.000 0.00 0.000 0.000 0.00 0.00 0.00 0.00 0.00 0.00

EmissionUnit Formaldehyde










(tpy)

Caterpiller 3406B Emergency Generator EQUI 1 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 3.72E-03 9.29E-04 9.29E-04 -- -- --Solar Mars 100-T15000S Turbine EQUI 2 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 4.08E-03 1.73E-02 1.73E-02 -- -- -- 9.05E-02 3.83E-01 3.83E-01 -- -- --Solar Mars 100-16000S Turbine EQUI 4 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 4.10E-03 1.75E-02 1.75E-02 -- -- -- 9.10E-02 3.89E-01 3.89E-01 -- -- --Caterpillar G3512 Emergency Generator EQUI 5 2.36E-04 5.91E-05 5.91E-05 2.22E-04 5.54E-05 5.54E-05 -- -- -- -- -- -- -- -- -- 3.09E-04 7.72E-05 7.72E-05 3.45E-04 8.62E-05 8.62E-05 9.23E-01 2.31E-01 2.31E-01 -- -- --Heater 1 EQUI 6 -- -- -- -- -- -- 4.92E-07 2.15E-06 2.15E-06 2.95E-08 1.29E-07 1.29E-07 4.22E-07 1.85E-06 1.85E-06 -- -- -- -- -- -- 2.63E-05 1.15E-04 1.15E-04 6.32E-04 2.77E-03 2.77E-03Heater 2 EQUI 7 -- -- -- -- -- -- 3.86E-07 1.69E-06 1.69E-06 2.95E-08 1.29E-07 1.29E-07 9.13E-08 4.00E-07 4.00E-07 -- -- -- -- -- -- 2.14E-07 9.39E-07 9.39E-07 7.38E-07 3.23E-06 3.23E-06Fugitive VOC Emissions - Valves FUGI 3 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Compressor Seal FUGI 2 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Flanges FUGI 1 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --

Total Facility Emissions 0.00 0.000 0.000 0.00 0.00 0.00 0.00 0.000 0.000 0.00 0.00 0.00 0.00 0.000 0.000 0.01 0.035 0.035 0.000 0.000 0.000 1.108 1.003 1.003 0.001 0.003 0.003

EmissionUnit Phenol POM










(tpy)

Caterpiller 3406B Emergency Generator EQUI 1 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 5.29E-04 1.32E-04 1.32E-04Solar Mars 100-T15000S Turbine EQUI 2 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 1.66E-04 7.01E-04 7.01E-04 -- -- -- -- -- -- 2.80E-04 1.19E-03 1.19E-03Solar Mars 100-16000S Turbine EQUI 4 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 1.67E-04 7.12E-04 7.12E-04 -- -- -- -- -- -- 2.82E-04 1.20E-03 1.20E-03Caterpillar G3512 Emergency Generator EQUI 5 8.63E-03 2.16E-03 2.16E-03 -- -- -- -- -- -- 1.94E-02 4.86E-03 4.86E-03 1.56E-04 3.89E-05 3.89E-05 5.79E-04 1.45E-04 1.45E-04 -- -- -- 1.87E-04 4.67E-05 4.67E-05 4.29E-04 1.07E-04 1.07E-04Heater 1 EQUI 6 -- -- -- 1.33E-07 5.85E-07 5.85E-07 9.13E-08 4.00E-07 4.00E-07 -- -- -- -- -- -- 2.14E-07 9.39E-07 9.39E-07 7.38E-07 3.23E-06 3.23E-06 -- -- -- -- -- --Heater 2 EQUI 7 -- -- -- 4.22E-07 1.85E-06 1.85E-06 2.63E-05 1.15E-04 1.15E-04 -- -- -- -- -- -- 6.67E-07 2.92E-06 2.92E-06 6.32E-04 2.77E-03 2.77E-03 -- -- -- -- -- --Fugitive VOC Emissions - Valves FUGI 3 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Compressor Seal FUGI 2 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Flanges FUGI 1 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --

Total Facility Emissions 0.009 0.002 0.002 0.000 0.000 0.000 0.000 0.000 0.000 0.019 0.005 0.005 0.000 0.000 0.000 0.001 0.002 0.002 0.001 0.003 0.003 0.000 0.000 0.00 0.00 0.00 0.00

EmissionUnit







(tpy)

Caterpiller 3406B Emergency Generator EQUI 1 -- -- -- -- -- -- -- -- -- 1.29E-03 3.22E-04 3.22E-04 -- -- -- 8.98E-04 2.24E-04 2.24E-04Solar Mars 100-T15000S Turbine EQUI 2 3.70E-03 1.56E-02 1.56E-02 -- -- -- -- -- -- 1.66E-02 7.01E-02 7.01E-02 -- -- -- 8.16E-03 3.45E-02 3.45E-02Solar Mars 100-16000S Turbine EQUI 4 3.72E-03 1.59E-02 1.59E-02 -- -- -- -- -- -- 1.67E-02 7.12E-02 7.12E-02 -- -- -- 8.21E-03 3.50E-02 3.50E-02Caterpillar G3512 Emergency Generator EQUI 5 -- -- -- -- -- -- 1.84E-04 4.59E-05 4.59E-05 3.17E-03 7.93E-04 7.93E-04 1.16E-04 2.90E-05 2.90E-05 1.43E-03 3.58E-04 3.58E-04Heater 1 EQUI 6 -- -- -- 8.43E-09 3.69E-08 3.69E-08 -- -- -- 1.19E-06 5.23E-06 5.23E-06 -- -- -- -- -- --Heater 2 EQUI 7 -- -- -- 1.33E-07 5.85E-07 5.85E-07 -- -- -- 8.43E-09 3.69E-08 3.69E-08 -- -- -- -- -- --Fugitive VOC Emissions - Valves FUGI 3 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Compressor Seal FUGI 2 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Fugitive VOC Emissions - Flanges FUGI 1 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --

Total Facility Emissions 0.01 0.03 0.03 0.00 0.00 0.00 0.00 0.00 0.00 0.04 0.14 0.14 0.00 0.00 0.00 0.02 0.07 0.07

Hazardous Air Pollutants

n-Hexane Methylene Chloride

Ethylbenzene Ethylene Dibromide

Manganese Mercury Methanol Nickel

Chromium

Propylene Oxide Styrene Toluene Vinyl Chloride XyleneSelenium

Hexane



NaphthaleneHazardous Air Pollutants

Chlorobenzene DichlorobenzeneChloroform

Benzene

Cobalt

Acrolein Arsenic

HAPsSingle- HAP

90 90

PM/PM10/PM2.5 LeadCriteria Pollutants

Total HAP

NNG PTE.xlsx Page 1 of 1 PTE Summary

EQUI 1, STRU 2POTENTIAL EMISSIONS SUMMARY

CATERPILLAR 3406B EMERGENCY GENERATORFARIBAULT COMPRESSOR STATION

NORTHERN NATURAL GAS COMPANYCapacity

450 Hp 140,000 Btu/gal7,000 Btu/hp-hr

Potential Emission Rate 3 GHG EmissionsPollutant (lb/hr) 1 (lb/MMBtu) 2 (lb/hr) (tpy) (kg/MMBtu) (lb/MMBtu) GWP (lb/hr) (tpy)

NOx 9.31 -- 9.31 2.33 CO21 73.96 163.05 1 514 128.40

VOC 0.16 -- 0.16 0.04 Methane2 0.003 0.0066 25 0.02 0.005 CO 2.77 -- 2.77 0.69 N2O2

0.0006 0.00132 298 0.004 0.0010 PM/PM10/PM2.5

4 0.82 -- 0.82 0.21 CO2e 515 129 SO2 0.64 -- 0.64 0.16

ACETALDEHYDE -- 7.7E-04 2.42E-03 6.04E-04 Notes:ACROLEIN -- 9.3E-05 2.91E-04 7.28E-05 1. Emission factor based on 40 CFR 98, Subpart C, Table C-1.BENZENE -- 9.3E-04 2.94E-03 7.35E-04 2. Emission factor based on 40 CFR 98, Subpart C, Table C-2.

1,3-BUTADIENE -- 3.9E-05 1.23E-04 3.08E-05FORMALDEHYDE -- 1.2E-03 3.72E-03 9.29E-04

POM -- 1.7E-04 5.29E-04 1.32E-04TOLUENE -- 4.1E-04 1.29E-03 3.22E-04XYLENE -- 2.9E-04 8.98E-04 2.24E-04

SINGLE HAP -- -- 3.72E-03 9.29E-04TOTAL HAP -- -- 1.22E-02 3.05E-03

Notes:1. Emission factors for NOX, VOC, CO, PM/PM10/PM2.5, and SO2 obtained from manufacturer data.2. Emissions factors are based on AP-42 factors (AP-42 Section 3.3 Gasoline and Diesel Industrial Engines, Table 3.3-2). 3. Potential emissions based on manufacturer emission factors, maximum horsepower, and 500 hours per year for emergency engines4. Emission factor shown is for PM. It is conservatively assumed that PM = PM10 = PM2.5.

Emission Factors PollutantEmission Factor

NNG PTE.xlsx Page 1 of 10 EQUI 1


SOLAR MARS 100-T15000S TURBINEFARIBAULT COMPRESSOR STATION

NORTHERN NATURAL GAS COMPANYBTU/scf scfm exhaust Hp MMBtu/hr

Above 0° F 939.2 2,185 16,490 123Below 0° F 939.2 2,262 16,966 127

Potential Emission Rate 4,5 Limited PTE GHG Emissions Limited PTE(grams/Hp-hr) (lb/MMBtu) (lb/hr) (tpy) (tpy) (kg/MMBtu) (lb/MMBtu) GWP (lb/hr) (tpy) (tpy)

NOx 0.57 0.10 21.3 53.9 1c CO21 53.06 116.98 1 14,908 65,296 65,296

VOC 0.23 0.035 8.60 18.9 18.9 Methane2 0.001 0.0022 25 0.28 1.23 1.23CO 0.82 0.122 30.7 65.8 1c N2O2

0.0001 0.00022 298 0.03 0.12 0.12PM/PM10/PM2.5

6 -- 0.015 1.91 8.09 8.09 CO2e 14,923 65,364 65,364

SO2 -- 0.0846 10.8 47.2 47.21-3-BUTADIENE -- 4.3E-07 5.48E-05 2.32E-04 2.32E-04 Notes:ACETALDEHYDE -- 4.0E-05 5.10E-03 2.16E-02 2.16E-02 1. Emission factor based on 40 CFR 98, Subpart C, Table C-1.

ACROLEIN -- 6.4E-06 8.16E-04 3.45E-03 3.45E-03 2. Emission factor based on 40 CFR 98, Subpart C, Table C-2.BENZENE -- 1.2E-05 1.53E-03 6.47E-03 6.47E-03

ETHYLBENZENE -- 3.2E-05 4.08E-03 1.73E-02 1.73E-02FORMALDEHYDE -- 7.1E-04 9.05E-02 3.83E-01 3.83E-01NAPHTHALENE -- 1.3E-06 1.66E-04 7.01E-04 7.01E-04

POM -- 2.2E-06 2.80E-04 1.19E-03 1.19E-03PROPYLENE OXIDE -- 2.9E-05 3.70E-03 1.56E-02 1.56E-02

TOLUENE -- 1.3E-04 1.66E-02 7.01E-02 7.01E-02XYLENE -- 6.4E-05 8.16E-03 3.45E-02 3.45E-02

SINGLE HAP -- -- 9.05E-02 3.83E-01 3.83E-01TOTAL HAP -- -- 1.31E-01 5.54E-01 5.54E-01

Notes:1. Emission factors for NOX, CO, and VOC obtained from manufacturer data

1a. Emission factors in gr/HP-hr are for emissions when temperatures are less than 0° F, these emission factors are worst case and are used to calculate hourly emissions1b. Annual average temperatures are above 0° F, therfore annual emissions are calcuated using emissions factors for when temperatures are above 0° F. 1c. To ensure compliance with NOX and CO, a 90 tpy limit is included in this permit (COMG 2) with monthly calculations and recordkeeping using applicable emissions factors based on ambient temperatur2. Emission factors for SO2 based on AP-42 (AP-42 Section 3.1 - Stationary Gas Turbines, Table 3.1-2a). Sulfur content is limited to 0.09% by weight3. Emission factors for HAPs based on AP-42 factors (AP-42 Section 3.1 - Stationary Gas Turbines, Table 3.1-3). 4. Potential emissions based on worst case emission factors, maximum horsepower or maximum MMBtu/hr rating5. The turbine is equipped with SoLoNOx to minimize emissions, and PACO logic emissions controls minimize emissions when ambient temperatures are less than 0 degrees F.6. Emission factor for PM based on manufacturer recommendations. PM = PM10 = PM2.5 is assumed

PollutantEmission FactorEmission Factors 1,2,3

Pollutant



SOLAR MARS 100-T15000S TURBINEFARIBAULT COMPRESSOR STATION


BTU/scf scfm exhaust MMBtu/hrAbove 0° F 939.2 2,218 16,427 125Below 0° F 939.2 2,276 16,969 128

Potential Emission Rate 4,5 Limited PTE

temp < 0° F temp > 0° F GHG Emissions Limited PTE

Pollutant (grams/Hp-hr) (grams/Hp-hr) (lb/MMBtu) (lb/hr) (tpy) (tpy) (kg/MMBtu) (lb/MMBtu) GWP (lb/hr) (tpy) (tpy)

NOx 0.57 0.21 -- 21.32 33.3 1c CO21 53.06 116.98 1 15,001 65,702 65,702

VOC 0.23 0.12 -- 8.60 19.0 19.0 Methane2 0.001 0.0022 25 0.28 1.24 1.24CO 0.82 0.21 -- 30.68 33.3 1c N2O2

0.0001 0.00022 298 0.03 0.12 0.12PM/PM10/PM2.5

6 -- -- 0.015 1.92 8.21 8.21 CO2e 15,016 65,770 65,770

SO2 -- -- 0.0846 10.85 47.5 47.51-3-BUTADIENE -- -- 4.3E-07 5.51E-05 2.35E-04 2.35E-04 Notes:

ACETALDEHYDE -- -- 4.0E-05 5.13E-03 2.19E-02 2.19E-02 1. Emission factor based on 40 CFR 98, Subpart C, Table C-1.ACROLEIN -- -- 6.4E-06 8.21E-04 3.50E-03 3.50E-03 2. Emission factor based on 40 CFR 98, Subpart C, Table C-2.BENZENE -- -- 1.2E-05 1.54E-03 6.57E-03 6.57E-03

ETHYLBENZENE -- -- 3.2E-05 4.10E-03 1.75E-02 1.75E-02FORMALDEHYDE -- -- 7.1E-04 9.10E-02 3.89E-01 3.89E-01NAPHTHALENE -- -- 1.3E-06 1.67E-04 7.12E-04 7.12E-04

POM -- -- 2.2E-06 2.82E-04 1.20E-03 1.20E-03PROPYLENE OXIDE -- -- 2.9E-05 3.72E-03 1.59E-02 1.59E-02

TOLUENE -- -- 1.3E-04 1.67E-02 7.12E-02 7.12E-02XYLENE -- -- 6.4E-05 8.21E-03 3.50E-02 3.50E-02

SINGLE HAP -- -- -- 9.10E-02 3.89E-01 3.89E-01TOTAL HAP -- -- -- 1.32E-01 5.62E-01 5.62E-01

Notes:1. Emission factors for NOX, CO, and VOC obtained from manufacturer data1a. Emission factors when temperatures are less than 0° F are worst case and are used to calculate hourly emissions1b. Annual average temperatures are above 0° F, therefore annual emissions are calcuated using emissions factors for when temperatures are above 0° F.

(Emission factors for NOX, CO, and VOC emissions when tempertures are greater than 0° F are 0.21, 0.21, and 0.12 respectively)1c. To ensure compliance with NOX and CO, a 90 tpy limit is included in this permit (COMG 2) with monthly calculations and recordkeeping using applicable emissions factors based on ambient temperatures2. Emission factors for SO2 based on AP-42 (AP-42 Section 3.1 - Stationary Gas Turbines, Table 3.1-2a). Sulfur content is limited to 0.09% by weight3. Emission factors for HAPs based on AP-42 factors (AP-42 Section 3.1 - Stationary Gas Turbines, Table 3.1-3). 4. Potential emissions based on worst case emission factors, maximum horsepower or maximum MMBtu/hr rating5. The turbine is equipped with SoLoNOx to minimize emissions, and PACO logic emissions controls minimize emissions when ambient temperatures are less than 0 degrees F.6. Emission factor for PM based on manufacturer recommendations. PM = PM10 = PM2.5 is assumed

Emission Factors 1,2,3

PollutantEmission Factor



CATERPILLAR G3512 EMERGENCY GENERATORFARIBAULT COMPRESSOR STATION

NORTHERN NATURAL GAS COMPANYCapacity

1,102 Hp 939.2 Btu/scf 905 scfm exhaust7.8 MMBtu/hr 7059 Btu/hp-hr (per Cat spec sheet)

Potential Emission Rate 4 GHG EmissionsPollutant (grams/Hp-hr) 1 (lb/MMBtu) 2,3 (lb/hr) (tpy) (kg/MMBtu) (lb/MMBtu) GWP (lb/hr) (tpy)

NOx 2.00 -- 4.86 1.21 CO21 53.06 116.98 1 910 227.49

VOC 0.23 -- 0.56 0.14 Methane2 0.001 0.0022 25 0.02 0.004 CO 1.86 -- 4.52 1.13 N2O2

0.0001 0.00022 298 0.002 0.0004 PM/PM10/PM2.5

5 -- 0.011 0.08 0.02 CO2e 911 228 SO2 -- 0.000588 0.00457 0.00114

ACETALDEHYDE -- 8.4E-03 6.50E-02 1.63E-02 Notes:ACROLEIN -- 5.1E-03 4.00E-02 1.00E-02 1. Emission factor based on 40 CFR 98, Subpart C, Table C-1.BENZENE -- 4.4E-04 3.42E-03 8.56E-04 2. Emission factor based on 40 CFR 98, Subpart C, Table C-2.BIPHENYL -- 2.1E-04 1.65E-03 4.12E-04

CARBON TETRACHLORIDE -- 3.7E-05 2.85E-04 7.14E-05CHLOROBENZENE -- 3.0E-05 2.36E-04 5.91E-05

CHLOROFORM -- 2.9E-05 2.22E-04 5.54E-05ETHYLBENZENE -- 4.0E-05 3.09E-04 7.72E-05

ETHYLENE DIBROMIDE -- 4.4E-05 3.45E-04 8.62E-05FORMALDEHYDE 0.38 -- 9.23E-01 2.31E-01

N-HEXANE -- 1.1E-03 8.63E-03 2.16E-03METHANOL -- 2.5E-03 1.94E-02 4.86E-03

METHYLENE CHLORIDE -- 2.0E-05 1.56E-04 3.89E-05NAPHTHALENE -- 7.4E-05 5.79E-04 1.45E-04

PHENOL -- 2.4E-05 1.87E-04 4.67E-05POM -- 5.5E-05 4.29E-04 1.07E-04

STYRENE -- 2.4E-05 1.84E-04 4.59E-05TOLUENE -- 4.1E-04 3.17E-03 7.93E-04

VINYL CHLORIDE -- 1.5E-05 1.16E-04 2.90E-05XYLENE -- 1.8E-04 1.43E-03 3.58E-04

SINGLE HAP -- -- 9.23E-01 2.31E-01TOTAL HAP -- -- 1.07E+00 2.67E-01

Notes:1. Emission factors for NOX, CO, VOC, and Formaldehyde obtained from manufacturer data.2. Emissions factors for SO2 and PM are based on AP-42 factors (AP-42 Section 3.2 - 4-Stroke Lean-Burn Engines, Table 3.2-2). 3. Potential HAP emissions based on AP-42 factors (AP-42 Section 3.2 - 4-Stroke Lean-Burn Engines, Table 3.2-2). 4. Potential emissions based on manufacturer emission factors, maximum horsepower, and 500 hours per year for emergency engines5. Emission factor shown is for PM. It is conservatively assumed that PM = PM 10 = PM2.5.

Emission Factors PollutantEmission Factor


POTENTIAL EMISSIONS SUMMARYEQUI 6, STRU 5

FARIBAULT COMPRESSOR STATIONNORTHERN NATURAL GAS COMPANY

Capacity0.3583 MMBtu/hr

Emission Factors Potential Emission Rates 2 GHG EmissionsPollutant 1 (lb/MMscf) 1 (lb/hr) (tpy) (kg/MMBtu) (lb/MMBtu) GWP (lb/hr) (tpy)

NOx 100.0 0.035 0.15 CO21 53.06 116.98 1 41.9 10.5

VOC 5.5 0.0019 0.0085 Methane2 0.001 0.0022 25 0.00079 0.0002 CO 84.0 0.030 0.13 N2O2

0.0001 0.00022 298 0.000079 0.00002 PM/PM10/PM2.5 7.6 0.0027 0.012 CO2e 42.0 10.5

SO2 0.6 0.00021 0.00092

LEAD 0.0005 1.76E-07 7.69E-07 Notes:ARSENIC 2.00E-04 7.03E-08 3.08E-07 2. Emission factor based on 40 CFR 98, Subpart C, Table C-2.BENZENE 2.10E-03 7.38E-07 3.23E-06 1. Emission factor based on 40 CFR 98, Subpart C, Table C-1.

BERYLLIUM 1.20E-05 4.22E-09 1.85E-08CADMIUM 1.10E-03 3.86E-07 1.69E-06

CHROMIUM 1.40E-03 4.92E-07 2.15E-06COBALT 8.40E-05 2.95E-08 1.29E-07

DICHLOROBENZENE 1.20E-03 4.22E-07 1.85E-06FORMALDEHYDE 7.50E-02 2.63E-05 1.15E-04

HEXANE 1.80E+00 6.32E-04 2.77E-03MANGANESE 3.80E-04 1.33E-07 5.85E-07

MERCURY 2.60E-04 9.13E-08 4.00E-07NAPTHALENE 6.10E-04 2.14E-07 9.39E-07

NICKEL 2.10E-03 7.38E-07 3.23E-06POM 1.90E-03 6.67E-07 2.92E-06

SELENIUM 2.40E-05 8.43E-09 3.69E-08TOLUENE 3.40E-03 1.19E-06 5.23E-06

SINGLE HAP -- 6.32E-04 2.77E-03TOTAL HAP -- 6.6E-04 2.9E-03

Notes: 1. Emission factors obtained from AP-42 Table 1.4-1 through 1.4-3. 2. Potential emissions based on maximum firing rate of 0.3583 MMBtu/hr, 1,020 Btu/scf fuel heating value, and 8,760 hours of operation per year.



POTENTIAL EMISSIONS SUMMARYEQUI 7, STRU 6


Capacity0.3583 MMBtu/hr

Emission Factors Potential Emission Rates 2 GHG EmissionsPollutant 1 (lb/MMscf) 1 (lb/hr) (tpy) (kg/MMBtu) (lb/MMBtu) GWP (lb/hr) (tpy)

NOx 100.0 0.035 0.15 CO21 53.06 116.98 1 41.9 10.5

VOC 5.5 0.0019 0.0085 Methane2 0.001 0.0022 25 0.00079 0.0002 CO 84.0 0.030 0.13 N2O2

0.0001 0.00022 298 0.000079 0.00002 PM/PM10/PM2.5 7.6 0.0027 0.012 CO2e 42.0 10.5

SO2 0.6 0.00021 0.00092

LEAD 0.0005 1.76E-07 7.69E-07 Notes:ARSENIC 2.00E-04 7.03E-08 3.08E-07 1. Emission factor based on 40 CFR 98, Subpart C, Table C-1.BENZENE 2.10E-03 7.38E-07 3.23E-06 2. Emission factor based on 40 CFR 98, Subpart C, Table C-2.

BERYLLIUM 1.20E-05 4.22E-09 1.85E-08CADMIUM 1.10E-03 3.86E-07 1.69E-06

CHROMIUM 1.40E-03 4.92E-07 2.15E-06COBALT 8.40E-05 2.95E-08 1.29E-07

DICHLOROBENZENE 1.20E-03 4.22E-07 1.85E-06FORMALDEHYDE 7.50E-02 2.63E-05 1.15E-04

HEXANE 1.80E+00 6.32E-04 2.77E-03MANGANESE 3.80E-04 1.33E-07 5.85E-07

MERCURY 2.60E-04 9.13E-08 4.00E-07NAPTHALENE 6.10E-04 2.14E-07 9.39E-07

NICKEL 2.10E-03 7.38E-07 3.23E-06POM 1.90E-03 6.67E-07 2.92E-06

SELENIUM 2.40E-05 8.43E-09 3.69E-08TOLUENE 3.40E-03 1.19E-06 5.23E-06

SINGLE HAP -- 6.32E-04 2.77E-03TOTAL HAP -- 6.64E-04 2.91E-03

Notes: 1. Emission factors obtained from AP-42 Table 1.4-1 through 1.4-3. 2. Potential emissions based on maximum firing rate of 0.3583 MMBtu/hr, 1,020 Btu/scf fuel heating value, and 8,760 hours of operation per year.



POTENTIAL EMISSIONS SUMMARYPROCESS PIPING FUGITIVES


Emission Type of Number of Emission Factors Potential VOC Emission Rates 4

Component Type Unit ID Service 1 Components 1 (lb/hr-component) 2 Percent VOC 3 (lb/hr) (T/yr)

Valves FUGI 3 Gas/Vapor 60 0.059 5.00% 0.18 0.78Compressor Seals FUGI 2 Gas/Vapor 1 1.4 5.00% 0.07 0.31Flanges FUGI 1 Gas/Vapor 115 0.00056 5.00% 0.0032 0.014

Totals: -- -- 176 -- -- 0.25 1.10

Notes: 1. Number of each component and type of service from original permit application for site. 2. Emission factors from MPCA Form EC-14, Table EC-14.1. 3. Percent VOC from representative gas analysis (refer to Table 7) is 1.05%. To estimate emissions conservatively, the VOC content is assumed to be 5%. 4. Emission rates based on 8,760 of operation hours per year.

NNG PTE.xlsx Page 8 of 10 FUGIs

Molecular AverageComponent 1 Weight Mol % 2 Molar Weight 3 Mass % 4

Hydrogen Sulfide 34 0.000% 0.00 0.00%Nitrogen 28 2.850% 0.80 4.59%Carbon Dioxide 44 0.110% 0.05 0.28%Methane 16 90.220% 14.44 83.01%Ethane 30 6.420% 1.93 11.08%Propane 44 0.360% 0.16 0.91%i-Butane 58 0.010% 0.01 0.03%n-Butane 58 0.030% 0.02 0.10%i-Pentane 72 0.000% 0.00 0.00%n-Pentane 72 0.000% 0.00 0.00%Hexanes + 86 0.000% 0.00 0.00%

Totals: 100.00% 17.39 100.00%

5 VOC Totals: 0.40% 0.18 1.05%

Notes: 1. Typical components listed in gas analysis for field gas. 2. Mol % values obtained from the gas analysis from a representative facility. 3. Molar weight = Molecular weight x Mol % /100. 4. Average mass % = Molar weight / Total molar weight. 5. VOC Totals include the following components (C3+): Propane i-Butane n-Butane i-Pentane n-Pentane Hexanes +


EXTENDED GAS ANALYSISFARIBAULT COMPRESSOR STATION

NNG PTE.xlsx Page 9 of 10 Gas Analysis

COMPRESSOR STATIONMINOR SOURCE OPERATING PERMIT APPLICATION

Facility Name (all caps): FARIBAULT COMPRESSOR STATIONCompany Name (all caps): NORTHERN NATURAL GAS COMPANY

COMPRESSOR ENGINE INFORMATION:

Normal Normal Less than 0 <0

EU-# Mfg./model # (EU-#)- all capsMfg./model # - not

all caps HP hrs/yr HP hrs/yr Non-operating hrs

EU 001SOLAR MARS 100-T15000S TURBINE

(EU 001)SolarMars 100-

T15000S Turbine 16,490 6,840 16966 720 hrs below 0 1200 7,5608,040 720 hrs below 08,040 720 hrs below 08,040 720 hrs below 0

EU 003SOLAR MARS 100-16000S TURBINE

(EU 003)SolarMars 100-16000S Turbine 16,427 5,640 16696 720 hrs below 0 2400 6,360

EU 004CATERPILLAR G3512 EMERGENCY

GENERATOR (EU 004)

Caterpillar G3512 Emergency Generator 1,102 500

(MMBTU/hr) (MMBTU/hr) - below 0 Normal Below 0 Normal Below 0EU 001 123.139 127.442 BTU/scf 939.2 939.2 scfm exhaust 2185.17 2261.54EU 003 124.985 128.235 BTU/scf 939.2 939.2 scfm exhaust 2217.93 2275.6EU 004 7.779 BTU/scf 905 -- scfm exhaust -- --

Below 0

EU 001 7,467Btu/hp-hr (per Solar

Turbines Inc.) 7511.629263

EU 003 7,608Btu/hp-hr (per Solar

Turbines, Inc.) 7680.558888

EU 004 7,059Btu/hp-hr (per Cat

spec sheet) --

Emission Factors: Less than 0 Efs verifiedEmission in lb/hr vary depending on elevation and temperature.

Emission Factors Solar provided the lb/hr estimates for NNG (phone conversation with NNG on 12/20/16)EU-# Criteria Pollutant AP-42/Stack Test Normal Less than 0

g/hp-hr lb/hr

EQUI 2 NOxManufacturer Data

lb/MMBtu 0.10 0.57 g/hp-hr 21.1 0.56 0.57

Turbine VOCManufacturer Data

lb/MMBtu 0.035 0.23 g/hp-hr 8.7 0.23 0.24

COManufacturer Data

lb/MMBtu 0.122 0.82 g/hp-hr 30.6 0.82 0.83CO2 AP-42 lb/MMBtu 110.00

PMManufacturer

Recommendation? 0.015 Manufacturer data for 0.015 verifiedSO2 AP-42 lb/MMBtu 0.0940

Formaldehyde AP-42 lb/MMBtu 0.00071


g/hp-hr 0.21 0.57 g/hp-hr <0 factors from Beatrice

Turbine VOCManufacturer Data

g/hp-hr 0.12 0.23 g/hp-hr

COManufacturer Data

g/hp-hr 0.21 0.82 g/hp-hrCO2 AP-42 lb/MMBtu 110.00

PMManufacturer

Recommendation 0.015 manufacturer information verified 120 lb 337850 lb 40.542 46 64.308

SO2 AP-42 lb/MMBtu 0.0034 1000000 lb hr 29

Formaldehyde AP-42 lb/MMBtu 0.00071150 337850 50.6775 28 48.93


g/hp-hr 2.00 1000000 29

Generator VOCManufacturer Data

g/hp-hr 0.23

COManufacturer Data

g/hp-hr 1.86 50 337850 16.8925 12 6.99CO2 AP-42 lb/MMBtu 110.00 1000000 29PM AP-42 lb/MMBtu 0.01

SO2 AP-42 lb/MMBtu 0.000588

FormaldehydeManufacturer Data

g/hp-hr 0.38 Verified in Permit application

Verified during permit action -002 and -001

Verified in Permit application

NNG PTE.xlsx Page 10 of 10 EFs and Capacity

Attachment 2. Requirements development report

Subject ItemID Seq. # Requirement

TFAC 1(13100058)

1Permit Appendices: This permit contains appendices as listed in the permit Table of Contents. The Permitteeshall comply with all requirements contained in Appendix A. Emission Calculations for COMG 2, Appendix B.Emission Calculations for EQUI 4, and Appendix C. Emission Calculations for EQUI 5.

3

PERMIT SHIELD: Subject to the limitations in Minn. R. 7007.1800, compliance with the conditions of this permitshall be deemed compliance with the specific provision of the applicable requirement identified in the permit asthe basis of each condition. Subject to the limitations of Minn. R. 7007.1800 and 7017.0100, subp. 2,notwithstanding the conditions of this permit specifying compliance practices for applicable requirements, anyperson (including the Permittee) may also use other credible evidence to establish compliance ornoncompliance with applicable requirements.

This permit shall not alter or affect the liability of the Permittee for any violation of applicable requirements priorto or at the time of permit issuance.

7Circumvention: Do not install or use a device or means that conceals or dilutes emissions, which wouldotherwise violate a federal or state air pollution control rule, without reducing the total amount of pollutantemitted.

8Air Pollution Control Equipment: Operate all pollution control equipment whenever the corresponding processequipment and emission units are operated.

9

Operation and Maintenance Plan: Retain at the stationary source an operation and maintenance plan for all airpollution control equipment. At a minimum, the O & M plan shall identify all air pollution control equipment andcontrol practices and shall include a preventative maintenance program for the equipment and practices, adescription of (the minimum but not necessarily the only) corrective actions to be taken to restore the equipmentand practices to proper operation to meet applicable permit conditions, a description of the employee trainingprogram for proper operation and maintenance of the control equipment and practices, and the records kept todemonstrate plan implementation.

10

Operation Changes: In any shutdown, breakdown, or deviation the Permittee shall immediately take all practicalsteps to modify operations to reduce the emission of any regulated air pollutant. The Commissioner may requirefeasible and practical modifications in the operation to reduce emissions of air pollutants. No emissions unitsthat have an unreasonable shutdown or breakdown frequency of process or control equipment shall bepermitted to operate.

11Fugitive Emissions: Do not cause or permit the handling, use, transporting, or storage of any material in amanner which may allow avoidable amounts of particulate matter to become airborne. Comply with all otherrequirements listed in Minn. R. 7011.0150.

12 Noise: The Permittee shall comply with the noise standards set forth in Minn. R. 7030.0010 to 7030.0080 at alltimes during the operation of any emission units. This is a state only requirement and is not enforceable by theEPA Administrator or citizens under the Clean Air Act.

Minn. R. 7007.0800, subp. 2

Minn. R. 7007.1800, (A)(2)

Minn. R. 7011.0020

Minn. R. 7007.0800, subp. 16(J), Minn.R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 14, Minn. R.7007.0800, subp. 16(J)

Minn. R. 7019.1000, subp. 4

Minn. R. 7011.0150

TSD Requirement (Print version)

Agency Interest Name: Northern Natural Gas Co - Faribault CompressorActivity Number: IND20160001

Subject ItemID Seq. # RequirementTFAC 1(13100058)

11

Fugitive Emissions: Do not cause or permit the handling, use, transporting, or storage of any material in amanner which may allow avoidable amounts of particulate matter to become airborne. Comply with all otherrequirements listed in Minn. R. 7011.0150.

12Noise: The Permittee shall comply with the noise standards set forth in Minn. R. 7030.0010 to 7030.0080 at alltimes during the operation of any emission units. This is a state only requirement and is not enforceable by theEPA Administrator or citizens under the Clean Air Act.

13Inspections: The Permittee shall comply with the inspection procedures and requirements as found in Minn. R.7007.0800, subp. 9(A).

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

15Performance Testing: Conduct all performance tests in accordance with Minn. R. ch. 7017 unless otherwisenoted in this permit.

16

Performance Test Notifications and Submittals:

Performance Test Notification and 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 Test

The Notification, Test Plan, and Test Report must be submitted in a format specified by the commissioner.

17

Limits set as a result of a performance test (conducted before or after permit issuance) apply until supersededas stated in the MPCA's Notice of Compliance letter granting preliminary approval. Preliminary approval is basedon formal review of 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 amendment incorporating the change.

18

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, including the date conducted, and anycorrective action that resulted. The Permittee shall include the calibration frequencies, procedures, andmanufacturer's specifications (if applicable) in the Operations and Maintenance Plan. Any requirements applyingto continuous emission monitors are listed separately in this permit.

19 Operation of Monitoring Equipment: Unless noted elsewhere in this permit, monitoring a process or controlequipment connected to that process is not necessary during periods when the process is shutdown, or duringchecks of the monitoring systems, such as calibration checks and zero and span adjustments. If monitoringrecords are required, they should reflect any such periods of process shutdown or checks of the monitoringsystem.

Minn. R. 7030.0010-7030.0080

Minn. R. 7007.0800, subp. 9(A)

Minn. R. 7007.0800, subp. 16

Minn. R. ch. 7017

Minn. R. 7017.2017, Minn. R.7017.2030, subps. 1-4, Minn. R.7017.2035, subps. 1-2

Minn. R. 7017.2025, subp. 3

Minn. R. 7007.0800, subp. 4(D)




18

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, including the date conducted, and anycorrective action that resulted. The Permittee shall include the calibration frequencies, procedures, andmanufacturer's specifications (if applicable) in the Operations and Maintenance Plan. Any requirements applyingto continuous emission monitors are listed separately in this permit.

19

Operation of Monitoring Equipment: Unless noted elsewhere in this permit, monitoring a process or controlequipment connected to that process is not necessary during periods when the process is shutdown, or duringchecks of the monitoring systems, such as calibration checks and zero and span adjustments. If monitoringrecords are required, they should reflect any such periods of process shutdown or checks of the monitoringsystem.

21

Recordkeeping: Retain all records at the stationary source, unless otherwise specified within this permit, for aperiod of five (5) years from the date of monitoring, sample, measurement, or report. Records which must beretained at this location include all calibration and maintenance records, all original recordings for continuousmonitoring instrumentation, and copies of all reports required by the permit. Records must conform to therequirements listed in Minn. R. 7007.0800, subp. 5(A).

22Recordkeeping: Maintain records describing any insignificant modifications (as required by Minn. R. 7007.1250,subp. 3) or changes contravening permit terms (as required by Minn. R. 7007.1350, subp. 2), including recordsof the emissions resulting from those changes.

23

If the Permittee determines that no permit amendment or notification is required prior to making a change, thePermittee must retain records of all calculations required under Minn. R. 7007.1200. These records shall be keptfor a period of five years from the date that the change was made. The records shall be kept at the stationarysource for the current calendar year of operation and may be kept at the stationary source or office of thestationary source for all other years. The records may be maintained in either electronic or paper format.

24

Shutdown Notifications: Notify the Commissioner at least 24 hours in advance of a planned shutdown of anycontrol equipment or process equipment if the shutdown would cause any increase in the emissions of anyregulated air pollutant. If the owner 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 requiredin the circumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 3.

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

25

Breakdown Notifications: Notify the Commissioner within 24 hours of a breakdown of more than one hourduration of any control equipment or process equipment if the breakdown causes any increase in the emissionsof 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 not required in thecircumstances 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 operator shall inform the Commissionerof the cause of the breakdown and the estimated duration. The owner or operator shall notify the Commissionerwhen the breakdown is over.

26Notification of Deviations Endangering Human Health or the Environment: As soon as possible after discovery,notify the Commissioner or the state duty officer, either orally or by facsimile, of any deviation from permitconditions which could endanger human health or the environment.

27 Notification of Deviations Endangering Human Health or the Environment Report: Within 2 working days ofdiscovery, notify the Commissioner in writing of any deviation from permit conditions which could endangerhuman health or the environment. 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 corrected;3. whether or not the deviation has been corrected;4. the anticipated time by which the deviation is expected to be corrected, if not yet corrected; and5. steps taken or planned to reduce, eliminate, and prevent reoccurrence of the deviation.

Minn. R. 7007.0800, subp. 4(D)

Minn. R. 7007.0800, subp. 5(C)

Minn. R. 7007.0800, subp. 5(B)

Minn. R. 7007.1200, subp. 4

Minn. R. 7019.1000, subp. 3

Minn. R. 7019.1000, subp. 2

Minn. R. 7019.1000, subp. 1




26

Notification of Deviations Endangering Human Health or the Environment: As soon as possible after discovery,notify the Commissioner or the state duty officer, either orally or by facsimile, of any deviation from permitconditions which could endanger human health or the environment.

27

Notification of Deviations Endangering Human Health or the Environment Report: Within 2 working days ofdiscovery, notify the Commissioner in writing of any deviation from permit conditions which could endangerhuman health or the environment. 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 corrected;3. whether or not the deviation has been corrected;4. the anticipated time by which the deviation is expected to be corrected, if not yet corrected; and5. steps taken or planned to reduce, eliminate, and prevent reoccurrence of the deviation.

28

The Permittee shall submit a semiannual deviations report : Due semiannually, by the 30th of January and JulyThe first semiannual report submitted by the Permittee shall cover the calendar half-year in which the permit isissued. The first report of each calendar year covers January 1 - June 30. The second report of each calendaryear covers July 1 - December 31. If no deviations have occurred, the Permittee shall submit the report statingno deviations.

30

Application for Permit Amendment: If a permit amendment is needed, submit an application in accordance withthe requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500. Submittal dates vary, depending on thetype of amendment needed.

Upon adoption of a new or amended federal applicable requirement, and if there are more than 3 yearsremaining in the permit term, the Permittee shall file an application for an amendment within nine months ofpromulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3.

31

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

32Emission Inventory Report: due on or before April 1 of each calendar year following permit issuance, to besubmitted on a form approved by the Commissioner.

33 Emission Fees: due 30 days after receipt of an MPCA bill.

34

The Permittee shall submit a compliance schedule progress report : Due semiannually, by the 30th of Januaryand July The Compliance Schedule Progress Report shall contain the information specified in Minn. R.7007.0800, subp. 6(B) and shall be submitted on a form approved by the Commissioner in accordance with theCompliance Schedule contained in this permit. Progress Reports will not be needed upon completion of allactivities contained in the Compliance Schedule.

35 The Permittee shall submit a compliance certification : Due annually, by the 31st of January (for the previouscalendar year). The Permittee shall submit this to the Commissioner on a form approved by the Commissioner.This report covers all deviations experienced during the calendar year.

Minn. R. 7019.1000, subp. 1

Minn. R. 7007.0800, subp. 6(A)(2)

Minn. R. 7007.0400, subp. 3, Minn. R.7007.1150 - 7007.1500

Minn. R. 7007.1400, subp. 1(H)

Minn. R. 7019.3000-7019.3100

Minn. R. 7002.0005-7002.0095

Minn. R. 7007.0800, subp. 6(B)




34

The Permittee shall submit a compliance schedule progress report : Due semiannually, by the 30th of Januaryand July The Compliance Schedule Progress Report shall contain the information specified in Minn. R.7007.0800, subp. 6(B) and shall be submitted on a form approved by the Commissioner in accordance with theCompliance Schedule contained in this permit. Progress Reports will not be needed upon completion of allactivities contained in the Compliance Schedule.

35The Permittee shall submit a compliance certification : Due annually, by the 31st of January (for the previouscalendar year). The Permittee shall submit this to the Commissioner on a form approved by the Commissioner.This report covers all deviations experienced during the calendar year.

COMG 2 1The Permittee shall limit emissions of Nitrogen Oxides <= 90 tons per year 12-month rolling sum to becalculated by the 15th day of each month for the previous 12-month period as described in this permit.

2The Permittee shall limit emissions of Carbon Monoxide <= 90 tons per year to be calculated by the 15th day ofeach month for the previous 12-month period as described in this permit.

3Hourly Recordkeeping. When ambient temperatures are less than or equal to 2 degrees Fahrenheit and greaterthan or equal to 0 degrees Fahrenheit, the Permittee shall monitor the temperature every hour for temperaturechanges. The Permittee shall record and maintain the ambient temperature while in operation.

4Daily Recordkeeping. Once each operating day, the Permittee shall calculate, record, and maintain the hours ofoperation and record and maintain the ambient temperature while in operation. This shall be based on written orelectronic usage logs.

6

Monthly Recordkeeping. By the 15th day of each month, the Permittee shall calculate and record the following:1) The total hours of operation for EQUI 2 and EQUI 4 for the previous calendar month using the daily recordswhen ambient temperatures are equal to or greater than 0 degrees Fahrenheit;2) The total hours of operation for EQUI 2 and EQUI 4 for the previous calendar month using the daily recordswhen ambient temperatures are less than 0 degrees Fahrenheit;3) The NOX emissions for the previous month using the emission factors, capacities, and equations specified inAppendix A of this permit;4) The CO emissions for the previous month using the emission factors, capacities, and equations specified inAppendix A of this permit;5) The 12-month rolling sum NOX emissions for the previous 12-month period by summing the monthly NOXemissions data for the previous 12 months. ..

7

The Permittee shall submit an annual report : Due annually, by the 31st of January The report shall documentCOMG 2 NOX and CO 12-month rolling sum calculations for the previous calendar year. The report shall besubmitted with the annual Compliance Certification required by this permit. As part of the Annual Report, thePermittee shall verify and certify that the Facility has maintained minor source status for New Source Review.

1 Opacity <= 20 percent opacity once operating temperatures have been attained.

Minn. R. 7007.0800, subp. 6(C)

To avoid major source under 40 CFR70.2 & Minn. R. 7007.0200

To avoid major source under 40 CFR70.2 & Minn. R. 7007.0200

Minn. R. 7007.0800, subp. 4-5

Minn. R. 7007.0800, subps. 4-5

Minn. R. 7007.0800, subps. 4-5

Minn. R. 7007.0800, subp. 2



Subject ItemID Seq. # RequirementCOMG 2

7

The Permittee shall submit an annual report : Due annually, by the 31st of January The report shall documentCOMG 2 NOX and CO 12-month rolling sum calculations for the previous calendar year. The report shall besubmitted with the annual Compliance Certification required by this permit. As part of the Annual Report, thePermittee shall verify and certify that the Facility has maintained minor source status for New Source Review.

EQUI 1(EU002)


2 The Permittee shall limit emissions of Sulfur Dioxide <= 0.50 pounds per million Btu heat input.

3The Permittee shall limit emissions of Sulfur Dioxide <= 0.0015 pounds per million Btu heat input. This limit iseffective on January 31, 2018.

4 Fuel type: No. 2 fuel oil/diesel fuel only.

5Hours of Operation: The Permittee shall maintain documentation on site that the unit is an emergency generatorby design that qualifies under the U.S. EPA memorandum entitled "Calculating Potential to Emit (PTE) forEmergency Generators" dated September 6, 1995, limiting operation to 500 hours per year.

6 The Permittee shall keep records of fuel type and usage on a monthly basis.

8

The Permittee shall;a. Change oil and filter every 500 hours of operation or annually, whichever comes first;b. Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first, and replace asnecessary; andc. Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and replace asnecessary.

If EQUI 1 is operating during an emergency and it is not possible to shut down the engine in order to perform themanagement practice requirements on the schedule required above, or if performing the management practiceon the required schedule would otherwise pose an unacceptable risk under federal, state, or local law, themanagement practice can be delayed until the emergency is over or the unacceptable risk under federal, state,..

9 If EQUI 1 operates or is contractually obligated to be available for more than 15 hours per calendar year for thepurpose specified in 40 CFR 63.6640(f)(4)(ii), the Permittee must use diesel fuel that meets the requirements in40 CFR 80.510(b) for nonroad diesel fuel, except that any existing diesel fuel purchased (or otherwise obtained)prior to January 1, 2015, may be used until depleted.

Minn. R. 7011.2300, subp. 1

Minn. R. 7011.2300, subp. 2(A)

Minn. R. 7011.2300, subp. 2(B)

Minn. R. 7005.0100, subp. 35a

Minn. R. 7007.0800, subps. 4-5

Minn. R. 7007.0800, subp. 5

40 CFR 63.6603(a), 40 CFR pt. 63,subp. ZZZZ, Table 2d, Minn. R.7011.8150



Subject ItemID Seq. # RequirementEQUI 1(EU002)

8

The Permittee shall;a. Change oil and filter every 500 hours of operation or annually, whichever comes first;b. Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first, and replace asnecessary; andc. Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and replace asnecessary.

If EQUI 1 is operating during an emergency and it is not possible to shut down the engine in order to perform themanagement practice requirements on the schedule required above, or if performing the management practiceon the required schedule would otherwise pose an unacceptable risk under federal, state, or local law, themanagement practice can be delayed until the emergency is over or the unacceptable risk under federal, state,..

9

If EQUI 1 operates or is contractually obligated to be available for more than 15 hours per calendar year for thepurpose specified in 40 CFR 63.6640(f)(4)(ii), the Permittee must use diesel fuel that meets the requirements in40 CFR 80.510(b) for nonroad diesel fuel, except that any existing diesel fuel purchased (or otherwise obtained)prior to January 1, 2015, may be used until depleted.

10The Permittee must operate and maintain EQUI 1 according to the manufacturer's emission-related writteninstructions.

11 The Permittee must install a non-resettable hour meter if one is not already installed.

12

The Permittee must minimize the engine's time spent at idle during startup and minimize the engine's startuptime to a period needed for appropriate and safe loading of the engine, not to exceed 30 minutes, after whichtime the emission standards applicable to all times other than startup in 40 CFR pt. 63, subp. ZZZZ, Table 2dapply.

13

The Permittee has the option of utilizing an oil analysis program in order to extend the specified oil changerequirement in 40 CFR pt. 63, subp. ZZZZ, Table 2d. The oil analysis must be performed at the same frequencyspecified for changing the oil in 40 CFR pt. 63, subp. ZZZZ, Table 2d. The analysis program must at a minimumanalyze the following three parameters: Total Base Number, viscosity, and percent water content. Thecondemning limits for these parameters are as follows: Total Base Number is less than 30 percent of the TotalBase Number of the oil when new; viscosity of the oil has changed by more than 20 percent from the viscosity ofthe oil when new; or percent water content (by volume) is greater than 0.5. If all of these condemning limits arenot exceeded, the Permittee is not required to change the oil. If any of the limits are exceeded, the Permitteemust change the oil within 2 business days of receiving the results of the analysis; if the engine is not inoperation when the results of the analysis are received, the Permittee must change the oil within 2 businessdays or before commencing operation, whichever is later. The Permittee must keep records of the parameters t..

14

(a) The Permittee must be in compliance with the emission limitations, operating limitations, and otherrequirements in 40 CFR pt. 63, subp. ZZZZ that apply at all times.

(b) At all times the Permittee must operate and maintain any affected source, including associated air pollutioncontrol equipment and monitoring equipment, in a manner consistent with safety and good air pollution controlpractices for minimizing emissions. The general duty to minimize emissions does not require the Permittee tomake any further efforts to reduce emissions if levels required by this standard have been achieved.Determination of whether such operation and maintenance procedures are being used will be based oninformation available to the Administrator which may include, but is not limited to, monitoring results, review ofoperation and maintenance procedures, review of operation and maintenance records, and inspection of thesource.

15The Permittee must demonstrate continuous compliance with each emission limitation, operating limitation, andother requirements in 40 CFR pt. 63, subp. ZZZZ, Table 2d that apply by operating and maintaining EQUI 1according to the manufacturer's emission-related operation and maintenance instructions.

16 The Permittee must report each instance in which the requirements in 40 CFR pt. 63, subp. ZZZZ, Table 8 thatapply to EQUI 1 were not met.

40 CFR 63.6604(b), Minn. R.7011.8150

40 CFR 63.6625(e), Minn. R.7011.8150

40 CFR 63.6625(f), Minn. R. 7011.8150

40 CFR 63.6625(h), Minn. R.7011.8150

40 CFR 63.6625(i), Minn. R. 7011.8150

40 CFR 63.6605, Minn. R. 7011.8150

40 CFR 63.6640(a), 40 CFR pt. 63,subp. ZZZZ, Table 6, Minn. R.7011.8150




15

The Permittee must demonstrate continuous compliance with each emission limitation, operating limitation, andother requirements in 40 CFR pt. 63, subp. ZZZZ, Table 2d that apply by operating and maintaining EQUI 1according to the manufacturer's emission-related operation and maintenance instructions.

16The Permittee must report each instance in which the requirements in 40 CFR pt. 63, subp. ZZZZ, Table 8 thatapply to EQUI 1 were not met.

17

The Permittee must operate the emergency stationary RICE according to the requirements below. In order forthe engine to be considered an emergency stationary RICE under 40 CFR pt. 63, subp. ZZZZ, any operationother than emergency operation, maintenance and testing, emergency demand response, and operation innon-emergency situations for 50 hours per year, as described below, is prohibited. If the Permittee does notoperate the engine according to the requirements below, the engine will not be considered an emergency engineunder 40 CFR pt. 63, subp. ZZZZ and must meet all requirements for non-emergency engines.

(1) There is no time limit on the use of emergency stationary RICE in emergency situations.

(2) The Permittee may operate EQUI 1 for a maximum of 100 hours per calendar year for maintenance checksand readiness testing, provided that the tests are recommended by federal, state or local government, the man..

18

(a) The Permittee must keep records as described below;

(1) A copy of each notification and report that the Permittee submitted to comply with 40 CFR pt. 63, subp.ZZZZ, including all documentation supporting any Initial Notification or Notification of Compliance Status that thePermittee submitted, according to the requirement in 40 CFR 63.10(b)(2)(xiv).

(2) Records of the occurrence and duration of each malfunction of operation (i.e., process equipment) or the airpollution control and monitoring equipment.

(3) Records of performance tests and performance evaluations as required in 40 CFR 63.10(b)(2)(viii)...

19

If the Permittee operates or is contractually obligated to be available for more than 15 hours per calendar yearfor the purpose specified in 40 CFR 63.6640(f)(4)(ii), the Permittee must submit an annual report according tothe requirements below.

(1) The report must contain the following information:

(i) Company name and address where the engine is located.

(ii) Date of the report and beginning and ending dates of the reporting period.

(iii) Engine site rating and model year. ..

20

Recordkeeping: The Permittee shall maintain files of all information required by 40 CFR pt. 63 in a form suitableand readily available for expeditious inspection and review.

The files should be retained for at least 5 years following the date of each occurrence, measurement,maintenance, corrective action, report, or record. Only the most recent two years of information must be kept onsite.

21

The Permittee shall maintain, at a minimum, the following information in the files:

1) the occurrence and duration of each startup, shutdown, or malfunction of operation when the startup orshutdown causes the source to exceed any applicable emission limitation in the relevant emission standards;2) the occurrence and duration of each malfunction of operation (i.e., process equipment) or the required airpollution control and monitoring equipment;3) all maintenance performed on the air pollution control and monitoring equipment;4) actions taken during periods of startup, shutdown, and malfunction when such actions are different from theprocedures specified in the affected source's startup, shutdown, and malfunction plan (SSMP). In this case, thePermittee shall report this action within 2 days of occurrence and follow by a written notification within 7 days ofoccurrence;..

22Prior to construction or reconstruction of a major-emitting "affected source" under the promulgated MACTstandards, the Permittee must apply for and obtain an air emission permit.

23 After the effective date of any relevant standard promulgated by the Administrator under 40 CFR pt. 63, thePermittee who constructs a new affected source that is not major-emitting or reconstructs an affected sourcethat is not major-emitting that is subject to such standard, or reconstructs a source such that the sourcebecomes an affected source subject to the standard, must notify the Administrator of the intended constructionor reconstruction. The notification must be submitted in accordance with the procedures in 40 CFR Section63.9(b).

40 CFR 63.6640(e), Minn. R.7011.8150

40 CFR 63.6640(f), Minn. R. 7011.8150

40 CFR 63.6655, Minn. R. 7011.8150

40 CFR 63.6650(h), Minn. R.7011.8150

40 CFR 63.10(b)(1), Minn. R.7019.0100, subp. 2(B)

40 CFR 63.10(b)(2), Minn. R.7019.0100, subp. 2(B)

40 CFR 63.5(b)(3)& Minn. R.7011.7000




22Prior to construction or reconstruction of a major-emitting "affected source" under the promulgated MACTstandards, the Permittee must apply for and obtain an air emission permit.

23

After the effective date of any relevant standard promulgated by the Administrator under 40 CFR pt. 63, thePermittee who constructs a new affected source that is not major-emitting or reconstructs an affected sourcethat is not major-emitting that is subject to such standard, or reconstructs a source such that the sourcebecomes an affected source subject to the standard, must notify the Administrator of the intended constructionor reconstruction. The notification must be submitted in accordance with the procedures in 40 CFR Section63.9(b).

24

After the effective date of any relevant standard promulgated by the Administrator under 40 CFR pt. 63,equipment added (or a process change) to an affected source that is within the scope of the definition of affectedsource under the relevant standard must be considered part of the affected source and subject to all provisionsof the relevant standard established for that affected source.

25

Circumvention. The Permittee shall not build, erect, install, or use any article, machine, equipment, or process toconceal an emission that would otherwise constitute noncompliance with a relevant standard. Such concealmentincludes, but is not limited to:

(1) The use of diluents to achieve compliance with a relevant standard based on the concentration of a pollutantin the effluent discharged to the atmosphere; or(2) The use of gaseous diluents to achieve compliance with a relevant standard for visible emissions.

27The Permittee shall submit a notification of equipment removal/dismantlement: Due 15 calendar days afterEquipment Removal and/or Dismantlement Date. This notification shall specify which Subject Items (by ID#)were removed and on what date.

EQUI 2(EU001)

1 Nitrogen Oxides <= 0.0157 percent by volume at 15 percent oxygen and on a dry basis.

2 Sulfur Dioxide <= 0.015 percent by volume at 15 percent oxygen and on a dry basis.

3Sulfur Dioxide <= 0.50 pounds per million Btu heat input (The potential to emit from the unit is 0.0846 lb/MMBtudue to equipment design and allowable fuels.).

4 Sulfur Dioxide <= 0.0015 pounds per million Btu heat input This limit is effective on January 1, 2018.

40 CFR 63.5(b)(4)& Minn. R.7011.7000

40 CFR 63.5(b), Minn. R. 7011.7000

40 CFR 63.4(b), Minn. R. 7011.7000

Minn. R. 7007.0800, subp. 2

40 CFR 60.332(d), Minn. R. 7011.2350

40 CFR 60.333(a), Minn. R. 7011.2350

Minn. R. 7011.2300, subp. 2(A)




3Sulfur Dioxide <= 0.50 pounds per million Btu heat input (The potential to emit from the unit is 0.0846 lb/MMBtudue to equipment design and allowable fuels.).



6Sulfur Content of Fuel <= 0.09 percent by weight. This limit is more stringent than 40 CFR 60.333(b). ThePermittee shall comply with this limit by complying with the sulfur monitoring requirements under 40 CFR pt. 60,subp. GG.

7 Sulfur Content of Fuel <= 0.8 percent by weight.

8 Fuel type: Natural gas only.

9

Reporting: If there is a change in fuel supply, the Permittee must notify the MPCA of such change forre-examination of the custom fuel-monitoring schedule. A substantial change in fuel quality shall be consideredas a change in fuel supply. Sulfur monitoring shall be conducted weekly during the interim period when thiscustom schedule is being re-examined.


11 Analysis for fuel sulfur content of the natural gas shall be conducted using one of the approved ASTM referencemethods for the measurement of sulfur in gaseous fuels, or an approved alternative method.

Minn. R. 7011.2300, subp. 2(B)

Minn. R. 7011.2300, subp. 1

Minn. R. 7007.0800, subp. 2, To avoidmajor source under 40 CFR 70.2 &Minn. R. 7007.0200

40 CFR 60.333(b), Minn. R. 7011.2350

Minn. R. 7005.0100, subp. 35a

40 CFR 60.334(b), Minn. R. 7011.2350

Minn. R. 7007.0800, subp. 5





11Analysis for fuel sulfur content of the natural gas shall be conducted using one of the approved ASTM referencemethods for the measurement of sulfur in gaseous fuels, or an approved alternative method.

12Sulfur monitoring shall be conducted twice monthly for six months. If this monitoring shows little variability in thefuel sulfur content, and indicates consistent compliance with 40 CFR Section 60.333, then sulfur monitoring shallbe conducted once per quarter for six quarters.

13

Sulfur Monitoring: If, after the first 2 years of sulfur monitoring, the sulfur content of the fuel shows littlevariability and, when calculated as sulfur dioxide, represents consistent compliance with the sulfur dioxideemission limits specified under 40 CFR Section 60.333, sample analysis shall be conducted twice per annum.This monitoring shall be conducted during the first and third quarters of each calendar year.

14

Notification of noncompliance: Should any sulfur analysis indicate noncompliance with 40 CFR Section 60.333,the Permittee shall notify the MPCA of such excess emissions and the custom fuel monitoring schedule shall bere-examined by the Administrator. Sulfur monitoring shall be conducted weekly during the interim period whenthis custom fuel-monitoring schedule is being re-examined.

15Recordkeeping: Records of sample analyses and fuel supply pertinent to the custom fuel-monitoring scheduleshall be retained for a period of five years, and be available for inspection by personnel of federal, state, andlocal air pollution control agencies.

16The Permittee shall submit a notification of any physical or operational change which increases emission rate:due 60 days (or as soon as practical) before the change is commenced.

17Recordkeeping: The Permittee shall maintain records of the occurrence and duration of any startup, shutdown,or malfunction in the operation of the facility including; any malfunction of the air pollution control equipment; orany periods during which a continuous monitoring system or monitoring device is inoperative.

18 Recordkeeping: The Permittee shall maintain a file of all measurements, maintenance, reports and records for atleast five years. This requirement is more stringent than 40 CFR Section 60.7(f), which specifies two years.

40 CFR 60.334(b), Minn. R. 7011.2350

40 CFR 60.334(b), Minn. R. 7011.2350

40 CFR 60.334(b), Minn. R. 7011.2350

40 CFR 60.334(b), Minn. R. 7011.2350

40 CFR 60.334(b), Minn. R. 7011.2350

40 CFR 60.7(a)(4), Minn. R.7019.0100, subp. 1

40 CFR 60.7(b), Minn. R. 7019.0100,subp. 1




17

Recordkeeping: The Permittee shall maintain records of the occurrence and duration of any startup, shutdown,or malfunction in the operation of the facility including; any malfunction of the air pollution control equipment; orany periods during which a continuous monitoring system or monitoring device is inoperative.

18Recordkeeping: The Permittee shall maintain a file of all measurements, maintenance, reports and records for atleast five years. This requirement is more stringent than 40 CFR Section 60.7(f), which specifies two years.

19No owner or operator shall build, erect, install, or use any article, machine, equipment or process, the use ofwhich conceals an emission which would otherwise constitute a violation of an applicable standard.

20

Nitrogen Oxides : The Permittee shall conduct a performance test : Due after Permit Issuance Date every 60months to measure emissions. The first test is due by the date specified and all subsequent tests are due by theend of each 60-month period following that date. The performance test shall be conducted at worst caseconditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 7E, or other methodapproved by MPCA in the performance test plan approval.

Testing conducted during the 60 days prior to the performance test due date satisfies the performance test duedate, and will not reset the test due date for future testing as required:1) by this permit;2) by the most recently approved Performance Test Frequency Plan; or3) within a Notice of Compliance letter. Testing conducted more than two months prior to the performance test ..

21Sulfur Content of Fuel : The Permittee shall submit an annual report : Due annually, by the 31st of January. Thereport shall document the sulfur monitoring analysis results for the previous calendar year. The report shall besubmitted with the annual Compliance Certification required by this permit.

EQUI 4 1The Permittee shall limit emissions of Nitrogen Oxides <= 25 parts per million at 15 percent oxygen, or 150 ng/Jof useful output (1.2 lb/MWh).

2 The Permittee shall limit emissions of Sulfur Dioxide <= 110 nanograms per joule (0.90 lb/MWh) gross output.


4 Sulfur Dioxide <= 0.50 pounds per million Btu heat input (The potential to emit from the unit is 0.0846 lb/MMBtudue to equipment design and allowable fuels).

40 CFR 60.7(f), Minn. R. 7007.0800,subp. 5(C), Minn. R. 7019.0100, subp.1

40 CFR 60.12, Minn. R. 7011.0050

Minn. R. 7017.2020, subp. 1

Minn. R. 7007.0800, subp. 2

40 CFR 60.4320(a), 40 CFR pt. 60,Table 1, Minn. R. 7011.2375

40 CFR 60.4330(a)(1), Minn. R.7011.2375

Minn. R. 7011.2300, subp. 1



Subject ItemID Seq. # RequirementEQUI 4


4Sulfur Dioxide <= 0.50 pounds per million Btu heat input (The potential to emit from the unit is 0.0846 lb/MMBtudue to equipment design and allowable fuels).


6Sulfur Content of Fuel <= 0.09 percent by weight. The Permittee shall comply with this limit by complying withthe sulfur monitoring requirements under 40 CFR pt. 60, subp. KKKK.

7

The Permittee is authorized to construct and operate EQUI 4 meeting the following design requirements, within18 months after permit issuance of Permit No. 13100058-101. The unit shall meet all applicable requirements ofthis permit.

Design Requirements;16,696 horsepower/hour capacity.



11The Permittee shall operate and maintain EQUI 4 stationary combustion turbine, air pollution control equipment,and monitoring equipment in a manner consistent with good air pollution control practices for minimizingemissions at all times including during startup, shutdown, and malfunction.

12 The Permittee must conduct an initial performance test, as required in 40 CFR 60.8 for NOX. Subsequent NOXperformance tests shall be conducted on an annual basis (no more than 14 calendar months following theprevious performance test).

For each NOX performance test run, the Permittee shall measure the NOX and diluent gas concentrations,using either EPA Methods 7E and 3A, or EPA Method 20 in appendix A of 40 CFR pt. 60 to conductperformance tests. Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), andmeasure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A of 40 CFR pt. 60 tocalculate the NOX emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in 40 CFR60.4350(f) to calculate the NOX emission rate in lb/MWh. 40 CFR 60.4350(f) equations are listed in Appendix Bof this permit.

Minn. R. 7011.2300, subp. 2(A)

Minn. R. 7011.2300, subp. 2(B)

Minn. R. 7007.0800, subp. 2, To avoidmajor source under 40 CFR 70.2 &Minn. R. 7007.0200

Minn. R. 7007.0800, subp. 2

Minn. R. 7005.0100, subp. 35a

Minn. R. 7007.0800, subp. 5

40 CFR 60.4333, Minn. R. 7011.2375




11

The Permittee shall operate and maintain EQUI 4 stationary combustion turbine, air pollution control equipment,and monitoring equipment in a manner consistent with good air pollution control practices for minimizingemissions at all times including during startup, shutdown, and malfunction.

12

The Permittee must conduct an initial performance test, as required in 40 CFR 60.8 for NOX. Subsequent NOXperformance tests shall be conducted on an annual basis (no more than 14 calendar months following theprevious performance test).

For each NOX performance test run, the Permittee shall measure the NOX and diluent gas concentrations,using either EPA Methods 7E and 3A, or EPA Method 20 in appendix A of 40 CFR pt. 60 to conductperformance tests. Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), andmeasure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A of 40 CFR pt. 60 tocalculate the NOX emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in 40 CFR60.4350(f) to calculate the NOX emission rate in lb/MWh. 40 CFR 60.4350(f) equations are listed in Appendix Bof this permit.

14

Calculate the hourly average NOX emission rates, in units of the emission standards under 40 CFR 60.4320,using either ppm for units complying with the concentration limit or Equation 1 of 40 CFR 60.4350(f) for unitscomplying with the output based standard.

For combined-cycle and combined heat and power complying with the output-based standard, use Equation 1 of40 CFR 60.4350(f), except that the gross energy output is calculated as the sum of the total electrical andmechanical energy generated by the combustion turbine, the additional electrical or mechanical energy (if any)generated by the steam turbine following the heat recovery steam generator, and 100 percent of the total usefulthermal energy output that is not used to generate additional electricity or mechanical output, expressed inequivalent MW, as in the Equations 2 and 3 of 40 CFR 60.4350(f).

15

Sampling traverse points for NOX are to be selected following EPA Method 20 and sampled for equal timeintervals. The sampling must be performed with a traversing single-hole probe, or, if feasible, with a stationarymulti-hole probe that samples each of the points sequentially. Alternatively, a multi-hole probe designed anddocumented to sample equal volumes from each hole may be used to sample simultaneously at the requiredpoints.

16The Permittee must demonstrate compliance with the NOX emission limit in 40 CFR 60.4320 at each tested loadlevel. Compliance is achieved if the three-run arithmetic average NOX emission rate at each tested level meetsthe applicable emission limit in 40 CFR 60.4320.

17

The NOX performance test must be done at any load condition within plus or minus 25 percent of 100 percent ofpeak load. The Permittee may perform testing at the highest achievable load point, if at least 75 percent of peakload cannot be achieved in practice. The Permittee must conduct three separate test runs for each performancetest. The minimum time per run is 20 minutes.

18 The ambient temperature must be greater than 0 °F during the NOX performance test.

19

(a) The Permittee must conduct an initial performance test, as required in 40 CFR 60.8 for SO2. SubsequentSO2 performance tests shall be conducted on an annual basis (no more than 14 calendar months following theprevious performance test).

(1) The Permittee shall periodically determine the sulfur content of the fuel combusted in the turbine, therefore arepresentative fuel sample shall be collected following ASTM D5287 (incorporated by reference, see 40 CFR60.17) for natural gas to conduct SO2 performance tests. The fuel analyses of 40 CFR 60.4415 may beperformed either by the Permittee, a service contractor retained by the Permittee, the fuel vendor, or any otherqualified agency. Analyze the samples for the total sulfur content of the fuel using:

(ii) For gaseous fuels, ASTM D1072, or alternatively D3246, D4084, D4468, D4810, D6228, D6667, or Gas Pro..20 The Permittee shall monitor the total sulfur content of the fuel being fired in the turbine. The sulfur content of the

fuel must be determined using total sulfur methods described in 40 CFR 60.4415. Alternatively, if the total sulfurcontent of the gaseous fuel during the most recent performance test was less than half the applicable limit,ASTM D4084, D4810, D5504, or D6228, or Gas Processors Association Standard 2377 (all of which areincorporated by reference, see 40 CFR 60.17), which measure the major sulfur compounds, may be used.

40 CFR 60.4400(a)(1)(ii), Minn. R.7011.2375

40 CFR 60.4350(f), Minn. R. 7011.2375

40 CFR 60.4400(a)(2), Minn. R.7011.2375

40 CFR 60.4400(b)(4), Minn. R.7011.2375

40 CFR 60.4400(b), Minn. R.7011.2375

40 CFR 60.4400(b)(6), Minn. R.7011.2375

40 CFR 60.4415, Minn. R. 7011.2375




19

(a) The Permittee must conduct an initial performance test, as required in 40 CFR 60.8 for SO2. SubsequentSO2 performance tests shall be conducted on an annual basis (no more than 14 calendar months following theprevious performance test).

(1) The Permittee shall periodically determine the sulfur content of the fuel combusted in the turbine, therefore arepresentative fuel sample shall be collected following ASTM D5287 (incorporated by reference, see 40 CFR60.17) for natural gas to conduct SO2 performance tests. The fuel analyses of 40 CFR 60.4415 may beperformed either by the Permittee, a service contractor retained by the Permittee, the fuel vendor, or any otherqualified agency. Analyze the samples for the total sulfur content of the fuel using:

(ii) For gaseous fuels, ASTM D1072, or alternatively D3246, D4084, D4468, D4810, D6228, D6667, or Gas Pro..

20

The Permittee shall monitor the total sulfur content of the fuel being fired in the turbine. The sulfur content of thefuel must be determined using total sulfur methods described in 40 CFR 60.4415. Alternatively, if the total sulfurcontent of the gaseous fuel during the most recent performance test was less than half the applicable limit,ASTM D4084, D4810, D5504, or D6228, or Gas Processors Association Standard 2377 (all of which areincorporated by reference, see 40 CFR 60.17), which measure the major sulfur compounds, may be used.

21

(i) The Permittee shall maintain daily total sulfur content measurements for 30 consecutive unit operating days,using the applicable methods specified in 40 CFR pt. 60 subp. KKKK. Based on the results of the 30 dailysamples, the required frequency for subsequent monitoring of the fuel's total sulfur content shall be as specifiedin 40 CFR 60.4370(c)(1)(ii), (iii), or (iv), as applicable.

(ii) If none of the 30 daily measurements of the fuel's total sulfur content exceeds half the applicable standard,subsequent sulfur content monitoring may be performed at 12-month intervals. If any of the samples taken at12-month intervals has a total sulfur content greater than half but less than the applicable limit, follow theprocedures in 40 CFR 60.4370(c)(1)(iii). If any measurement exceeds the applicable limit, follow the proceduresin 40 CFR 60.4370(c)(1)(iv) ...

22The Permittee shall submit reports of excess emissions and monitor downtime, in accordance with 40 CFR60.7(c) for EQUI 4 that requires the Permittee to periodically determine the fuel sulfur content. Excess emissionsmust be reported for all periods of unit operation, including start-up, shutdown, and malfunction.

23The Permittee shall submit a written report of the results of each performance test before the close of businesson the 60th day following the completion of the performance test.

24

Excess emissions and monitoring downtime for monitoring the sulfur content of fuel are defined as follows:

(a) For samples of gaseous fuel and for oil samples obtained using daily sampling, flow proportional sampling, orsampling from the unit's storage tank, an excess emission occurs each unit operating hour included in the periodbeginning on the date and hour of any sample for which the sulfur content of the fuel being fired in thecombustion turbine exceeds the applicable limit and ending on the date and hour that a subsequent sample istaken that demonstrates compliance with the sulfur limit.

(c) A period of monitor downtime begins when a required sample is not taken by its due date. A period ofmonitor downtime also begins on the date and hour of a required sample, if invalid results are obtained. Theperiod of monitor downtime ends on the date and hour of the next valid sample.



27 Recordkeeping: The Permittee shall maintain a file of all measurements, maintenance, reports and records for atleast five years. This requirement is more stringent than 40 CFR Section 60.7(f), which specifies two years.

40 CFR 60.4360, Minn. R. 7011.2375

40 CFR 60.4370(c)(1), Minn. R.7011.2375

40 CFR 60.4375(a), Minn. R.7011.2375

40 CFR 60.4375(b), Minn. R.7011.2375

40 CFR 60.4385, Minn. R. 7011.2375

40 CFR 60.7(a)(4), Minn. R.7019.0100, subp. 1

40 CFR 60.7(b), Minn. R. 7019.0100,subp. 1




26

Recordkeeping: The Permittee shall maintain records of the occurrence and duration of any startup, shutdown,or malfunction in the operation of the facility including; any malfunction of the air pollution control equipment; orany periods during which a continuous monitoring system or monitoring device is inoperative.



29

Nitrogen Oxides : As required in 40 CFR 60.8, the Permittee shall conduct an initial performance test within 60days after achieving the maximum production rate at which the facility will be operated, but no later thePermittee shall conduct an initial performance test : Due 180 calendar days after Initial Startup Date. Theperformance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, usingEPA Reference Method 20, or other method approved by MPCA in the performance test plan approval.

30

Nitrogen Oxides : The Permittee shall conduct a performance test : Due annually, but no more than 14 monthsfollowing the previous performance test. The performance test shall be conducted at worst case conditions asdefined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 20, or other method approved by MPCAin the performance test plan approval.

The Permittee is not using water or steam injection to control NOX emissions.

If the NOX emission result from the performance test is less than or equal to 75 percent of the NOX emissionlimit for the turbine, the Permittee may reduce the frequency of subsequent performance tests to once every 2years (no more than 26 calendar months following the previous performance test). If the results of anysubsequent performance test exceed 75 percent of the NOX emission limit for the turbine, the Permittee must r..

31

Sulfur Dioxide : As required in 40 CFR 60.8, the Permittee shall conduct an initial performance test within 60days after achieving the maximum production rate at which the facility will be operated, but no later thePermittee shall conduct an initial performance test : Due 180 calendar days after Initial Startup Date Theperformance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, usingEPA Reference Method 20, or other method approved by MPCA in the performance test plan approval.

32

Sulfur Dioxide : The Permittee shall conduct a performance test : Due annually, but no more than 14 monthsfollowing the previous performance test. The performance test shall be conducted at worst case conditions asdefined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 20, or other method approved by MPCAin the performance test plan approval.

33The Permittee shall submit a notification of date construction began: Due 30 calendar days after Date ofConstruction Start. Submit the name and number of the Subject Item and the date construction began.

34 The Permittee shall submit a notification of the actual date of initial startup: Due 15 calendar days after InitialStartup Date. Submit the name and number of the Subject Item and the date of startup. Startup is as defined inMinn. R. 7005.0100, subp. 42a.


40 CFR 60.12, Minn. R. 7011.0050

40 CFR 60.4400(a), Minn. R.7011.2375

40 CFR 60.4340, 40 CFR 60.4400(a),Minn. R. 7011.2375

40 CFR 60.4415(a), Minn. R.7011.2375

40 CFR 60.4415(a), Minn. R.7011.2375

40 CFR 60.7(a)(1), Minn. R.7007.0800, subp. 16(L), Minn. R.7019.0100, subp. 1





34The Permittee shall submit a notification of the actual date of initial startup: Due 15 calendar days after InitialStartup Date. Submit the name and number of the Subject Item and the date of startup. Startup is as defined inMinn. R. 7005.0100, subp. 42a.

35Sulfur Content of Fuel : The Permittee shall submit an annual report : Due annually, by the 31st of January. Thereport shall document the sulfur monitoring analysis results for the previous calendar year. The report shall besubmitted with the annual Compliance Certification required by this permit.

EQUI 5 1 The Permittee shall limit emissions of Nitrogen Oxides <= 2.0 grams per horsepower-hour.

2 The Permittee shall limit emissions of Carbon Monoxide <= 4.0 grams per horsepower-hour.

3 The Permittee shall limit emissions of Volatile Organic Compounds <= 1.0 grams per horsepower-hour.


5Sulfur Dioxide <= 0.50 pounds per million Btu heat input. The potential to emit from the unit is 0.000588lb/MMBtu due to equipment design and allowable fuels.

6 Sulfur Dioxide <= 0.0015 pounds per million Btu heat input. This limit is effective on January 31, 2018. Thepotential to emit from the unit is 0.000588 lb/MMBtu due to equipment design and allowable fuels.


Minn. R. 7007.0800, subp. 2

40 CFR 60.4233(e), 40 CFR63.6590(c), 40 CFR pt. 60, subp. JJJJ,Table 1, Minn. R. 7011.2310, Minn. R.7011.8150



Minn. R. 7011.2300, subp. 1

Minn. R. 7011.2300, subp. 2(A)




5Sulfur Dioxide <= 0.50 pounds per million Btu heat input. The potential to emit from the unit is 0.000588lb/MMBtu due to equipment design and allowable fuels.

6Sulfur Dioxide <= 0.0015 pounds per million Btu heat input. This limit is effective on January 31, 2018. Thepotential to emit from the unit is 0.000588 lb/MMBtu due to equipment design and allowable fuels.

7


Design Requirements:1,102 brake horsepower/hourSI-4SLB firing method.


9Hours of Operation: The Permittee shall maintain documentation on site that the unit is an emergency generatorby design that qualifies under the U.S. EPA memorandum entitled "Calculating Potential to Emit (PTE) forEmergency Generators" dated September 6, 1995, limiting operation to 500 hours per year.


12

EQUI 5 is a new stationary RICE located at an area source and the Permittee must meet the requirements of 40CFR pt. 63, subp. ZZZZ by meeting the requirements of 40 CFR pt. 60 subp. IIII, for compression ignitionengines or 40 CFR pt. 60 subp. JJJJ, for spark ignition engines. No further requirements apply for such enginesunder 40 CFR pt. 63, subp. ZZZZ.

13The Permittee is an owner and operator of EQUI 5 that is an emergency stationary SI ICE with a maximumengine power greater than 19 KW (25 HP) that commenced construction after June 12, 2006, and wasmanufactured on or after January 1, 2009.

15 The Permittee shall not install engines that do not meet the applicable requirements in 40 CFR 60.4233 afterJanuary 1, 2011.

Minn. R. 7011.2300, subp. 2(B)

Minn. R. 7007.0800, subp. 2

Minn. R. 7005.0100, subp. 35a

Minn. R. 7007.0800, subps. 4-5

Minn. R. 7007.0800, subp. 5

40 CFR 63.6590(c)(1), Minn. R.7011.8150

40 CFR 60.4230(a)(4), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150




13

The Permittee is an owner and operator of EQUI 5 that is an emergency stationary SI ICE with a maximumengine power greater than 19 KW (25 HP) that commenced construction after June 12, 2006, and wasmanufactured on or after January 1, 2009.

15The Permittee shall not install engines that do not meet the applicable requirements in 40 CFR 60.4233 afterJanuary 1, 2011.

16 The Permittee must install a non-resettable hour meter.

17The Permittee must operate and maintain EQUI 5 that achieves the emission standards as required in 40 CFR60.4233 over the entire life of the engine.

18

The Permittee must operate EQUI 5 according to the requirements in 40 CFR 620.4243(d)(1) through (3). Inorder for the engine to be considered an emergency stationary ICE under 40 CFR pt. 60, subp. JJJJ, anyoperation other than emergency operation, maintenance and testing, emergency demand response, andoperation in non-emergency situations for 50 hours per year, as described in 40 CFR 620.4243(d)(1) through(3), is prohibited. If the Permittee does not operate the engine according to the requirements in 40 CFR620.4243(d)(1) through (3), the engine will not be considered an emergency engine under 40 CFR pt. 60, subp.JJJJ and must meet all requirements for non-emergency engines.

(1) There is no time limit on the use of emergency stationary ICE in emergency situations.

(2) The Permittee may operate EQUI 5 for any combination of the purposes specified in 40 CFR 60.4243(d)(2..

19

The Permittee is purchasing a non-certified engine that must demonstrate compliance with the emissionstandards specified in 40 CFR 60.4233(d), according to the requirements specified in 40 CFR 60.4244, asapplicable, and according to 40 CFR 60.4243(b)(2)(ii).

The Permittee must keep a maintenance plan and records of conducted maintenance and must, to the extentpracticable, maintain and operate the engine in a manner consistent with good air pollution control practice forminimizing emissions. In addition, the Permittee must conduct an initial performance test and conductsubsequent performance testing every 8,760 hours or 3 years, whichever comes first, thereafter to demonstratecompliance.

20

(a) Each performance test must be conducted within 10 percent of 100 percent peak (or the highest achievable)load and according to the requirements in 40 CFR 60.8 and under the specific conditions that are specified by40 CFR pt. 60, subp. JJJJ, Table 2.

(b) The Permittee shall not conduct performance tests during periods of startup, shutdown, or malfunction, asspecified in 40 CFR 60.8(c). If EQUI 5 is non-operational, the Permittee does not need to startup the enginesolely to conduct a performance test; however, the Permittee must conduct the performance test immediatelyupon startup of the engine.

(c) The Permittee must conduct three separate test runs for each performance test required in 40 CFR 60.4244,as specified in 40 CFR 60.8(f). Each test run must be conducted within 10 percent of 100 percent peak (or the ..

21

The Permittee must submit a copy of each performance test as conducted in 40 CFR 60.4244 within 60 daysafter the test has been completed. Performance test reports using EPA Method 18, EPA Method 320, or ASTMD6348-03 (incorporated by reference—see 40 CFR 60.17) to measure VOC require reporting of all QA/QC data.For Method 18, report results from sections 8.4 and 11.1.1.4; for Method 320, report results from sections 8.6.2,9.0, and 13.0; and for ASTM D6348-03 report results of all QA/QC procedures in Annexes 1-7.

22 The Permittee must keep the following records of the information:

(1) All notifications submitted to comply with 40 CFR pt. 60, subp. JJJJ and all documentation supporting anynotification.

(2) Maintenance conducted on the engine.

(4) Documentation that the engine meets the emission standards.

40 CFR 60.4236(c), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150

40 CFR 60.4237(a), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150

40 CFR 60.4234, 40 CFR 63.6590(c),Minn. R. 7011.2310, Minn. R.7011.8150

40 CFR 60.4243(d), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150

40 CFR 60.4243(b)(2)(ii), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150

40 CFR 60.4244, 40 CFR 63.6590(c),Minn. R. 7011.2310, Minn. R.7011.8150

40 CFR 60.4245(d), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150




21

The Permittee must submit a copy of each performance test as conducted in 40 CFR 60.4244 within 60 daysafter the test has been completed. Performance test reports using EPA Method 18, EPA Method 320, or ASTMD6348-03 (incorporated by reference—see 40 CFR 60.17) to measure VOC require reporting of all QA/QC data.For Method 18, report results from sections 8.4 and 11.1.1.4; for Method 320, report results from sections 8.6.2,9.0, and 13.0; and for ASTM D6348-03 report results of all QA/QC procedures in Annexes 1-7.

22

The Permittee must keep the following records of the information:

(1) All notifications submitted to comply with 40 CFR pt. 60, subp. JJJJ and all documentation supporting anynotification.

(2) Maintenance conducted on the engine.

(4) Documentation that the engine meets the emission standards.

23

The Permittee must submit an initial notification as required in 40 CFR 60.7(a)(1). The notification must includethe information below:

(1) Name and address of the Permittee;

(2) The address of the affected source;

(3) Engine information including make, model, engine family, serial number, model year, maximum enginepower, and engine displacement;

(4) Emission control equipment; and ..





29


30 Nitrogen Oxides : Whichever comes first, the Permittee shall conduct a performance test every 8,760 hours orconduct a performance test : Due after Initial Performance Test Date every 36 months. The performance testshall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA ReferenceMethod 20, or other method approved by MPCA in the performance test plan approval.

40 CFR 60.4245(a), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150

40 CFR 60.4245(c), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150

40 CFR 60.7(a)(4), Minn. R.7019.0100, subp. 1

40 CFR 60.7(b), Minn. R. 7019.0100,subp. 1


40 CFR 60.12, Minn. R. 7011.0050

40 CFR 60.4243(b)(2)(ii), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150, Minn. R. 7017.2020




29


30

Nitrogen Oxides : Whichever comes first, the Permittee shall conduct a performance test every 8,760 hours orconduct a performance test : Due after Initial Performance Test Date every 36 months. The performance testshall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA ReferenceMethod 20, or other method approved by MPCA in the performance test plan approval.

33

Carbon Monoxide : As required in 40 CFR 60.8, the Permittee shall conduct an initial performance test within 60days after achieving the maximum production rate at which the facility will be operated, but no later thePermittee shall conduct an initial performance test : Due 180 calendar days after Initial Startup Date. Theperformance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, usingEPA Reference Method 10, or other method approved by MPCA in the performance test plan approval.

34

Carbon Monoxide : Whichever comes first, the Permittee shall conduct a performance test every 8,760 hours orconduct a performance test : Due after Initial Performance Test Date every 36 months. The performance testshall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA ReferenceMethod 10, or other method approved by MPCA in the performance test plan approval.

35

Volatile Organic Compounds : As required in 40 CFR 60.8, the Permittee shall conduct an initial performancetest within 60 days after achieving the maximum production rate at which the facility will be operated, but no laterthe Permittee shall conduct an initial performance test : Due 180 calendar days after Initial Startup Date. Theperformance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, usingEPA Reference Method 18, 25A, and 320, or other method approved by MPCA in the performance test planapproval.

36

Volatile Organic Compounds : Whichever comes first, the Permittee shall conduct a performance test every8,760 hours or conduct a performance test : Due after Initial Performance Test Date every 36 months. Theperformance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, usingEPA Reference Method 18, 25A, and 320, or other method approved by MPCA in the performance test planapproval.


38The Permittee shall submit a notification of the actual date of initial startup: Due 15 calendar days after InitialStartup Date. Submit the name and number of the Subject Item and the date of startup. Startup is as defined inMinn. R. 7005.0100, subp. 42a.

1 Particulate Matter <= 0.40 pounds per million Btu heat input (The potential to emit from the unit is 0.00745lb/MMBtu due to equipment design and allowable fuels.).

40 CFR 60.4243(b)(2)(ii), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150, Minn. R. 7017.2020

40 CFR 60.4243(b)(2)(ii), 40 CFR63.6590(c), Minn. R. 7011.2310, Minn.R. 7011.8150, Minn. R. 7017.2020,subp. 1









38

The Permittee shall submit a notification of the actual date of initial startup: Due 15 calendar days after InitialStartup Date. Submit the name and number of the Subject Item and the date of startup. Startup is as defined inMinn. R. 7005.0100, subp. 42a.

EQUI 6 1Particulate Matter <= 0.40 pounds per million Btu heat input (The potential to emit from the unit is 0.00745lb/MMBtu due to equipment design and allowable fuels.).

2 Opacity <= 20 percent opacity except for one six-minute period per hour of not more than 60 percent opacity.

3


Design Requirements;0.3583 MMBtu/hr capacity.

EQUI 7 1Particulate Matter <= 0.40 pounds per million Btu heat input (The potential to emit from the unit is 0.00745lb/MMBtu due to equipment design and allowable fuels.).

2 Opacity <= 20 percent opacity except for one six-minute period per hour of not more than 60 percent opacity.

3


Design Requirements;0.3583 MMBtu/hr capacity.

Minn. R. 7011.0515, subp. 1

Minn. R. 7011.0515, subp. 2

Minn. R. 7007.0800, subp. 2

Minn. R. 7011.0515, subp. 1

Minn. R. 7011.0515, subp. 2

Minn. R. 7007.0800, subp. 2



Attachment 3. Subject item inventory/details

Category Type ID Designation Description Groups Include In Permit Sort Order End Date

Equipment Process Heater EQUI0000000006 Heater 1 None Yes

Equipment Process Heater EQUI0000000007 Heater 2 None Yes

Equipment Reciprocating IC Engine EQUI0000000001 EU002 Emergency Generator None Yes

Equipment Reciprocating IC Engine EQUI0000000005 Reciprocating IC Engine None Yes

Equipment Turbine EQUI0000000002 EU001 Natural Gas Turbine COMG0000000002 Yes

Equipment Turbine EQUI0000000004 Solar mars Turbine 100‐16000S COMG0000000002 Yes

Fugitive Equipment Leaks FUGI0000000001 FS003 115 Flanges None Yes

Fugitive Equipment Leaks FUGI0000000002 FS002 1 Compressor Seal None Yes

Fugitive Equipment Leaks FUGI0000000003 FS001 60 Valves None Yes

Structure Stack/Vent STRU0000000001 SV001 Solar Mars Turbine 100 – T15000S Stack None Yes

Structure Stack/Vent STRU0000000002 SV002 None Yes

Structure Stack/Vent STRU0000000003 Solar Mars Turbine 100 – 16000S Stack None Yes

Structure Stack/Vent STRU0000000004 Caterpillar G3512 Generator Stack None Yes

Structure Stack/Vent STRU0000000005 Process Heater None Yes

Structure Stack/Vent STRU0000000006 Process Heater None Yes

Total Facility Air Quality Total Facility TFAC0000000001 13100058 Northern Natural Gas Co ‐ Faribault None Yes 1.00

Category Type ID Designation Description Components Include In Permit Sort Order

Component Group Air Component Group COMG0000000002 Limits to avoid Part 70 EQUI0000000002, EQUI0000000004 Yes

Category Type ID Designation Description Sort OrderAI Conventional site AISI0000001293 1.00

Attachment 4. Points Calculator

Points Calculator

1) AI ID No.: 1293 Total Points 652) Facility Name: Northern Natural Gas Co - Faribault Compressor 3) Small business? y/n? n 4) Air Project Tracking Numbers (including all 5568 5) Date of each Application Received: May 20, 20166) Final Permit No. 13100058-1017) Permit Staff AW

Total TotalApplication Type Air Project Tracking No. Tempo Activity ID Qty. Points Points Additionl Cost DetailsAdministrative Amendment 1 0 -$ Minor Amendment 4 0 -$ Applicability Request 10 0 -$ Moderate Amendment 15 0 -$ Major Amendment 5568 IND20160001 1 25 25 7,125.00$ Individual State Permit (not reissuance) 50 0 -$ Individual Part 70 Permit (not reissuance) 75 0 -$

Additional PointsModeling Review 15 0 -$

BACT Review 15 0 -$ LAER Review 15 0 -$ CAA section 110(a)(2)(D)(i)(I) Review (i.e., Transport Rule/CAIR/CSAPR)

10 0 -$

Part 75 CEM analysis 10 0 -$ NSPS Review 5568 IND20160001 2 10 20 5,700.00$ KKKK, JJJJNESHAP Review 5568 IND20160001 1 10 10 2,850.00$ ZZZZCase-by-case MACT Review 20 0 -$ Netting 10 0 -$ Limits to remain below threshold 5568 IND20160001 1 10 10 2,850.00$ Part 70Plantwide Applicability Limit (PAL) 20 0 -$ AERA review 15 0 -$ Variance request under 7000.7000 35 0 -$ Confidentiality request under 7000.1300 2 0 -$ EAW review 0Part 4410.4300, subparts 18, item A; and 29 15 0 -$ Part 4410.4300, subparts 8, items A & B; 10, items A to C; 16, items A & D; 17, items A to C & E to G; and 18, items B & C

35 0 -$

Part 4410.4300, subparts 4; 5 items A & B; 13; 15; 16, items B & C; and 17 item D

70 0 -$

Add'l Points 40

NOTES:

(DQ Points)

Attachment 5. Manufacturer Information and Data to Support PTE Calculations

EQUI 1 Manufacturer Data to support Emission Factors

SOLAR TURBINES INCORPORATED DATE RUN: 16-Oct-15ENGINE PERFORMANCE CODE REV. 4.16.1.18.10 RUN BY: Michael E ClayCUSTOMER: NNGJOB ID: Faribault

--- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 1

HP=16696, %Full Load=100.0, Elev= 1000ft, %RH= 60.0, Temperature=-20.0F

GENERAL INPUT SPECIFICATIONS

ENGINE FUEL: SD NATURAL GAS 28.86 in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY 0.0002 --- SP. HUMIDITY (LBM H2O/LBM DRY AIR)

FUEL GAS COMPOSITION (VOLUME PERCENT)LHV (Btu/Scf) = 939.2 SG = 0.5970 W.I. @60F (Btu/Scf) = 1215.6

Methane (CH4) = 92.7899 Ethane (C2H6) = 4.1600 Propane (C3H8) = 0.8400 N-Butane (C4H10) = 0.1800 N-Pentane (C5H12) = 0.0400 Hexane (C6H14) = 0.0400 Carbon Dioxide (CO2) = 0.4400 Hydrogen Sulfide (H2S) = 0.0001 Nitrogen (N2) = 1.5100

STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: 29.92 in HgNORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: 29.92 in Hg

GENERAL OUTPUT DATA

6221. lbm/hr FUEL FLOW 2275.60 Scfm FUEL FLOW 20612. Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE 80001. Scfm EXHAUST FLOW @ 14.7 PSIA & 60F 209666. Acfm ACTUAL EXHAUST FLOW CFm 361707. lbm/hr EXHAUST GAS FLOW 28.60 --- MOLECULAR WEIGHT OF EXHAUST GAS 57.29 --- AIR/FUEL RATIO

EXHAUST GAS ANALYSIS

ARGON CO2 H2O N2 O2

0.91 3.02 5.79 75.81 14.48 VOLUME PERCENT WET 0.96 3.20 0.00 80.47 15.37 VOLUME PERCENT DRY 4579. 16785. 13189. 268567. 58580. lbm/hr 0.74 2.70 2.12 43.17 9.42 g/(g FUEL)



HP=16427, %Full Load=100.0, Elev= 1000ft, %RH= 60.0, Temperature= 0.0F






!!! PLEASE, SUBMIT INQUIRY ON GAS FUEL SUITABILITY TO SAN DIEGO !!!

GENERAL OUTPUT DATA



ARGON CO2 H2O N2 O2



NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 2

Fuel: SD NATURAL GAS Customer: NNG Water Injection: NO Inquiry Number: SL15-0009 Model: MARS 100-16000S CS/MD STANDARD GAS Emissions Data: REV. 1.0

The following predicted emissions performance is based on the following specificsingle point:


NOX CO UHC 15.00 25.00 25.00 PPMvd at 15% O2 32.91 33.40 19.13 ton/yr 0.060 0.061 0.035 lbm/MMBtu (Fuel LHV) 7.51 7.63 4.37 lbm/hr 0.21 0.21 0.12 g/(Hp-hr) (gas turbine shaft pwr) 0.054 0.055 0.032 lbm/MMBtu (Fuel HHV)

NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F or -20 deg C, and between 50% and 100% load or gas, fuel, and between 65% and 100% load for liquid fuel except for the Centaur 40). An emission warranty for non-SoLoN x equipment is available for greater than 0 deg F or -20 deg C an 3. Fuel must meet Solar standard fuel specification ES 9-98. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as non- warranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event.










GENERAL OUTPUT DATA



ARGON CO2 H2O N2 O2




HP=12303, %Full Load=100.0, Elev= 1000ft, %RH= 60.0, Temperature=100.0F







GENERAL OUTPUT DATA



ARGON CO2 H2O N2 O2






HP=12303, %Full Load=100.0, Elev= 1000ft, %RH= 60.0, Temperature=100.0F




MARS 100-16000S CS/MD STANDARD GAS TMG-2S REV. 1.0

DATA FOR MINIMUM PERFORMANCE

Fuel Type SD NATURAL GAS

Elevation feet 1000 Inlet Loss in H2O 4.0 Exhaust Loss in H2O 4.0 Accessory on GP Shaft HP 27.8

Engine Inlet Temp.** deg F -20.0 0 40.0 60.0 80.0 100.0 Relative Humidity % 60.0 60.0 60.0 60.0 60.0 60.0 Elevation Loss HP 630 620 576 546 508 465 Inlet Loss HP 274 271 256 245 232 217 Exhaust Loss HP 102 102 99 97 94 90

Driven Equipment Speed RPM 9443 9388 9206 9056 8858 8625 Optimum Equipment Speed RPM 9443 9388 9206 9056 8858 8625 Gas Generator Speed RPM 11168 11168 11168 11159 11158 11156

Specified Load HP FULL FULL FULL FULL FULL FULL Net Output Power HP 16696 16427 15272 14459 13435 12303 Fuel Flow mmBtu/hr 128.24 124.99 116.79 111.96 106.25 100.40 Heat Rate Btu/HP-hr 7681 7608 7648 7744 7908 8161 Therm Eff % 33.128 33.442 33.271 32.858 32.174 31.179

Inlet Air Flow lbm/hr 356413 348571 329713 316831 301636 283654 Engine Exhaust Flow lbm/hr 361707 353728 334522 321439 306006 287787 PCD psiG 258.3 255.0 241.6 232.3 221.0 207.8 Compensated PTIT deg F 1325 1334 1351 1360 1360 1360 PT Exit Temperature deg F 855 864 892 909 925 946 Exhaust Temperature deg F 854 864 892 909 925 946





This performance was calculated with a basic inlet and exhaust system. Special equipment such as low noise silencers, special filters, heat recovery systems or cooling devices will affect engine performance. Performance shown is "Expected" performance at the pressure drops stated, not guaranteed.

**Cannot guarantee emissions with ambient temperature below 0 deg F. Please submit SER for this application.

PREDICTED EMISSION PERFORMANCE

Customer

NNG Job ID

Faribault Inquiry Number

SL15-0009 Run By Date Run

Michael E Clay 16-Oct-15

Engine Model

MARS 100-16000S CS/MD STANDARD

Fuel Type Water Injection

SD NATURAL GAS NO Engine Emissions Data

REV. 1.0

NOx EMISSIONS CO EMISSIONS UHC EMISSIONS

2 16427 HP 100.0% Load Elev. 1000 ft Rel. Humidity 60.0% Temperature 0 Deg. F

15.00 25.00 25.00 PPMvd at 15% O2 32.91 33.40 19.13 ton/yr 0.060 0.061 0.035 lbm/MMBtu (Fuel LHV) 7.51 7.63 4.37 lbm/hr 0.21 0.21 0.12 g/(Hp-hr)

(gas turbine shaft pwr) 0.054 0.055 0.032 lbm/MMBtu (Fuel HHV)

3 15272 HP 100.0% Load Elev. 1000 ft Rel. Humidity 60.0% Temperature 40.0 Deg. F



Notes

1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another.

2. Solar’s typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F or -20 deg C, and between 50% and 100% load for gas, fuel, and between 65% and 100% load for liquid fuel (except f or the Centaur 40). An emission warranty for non-SoLoNOx equipment is available for greater than 0 deg F or -20 deg C and betwee

3. Fuel must meet Solar standard fuel specification ES 9-98. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent.

4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as non-warranted emissions of SO2, PM10/2.5, VOC, and formaldehyde.

5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request.

6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event.


Customer

NNG Job ID




Engine Model




REV. 1.0








Notes








Customer

NNG Job ID




Engine Model




REV. 1.0





Notes







PREDICTED ENGINE PERFORMANCE

Customer

NNG Job ID

Faribault Run By Date Run

Michael E Clay 16-Oct-15 Engine Performance Code Engine Performance Data

REV. 4.16.1.18.10 REV. 1.0

Model

MARS 100-16000S Package Type

CS/MD Match

STANDARD Fuel System

GAS Fuel Type

SD NATURAL GAS

DATA FOR MINIMUM PERFORMANCE

Elevation feet 1000 Inlet Loss in H2O 4.0 Exhaust Loss in H2O 4.0 Accessory on GP Shaft HP 27.8

1 2 3 4 5 6

Engine Inlet Temperature deg F -20.0 0 40.0 60.0 80.0 100.0 Relative Humidity % 60.0 60.0 60.0 60.0 60.0 60.0

Driven Equipment Speed RPM 9443 9388 9206 9056 8858 8625

Specified Load HP FULL FULL FULL FULL FULL FULL Net Output Power HP 16696 16427 15272 14459 13435 12303 Fuel Flow mmBtu/hr 128.24 124.99 116.79 111.96 106.25 100.40 Heat Rate Btu/HP-hr 7681 7608 7648 7744 7908 8161 Therm Eff % 33.128 33.442 33.271 32.858 32.174 31.179

Engine Exhaust Flow lbm/hr 361707 353728 334522 321439 306006 287787 PT Exit Temperature deg F 855 864 892 909 925 946 Exhaust Temperature deg F 854 864 892 909 925 946

Fuel Gas Composition (Volume Percent)

Methane (CH4) 92.79 Ethane (C2H6) 4.16 Propane (C3H8) 0.84 N-Butane (C4H10) 0.18 N-Pentane (C5H12) 0.04 Hexane (C6H14) 0.04 Carbon Dioxide (CO2) 0.44 Hydrogen Sulfide (H2S) 0.0001 Nitrogen (N2) 1.51

Fuel Gas Properties LHV (Btu/Scf) 939.2 Specific Gravity 0.5970 Wobbe Index at 60F 1215.6

This performance was calculated with a basic inlet and exhaust system. Special equipment such as low noise silencers, special filters, heat recovery systems or cooling devices will affect engine performance. Performance shown is "Expected" performance at the pressure drops stated, not guaranteed.

G3512ENGINE SPEED (rpm): 1800 RATING STRATEGY: STANDARDCOMPRESSION RATIO: 9.7:1 APPLICATION: PACKAGED GENSETAFTERCOOLER TYPE: SCAC RATING LEVEL: STANDBYAFTERCOOLER - STAGE 2 INLET (ºF): 130 FUEL: NAT GASAFTERCOOLER - STAGE 1 INLET (ºF): 190 FUEL SYSTEM: CAT LOW PRESSUREJACKET WATER OUTLET (ºF): 210 WITH AIR FUEL RATIO CONTROLASPIRATION: TA FUEL PRESSURE RANGE (psig): 0.5-5.0COOLING SYSTEM: JW+OC+1AC, 2AC FUEL METHANE NUMBER: 85CONTROL SYSTEM: ADEM4 W/ IM FUEL LHV (Btu/scf): 905EXHAUST MANIFOLD: DRY ALTITUDE CAPABILITY AT 77ºF INLET AIR TEMP. (ft): 4114COMBUSTION: LOW EMISSION POWER FACTOR: 0.8NOx EMISSION LEVEL (g/bhp-hr NOx): 2.0 VOLTAGE (V): 480-0FAN POWER (BHP): 47

RATING NOTES LOAD 100% 75% 50%PACKAGE POWER (WITH FAN) (1) (2) ekW 750PACKAGE POWER (WITH FAN) (1) (2) KVA 938ENGINE POWER (WITHOUT FAN) (2) bhp 1102GENERATOR EFFICIENCY (1) % 95.3PACKAGE EFFICIENCY (@ 0.8 Power Factor) (ISO 3046/1) (3) % 33.5THERMAL EFFICIENCY (4) % 50.5TOTAL EFFICIENCY (@ 0.8 Power Factor) (5) % 84.0

ENGINE DATAPACKAGE FUEL CONSUMPTION (ISO 3046/1) (6) Btu/ekw-hr 10177PACKAGE FUEL CONSUMPTION (NOMINAL) (6) Btu/ekw-hr 10375ENGINE FUEL CONSUMPTION (NOMINAL) (6) Btu/bhp-hr 7059AIR FLOW (77ºF, 14.7 psia) (WET) (7) (8) ft3/min 2388AIR FLOW (WET) (7) (8) lb/hr 10591FUEL FLOW (60ºF, 14.7 psia) scfm 143COMPRESSOR OUT PRESSURE in HG(abs) 69.1COMPRESSOR OUT TEMPERATURE ºF 280AFTERCOOLER AIR OUT TEMPERATURE ºF 138INLET MAN. PRESSURE (9) in HG(abs) 61.6INLET MAN. TEMPERATURE (MEASURED IN PLENUM) (10) ºF 137TIMING (11) ºBTDC 32EXHAUST TEMPERATURE - ENGINE OUTLET (12) ºF 991EXHAUST GAS FLOW (@engine outlet temp, 14.5 psia) (WET) (13) (8) ft3/min 6959EXHAUST GAS MASS FLOW (WET) (13) (8) lb/hr 10984

EMISSIONS DATA - ENGINE OUTNOx (as NO2) (14) (15) g/bhp-hr 2.00CO (14) (16) g/bhp-hr 1.86THC (mol. wt. of 15.84) (14) (16) g/bhp-hr 2.26NMHC (mol. wt. of 15.84) (14) (16) g/bhp-hr 0.34NMNEHC (VOCs) (mol. wt. of 15.84) (14) (16) (17) g/bhp-hr 0.23HCHO (Formaldehyde) (14) (16) g/bhp-hr 0.38CO2 (14) (16) g/bhp-hr 500EXHAUST OXYGEN (14) (18) % DRY 9.2LAMBDA (14) (18) 1.70

ENERGY BALANCE DATALHV INPUT (19) Btu/min 129688HEAT REJECTION TO JACKET WATER (JW) (20) (28) Btu/min 28739HEAT REJECTION TO ATMOSPHERE (21) Btu/min 4871HEAT REJECTION TO LUBE OIL (OC) (22) (28) Btu/min 5481HEAT REJECTION TO EXHAUST (LHV TO 77ºF) (23) (24) Btu/min 36810HEAT REJECTION TO EXHAUST (LHV TO 248ºF) (23) Btu/min 27348HEAT REJECTION TO A/C - STAGE 1 (1AC) (25) (28) Btu/min 3259HEAT REJECTION TO A/C - STAGE 2 (2AC) (26) (29) Btu/min 2811PUMP POWER (27) Btu/min 971

CONDITIONS AND DEFINITIONS

For notes information consult page 3.

Data generated by Gas Engine Data Master Version 5.01.00Ref. Data Set G15-3500-224-00-001, Printed 7/29/2015 Page 1 of 3

The engine technical performance data listed above is preliminary in nature and can change as the development program for this new product progresses. This data represents Caterpillar's best knowledge to date on this product but carries no guarantees or warranty, either expressed or implied. This data will be superseded by the final production data when the product completes the development program and the production data is published in TMI. This data should not be used for final designs, sizing, purchase of equipment or financial calculations as it is subject to change.

GAS ENGINE TECHNICAL DATA

Emission levels are at engine exhaust flange prior to any after treatment. Values are based on engine operating at steady state conditions, adjusted to the specified NOx level as 100% load. Tolerances are dependent upon fuel quality. Fuel methane number cannot vary more than ± 3. Published part load data is with air fuel ratio control.

Engine rating obtained and presented in accordance with ISO 3046/1. Standard reference conditions of 77ºF, 29.60 IN HG barometric pressure. No overload permitted at rating shown. Consult the altitude deration factor chart for applications that exceed the rated altitude or temperature.

G3512FUEL USAGE GUIDE:

ALTITUDE DERATION FACTORS:

ACTUAL ENGINE RATING:

To determine the actual power available, take the lowest factor between 1) and 2).1) Fuel usage Guide Deration2) 1-((1-Altitude/Temperature Deration) + (1-RPC))

AFTERCOOLER HEAT REJECTION FACTORS(ACHRF):

NOTES:

Data generated by Gas Engine Data Master Version 5.01.00Ref. Data Set G15-3500-224-00-001, Printed 7/29/2015 Page 2 of 3

25. Heat rejection to A/C - Stage 1 based on treated water. Tolerance is ±5% of full load data.26. Heat rejection to A/C - Stage 2 based on treated water. Tolerance is ±5% of full load data.27. Pump power includes engine driven jacket water and aftercooler water pumps. Engine brake power includes effects of pump power.

29. Total Second Stage Aftercooler Circuit heat rejection is calculated as: (2AC x 1.05) + [(1AC + 2AC) x 0.15 x (ACHRF - 1) x 1.05]. Heat exchanger sizing criterion is maximum circuit heat rejection at site conditions, with applied tolerances. A cooling system safety factor may be multiplied by the total circuit heat rejection to provide additional margin.

1. Generator efficiencies, power factor, and voltage are based on standard generator. [Package Power (ekW) is calculated as: (Engine Power (bkW) - Fan Power (bkW)) x Generator Efficiency], [Package Power (kVA) is calculated as: (Engine Power (bkW) - Fan Power (bkw)) x Generator Efficiency / Power Factor]2. Rating is with two engine driven water pumps. Tolerance is (+)3, (-)0% of full load.

4. Thermal Efficiency is calculated based on energy recovery from the jacket water, lube oil, 1st stage aftercooler, and exhaust to 248ºF with engine operation at ISO 3046/1 Package Efficiency, and assumes unburned fuel is converted in an oxidation catalyst.

6. ISO 3046/1 Package fuel consumption tolerance is (+)5, (-)0% at the specified power factor. Nominal package and engine fuel consumption tolerance is ± 3.0% of full load data at the specified power factor.

13. Exhaust flow value is on a 'wet' basis. Flow is a nominal value with a tolerance of ± 6 %.

24. Heat rejection to exhaust (LHV to 77ºF) value shown includes unburned fuel and is not intended to be used for sizing or recovery calculations.

28. Total Jacket Water Circuit heat rejection is calculated as: (JW x 1.1) + (OC x 1.2) + (1AC x 1.05) + [0.85 x (1AC + 2AC) x (ACHRF - 1) x 1.05]. Heat exchanger sizing criterion is maximum circuit heat rejection at site conditions, with applied tolerances. A cooling system safety factor may be multiplied by the total circuit heat rejection to provide additional margin.


9. Inlet manifold pressure is a nominal value with a tolerance of ± 5 %.

To determine the actual rating of the engine at site conditions, one must consider seperately, limitations due to fuel characteristics and air system limitations. The fuel usage guide deration establishes fuel limitations. The altitude/temperature deration factors and the RPC (reference to the Caterpillar Methane Program) establish air system limitations. RPC comes into play when the altitude/temperature deration is less than 1.0 (100%). Under this condition, add the two factors together. When the site conditions do not require an altitude/temperature derate (factor is 1.0), it is assumed the turbocharger has sufficient capability to overcome the low fuel relative power, and RPC is ignored.

To maintain a constant air inlet manifold temperature, as the inlet air temperature goes up, so must the heat rejection. As altitude increases, the turbocharger must work harder to overcome the lower atmospheric pressure. This increases the amount of heat that must be removed from the inlet air by the aftercooler. Use the aftercooler heat rejection factor (ACHRF) to adjust for inlet air temp and altitude conditions. See notes 28 and 29 for application of this factor in calculating the heat exchanger sizing criteria. Failure to properly account for these factors could result in detonation and cause the engine to shutdown or fail.

This table shows the derate factor and full load set point timing required for a given fuel. Note that deration and set point timing reduction may be required as the methane number decreases. Methane number is a scale to measure detonation characteristics of various fuels. The methane number of a fuel is determined by using the Caterpillar methane number calculation program.

This table shows the deration required for various air inlet temperatures and altitudes. Use this information along with the fuel usage guide chart to help determine actual engine power for your site.

3. Package Efficiency published in accordance with ISO 3046/1, based on a 0.8 power factor.

8. Inlet and Exhaust Restrictions must not exceed A&I limits based on full load flow rates from the standard technical data sheet.

5. Total efficiency is calculated as: Package Efficiency + Thermal Efficiency. Tolerance is ±10% of full load data.

17. VOCs - Volatile organic compounds as defined in US EPA 40 CFR 60, subpart JJJJ

10. Inlet manifold temperature is a nominal value with a tolerance of ± 9°F.

12. Exhaust temperature is a nominal value with a tolerance of (+)63°F, (-)54°F.11. Timing indicated is for use with the minimum fuel methane number specified. Consult the appropriate fuel usage guide for timing at other methane numbers.

23. Exhaust heat rate based on treated water. Tolerance is ± 10% of full load data.22. Lube oil heat rate based on treated water. Tolerance is ± 20% of full load data.

19. LHV rate tolerance is ± 3.0%.20. Heat rejection to jacket water value displayed includes heat to jacket water alone. Value is based on treated water. Tolerance is ± 10% of full load data.21. Heat rejection to atmosphere based on treated water. Tolerance is ± 50% of full load data.

14. Emissions data is at engine exhaust flange prior to any after treatment.

18. Exhaust Oxygen tolerance is ± 0.5; Lambda tolerance is ± 0.05. Lambda and Exhaust Oxygen level are the result of adjusting the engine to operate at the specified NOx level.

7. Air flow value is on a 'wet' basis. Flow is a nominal value with a tolerance of ± 5 %.

15. NOx values are "Not to Exceed".16. CO, CO2, THC, NMHC, NMNEHC, and HCHO values are "Not to Exceed" levels. THC, NMHC, and NMNEHC do not include aldehydes. An oxidation catalyst may be required to meet Federal, State or local CO or HC requirements.

G3512

Transient Load Acceptance

Load Step Recovery Time

Classification as Defined by ISO 8528 -

5Notes

sec

100 10

90 10

80 10

60 10 G1 2

40 6 G2 3

Breaker Open 5 1

Steady State Specification

Recovery Specification

Transient Information

Notes1

2

3

Data generated by Gas Engine Data Master Version 5.01.00 Ref. Data Set G15-3500-224-00-001, Printed 7/29/2015 Page 3 of 3

+1.75 / ‐1.75

+1.25 / ‐1.25

+25 / ‐25

+12 / ‐10 +25 / ‐20

+35 / ‐35

+5 / ‐5

+5 / ‐5

+17 / ‐17 +48 / ‐48

+16 / ‐16 +46 / ‐46

+35 / ‐25+18 / ‐15


Fuel supply pressure and stability is critical to transient performance. Proper installation requires that all fuel train components (including filters, shut off valves, and regulators)

be sized to ensure adequate fuel be delivered to the engine. The following are fuel pressure requirements to be measured at the engine mounted fuel control valve.

B. Transient fuel Pressure Stability +/‐ 48.2 mbar/sec (+/‐ 0.7 psi/sec)

Inlet water temperature to the SCAC must be maintained at specified value for all engines. It is important that the external cooling system design is able to maintain the inlet

water temp to the SCAC to within +/‐ 1 °C during all engine‐operating cycles. The SCAC inlet temperature stability criterion is to maintain stable inlet manifold air temperature.

The Air Fuel Ratio control system requires up to 180 seconds to converge after a load step has been performed for NOx to return to nominal setting. If the stabilization time is

not met between load steps the transient performance listed in the document may not be met.

Engine Governor gains and Voltage regulator settings may need to be tuned for site conditions.

Differences in generator inertia may change the transient response of engine.

The transient load steps listed above are stated as a percentage of the engine’s full rated load as indicated in the appropriate performance technical data sheet. Site ambient

conditions, fuel quality, inlet/exhaust restriction and emissions settings will all affect engine response to load change. Engines that are not operating at the standard conditions

stated in the technical data sheet should be set up according to the guidelines included in the technical data; applying timing changes and/or engine derates as needed.

Adherence to the engine settings guidelines will allow the engines to retain the transient performance stated in the tables above as a percentage of the site derated power

(where appropriate).

A. Steady State Fuel Pressure Stability +/‐ 6.9 mbar/sec (+/‐ 0.1 psi/sec)

Frequency Deviation

+/- Voltage Deviation

+/-% %

+19 / ‐19 +50 / ‐50

drop to no load. In the event that the generator load drops to zero the strategy resets all control inputs to the rated idle condition. This prevents engine over speeding and

will allow the engine to remain running unloaded at the rated synchronous speed.

The engine was tested against the voltage deviation, frequency deviation, and recovery time requirements defined in ISO 8528 ‐ 5. At this time the engine will meet class

G1 transient performance as defined by ISO 8528 ‐ 5 with excpetions.

The engine was tested against the voltage deviation, frequency deviation, and recovery time requirements defined in ISO 8528 ‐ 5. At this time the engine will meet class

G2 transient performance as defined by ISO 8528 ‐ 5 with excpetions.

Engines must be maintained in accordance to guidelines specified in the Caterpillar Service Manuals applicable to each engine. Wear of components outside of the specified

tolerances will affect the transient capability of the engine.

Data is representative of a properly warmed engine which is achieved when engine reaches nominal operating temperatures under steady state conditions.

For unloading the engine to 0% load from a loaded condition no external input is needed. The engine control algorithm employs a load sensing strategy to determine a load

0

20

40

60

80

100

120

0 10 20 30 40 50 60 70 80 90 100

Load

Step (%)

Initial Load (%)

Load Acceptance

Max

G1

G2

Manufacturer Data to support Emission Factors for EQUIs 2 and 4 when temperatures are less than 0° F

Solar Turbines Incorporated Product Information Letter 167

SoLoNOx Products: Emissions in Non-SoLoNOx Modes

Leslie Witherspoon Solar Turbines Incorporated

PURPOSE Solar’s gas turbine dry low NOx emissions combustion systems, known as SoLoNOx™, have been developed to provide the lowest emissions possible during normal operating conditions. In order to optimize the performance of the turbine, the combustion and fuel systems are designed to reduce NOx, CO and unburned hydrocarbons (UHC) without penalizing stability or transient capabilities. At very low load and cold temperature extremes, the SoLoNOx system must be controlled differently in order to assure stable operation. The required adjustments to the turbine controls at these conditions cause emissions to increase. The purpose of this Product Information Letter is to provide emissions estimates, and in some cases warrantable emissions for NOx, CO and UHC, at off-design conditions. Historically, regulatory agencies have not required a specific emissions level to be met at low load or cold ambient operating conditions, but have asked what emissions levels are expected. The expected values are necessary to appropriately estimate emissions for annual emissions inventory purposes and for New Source Review applicability determinations, air dispersion modeling, and permitting.

COLD AMBIENT EMISSIONS ESTIMATES Solar’s standard temperature range warranty for gas turbines with SoLoNOx combustion is ≥ 0°F (–20°C). The Titan™ 250 is an exception, with a lower standard warranty at ≥ –20°F (–29°C). At ambient temperatures below 0°F, many of Solar’s turbine engine models are controlled to increase pilot fuel which improves flame stability but leads to higher emissions. Without the increase in pilot fuel at temperatures below 0°F the engines may exhibit combustor rumble, as operation may be near the lean stability limit. If a cold ambient emissions warranty is requested, a new production turbine configured with the latest combustion hardware is required. For most models this refers to the inclusion of “Cold Ambient Fuel Control Logic”. A cold ambient emissions warranty is only available on gas turbines being fired on natural gas and not offered for ambient temperatures below –20°F (–29°C). In general, standard natural gas as defined in ES9-98 is required to offer a cold ambient warranty, but non-standard fuels on a project basis can be reviewed by Solar to determine applicability. In addition, cold ambient emissions warranties cannot be offered for the Centaur® 40 turbine. Note that a cold ambient warranty cannot be offered for liquid fuel operation at this time. Table 1 provides expected and warrantable (upon Solar’s documented approval) emissions levels for Solar’s SoLoNOx combustion turbines. All emissions levels are in ppm at 15% O2. Refer to Product Information Letter 205 for Mercury™ 50 turbine emissions estimates. For information on the availability and approvals for cold ambient temperature emissions warranties, please contact Solar’s sales representatives.

Product Information Letter

PIL 167

PIL 167 Revision 5 31 March 2015 © 2015 Solar Turbines Incorporated Caterpillar Confidential Green: Information contained herein is to be treated as Confidential and Proprietary to Caterpillar.

1


Table 1. Warrantable Emissions Between 0°F and –20°F (–20° to –29°C)

for New Production (NOx ppm values corrected to 15% O2.)

Turbine Model Fuel System Fuel Applicable

Load NOx, ppm

CO, ppm

UHC, ppm

Centaur 50 Gas Only Gas 50 to 100% load 42 100 50 Dual Fuel Gas 50 to 100% load 72 100 50

Taurus™ 60 Gas Only or Dual Fuel Gas 50 to 100% load 42 100 50 Taurus 65 Gas Only Gas 50 to 100% load 42 100 50 Taurus 70 Gas Only or Dual Fuel Gas 50 to 100% load 42 100 50 Mars® 90 Gas Only Gas 50 to 100% load 42 100 50 Mars 100 Gas Only or Dual Fuel Gas 50 to 100% load 42 100 50 Titan 130 Gas Only or Dual Fuel Gas 50 to 100% load 42 100 50

Titan 250 Gas Only Gas 40 to 100% load 25 50 25 Gas Only Gas 40 to 100% load 15 25 25

Table 2 summarizes “expected” emissions levels for ambient temperatures below 0°F (–20°C) for Solar’s SoLoNOx turbines that do not have current production hardware or for new production hardware that is not equipped with the Cold Ambient Fuel Control Logic. The emissions levels are extrapolated from San Diego factory tests and may vary at extreme temperatures and as a result of variations in other parameters, such as fuel composition, fuel quality, etc. For more conservative NOx emissions estimate on new equipment, customers can refer to the New Source Performance Standard (NSPS) 40CFR60, subpart KKKK, where the allowable NOx emissions level for ambient temperatures < 0°F (–20°C) is 150 ppm NOx at 15% O2. For pre-February 18, 2005, SoLoNOx combustion turbines subject to 40CFR60 subpart GG, a conservative estimate is the appropriate subpart GG emissions level. Subpart GG levels range from 150 to 214 ppm NOx at 15% O2 on natural gas (and 150-210 on liquid fuel) depending on the turbine model. Table 2. Expected Emissions below 0°F (–20°C) for SoLoNOx Combustion

Turbines (NOx ppm values corrected to 15% O2.)

Turbine Model Fuel System Fuel Applicable

Load NOx, ppm

CO, ppm

UHC, ppm

Centaur 40 Gas Only or Dual Fuel Gas 80 to 100% load 120 150 50

Centaur 50 Gas Only Gas 50 to 100% load 120 150 50 Dual Fuel Gas 50 to 100% load 120 150 50

Taurus 60 Gas Only or Dual Fuel Gas 50 to 100% load 120 150 50 Taurus 65 Gas Only Gas 50 to 100% load 120 150 50 Taurus 70 Gas Only or Dual Fuel Gas 50 to 100% load 120 150 50 Mars 90 Gas Only Gas 80 to 100% load 120 150 50

Mars 100 Gas Only or Dual Fuel Gas 50 to 100% load 120 150 50 Titan 130 Gas Only or Dual Fuel Gas 50 to 100% load 120 150 50

Centaur 40 Dual Fuel Liquid 80 to 100% load 150 150 75 Centaur 50 Dual Fuel Liquid 65 to 100% load 150 150 75 Taurus 60 Dual Fuel Liquid 65 to 100% load 150 150 75 Taurus 70 Dual Fuel Liquid 65 to 100% load 150 150 75 Mars 100 Dual Fuel Liquid 65 to 100% load 150 150 75 Titan 130 Dual Fuel Liquid 65 to 100% load 150 150 75

PIL 167 Revision 5 31 March 2015 © 2015 Solar Turbines Incorporated Caterpillar Confidential Green: Information contained herein is to be treated as Confidential and Proprietary to Caterpillar.

2

Manufacturer Data to support PM Emission Factors for Turbines, EQUIs 2 and 4


Particulate Matter Emission Estimates

Leslie Witherspoon Solar Turbines Incorporated

PURPOSE This document summarizes Solar’s recommended PM10/2.5 emission levels for our combustion turbines. The recommended levels are based on an analysis of emissions tests collected from customer sites.

Particulate Matter Definition National Ambient Air Quality Standards (NAAQS) for particulate matter were first set in 1971. Total suspended particulate (TSP) was the first indicator used to represent suspended particles in the ambient air. Since July 1, 1987, the Environmental Protection Agency (EPA) has used the indicator PM10, which includes only the particles with aerodynamic diameter smaller than 10 micrometers (µm). PM10 (coarse particles) come from sources such as windblown dust from the desert or agricultural fields and dust kicked up on unpaved roads by vehicle traffic. The EPA added a PM2.5 ambient air standard in 1997. PM2.5 includes particles with an aerodynamic diameter less than 2.5 µm. PM2.5 (fine particles) are generally emitted from industrial and residential combustion and from vehicle exhaust. Fine particles are also formed in the atmosphere when gases such as sulfur dioxide, nitrogen oxides, and volatile organic compounds, emitted by combustion activities, are transformed by chemical reactions. Nearly all particulate matter from gas turbine exhaust is less than one micrometer (micron) in diameter. Thus the emission rates of TSP, PM10, and PM2.5 from gas turbines are theoretically equivalent although source testing will show variation due to test method detection levels and processes.

TESTING FOR PARTICULATE MATTER The turbine combustion process has little effect on the particulate matter generated and measured. The largest contributor to particulate matter emissions for gas and liquid fired combustion turbines is measurement technique and error. Other, minor contributing, sources of particulate matter emissions include carbon, ash, fuel-bound sulfur, artifact sulfate formation, compressor/lubricating oils, and inlet air. Historical customer particulate matter source test data show that there is significant variability from test to test. The source test results support the common industry argument that particulate matter from natural gas fired combustion sources is difficult to measure accurately. The reference test methods for particulate matter were developed primarily for measuring emissions from coal-fired power plants and other major emitters of particulates. Particulate concentrations from gas turbine can be 100 to 10,000 times lower than the “traditional” particulate sources. The test methods were not developed or verified for low emission levels. There are interferences, insignificant at higher exhaust particulate matter concentrations that result in emissions greater than the actual emissions from gas turbines. New methods are being developed to address this problem. Due to measurement and procedural errors, the measured results, in most cases, may not be representative of actual particulate matter emitted. There are many potential error sources in measuring particulate matter. Most of these have to do with contamination of the samples, material from the sampling apparatus getting into the samples, and general human error in samples and analysis. Over the past few years, source test firms are gaining experience in measuring particulate matter and the variability that we’ve seen historically from test to test and the emissions levels measured has decreased.

Product Information Letter PIL 171

PIL 171 Revision 5 6 May 2015 Caterpillar Confidential Green: Information contained herein is to be treated as Confidential and Proprietary to Caterpillar. © 2015 Solar Turbines Incorporated

1


Recommended Particulate Matter Emission Factors When necessary to support the air permitting process Solar recommends the following PM10/2.5 emission factors:

• Pipeline Natural Gas*: 0.015 lb/MMBtu fuel input (HHV) • Landfill Gas†: 0.03 lb/MMBtu fuel input (HHV) • Liquid Fuel#: 0.039 lb/MMBtu fuel input (HHV)

* Pipeline natural gas emissions factor assumes <1 grains of Sulfur per 100 standard cubic feet. † Landfill gas emissions factor assumes <0.15 lb SO2/MMBtu heat input. # Liquid fuel emission factor assumes fuel sulfur content is <500 ppm and ash content is <0.005% by wt.

Contact Solar’s Environmental Programs group for particulate matter emissions estimates for fuels not listed above. The conversion of a particulate matter emissions request from mg/Nm3 to lb/MMBtu (HHV) units involves several specific turbine parameters. Please contact Solar if you need the calculation performed. Recent customer source testing has shown that AP-42 (EPA AP-42 "Compilation of Air Pollutant Emission Factors.”) emission factors for natural gas are achievable in the field, when the test method recommendations shown below are followed. Historically, Solar did not recommend using AP-42 because while some source test firms have measured below AP-42 levels, others have measured higher. Because particulate matter emissions levels are highly dependent on the test firm and have very little to do with the turbine, Solar does not warrant AP-42 levels but does recognize they are achievable in the field. Customers generally choose a particulate matter emissions factor at or above the AP-42 level that works for their site permitting recognizing that the lower the emissions factor the higher the risk for source testing.

Test Method Recommendation Solar recommends that EPA Methods 201/201A¹ be used to measure the “front half”. “Front half” represents filterable particulate matter. EPA Method 202² (with nitrogen purge and field blanks) should be used to measure the “back half”. “Back half” measurements represent the condensable portion of particulate matter. EPA Method 5³, which measures the front and back halves may be substituted (e.g. where exhaust temperatures do not allow the use of Method 202). The turbine should have a minimum of 300 operating hours prior to conducting particulate matter source testing. The turbine should be running for 3-4 hours prior to conducting a particulate matter source test so that the turbine and auxiliary equipment is in a sustained “typical” operating mode prior to gathering samples. Testing should include three 4-hour test runs. Solar recommends using the aforementioned test methods until more representative test methods are developed and widely commercially available.

References ¹ EPA Method 201, Determination of PM10 Emissions, Exhaust Gas Recycle Procedure. EPA Method 201A, Determina-tion of PM10 Emissions, Constant Sampling Rate Procedure, 40 CFR 60, Part 60, Appendix A. ² EPA Method 202, Determination of Condensible Particulate Emissions from Stationary Sources, 40 CFR 60, Part 60, Appendix A. ³ EPA Method 5, Determination of Particulate Emissions from Stationary Sources, 40 CFR 60, Part 60, Appendix A.

Solar Turbines Incorporated 9330 Sky Park Court San Diego, CA 92123-5398 Cat and Caterpillar are registered trademarks of Caterpillar Inc. Solar, Saturn, Centaur, Taurus, Mercury, Mars, Titan, SoLoNOx, Turbotronic, InSight System, and InSight Connect, are trademarks of Solar Turbines Incorporated. All other trademarks are the intellectual property of their respective companies. © 2015 Solar Turbines Incorporated. All rights reserved. Specifications are subject to change without notice.

PIL 171 Revision 5 6 May 2015 Caterpillar Confidential Green: Information contained herein is to be treated as Confidential and Proprietary to Caterpillar. © 2015 Solar Turbines Incorporated

2

Attachment 6. Performance testing report for EQUI 2

Doc 5724151

Attachment 7. Sulfur monitoring records

Location: Faribault Compressor StationUnit(s): 1 Solar TurbineApplicable Standard: less than 0.8% total sulfur (0.8% = 3774 ppmv)Applicable Standard: 0.06 lbs SO2/MMBTU (0.06 = 356 PPM at 1,000 BTU/SCF)Tube Model Number: Draeger accuro Pump/Draeger Short Term Dectection Tube/Hydrogen SulfideTube Detection Range: Measurement range 0.2 to 5 ppm with 10 strokesAllowable Gas Temperature Range: 35.6 to 104 degrees FahrenheitMinimum Bottle Purge Time: 3 minutesTest Frequency: Semi-annually during the 1st and 3rd quarters of the calendar year

3/17/2016 10 0.4 0.001124 0.000084988 CS good 3min HM-2201 2/1/2018 53.60 00 00 00 0

Custom Fuel Sulfur Sampling

Tube Expiration DateDate

Pump Strokes

Reading, ppmv

Test Technician

Pump Leak Test

Bottle Purge Time

Calculation Adjustments

Environmental Procedure 330.102

Gas Temp., F Comments

Tube Batch Number

Pump Maintenance Comments:

% Wt H2S/Sulfur

lbs SO2/ MMBTU

GPA Standard 2377-86

Location: Faribault Compressor StationUnit(s): 1 Solar TurbineApplicable Standard: less than 0.8% total sulfur (0.8% = 3774 ppmv)Applicable Standard: 0.06 lbs SO2/MMBTU (0.06 = 356 PPM at 1,000 BTU/SCF)Tube Model Number: Draeger accuro Pump/Draeger Short Term Dectection Tube/Hydrogen SulfideTube Detection Range: Measurement range 0.2 to 5 ppm with 10 strokesAllowable Gas Temperature Range: 35.6 to 104 degrees FahrenheitMinimum Bottle Purge Time: 3 minutesTest Frequency: Semi-annually during the 1st and 3rd quarters of the calendar year

7/26/2016 10 0.2 0.000562 0.000042494 CS good 3min HM-2201 2/28/2018 74.10 00 00 00 0

Custom Fuel Sulfur Sampling

Tube Expiration DateDate

Pump Strokes

Reading, ppmv

Test Technician

Pump Leak Test

Bottle Purge Time

Calculation Adjustments

Environmental Procedure 330.102

Gas Temp., F Comments

Tube Batch Number

Pump Maintenance Comments:

% Wt H2S/Sulfur

lbs SO2/ MMBTU

GPA Standard 2377-86

Doc 219931237

technical support document draft air emission permit no ... 13100058-101 - 2017_0.pdfnorthern...

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